ML21130A084

Fifth Ten-Year Interval Inservice Inspection Program and Third Ten-Year Interval Containment Inservice Inspection Program, Revision 3

ML21130A084
Person / Time
Site:	Cooper
Issue date:	04/21/2021
From:	Nebraska Public Power District (NPPD)
To:	Office of Nuclear Reactor Regulation
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References
NLS2021013
Download: ML21130A084 (402)

Text

Cooper Station 5th ISI &

3rd Interval CISI Program COOPER NUCLEAR STATION FIFTH TEN-VEAR INTERVAL INSERVICE INSPECTION PROGRAM AND THIRD TEN-VEAR INTERVAL CONTAINMENT INSERVICE INSPECTION PROGRAM REVISION 3 Prepared by: Tim McClure/ -;;z,Ml,t---.- I q_z,~ Zo ISi Engineer Date Reviewed by: Phil L e i~ nin~ A ~ .~ ~ - 1* 2- _ze>

ISi Engineer Date Approved by: Todd Steve Code Programs Supervisor Approved by: Jason Stairs/ ~

EP&C Manager NEBRASKA PUBLIC POWER DISTRICT (1-1) Revision 3.0

Munich RE Nebraska Public Power District 25 September 2020 Cooper Nuclear Station Ryan R Lange PO Box 98 Authorized Nuclear lnseNice lnsp.

Brownsville, NE 68321 Ryan_Lange@HSB.com Attn: Mr. Tim McClure ISi Engineer

!Risk Solutions /

Review of Cooper Nuclear Station Fifth Ten-Year Interval lnservice Inspection The Hartford Steam Boiler Inspection and Insurance Co.

Program and Third Ten-Year Interval Containment lnservice Inspection One State Street Program Revision 3 P.O. Box 5024 Hartford, CT 06102-5024 www.munichre.com/HSB Mr. McClure, The purpose of this memo is to satisfy the requirement given in accordance with The Hartford Steam Boiler Quality Procedure Manual Revision 10 procedure QP 4.10 paragraph 3.3.1 (3) which states the Authorized Nuclear lnservice Inspector shall perform a review of the Owner's 10 Year Inspection plans, implementation schedule and revisions as required by ASME Section XI IWA-2110.

This revision incorporates NPPD Relief Request RRS-04 to use the 2017 Edition of ASME Section XI, specifically sub paragraph IWA-4540(b), which adds "Bolts, studs, nuts, or washers" to the list of components which are excluded from any pressure testing requirements, therefore application of the 2017 Edition of the Code would allow CNS to exclude additional pressure testing for maintenance where mechanical joints are separated.

Reviewed associated NRC Safety Evaluation Report (ML20255A217) which authorized the requested use of ASME Section XI 2017 Edition sub paragraph IWA-4540(b) through the entire ISi 5th Interval.

I have also verified Cooper Nuclear Station personnel have access to the ASME 2007 Edition, 2008 Addenda Code books as required by QAl-1.

Regards, Ryan Lange Authorized Nuclear lnservice Inspector The Hartford Steam Boiler Inspection and Insurance Company Hartford Steam Boiler

Cooper Station 5 th ISI &

3rd Interval CISI Program 1.0 TABLE OF CONTENTS Section Description Pages Revision 1 Table of Contents 1-1 to 1-3 3 2 Revision Summary Sheet 2-1 3 3 Introduction and Program Basis Description 3-1 to 3-36 3 4 Application of Exemption Criteria 4-1 to 4-5 0 5 lnservice Inspection Summary Table 5-1 to 5-22 2 6 lnservice Inspection Technical Approach and 6-1 to 6-5 0 Position Index/Summaries 7 lnservice Inspection Relief Requests and 7-1 to 7-170 3 Requests for Alternatives 8 Pressure Testing 8-1 to 8-4 0 9 System Pressure Testing Technical Approach and 9-1 to 9-6 0 Position Index/Summaries 10 System Pressure Testing Relief Requests and 10-1 to 10-38 3 Requests for Alternatives 11 Augmented lnservice Inspection 11-1 to 11-6 1 12 List of Applicable P&ID's, Isometric and 12-1 to 12-4 0 Component Drawings 13 Nondestructive Examination Procedure Listing 13-1 to 13-2 0 14 Ultrasonic Calibration Blocks 14-1 to 14-7 1 15 Component Examination Summary Tables 15-1 1 16 Index of Abbreviations 16-1 to 16-19 0 17 Risk Informed Program 17-1 to 17-6 3 (1-2) Revision 3. 0

Cooper Station 5th ISI &

3rd In t ervaI CISI P rogram Section Description Pages Revision 18 Commitment Management 18-1 to 18-3 1 19 Containment Indication Tracking 19-1 to 19-61 2 20 lnservice Inspection {ISi) and Containment 20-1 to 20-5 1 Inspection (CISI) History (1-3) Revision 3.0

Cooper Station 5th ISI &

yd Interval CISI Program 2.0 REVISION

SUMMARY

SHEET Section Summary of Changes Revision Date Effective ALL All Sections were updated to the 2007 Edition through the 2008 Addenda of ASME Section XI for the ISi 5th 10-year interval and CISI 3rd 10-year interval.

1 Updated to note new revision. 3 See Coversht.

See Coversht.

2 Updated to note new revision. 3 See Coversht.

3 Updated to include new applicable code cases approved in latest revision of 3

RG 1.147.

4 Initial Issue 0 04/01/16 5 Updated to reschedule R-A component from Period 1 to Period 2. Removed table for augmented inspections per GE SIL 459 associated with Recirc pump shafts and covers. This augmented inspection requirement is not needed as 2 1/24/19 CNS replaced the rotating assemblies and covers to both RR pumps in RE28 and RE29 with a new GEN 4 design. Therefore, SIL recommendations are not applicable.

6 Initial Issue 0 04/01/16 7 Updated to include references to recently NRC approved relief requests, RIS-3 See Coversht.

02, Rev 2 and RRS-04.

8 Initial Issue 0 04/01/16 9 Initial Issue 0 04/01/16 10 Updated to include NRC SE for Relief Request PRS-02 and added Relief 3 See Coversht.

Request RPS-02 and associated NRC SE approval.

11 Update section to remove reference to GE SIL 459 associated with Recirc pump shafts and covers. This augmented inspection requirement is not needed as CNS replaced the rotating assemblies and covers to both RR pumps 1 09/27/18 in RE28 and RE29 with a new GEN 4 design. Therefore, SIL recommendations are not applicable.

12 Initial Issue 0 04/01/16 13 Initial Issue 0 04/01/16 14 Revised to include new RR pump stud UT calibration block No. 145. Replaces 1 09/27/18 old calibration block No. 143.

15 Updated to reference controlled copy document that lists all ASME Section components subject to examination and associated examination schedule by 1 09/27/18 outage.

16 Initial Issue 0 04/01/16 17 Revised to include First Period RI-ISi review and update. 3 See Coversht.

18 Updated to reference revised commitments associated with torus underwater inspections per EE 18-012. Added Commitment NLS2018029-01 to note NRC 1 09/27/18 limitations associated with approval of Relief RRS-03.

19 Updated to include IWE inspection results from RE29. 2 01/24/19 20 Initial Issue 0 04/01/16 (2-1)

Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program

3.0 INTRODUCTION

AND PROGRAM BASIS DESCRIPTION 3.1 Introduction 3.1.1 This Program outlines the requirements for the nondestructive examination of ASME Class 1, 2, and 3 pressure-retaining components and their supports and Class MC (metallic containments) components at Cooper Nuclear Station (CNS). The Primary Containment consists of the Drywell, the Suppression Chamber (torus), and the connecting piping (vent headers).

3.1.2 The Fifth Ten-Year Interval lnservice Inspection (ISi) Program effective start date is April 1, 2016 and end date is February 28, 2026. The Third Ten-Year Interval Containment lnservice Inspection (CISI) Program is aligned with the ISi Program under Request for Alternative RC3-01 "Alignment and Synchronization of the Containment lnservice Inspection (CISI) Program Third Ten-Year Interval with the lnservice Inspection {ISi) Program Fifth Ten-Year Interval."

3.1.3 The key features of this Program are the introduction and program description, relief requests, technical approach and positions, and summary tables. The details of the ISi and CISI Programs are supported by other documents that are available at CNS. These documents include, but are not limited to, component detail drawings, piping and instrumentatio n diagrams, piping isometric drawings, procedures, calibration blocks, and other records required to execute the ISi or CISI Programs at CNS.

3.1.4 Regulatory Bases The regulations in 10 CFR 50.55a(g)(4) establish the effective ASME Code edition and addenda to be used by licensees for performing inservice inspections of components (including supports). Paragraph 50.55a(g)(4)(ii) requires the use of the latest edition and addenda that has been incorporated by 10 CFR 50.SSa(a),

one year prior to the beginning of each 120-month ISi interval. This is considered the Code of Record. The Code of Federal Regulation in effect one year prior to the beginning of the fifth interval was CFR76FR36232 published June 21, 2011. This CFR incorporated, by reference, the ASME Section XI, 2007 Edition with the 2008 Addenda in paragraph (a)(l)(ii) with conditions.

Based on the referenced CFR above, the CNS Fifth Ten-Year Interval ISi and Third Ten-Year Interval CISI Program Plan is based on the requirements of the 2007 Edition through the 2008 Addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI. An updated CFR79FR214 1 was published in November 2014 with the conditions contained in 10 CFR 50.55a(b)(2) as defined below:

1 A correction was issued under CFR79FR238 (3-1) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program 3.1.4.1 10 CFR S0.5Sa(b)(2)(ix)(A)(2), For each inaccessible area identified for evaluation, the applicant or licensee must provide the following in the ISi Summary Report as required by IWA-6000 3.14.1.1 A description of the type and estimated extend of degradation and the conditions that led to the degradations; 3.14.1.2 An evaluation of each area and the result of the evaluation; and 3.14.1.3 A description of necessary corrective actions.

3.1.4.2 10 CFR S0.SSa(b)(2)(ix)(B), Metal containment examinations: second provision. When performing remotely the visual examinations required by Subsection IWE, the maximum direct examination distance specified in Table IWA-2210-1 (IWA-2211-1 in 2007 Ed., 2008 Add.) may be extended and the minimum illumination requirements specified in Table IWA-2210-1 may be decreased provided that the conditions or indications for which the visual examination is performed can be detected at the chosen distance and illumination.

3.1.4.3 10 CFR S0.SSa(b)(2)(ix)(J), Metal containment examinations: tenth provision. In general, a repair/replacement activity such as replacing a large containment penetration, cutting a large construction opening in the containment pressure boundary to replace steam generators, reactor vessel heads, pressurizers, or other major equipment; or other similar modification is considered a major containment modification. When applying IWE-S000 to Class MC pressure-retaining components, any major containment modification or repair/replacement, must be followed by a Type A test to provide assurance of both containment structural integrity and leak tight integrity prior to retuning to service, in accordance with 10 CFR part SO Appendix J, Option A or Option Bon which the applicant's or licensee's Containment Leak-Rate Testing Program is based. When applying IWE-5000, if a Type A, B, or C Test is performed, the test pressure and acceptance standard for the test must be in accordance with 10 CFR part SO, Appendix J.

3.1.4.4 10 CFR S0.SSa(b)(2)(xiv),Section XI condition: Appendix VIII personnel qualification. All personnel qualified for preforming ultrasonic examinations in accordance with Appendix VIII must receive 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of annual hands-on training on specimens that contain cracks. Licensees applying the 1999 Addenda through the latest edition and addenda incorporated by reference in paragraph (a)(l)(ii) of this section may use the annual practice requirements in Vll-4240 of Appendix VII of Section XI in place of the 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of annual hands-on training provided that the supplemental practice is performed on material or welds that contain cracks, or by analyzing pre-recorded data from material or welds that contain cracks. In either case, training used must be completed no earlier than 6 months prior to performing ultrasonic examinations at a licensee's facility.

(3-2) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program 3.1.4.5 10 CFR 50.55a(b)(2)(xviii)(A), NOE personnel certification: first provision.

Level I and II nondestructive examination personnel must be recertified on a 3-year interval in lieu of the 5-year interval specified in the 1997 Addenda and 1998 Edition of IWA-2314, and IWA-2314(a) and IWA-2314(b) of the 1999 Addenda through the latest edition and addenda incorporated by reference in paragraph (a)(l)(ii) of this section.

3.1.4.6 10 CFR 50.55a(b)(2)(xxii),Section XI condition: Surface Examination. The use of the provision in IWA-2220, "Surface Examination," of Section XI, 2001 Edition through the latest edition and addenda incorporated by reference in paragraph (a)(l)(i) of this section, that allow use of an ultrasonic examination method is prohibited.

The ISi Program at CNS is based on and documents compliance with 10CFRS0.SSa, which incorporated by reference the 2007 Edition, 2008 Addenda of the ASME Code,Section XI, Subsections IWA, IWB, IWC, IWD and IWF for Inspection Program. The CNS Containment lnservice Inspection {CISI) Program is in accordance with the 2007 Edition, 2008 Addenda, of the ASME Code,Section XI, Subsection IWE. It is important to note that Section XI of the ASME Code is not by itself considered to be law and alternatives to ASME Section XI may be implemented with NRC prior approval. These alternatives can be in the form of previously reviewed and approved Code cases or CNS specific Relief Requests clearly delineated in the ten-year inspection plan. Previously reviewed and approved Code cases are documented in NRC Regulatory Guide (RG) 1.147, lnservice Inspection Code Case Alternatives, ASME Section XI, Division 1.

From a licensing basis perspective, compliance with 10CFRS0.SSa and the ASME Section XI requirements (except where relief has been granted by the NRC) is also stipulated in Section T3.7.2 of the CNS Technical Requirements Manual (TRM).

(3-3) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program Compliance with the regulatory requirements for the ISi Program is summarized in the following matrix:

Requirement Basis for Compliance Implementing Method(s) 10CFRS0.SSa and Compliance is achieved through the EP 3.28.1, EP 3.28.1.X Technical ISi Program which is established and series procedures, various Requirements implemented by Engineering CNS Maintenance Manual (TRM) T3.7.2: Procedure (EP) 3.28.1. The ten-year Procedures, various CNS Implement ISi inspection interval ISi plan (or ISi Surveillance Procedures, Program per ASME Program) contains specific details and vendor NOE Section XI relative to program scope, and procedures.

inspection frequencies.

10CFRS0.SSa and Deviation from ASME Section XI EP 3.28.1 TRM T3.7.2: requirements may be obtained Implement ISi through Relief Requests or Program per ASME previously approved Code cases.

Section XI, except These deviations are delineated in where relief has been the ten-year inspection interval ISi granted. plan (or ISi Program). Generation of Relief Requests is controlled by EP 3.28.1.

3.2. Basis lnservice Inspection Program 3.2.1 The commercial operation date for Cooper Nuclear Station is July 1, 1974. The first, second and fourth intervals were extended as allowed by IWA-2430. CNS began the third interval on March 1, 1996. The fourth interval began on March 1, 2006.

The CNS fifth interval start date is April 1, 2016.

3.2.2 The three inspection periods and corresponding outages for Class 1, 2, 3 and MC during the fifth ISi inspection and 3rd CISI inspection intervals are as follows. CNS is currently on 24 month cycles that started during the previous interval.

First Period: April 1, 2016 to February 28, 2019 RE29 - October 2016 RE30 - October 2018 Second Period: March 1, 2019 to February 28, 2023 RE31- October 2020 RE32 - October 2022 Third Period: March 1, 2023 to February 28, 2026 RE33 - October 2024 (3-4) Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program Containment lnservice Inspection Program 3.2.3 In the Federal Register, dated August 8, 1996 (61 FR 41303), the NRC amended its regulations (rule) to incorporate by reference the 1992 Edition and Addenda of Subsections IWE and IWL of Section XI of the ASME Code. Subsections IWE and IWL give the requirements for inservice inspection (ISi) of Class CC (concrete containments), and Class MC (metal containments) of light-water-cooled power plants. The amended rule became effective on September 9, 1996; it requires the licensees to incorporate the new requirements into their ISi plans and to complete the first containment inspection within five years (i.e., no later than September 9, 2001). Any repair or replacement (R/R) activity to be performed on containments after the effective date of September 9, 1996, has to be carried out in accordance with the respective requirements of Subsections IWE and IWL.

3.2.4 In the Federal Register, dated September 26, 1995 (60 FR 49505), the NRC amended its regulations (rule) to incorporate Option B - Performance-Based Requirements, into 10 CFR 50 Appendix J. The original requirements are now referred to as Option A - Prescriptive Requirements. Option B Section Ill.A states A general visual inspection of the accessible interior and exterior surfaces of the containment system for structural deterioration which may affect the containment leak-tight integrity must be conducted prior to each test and at a periodic interval between tests based on the performance of the containment system On October 6, 1999, the District submitted to the NRC proposed changes to the CNS Technical Specifications for the implementation of Option B. The amended Technical Specifications were issued by the NRC on March 3, 2000. The General Visual Examination requirements specified herein satisfies the visual examination requirements specified in Option B.

3.2.5 Aging Management Mitigation Strategy - Torus Underwater Region The monitoring strategy associated with the torus underwater interior region is implemented using the augmented visual examination requirements as specified in ASME Section XI. CNS has classified this region as Category E-C, Containment 11 Surfaces Requiring Augmented Examination" due to the observed active pitting degradation mechanism. Visible surfaces subject to augmented examination are examined using the VT-1 visual examination method as specified in Table IWE-2500-

1. CNS calculations provide the technical basis for when to recoat corrosion areas per NEDC 92-213 Review of Pacific Nuclear Calculation NPD037.0200 ASME NE Code 11 Evaluation of Suppression Chamber/ Torus Shell Including Effects of Pitting Corrosion" and NEDC 01-001, "Torus Downcomers Minimum Wali Thickness". The intent of the inspection screening criteria is to ensure corroded areas/pits are identified and recoated during scheduled examinations well in advance of those corrosion areas/pits reaching a depth that could challenge the structural or pressure boundary integrity ofthe containment shell including the downcomers of the torus 11 11 vent system.

(3-5) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program The following provides general guidance for identifying areas of corrosion attack and thresholds for coating repair and/or engineering evaluation:

3.2.5.1 Examination region and areas The torus shell is of prime importance when evaluating immersion area coatings (underwater) and base metal condition. Loss of base metal due to corrosive attack may ultimately compromise the integrity of the vessel if not properly evaluated and repaired. Due to large surface area, the shell is sub-divided into smaller, identifiable regions and areas as described in the following sections. This process provides a reasonable but consistent approach in monitoring and mitigation actions.

• General Shell regions below the equatorial seam are defined as any area on the immersed shell not included in an area defined as a "Near Ring Girder" region or a "Near Penetration" region. The general shell will be sub-divided into bays by the structural ring girders.

• "Near Ring Girder" regions below the equatorial seam are defined as follows:

o Areas on the general shell extending 12 11 from the face of the ring girder web on the side without the miter joint and extending 12 11 from the miter on the side with the miter joint.

o Areas within 12 of any of the 3 sides of the ring girder stiffener 11 plates.

• "Near Penetration" regions are defined as follows:

o Areas below the equatorial seam on the shell within 12 of a 11 penetration nozzle.

o For penetrations with a thickened insert plate, the area extends 12 11 from the insert plate/ torus shell intersection.

o For heavily loaded penetrations (X- 223A & B, X-227 A & B, X-226, and X-225 A, B, C, and D) the area extends 2-1/2' from the insert plate/ torus shell intersection.

o Penetrations X-223 A & B are located above the waterline, but the 11 Near Penetration" region extends below the waterline.

o If a Near Penetration region overlaps a Near Ring Girder region, the requirements for the Near Penetration region shall control.

(3-6) Revision 3.0

Cooper Station 5th ISI &

3rd Interval crsr Program 11 Downcomer regions are defined as follows:

11 o Accessible surfaces of the downcomers below the waterline.

3.2.5.2 Examination of Coated Areas This section provides the general guidance for examination of the torus shell protective coatings in immersion service to identify and document relevant coating deficiencies. For the purpose of this examination, there are two general categories of relevant coating deficiencies.

o Category 1 includes coating deficiencies that may result in the release of coating material from the substrate.

o Category 2 includes coating deficiencies that expose base metal and may be associated with pitting at threshold depths requiring coating repair or engineering evaluation of the shell base metal.

The coating examination shall identify, classify, and evaluate relevant coating deficiencies as follows:

o Cracking (common to both barrier and sacrificial coatings) is the formation of breaks in a coating film that extend through to the underlying surface. If the underlying surface is a prime or intermediate coating and does not extend to substrate, it shall be described as "topcoat cracking". Cracking which extends to the substrate shall be described as "cracking to substrate". In both instances the affected area shall be evaluated for delamination.

o Delamination (common to both barrier and sacrificial coatings) is a separation of one coat from another coat within a coating system, or from the substrate. The deficient area shall be probed with a knife blade or paint scraper until sound adherent coating is found.

o Blistering (common to barrier coatings) appears as raised spherical bulges above the surface plane of the coating. Blister size and frequency shall be evaluated in accordance with ASTM Standard D 714.

o Mechanical Damage through to Substrate is typically caused by dropping or dragged object(s) from the surface. Rusting and /or pitting corrosion shall be identified.

o Discoloration (common to both barrier and sacrificial coatings) on the surface of the coating may be superficial or indicative of coating damage. Conditions such as pinpoint rusting, mechanical damage, radiation exposure, and chemical breakdown may cause discoloration.

(3-7) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program o Tiger Striping (common only to inorganic zinc coatings) Tiger striping appears as alternating light and dark vertical stripes. Tiger striping is evaluated for the degree of deterioration in the anodic areas for signs of rusting, either moderate or extensive rusting with identifiable metal loss.

3.2.5.3 Examination of Un-coated surfaces Corrosion on components and surfaces in immersion shall be examined to assess the general extent of base metal corrosion.

Corrosion conditions shall be identified and classified as follows:

o Pinpoint Rusting is rusting of the substrate that appears as pinpoint size rust stain or deposits that extend through the coating.

o Uniform Rusting of substrate occurs in areas where the protective coatings have failed or in areas that were not coated.

o Pitting corrosion shall be evaluated by visual assessment or measuring device such as go-no/go gauge or dial depth gauge as necessary to identify pits requiring quantitative evaluation.

Minimum and maximum threshold values for pits in various regions of the torus shell and downcomers that require evaluation in accordance with Table A below.

During the corrosion evaluation, the examiner(s) shall visually assess pits or take random pit depth measurements on the shell and downcomers using a dial depth gauge or go/no-go gauge.

3.2.5.4 Quantitative Evaluation of Metal Loss Minimum and maximum threshold values for pitting in various regions of the torus shell and downcomers is listed in Table A below. A quantitative evaluation shall be performed to accurately determine metal loss values for the following conditions:

Pit Depth Thresholds

• Shallow Pit - Shallow pits are defined as pits deeper than the minimum threshold but less than the maximum threshold for a given region.

• Deep Pit - Deep pits are defined as pits exceeding the maximum threshold for a given region. The following table provides the inspection and coating repair requirements for various pit depths by region. All requirements refer to submerged surfaces that lie below the equatorial seam of the torus pressure boundary.

(3-8) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program Near Penetration (Below the Equatorial Seam)

(<12" from nozzle or insert & 18" from reinf.

penetration) Deep ~30mil YES Detailed YES YES N/A <SO mil NO NO NO NO Near Ring Girder (Below the Equatorial Seam)

Shallow ~ 50 mil < 90 mil YES Approx NO NO

(< 12" from RG Web, miter joints, stiffeners)

Deep ~90mil YES Detailed YES YES N/A <9 NO NO General Shell (Below the Equatorial Seam) Shallow ~ 90 mil <150 m"I E ro NO NO Deep ~ 150 mil YES Detaile ES YES N/A <SO mil NO NO NO NO Downcomers Shallow ~ 50 mil< 90 mil NO Detailed YES YES Deep ~90mil YES Detailed YES YES Table A Notes:

o Region refers to areas defined in Section 3.2.6.1.

o Pit Types and the corresponding threshold pit depths are shown in columns 3 and 4.

o Column 5 identifies pits requiring coating repair.

o Column 6 indicates the requirements for pit location by X /Y coordinate or azimuth and distance.

o Column 7 identifies pit types requiring identification of adjacent pits.

o Column 8 identifies pit types requiring notification of engineering for evaluation of structural integrity related to NEDC 92-213.

o Pits identified with greater than 10% loss shall be documented as relevant indications per IWE-3521.

I (3-9) Revision 3. 0

Cooper Station 5th ISi &

3rd Interval CISI Program 3.2.6.5 Pit Grouping In certain cases, it is acceptable to group pits by proximity in order to reduce the number of individual pits requiring documentation.

When pits are grouped, the pit group can be documented as one pit by recording the depth of the deepest single pit and the diameter of the pit group.

Table B summarizes the pit grouping rules:

Near Penetration Shallow > 0 mil < 30 mil 2.5" N/A N/A N/A below the equatorial seam

(<12" from Insert Deep ~30 mil 1.5" 2.5" N/A N/A Plate)

Near Ring Girder Shallow~ 50 mil< 90 mil 2.5" N/A N/A N/A below the equatorial seam

(<12" from Ring Deep~ 90 mils N/A N/A N/A N/A Girder Web)

General Shell (below the equatorial seam Shallow~ 90 mil <150 mil 2.5" N/A 19" N/A and away from penetrations and ring girders) Deep ~ 150 mil 2.5" 2.5" 19" 24" Shallow~ 50 mil< 90 mil 2.5" 2.5" N/A N/A Downcomer Deep~ 90 mil 2.5" 2.5" N/A N/A Combined ISi and IWE Program 3.2.6 The three inspection periods and corresponding outages for Class MC during the third inspection interval are the same as the ISi Program (see 3.2.2 above, Request for Alternative RC3-01 was submitted to align the ISi and CISI Intervals).

3.2.7 This Program was developed in accordance with the requirements of 10 CFR 50.55a and the 2007 Edition, 2008 Addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code),Section XI, Subsections IWA, IWB, IWC, IWD, IWE, and IWF for Inspection Program. Later editions and addenda of the Code may be used, provided that the NRC has approved them, and all related requirements are met. Prior NRC approval to use later editions and addenda is required per 10CFRS0.5Sa(g)(4)(iv) (see Regulatory Issue Summary (RIS) 2004-12).

3.2.7.1 The scram discharge volume is considered as Class 2 piping for examination purposes, but is pressure tested with the reactor coolant pressure boundary piping each refueling outage, in accordance with GL 86-01.

(3-10) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program 3.2.8 This section contains the ASME Code Cases applicable to the CNS ISi Fifth Inspection Interval and CISI Third Inspection Interval.

3.2.8.1 Adoption of Code Cases ASME Section XI Code Cases adopted for the ISI/CISI activities for the Fifth and Third Interval are listed in Tables 3.2. 7-1, 3.2. 7-2, and 3.2. 7-3. The use of Code Cases is in accordance with ASME Section XI, IWA-2420, 10 CFR 50.SSa, and Regulatory Guide 1.147 2

• As permitted by ASME Section XI and Regulatory Guide 1.147 or 10 CFR 50.SSa, ASME Section XI Code Cases may be adopted and used as described below:

Adoption of Code Cases Listed for Generic Use in Regulatory Guide 1.147 Code Cases that are listed for generic use in the latest revision of Regulatory Guide 1.147 may be included in the ISI/CISI program provided any additional provisions specified in the Regulatory Guide are also incorporated. Table 3.2.7-1 identifies the Code Cases approved for generic use and adopted for the fifth interval and third interval.

Adoption of Code Cases Not Approved in Regulatory Guide 1.147 Certain Code Case that has been approved by the ASME Board of Nuclear Codes and Standards may not have been reviewed and approved by the NRC Staff for generic use and listed in Regulatory Guide 1.147. Use of such Code Cases may be requested in the form of a "Request for Alternative" in accordance with 10 CFR 50.SSa(z). Once approved, these Requests for Alternatives will be available for use until such time that the Code Cases are adopted into Regulatory Guide 1.147, at which time compliance with the conditions in the Regulatory Guide is required.

Table 3.2.7-2 identified those Code Cases that have been requested through Requests for Alternatives. For convenience to the user of this ISI/CISI Program, the appropriate internal correspondence number is provided to assist in their retrieval from Document Control. All other Requests for Alternatives and Relief Requests (those not associated with NRC approval of Code Cases) are addressed in Section 7.0.

Adoption of Code Cases Mandated by 10 CFR 50.SSa Code Cases required by rule in 10 CFR 50.SSa are incorporated into the ISi Program and implemented at the specified schedule. Code Cases currently required by 10 CFR 50.SSa and that are applicable to CNS are identified in Table 3.2.7-3.

2 The Original Revision of RG 1.147 that was used for this Interval is Rev. 17.

(3-11) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program Use of Annulled Code Cases As permitted by Regulatory Guide 1.147, Code Cases that have been adopted for use in the current interval that are subsequently annulled by ASME, may be used for the remainder of the interval.

Code Case Revisions Initial adoption of a Code Case requires use of the latest revision of that Code Case listed in Regulatory Guide 1.147. However, if an adopted Code Case is later revised and approved by the NRC, then either the earlier or later revision may be used. An exception to this provision would be the inclusion of a limitation or condition on the later revision necessary to enhance safety. In this situation, the limitation imposed on the later revision must be incorporated into the program.

Adoption of Code Cases Issued Subsequent to Filing the lnservice Inspection Plan Code Cases issued by ASME subsequent to filing the lnservice Inspection Plan with the NRC may be incorporated within the provisions of RG 1.147 by revision to this ISi Plan. Any subsequent Code Cases shall be incorporated into the program and identified in either Table 3.2.7-1 or 3.2.7-2, as applicable, prior to their use.

Code Cases not approved for use by the NRC Certain Code Cases that have been approved by the ASME Board of Nuclear Codes and Standards have been reviewed and are not approved by the NRC Staff for generic use. These Code Cases are listed in Regulatory Guide 1.193, ASME Code Cases Not Approved for Use. However, the NRC may approve their use in specific cases. Code Cases listed in the Regulatory Guide will not be used at CNS without an approved Request for Alternative in accordance with 10 CFR 50.SSa(z).

1971 Edition with the Repair Welding Using Summer Automatic or Machine 1973 Gas Tungsten-Arc N-432-1 18 None Addenda up Welding (GTAW) to 2015 Temper Bead Edition Technique (3-12) Revision 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program 1989 Edition Rotation of Snubbers up to 2007 and Pressure Retaining NRC condition is only applicable to N-508-4 Edition with 18 Items for the Purpose plants using Section XI 2006 Edition or 2008 of Testing or Preventive earlier Addenda Maintenance 1983 Edition with the Winter Evaluation Criteria for The repair or replacement activity 1985 Temporary Acceptance temporarily deferred under the N-513-3 Addenda up 18 of Flaws in Moderate provisions of this Code Case shall be to 2007 Energy Class 2 or 3 performed during the next scheduled Edition with Piping outage.

2008 Addenda Evaluation of Criteria 1995 Edition for Temporary with the Acceptance of Flaws in 1996 N-513-4 19 Moderate None Addenda up Energy Class 2 or 3

• to Piping,Section XI, 2019 Edition Division 1 1977 Edition with the Licensees must obtain NRC approval Summer in accordance with 10 CFR 50.SSa(z)

N-516-3 1978 18 Underwater Welding regarding the technique to be used in Addenda up the weld repair or replacement of to 2013 irradiated material underwater.

Edition (3-13) Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program (1) Licensees must obtain NRC approval in accordance with 10 CFR 50.55a(z) regarding the welding technique to be used prior to performing welding on ferritic material exposed to fast neutron fluence greater than lx1017 n/cm2 (E

> 1 MeV).

(2) Licensees must obtain NRC approval in accordance with 10 CFR 50.55a(z) regarding the 1995 Edition welding technique to be used prior to with the performing welding on austenitic 1996 material other than P-No. 8 material N-516-4 19 Underwater Welding Addenda up exposed to therm a I neutron fluence to greater than 1x1017 n/cm2 2013 Edition (E < 0.5 eV).

(3) Licensees must obtain NRC approval in accordance with 10 CFR 50.55a(z) regarding the welding technique to be used prior to performing welding on P-No. 8 austenitic material exposed to thermal neutron fluence greater than 1x1017 n/cm2 (E < 0.5 eV) and measured or calculated helium concentration of the material greater than 0.1 atomic parts per million.

1974 Edition Alternative up to Requirements for N-526 2010 Edition 18 None Successive Inspections with 2011 of Class 1 and 2 Vessels Addenda Repair/Replacement 1995 Edition Activity Documentation with the Requirements and 1996 N-532-5 18 lnservice Inspection None Addenda up Summary Report to Preparation and 2013 Edition Submission (3-14) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program (1) To achieve consistency with the 10 CFR 50.SSa rule change published September 22, 1999 (64 FR 51370), incorporating Appendix VIII, "Performance Demonstration for Ultrasonic Examination Systems," to Section XI, add the following to the specimen 2004 Edition Alternative Methods -

requirements:

up to 2010 Qualification for Nozzle

a. "At least 50 percent of the flaws N-552-1 Edition with 18 Inside Radius in the demonstration test set the 2011 Section from the must be cracks and the Addenda Outside Surface maximum misorientation must be demonstrated with cracks.

Flaws in nozzles with bore diameters equal to or less than 4 inches may be notches."

b. Add to detection criteria, "The number of false calls must not exceed three."

(1) Paragraph 5(b): for repairs performed on a wet surface, the overlay is only acceptable until the next refueling outage (2) Paragraph 7(c): if the cause of the degradation has not been Alternative determined, the repair is only Requirements for Wall 1977 Edition acceptable until the next refueling Thickness Restoration N-561-2 up to 18 outage of Class 2 and High 2015 Edition (3) The area where the weld overlay is Energy Class 3 Carbon to be applied must be examined Steel Piping using ultrasonic methods to demonstrate that no crack-like defects exist.

(4) Piping with wall thickness less than the diameter of the electrode shall be depressurized before welding.

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Cooper Station 5th ISi &

3rd Interval CISI Program (1) Paragraph S(b): for repairs performed on a wet surface, the overlay is only acceptable until the next refueling outage (2) Paragraph 7(c): if the cause of the degradation has not been Alternative determined, the repair is only Requirements for Wall 1977 Edition acceptable until the next refueling Thickness Restoration N-562-2 up to 18 outage of Class 3 Moderate 2015 Edition (3) The area where the weld overlay is Energy Carbon Steel to be applied must be examined Piping using ultrasonic methods to demonstrate that no crack-like defects exist.

(4) Piping with wall thickness less than the diameter of the electrode shall be depressurized before welding.

1977 Edition with the Summer Alternative Additional 1978 Examination Addenda up Requirements for N-586-1 18 None to Classes 1, 2, and 3 2007 Edition Piping, Components, with the and Supports 2008 Addenda (3-16) Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program (1) The use of Code Case N-597-3 for any degradation mechanisms other than flow-accelerated corrosion is not authorized unless an alternative is proposed and approved in accordance with 10 CFR 50.SSa(z).

(2) Use of Code Case N-597-3 to mitigate flow-accelerated corrosion is authorized subject to the following conditions:

a. The Code Case must be supplemented by the provisions of the EPRI/Nuclear Safety Analysis Center Report (NSAC) report EPRI/NSAC-202L.

2, "Recommendations for an Effective Flow Accelerated Corrosion Program,"

issued April 1999 (Ref. 7), for developing the inspection requirements, the method of predicting the rate of wall-thickness 1974 Edition Requirements for loss, and the value of the predicted N-597-3 up to 2019 19 Analytical Evaluation of remaining wall thickness. As used in Edition Pipe Wall Thinning EPRI/NSAC-202L-R2, the term "should" is to be applied as 11 shall" (i.e., a requirement}.

b. Components affected by flow-accelerated corrosion to which this Code Case is applied must be repaired or replaced in accordance with the Construction Code of Record and the owner's requirements or a later NRC-approved edition of Section Ill before the value oft reaches the allowable minimum wall thickness, tmin, as specified in Figure-3622.l(a)(l) of this Code Case. Alternatively, use of the Code Case is subject to NRC review and approval in accordance with 10 CFR 50.SSa(z}.

(3) For those components that do not require immediate repair or replacement, the rate of wall-thickness loss is to be used to determine a suitable inspection (3-17) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program frequency so that repair or replacement occurs prior to reaching allowable minimum wall thickness, tmin.

(4) The evaluation criteria in Code Case N-513-4 may be applied to Code Case N-597-3 for the temporary acceptance of wall thinning (until the next refueling outage) for moderate-energy Class 2 and 3 piping.

(5) Code Case N-597-3 shall not be used to evaluate through-wall leakage conditions.

1977 Edition with the Summer Transfer of Welder, 1978 Welding Operator, Addenda up N-600 18 Brazer, and Brazing None to Operator Qualifications 2010 Edition Between Owners with the 2011 Addenda Prior to welding, an examination or 1977 Edition Similar and Dissimilar verification must be performed to with the Metal Welding Using ensure proper preparation of the base Summer Ambient Temperature metal, and that the surface is properly N-606-2 1978 19 Machine GTAW Temper contoured so that an acceptable weld Addenda up Bead Technique for can be produced. This verification is to BWR CRD Housing/Stub to be required in the welding 2019 Edition Tube Repairs procedure.

1989 Edition Ultrasonic Examination with the of Penetration Nozzles 1989 in Vessels, Examination Addenda up Category B-D, Item Nos.

N-613-2 to 18 83.10 and 83.90, None 2007 Edition Reactor Nozzle-to-with the Vessel Welds, Figs.

2008 IWB-2500-7(a), (b), and Addenda {c)

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Cooper Station 5th ISi &

3rd Interval CISI Program 1977 Edition with the Summer Use of Fracture 1978 Toughness Test Data to Addenda up Establish Reference N-629 18 None to Temperature for 2010 Edition Pressure Retaining with the Materials 2011 Addenda 1980 Edition Similar and Dissimilar with the Metal Welding Using Demonstration of ultrasonic Winter Ambient Temperature examination of the repaired volume is N-638-7 1981 19 Machine required using representative samples Addenda up GTAW Temper Bead that contain construction-type flaws.

to Technique, 2019 Edition Chemical ranges of the calibration block may vary from the materials 1986 Edition specification if (1) it is within the with the chemical range of the component 1987 Alternative Calibration N-639 18 specification to be inspected, and (2)

Addenda up Block Material the phase and grain shape are to maintained in the same ranges 2015 Edition produced by the thermal process required by the material specification.

1977 Edition Alternative Pressure-with the Temperature Summer Relationship and Low N-641 1978 18 Temperature None Addenda up Overpressure to Protection System 2015 Edition Requirements (3-19) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program In lieu of a UT Examination, licensees 1977 Edition may perform a VT-1 examination in with the Alternative accordance with the code of record Summer Requirements for Inner for the lnservice Inspection Program N-648-1 1978 18 Radius Examination of utilizing the allowable flaw length Addenda up Class 1 Reactor Vessel criteria of Table IWB-3512-1 with to Nozzles limiting assumptions on the flaw 2015 Edition aspect ratio.

1977 Edition Ferritic and Dissimilar with the Metal Welding Using Summer SMAW Temper Bead N-651 1978 18 Technique Without None Addenda up Removing the Weld to Bead Crown for the 2013 Edition First Layer Alternative Requirements for Wall 1977 Edition Thickness Restoration N-661-3 up to 2019 19 of Class 2 and 3 None Edition Carbon Steel Piping for Raw Water Service Section XI, Division 1 A surface examination (magnetic particle or liquid penetrant) must be 1995 Edition performed after installation of the with the weld overlay on Class 1 and 2 piping Weld Overlay of Class 1996 socket welds. Fabrication defects, if N-666-1 18 1, 2, and 3 Socket Addenda up detected, must be dispositioned using Welded Connections to the surface examination acceptance 2015 Edition criteria of the Construction Code identified in the Repair/Replacement Plan.

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Cooper Station 5th ISI &

ya Interval CISI Program Examiners qualified using the 0.25 RMS error for measuring the depths of flaws using Code Case N-695-1 are not qualified to depth-size inner-diameter (ID) surface-breaking Qualification flaws greater than SO-percent 2001 Edition Requirements for through-wall in dissimilar metal welds N-695-1 up to 2013 19 Dissimilar Metal Piping 2.1 inches or greater in thickness. If Edition Welds an examiner qualified using Code Case N-695-1 measures a flaw as greater than SO-percent through-wall in a dissimilar metal weld from the ID, the flaw shall be considered to have an indeterminate depth.

Examiners qualified using the 0.25 RMS error for measuring the depths of flaws using Code Case N-696-1 in dissimilar metal or austenitic welds Qualification are not qualified to depth-size ID Requirements for surface-breaking flaws greater than 2001 Edition Mandatory Appendix SO-percent through-wall in dissimilar N-696-1 up to 2019 19 VIII Piping metal or austenitic welds 2.1 inches Edition Examinations or greater in thickness. If an examiner Conducted from the qualified using Code Case N-696-1 Inside Surface Section measures a flaw as greater than 50-percent through-wall in a dissimilar metal or austenitic weld from the ID, the flaw shall be considered to have an indeterminate depth.

The ASME Code repair or 1983 Edition replacement activity temporarily with the deferred under the provisions of this Evaluation Criteria for Winter Code Case shall be performed during Temporary Acceptance 1985 the next scheduled refueling outage of Degradation in N-705 Addenda up 19 for through-wall flaws.

Moderate Energy Class to 2010 (Note: The NRC previously approved 2 or 3 Vessels and Edition with this Code Case without condition in Tanks the 2011 Rev 18 of RG 1.147s; Addenda this is a new condition for Rev 19 of RG 1.147)

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Cooper Station 5th ISI &

3rd Interval CISI Program Code Case N-711-1 shall not be used to redefine the required examination Alternative volume for preservice examinations Examination Coverage 1989 Edition or when the postulated degradation Requirements for N-711-1 up to 2019 19 mechanism for piping welds is Examination Category Edition primary water stress-corrosion 8-F, 8-J, C-F-1, C-F-2, cracking or and R-A Piping Welds crevice-corrosion degradation mechanisms Alternative Piping 1995 Edition Classification and N-716-1 up to 2015 18 None Examination Edition Requirements Roll Expansion of Class 1989 Edition 1 Control Rod Drive N-730-1 up to 2015 18 None Bottom Head Edition Penetrations in BWRs.

1995 Edition with the Successive Inspections 1996 N-735 18 of Class 1 and 2 Piping None Addenda up Welds.

to 2015 Edition 1989 Edition Reactor Vessel Head-N-747 up to 18 to-Flange Weld None 2015 Edition Examinations When a 10 CFR, Appendix J, Type C test is performed as an alternative to the requirements of IWA-4540 (IWA-1989 Edition Pressure Testing of 4700 in the 1989 edition through the N-751 up to 2015 18 Containment 1995 edition) during repair and Edition Penetration Piping replacement activities, nondestructive examination must be performed in accordance with IWA-4540(a)(2) of the 2002 Addenda of Section XI.

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Cooper Station 5th ISI &

3rd Interval CISI Program 1995 Edition Temper Bead with the Procedure Qualification 1995 Requirements for N-762 18 None Addenda up Repair/Replacement to Activities Without Post 2010 Edition Weld Heat Treatment.

Temper Bead 1995 Edition Procedure Qualification with the Requirements for 1995 Repair/Replacement N-762-1 19 None Addenda up Activities Without to Postweld Heat 2010 Edition Treatment,Section XI, Division 1 1989 Edition Alternative to up to 2007 Inspection Interval N-765 Edition with 18 Scheduling None the 2008 Requirements of IWA-Addenda 2430.

Roll Expansion of Class 1989 Edition 1 In-Core Housing N-769-2 up to 18 None Bottom Head 2015 Edition Penetrations in BWRs.

1989 Edition Alternative to IWA-N-776 up to 18 5244 Requirements for None 2010 Edition Buried Piping.

Licensees must submit the following Alternative reports to the regulatory authority:

Requirements for

1) The preservice inspection summary 1989 Edition Preparation and report must be submitted prior to the up to 2007 Submittal of lnservice date of placement of the unit into N-778 Edition with 18 Inspection commercial service.

the 2009 Plans, Schedules, and

2) The inservice inspection summary Addenda Preservice and report must be submitted within 90 lnservice Inspection calendar days of the completion of Summary Reports, each refueling outage.

(3-23) Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program Alternative 1995 Edition Requirements for with the Sleeve Reinforcement 1996 N-786-1 18 of Class 2 and 3 None Addenda up Moderate-to Energy Carbon Steel 2015 Edition Piping,Section XI Areas containing pressure pads shall be visually observed at least once per month to monitor for evidence of 1995 Edition Alternative leakage. If the areas containing with the Requirements for Pad pressure pads are not accessible for 1996 Reinforcement of Class direct observation, then monitoring N-789 18 Addenda up 2 and 3 Moderate- will be accomplished by visual to 2015 Energy Carbon Steel assessment of surrounding areas or Edition Piping. ground surface areas above pressure pads on buried piping, or monitoring of leakage collection systems, if available.

Alternative Requirements for Pad 1998 Edition Reinforcement of Class N-789-2 up to 2019 19 2 and 3 Moderate None Edition Energy Carbon Steel Piping for Raw Water Service, (3-24) Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program

1) The use of nuclear heat to conduct the BWR Class 1 system leakage test is prohibited (i.e., the reactor must be in a non-critical state), except during Alternative refueling outages in which the ASME 1998 Edition Requirements for BWR Section XI Category B-P pressure with the Class 1 System Leakage test has already been performed, or 1999 N-795 18 Test Pressure at the end of mid-cycle maintenance Addenda up Following outages fourteen {14) days or less in to Repair/Replacement duration.

2015 Edition Activities 2) The test condition holding time, after pressurization to test conditions, and before the visual examinations commence, shall be 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for non-insulated components.

Alternative Pressure None 1992 Edition Testing Requirements with the for Class 1 Piping 1993 N-798 18 Between the Addenda up First and Second Vent, to Drain, and Test 2015 Edition Isolation Devices.

1992 Edition Alternative Pressure None with the Testing Requirements 1993 for Class 1 Piping N-800 18 Addenda up Between the to First and Second 2015 Edition Injection Valves.

Similar and Dissimilar Metal Welding Using Ambient Temperature 1980 Edition Automatic N-803 up to 2010 18 or Machine Dry None Edition Underwater Laser Beam Welding {ULBW)

Temper Bead Technique.

(3-25) Revision 3.0

Cooper Station 5th ISI &

yd Interval CISI Program Alternative to Class 1 Extended Boundary End of Interval or Class 2 1992 Edition System N-805 up to 2013 18 Leakage Testing of the None Edition Reactor Vessel Head Flange O-Ring Leak-Detection System.

2001 Edition with the 2003 Addenda up N-823 18 Visual Examination None to 2010 Edition with the 2011 Addenda N-823-1 19 Visual Examination None (1) Instead of Paragraph l(c)(l)(c)(2},

licensees shall use a search unit with a center frequency of 500 kHz 2001 Edition with a tolerance of plus or minus with the Ultrasonic Examination 20 percent for piping greater than 1.6 2003 of Cast Austenitic N-824 19 in (41 mm) thick.

Addenda up Piping Welds from the (2) Instead of Paragraph l(c)(l)(d),

to Outside Surface the search unit must produce angles, 2013 Edition including those at, but not limited to, 30 to 55 degrees with a maximum increment of 5 degrees.

1995 Edition Alternative with the Requirements for 1996 N-825 18 Examination of Control None Addenda up Rod Drive Housing to 2013 Welds Edition (3-26) Revision 3. 0

Cooper Station 5th ISI &

3rd Interval CISI Program The provisions of Paragraph 3(e)(2) or Austenitic Stainless- 3(e)(3) may only be used when it is 1995 Edition Steel Cladding and impractical to use the interpass with the Nickel Base Cladding temperature measurement methods 1996 N-829 19 Using Ambient described in Paragraph 3(e)(1), such Addenda up Temperature Machine as in situations where the weldment to GTAW Temper Bead area is inaccessible (e.g., internal bore 2019 Edition Technique welding) or when there are extenuating radiological conditions Use of Code Case N-830, Paragraph Direct Use of Master (f), which provides an alternative to Fracture Toughness 1992 Edition limiting the lower shelf of the 95-Curve for Pressure N-830 up to 2019 19 percent lower tolerance bound Retaining Edition Master Curve toughness, KJC-lower Materials of Class 1 95%, to a value consistent with the Vessels current KIC curve, is prohibited.

1995 Edition with the Ultrasonic Examination 1996 in Lieu of Radiography Code Case N-831 is prohibited for use N-831 19 Addenda up for Welds in Ferritic in new reactor construction.

to Pipe 2019 Edition 1989 Edition with the Flaw Tolerance Code Case N-838 shall not be used to 1989 Evaluation of Cast evaluate flaws in cast austenitic N-838 19 Addenda up Austenitic Stainless- stainless steel piping where the delta to Steel Piping ferrite content exceeds 25 percent.

2019 Edition Similar and Dissimilar 1995 Edition Metal Welding Using with the Ambient Temperature N-839 1996 19 None SMAW Addenda Temper Bead 2019 Ed it ion Technique 2007 Edition with the Alternative Inspection 2008 N-842 19 Program for Longer None Addenda up Fuel Cycles to 2019 Edition (3-27) Revision 3.0

Cooper Station 5th ISI &

3 rd Interval CISI Program Alternative Pressure If the portions of the system that Testing Requirements requires pressure testing are Following Repairs or associated with more than one safety 1980 Edition Replacements for Class function, the pressure test and visual N-843 up to 2019 19 1 Piping between the examination VT-2 shall be performed Edition First and Second during a test conducted at the higher Inspection of the operating pressures for the Isolation Valves respective system safety functions.

1995 Edition with the Qualification 1996 N-845 18 Requirements for Bolts None Addenda up and Studs to 2013 Edition 2001 Edition Alternative Pressure with the Testing Requirements 2003 for Class 2 and 3 N-854 19 None Addenda up Components to Connected to the Class 2013 Edition 1 Boundary Code Cases Approved Through Request for Alternatives The following ASME Code Cases are not contained in Regulatory Guide 1.147, Revision 18 and require a request for alternative prior to implementation. Reference Section 7.0 of this plan for the applicable requests.

1995 Edition Evaluation Criteria for Temporary with the 1996 N-513-4 Acceptance of Flaws in Moderate Energy RR5-02, RR5-03 Addenda to Class 2 or 3 Piping Section XI, Division 1 2013 Edition Alternative Requirements for Boiling 1986 Edition to Water Reactor (BWR) Nozzle Inner N-702 2007 Edition, Radius and Nozzle-to-Shell Welds Rl5-03 2008 Addenda Section XI, Division 1 (3-28) Revision 3.0

Cooper Station 5th ISI &

yd Interval CISI Program 1998 Edition Alternative Requirements for BWR Class RPS-01 (Superseded by NRC with the 1999 N-795 1 System Leakage Test Pressure approval of N-795 in Rev 18 Addenda Following Repair/Replacement Activities of R.G. 1.147).

2015 Edition Code Cases Required by 10 CFR 50.SSa The following ASME Code Cases are not contained in Regulatory Guide 1.147, Revision 18, but are mandated in 10 CFR 50.SSa and applicable to CNS.

3.3. System Classification 3.3.1 In accordance with the Code, IWA-1400(a), it is the Owner's responsibility to determine the appropriate code class for each component and to identify the system boundaries subject to inspection. IWA-1300 states that components identified for inspection and testing shall be included in the ISi Program, and that the selection of components for the ISi Program is subject to review by the regulatory and enforcement authorities having jurisdiction at the plant site. The component classifications of the Code (Class 1, 2, 3, or MC) determine the rules and requirements for inspection and testing and define the ASME Section XI examination boundaries. Because early vintage nuclear plants were designed and constructed before ASME Section Ill of the Code was incorporated into 10CFRS0.SSa, the ASME Section XI code classifications for ISi may differ from the original design classifications. The ASME code classifications determine applicability of the rules for repair/replacement activities, and for component inspection requirements.

3.3.2 The NRC issued the construction permit for the CNS in June 1968. The plant design was completed when the Nebraska Public Power District (NPPD) applied for an operating license and submitted the Final Safety Analysis Report (FSAR) for the facility in March 1971. The license was issued in January 1974. The United States of America Standards (USAS) used for the original design and construction of CNS were 831.1 (1967), Code for Power Piping, and 831.7 (February 1968 with Draft and Errata of June 1968), Code for Nuclear Power Piping. The ASME Code, Section Ill, Class B, 1965 Edition, 1967 Addenda, and Code Cases 1177 and 1330 were used for the design, fabrication, erection, and testing of the Primary Containment. The "General Design Criteria for Nuclear Power Plant Construction Permits" was published for comment in the Federal Register in July 1967. The final version of (3-29) Revision 3. 0

Cooper Station 5th ISi &

3rd Interval CISI Program these design criteria were not incorporated into the Code of Federal Regulations (10 CFR 50, Appendix A) until February 1971, approximately the same time that NPPD submitted its FSAR to the NRC. As discussed in the NRC Safety Evaluation Report dated February 14, 1973, the license for CNS is based, in part, on the intent of the Draft General Design Criteria published in July 1967.

The current component classifications did not exist at the time of CNS design and construction. Boundary classifications are located in DCD-39, CNS ISi Boundary Basis.

Because CNS was designed and constructed prior to the issuance of Regulatory Guide 1.26 and NUREG-0800, these documents were not used to establish the original ASME Section XI examination boundaries. NPPD has not formally committed to the use of Regulatory Guide 1.26 or NUREG-0800, Section 3.3.2.

However, the CNS ISi Program for the fifth ten-year inspection interval and CISI of the third ten-year inspection interval uses these documents for guidance in determining the applicability of component inspections and the examination boundaries.

3.3.3 The primary containment structure is a portion of the General Electric (GE) Mark I Primary Containment Pressure Suppression System. The complete pressure suppression system consists of the Drywell, which houses the reactor vessel and reactor coolant recirculation loops, the pressure Suppression Chamber, the connecting vent system between the Drywell and pressure Suppression Chamber, isolation valves, vacuum relief system, and containment cooling systems. The isolation valves and vacuum relief system are discussed elsewhere in this document.

3.3.4 The Drywell is a low leakage steel pressure vessel designed to confine the reactor coolant that would be released during a postulated pipe rupture, and prevent the gross release of radioactive materials to the environment. The lower portion of the Drywell is spherical with a 65 foot diameter and the upper portion is cylindrical with a 35 foot, 7 inch diameter. The overall height of the Drywell is 110 feet.

The Drywell is enclosed in reinforced concrete to provide the required radiological shielding during normal plant operations. The concrete also provides additional resistance to deformation and buckling. Shielding above the Drywell is provided by removable, segmented reinforced concrete plugs.

The Drywell is designed for an internal design pressure of 56.0 psig (62.0 psig maximum code allowable), 2.0 psid external design pressure, and a maximum temperature of 281 °F. The applicable dead, live, and seismic loads are imposed on the shell along with the above design conditions.

3.3.5 The Suppression Chamber is a steel pressure vessel designed to hold a large volume of water for use as a heat sink for any postulated transient or accident conditions (3-30) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program in which the normal heat sink is unavailable. The water volume (Suppression Pool) also serves as a heat sink for the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) turbine exhaust. The Suppression Pool also functions as a water source for the Emergency Core Cooling Systems. The Suppression Pool is the primary water source for the Core Spray (CS) and Residual Heat Removal (RHR) Systems and a secondary water source for the HPCI and RCIC Systems.

Transient conditions which require the operation of the Main Steam (MS) relief valves will transfer energy to the suppression pool via the relief valve discharge piping. Postulated pipe ruptures in the Drywell will transfer energy to the Suppression Pool via the vent system. In each case the steam flow is discharged below the surface of the Suppression Pool and condensed. Any non-condensable gases and fission products are released to the Suppression Chamber air space.

The Suppression Chamber is a toroidal shape located below and completely encircling the Drywell with a centerline diameter of 102 feet with a cross-sectional diameter of 28 feet, 9 inches. The Suppression Chamber {also known as the Torus}

is constructed of 16 mitered sections to eliminate the need for compound curves in the shell.

The shell is stiffened by sixteen (16) internal ring girders located at the miter joints.

The torus is supported by sixteen (16) pairs of reinforced W14x136 columns at the ring girder locations. The Suppression Chamber is designed to the same material and code requirements as the Drywell.

3.3.6 The Drywell and Suppression Chamber are connected with eight (8) 5'-11 11 diameter circular vent pipes anchored at the Drywell. The vent pipes are located at 45° intervals and penetrate the Suppression Chamber shell at alternating segments midway between the ring girders. The vent pipes are provided with expansion joints to accommodate differential movement of the Drywell and Suppression Chamber, and jet deflectors located at the Drywell entrance to the vent to prevent damage that might occur due to jet forces associated with a pipe break in the Drywell.

The vent pipes connect to a 4'-2" diameter vent header contained in the air space of the Suppression Chamber. Projecting downward from the vent header to a minimum submergence depth of 3'-0" are 80 downcomer pipes, 24 inches in diameter to direct steam flow to the suppression pool for condensation.

The vent system is designed to the same pressure and temperature requirement as the Drywell and Torus. The Mark I Containment Program Plant Unique Analysis Report for Cooper Nuclear Station provides additional design information and a summary of modifications performed to meet the originally intended design safety margins for the redefined hydrodynamic loads not explicitly included in the original design.

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Cooper Station 5th ISI &

3rd Interval CISI Program 3.3. 7 The Personnel Airlock serves as an access into or out of the Primary Containment Vessel (Drywell). The airlock was furnished as an assembly and consists of a cylinder with a stiffened bulkhead at each end containing a door. The doors are hinged so a positive pressure inside containment tends to seat the doors. Each door is equipped with an elastomer gasket to provide a positive seal. The doors are equipped with a positive latch mechanism. The control mechanism is interlocked such that only one door may be opened at a time unless the interlock is intentionally bypassed when primary containment integrity is not required.

3.3.8 The Drywell and the Suppression Chamber were designed and constructed to the requirements of the ASME Boiler and Pressure Vessel Code and therefore have certain additional plate thickness in the shell for corrosion allowance. As a matter of good practice the interior of the Drywell and the Suppression Chamber were coated to provide protection against corrosion of the surface.

3.4. Contents of ISI/CISI Program The ISi Program addresses the requirements for inservice inspection of components, system pressure testing, and augmented inspection. Although some sections of this Program are common, the specific requirements for component inspections, system pressure testing, and augmented inspections are addressed separately. A general description of each section follows:

3.4.1 Section 1-Table of Contents Provides the organizational format for the ISi Program.

3.4.2 Section 2 - Revision Summary Sheet Provides the revision status of the effective sections in the ISi Program.

3.4.3 Section 3 - Introduction and Program Basis Description Provides details on the background, scope, basis, and contents of the ISi Program, system classifications, and augmented inservice inspection requirements.

3.4.4 Section 4 - Application of Exemption Criteria Provides the basis for determining the Class 1, 2, and 3 exempted components from surface and volumetric examination requirements in accordance with ASME Section XI, Subsections IWB-, IWC-, and IWD-1200.

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Cooper Station 5th ISI &

3rd Interval CISI Program 3.4.5 Sections 5 - lnservice Inspection Summary Table The CNS ISI/CISI Table provides the following information:

3.4.5.1 Examination Category Provides the examination category as identified in ASME Section XI, Tables IWB-2500-1, IWC-2500-1, IWD-2500-1, IWE-2500-1, and IWF-2500-1. Only those examination categories applicable to CNS are identified.

Also includes Category R-A in accordance with the Risk Informed methodology described in Code Case N-716-1.

3.4.5.2 Item Number and Item Description Provides the item number and description as defined in ASME Section XI, Tables IWB-2500-1, IWC-2500-1, IWD-2500-1, IWE-2500-1, and IWF-2500-1.

Only those item numbers applicable to CNS are identified.

3.4.5.3 Examination Method Provides the examination method(s) as defined in ASME Section XI, Tables IWB-2500-1, IWC-2500-1, IWD-2500-1, IWE-2500-1, and IWF-2500-1. Only those item numbers applicable to CNS are identified.

3.4.5.4 Number of Components in the Item No.

Provides the population of components subject to examination. The number of components actually examined during the inspection interval will be based upon the Code requirements for the subject item number.

3.4.5.5 Required to be Examined During Interval Provides the total required number of components/items that are to be examined during the interval based on the selection requirements required by ASME Section XI, Tables IWB-2500-1, IWC-2500-1, IWD-2500-1, IWE-2500-1, and IWF-2500-1. Only those item numbers applicable to CNS are identified.

3.4.5.6 Examination Percentage Required Provides the percentage required based on the selection requirements in ASME Section XI, Tables IWB-2500-1, IWC-2500-1, IWD-2500-1, IWE-2500-1, and IWF-2500-1. Only those item numbers applicable to CNS are identified.

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Cooper Station 5th ISI &

3rd Interval CISI Program 3.4.5. 7 Number to be Examined in Period Provides the total number to be examined in each inspection period based on the requirements in Table IWB-2411-1, IWC-2411-1, IWD-2411-1, IWE-2411-1, and IWF-2410-1. Only those item numbers applicable to CNS are identified.

3.4.6 Section 6 - lnservice Inspection Technical Approach and Position Index Summaries When the requirements of ASME Section XI are not easily interpreted, CNS has reviewed general licensing/regulatory requirements, industry practices and code interpretations to determine the appropriate method of implementing Code requirements. The technical positions contained in this section have been provided to clarify CNS's implementation of ASME Section XI requirements for inservice inspection.

3.4.7 Section 7 - lnservice Inspection Relief Requests and Requests for Alternatives This section contains relief requests for impracticable nondestructive examinations in accordance with 10 CFR 50.SSa(g)(S). If examination requirements are determined to be impracticable during the course of the interval, additional or modified relief requests will be submitted, in accordance with 10 CFR 50.SSa (g)(S).

In addition, requests for alternatives in accordance with 10 CFR 50.SSa(z) are listed.

3.4.8 Sections 8 - Pressure Testing The CNS System Pressure Testing Summary Tables provide the following information:

3.4.8.1 Examination Category Provides the examination category as identified in ASME Section XI, Tables IWB-2500-1, IWC-2500-1 and IWD-2500-1. Only those examination categories applicable to CNS are identified.

3.4.8.2 Item Number Provides the item number as identified in accordance with the applicable table of IWB, IWC, and IWD-2500-1.

3.4.8.3 Test Type Describes the required Code test that is being performed.

3.4.8.4 Test Frequency (3-34) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program Provides the frequency that a required Code pressure test is performed. The tests are performed either on a Period or refueling outage basis.

3.4.8.5 Technical Positions and Relief Requests Provides a listing of technical positions and relief requests applicable to the performance of pressure tests. If a technical position number is identified, see the corresponding technical position in Section 9. If a relief request number is identified, see the corresponding relief request in Section 10.

3.4.9 Section 9 - System Pressure Testing Technical Approach and Position Index Summaries When the requirements of ASME Section XI are not easily interpreted, CNS has reviewed general licensing/regulatory requirements, industry practice and code interpretations to determine the appropriate method of implementing the Code requirement. The technical approach and position documents contained in this section have been provided to clarify CNS's implementation of ASME Section XI requirements for system pressure testing.

3.4.10 Section 10 - System Pressure Testing Relief Requests and Requests for Alternatives This section contains relief requests for impracticable pressure tests in accordance with 10 CFR 50.SSa(g)(S). If testing requirements are determined to be impracticable during the course of the interval, additional or modified relief requests will be submitted, in accordance with 10 CFR 50.SSa(g)(S). In addition, requests for alternatives in accordance with 10 CFR 50.SSa(z) are listed.

3.4.11 Section 11-Augmented lnservice Inspection This section contains component examination requirements not addressed by ASME Section XI. These requirements may come from regulatory commitments, vendor recommendations (e.g. GE SILs), or CNS management directives.

3.4.12 Section 12 - List of Applicable P&IDs, Isometric and Component Drawings Provides a listing of P&ID's, piping isometric and component drawings corresponding to each system that contains components subject to examination under this Program.

3.4.13 Section 13 - Nondestructive Examination Procedure Listing This section contains the listing of CNS visual examination procedures. CNS does not have the in-house capability to perform surface or volumetric nondestructive (3-35) Revision 3.0

Cooper Station 5th ISI &

3rd Interval CISI Program examinations. Vendor procedures are used during outages to perform the required examinations.

3.4.15 Section 14 - Ultrasonic Calibration Blocks This section contains the listing of Ultrasonic calibration blocks for examination of components in accordance with regulatory requirements, vendor recommendations, or CNS management directives.

3.4.16 Section 15 - Component Examination Summary Tables This section contains the references to tables and the schedule for examination of ISI/CISI components and component supports in accordance with the requirements of ASME Section XI. The component listing is maintained in controlled document as "Cooper Nuclear Station Fifth ISi and Third Interval CISI Component Listing".

3.4.17 Section 16 - Index of Abbreviations This section contains the abbreviations used in the preceding tables.

3.4.18 Section 17 - Risk Informed Program This section contains the RI-ISi Living Program Evaluation. It also includes the RI-ISi Program Plan.

3.4.19 Section 18 - Commitment Management This section contains NRC Commitments that were made and are applicable to the ISI/CISI Program.

3.4.20 Section 19 - Containment Indication Tracking This section contains a tabular listing, along with several figures, of key surface indications identified during various visual examinations of underwater Torus, Torus exterior, and Drywell.

3.4.21 Section 20 - ISi and CISI Program History This section contains the history of both the ISi and CISI Programs.

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Cooper Station 5th ISi &

3rd Interval GISI Program 4.0 APPLICATION OF EXEMPTION CRITERIA 4.1.Section XI Class 1 Exemptions:

4.1.1 ASME Section XI, Subparagraph IWB-1220(a}, gives specific guidance for exempting components from the volumetric and surface examination requirements of IWB-2500, if they are: connected to the reactor coolant system

{RCS); and are part of the reactor coolant pressure boundary; and of such a size and shape so that, upon postulated rupture, the resulting flow of coolant from the RCS, under normal plant operating conditions, is within the capacity of makeup systems that are operable from on-site emergency power. The emergency core cooling systems are excluded from the calculation of makeup capacity.

Components and items that are exempt from the volumetric and surface examination requirements of ASME Section XI, and from the provisions of referenced code cases, are not exempt from the requirements for repair/replacement activities or pressure testing.

4.1.2 CNS performed an analysis per IWB-1220{a) to identify those systems and piping line sizes that could be exempted. This analysis was performed under Calculation Number GENE-637-05-1192 "ASME Section XI Code Pipe Exclusion Revised Analysis for Cooper Nuclear Station" (Roll#07176, Frame 0674).

In determining the size of the liquid and steam lines excluded from surface and volumetric examination, liquid lines were defined as those that penetrate the reactor pressure vessel (RPV) below the normal water level, and steam lines as those that penetrate the RPV above the normal water level.

The systems credited in this calculation with providing normal makeup are the Reactor Core Isolation Cooling (RCIC) and Control Rod Drive (CRD) systems.

System Pump Flow Maximum Fluid Emergency Rate (gpm) Temperature (° F) Power CRD System 160 140 Yes, on-site RCIC System 400 140 Yes, on-site (4-*i) Revision 0

Cooper Station 5th ISi &

3rd Interval CISI Program Water flow rates from a liquid line break are taken as 8000 lbs/sec/ft2 at 1000 psi. Steam flow rates from a steam line are taken as 2000 lbs/sec/ft 2 at 1000 psi.

Make-up water weighs 8.33 lbs per gallon at 70° F. On this basis, the exclusion diameters based on reactor coolant make-up system capacity are as follows:

(560gpm)(1 ft 3/7.48gal)(62.4 lbm/ft3 }(1 min/60sec)= 77.86 lb/sec (77.86 lb/sec)/(2000L b/sec-ft2 )= 0.0389 ft 2 for steam (77.86 lb/sec)/(8000L b/sec-ft2 )= 0.0097 ft 2 for water Therefore, the exempt diameter for steam is 0.22ft ID and the exempt diameter for water is 0.11ft ID. Thus those portions of steam piping with an inside diameter of 2.64 inches, and water piping with an inside diameter of 1.34 inches, may be exempted from the surface and volumetric examination requirements of Table IWB-2500-1.

4.1.3 ASME Section XI, Subparagraph IWB-1220(b}, provides additional criteria that can be used to exempt components and piping segments from examination using size. Components and piping segments are NPS 1 and smaller, components and piping segments which have one inlet and one outlet, both of which are NPS 1 and smaller or components and piping segments which have multiple inlets or multiple outlets whose cumulative pipe cross-section area does not exceed the cross-sectional area defined by the OD of NPS 1 pipe.

4.1.4 In accordance with IWB-1220(c), the reactor vessel drain line nozzle and associated piping are exempt.

4.1.5 ASME Section XI, Subparagraph IWB-1220(d) allows inaccessible welds or portions or welds to be exempt due to being encased in concrete, buried underground, located inside a penetration, or encapsulated by guard pipe.

4.2.Section XI Class 2 Exemptions 4.2.1. Components Within Residual Heat Removal (RHR}, Emergency Core Cooling(ECC}, and Containment Heat Removal (CHR} Systems 4.2.2.1. Components and piping segments 4 NPS and smaller.

4.2.2.2. Components and piping segments which have one inlet and one outlet both of which are NPS 4 or smaller or multiple inlets or multiple outlets whose cumulative pipe cross-sectional area does not exceed the cross-sectional area defined by the OD of NPS 4 pipe.

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Cooper Station 5th ISi &

3rd Interval GISI Program 4.2.2.3. Piping and other components of any size beyond the last shutoff valve in open ended portions of systems that do not contain water during normal plant operating conditions.

4.2.2. Components Within Systems or Portions of Systems Other than RHR, ECC, and CHR Systems 4.2.2.1. Components and Piping segments 4 NPS and smaller.

4.2.2.2. Vessels, piping, pumps, valves, other components and component connections of any size in systems or portions of systems that operate (when the system function is required} at a pressure equal to or less than 275 psig and at a temperature equal to or less than 2QQQF.

4.2.2.3. Components and piping segments which have one inlet and one outlet both of which are NPS 4 and smaller or component and piping segments which have multiple inlets or multiple outlets whose cumulative pipe cross-sectional area does not exceed the cross-sectional area defined by the OD of NPS 4 pipe.

4.2.2.4. Piping and other components of any size beyond the last shutoff valve in open ended portions of systems that do not contain water during normal plant operating conditions.

4.2.2.5. Welds or portions of welds that are inaccessible due to being encased in concrete, buried underground, located inside a penetration, or encapsulated by guard pipe.

4.3.Section XI Class 3 Exemptions:

4.3.1 Components and piping segments 4 NPS and smaller.

4.3.2 Components and piping segments which have one inlet and one outlet both of which are NPS 4 and smaller or components and piping segments which have multiple inlets or multiple outlets whose cumulative pipe cross-sectional area does not exceed the cross-sectional area defined by the OD of NPS 4 pipe.

4.3.3. Components that operate at a pressure of 275 psig or less and at a temperature of 2QQQF or less in systems (or portions of systems} whose function is not required in support of residual heat removal, containment heat removal, and emergency core cooling.

4.3.4 Welds or portions of welds that are inaccessible due to being encased in concrete, buried underground, located inside a penetration, or encapsulated by guard pipe.

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Cooper Station 5th ISi &

3rd Interval CISI Program 4.4 Section XI Class MC Exemptions:

4.4.1 IWE-1220 gives specific guidance for exempting components from the examination requirements of IWE-2500 if they are: vessels, parts, and appurtenances outside the boundaries of the containment system as defined in the design specifications; embedded or inaccessible portions of containment vessels, parts, and appurtenances with welds that meet the requirements of the original Construction Code; portions of containment vessels, parts, and appurtenances that become embedded or inaccessible as a result of vessel repair/replacement activities if the conditions of IWE-1232(a) and (b) and IWE-5220 are met; piping, pumps, and valves that are part of the containment system, or which penetrate, or are attached to the containment vessel.

4.4.2 The concrete biological shield and the shield plugs are not part of the containment design and are, therefore excluded from this program.

4.4.3 The portion of the drywell below the concrete floor is inaccessible. The welds in the lower head were double butt-welded and radiographed in accordance with the Construction Code. Therefore, the lower head of the drywell below the concrete floor is exempt per IWE-1220(b).

4.4.4 Welded attachments to components which are exempt from examination under IWE-1220 are also exempt from the examination requirements of IWE-2500 and Table IWE-2500-1.

4.4.5 Welded attachments to components which are classified as ASME 1, 2 or 3 are examined under the rules of IWB, IWC, or IWD as applicable.

4.4.6 Moisture barriers are not part of the containment pressure boundary (NE-2110(b). The placement of the concrete and the moisture barrier for the exterior biological shield was not subject to Code rules during construction. In response to IN 86-77 and GL 87-05, CNS performed a special test of the drywell sand cushion. No moisture was detected. Furthermore, the moisture barrier external to the containment is not accessible for examination. Therefore, the moisture barrier external to the drywell is exempt.

4.5.Section XI IWF Exemptions:

4.5.1 Supports connected to piping and other items exempted from the volumetric, surface, or VT-1 or VT-3 visual examination requirements of IWB-1220, IWC-1220, IWD-1220, and IWE-1220 are exempt. In addition, portions of supports that are inaccessible due to being encased in concrete, buried underground, located inside a penetration, or encapsulated by guard pipe are also exempt.

(4-4) Revision 0

Cooper Station 5th ISi &

3rd Interval GISI Program 4.6.Section XI Repair/Replacement Activity Exemptions:

4.6.1 IWA-4120(a thru e) identifies the applicability of the ASME XI repair/replacemen t activity rules.

4.6.2 Per IWA-4131.1 (a)(l) and IWA-4131.l(b), class 1 piping, tubing (except heat exchanger tubing, an sleeves and plugs used for heat exchanger tubing) valves, fittings and associated supports no larger than NPS 1 and Class, 2 and 3 piping, tubing (except heat exchanger tubing, and sleeves and welded plugs used for heat exchanger tubing) valves, and fittings NPS 1 and smaller and associated supports are exempt from the repair /

replacement rules. IWA-4131.1(a)(2) is not used.

4.6.3 For the exempt items in 4.6.2 above, the rules of IWA-4131.2 shall be followed. That is, the items must be purchased and installed in accordance with the CNS Quality Assurance Program to assure that material is furnished in accordance with the applicable material specification and construction code requirements.

4.6.4 The repair and replacement activity provisions in IWA-4540(c) of the 1998 Edition through the 2000 Addenda of Section XI for pressure testing Class 1, 2, and 3 mechanical joints shall be applied per 10 CFR 50.55a(b)(2)(xxvi).

Revision 0 I.A C\

\**h.JJ

Cooper Station 5th ISI &

3rd Interval CISI Program Reactor Vessel B-A(l) B1.11 Circumferential Shell I Volumetric I 4 I 0%(2)

I 0(2)

I 0(2)

I a121 I 0%(2)

I a121 I 0%(2)

I o!2)

I 0%(2)

Welds B-A(l) B1.12 Reactor Vessel Longitudinal Shell Welds I Volumetric I 12 I 100% I 12 I 12 I 10 I 100% I 0 I 0% I 2(3)

I 100%

I Volumetric I Reactor Vessel B-A(l) B1.21 Circumferential Head Welds 3

I 66.67%

141 I 2(4)

I 2(4)

I o'4l I 0%(4)

I 1(4)

I 50%( 4) I 1(4)

I 100%

B-A(l) Reactor Vessel B1.22 Meridional Head Welds I Volumetric I 22 I 100% I 22 I 22 I 0 I 0% I 14 I 64% I 8 I 100%

B-A(l) Reactor Vessel Shell to B1.3Q! 5l Flange Weld I Volumetric I 1 I 100% I 1 I 1 I 1 I 100% I 0 I 100% I 0 I 100%

B-A(l) 61 Reactor Vessel Head to Volumetric/ 0%

B1.4o' 1 100% 2 2 0 0 0 2 100%

Flange Weld Surface

~tegory Total I 43 39 39 11 28% 15 67% 13 100%

Note 1: Table IWB-2411-1 percentages do not apply.

Note 2: Table IWB-2500-1 requires 100%, however none are required based on approved NRC Relief Request RIS-01.

Note 3: Welds VLC-BB-2 and VLC-BB-3 require manual pick-ups to meet the volumetric percentage requirements through feedwater nozzle shield doors for N4-B and N4-C.

Note 4: Table IWB-2500-1 requires accessible length of all welds, however HMD-BB-1 is not accessible and therefore not required to be examined (See Technical Positon TP-72).

Notes for Cat. B-A Note 5: Permissible to defer based on meeting Note 3 or 5 in Table IWB-2500-1, Category B-A (Intent Interpretation Xl-1-13-08R clarified that either note can be used independent of each other).

Note 6: Permissible to defer based on meeting Note 4 or 5 in Table IWB-2500-1, Category B-A (Intent Interpretation Xl-1-13-08R clarified that either note can be used independent of each other).

(5-1) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program B-D 111 I B3.90 I Reactor Vessel Nozzle to I V OI t . I 28 I 50% I 14' 21 I 14 I 6 I 29%

131 I 2 I 62% 131 I 6 100%

Vessel Welds ume ric B-D 111 I B3.100 I Reactor Vessel Nozzle Inside Radius Section Volumetric I 19 I 52.6% I 1o'21 I 10 I 4 I 24% 131 I 0 I 53% 131 I 6 100%

B-D 111 I B3.100 I Reactor Vessel Nozzle Inside Radius Section Visual*

{VT-1)

I 9 I 44.44% I 412)

I 4 I 2 I 50% I 2 I 100% I 0 100%

Category Total I 56 I I 28 1 1

' I 28 I 12 I 43% 1 1

" I 4 I 64W" 1 I 12 I 101%

st Note 1: Table IWB-2411-1 percentages do not apply with exception that 1 Period percentages are minimum of 25% per IWB-2500-1, Category B-D Note 2.

Note 2: Number of welds based on NRC approval of Relief Request RIS-03 using BWRVIP-108, BWRVIP-241 and Code Case N-702 as basis for relief.

Note 3: Percentages based on NRC approval of Relief Request RIS-03 using BWRVIP-108, BWRVIP-241 and Code Case N-702 as basis for relief.

Notes for Cat. B-D Note 4: Visual VT-1 examination based on application of CC N-648-1 with the applicable NRC conditions in RG 1.147. CC only allowed to be used on nozzles not containing thermal sleeves {i.e., Nl, N3, NG, N7's). RIS-03 requires the latest version of N-648-X to be used at the time of the applicable nozzle IR examinations.

(S-2) Revision 2 I

Cooper Station 5th ISi &

3rd Interval CISI Program B-F(l) I FormerlyB I Nozzle-to-Safe End Butt Volumetric See I I 5.10 Welds, NPS 4 or Larger and surfacel 3l 1 17 I N/A I N/A I Cat R-A 0 N/A I 0 I N/A I 0 I N/A I Former! I Nozzle-to-Safe End Butt See I I I B-F(l) B s.io y Welds, Less than NPS 4 Surface 5 N/A N/A I Cat R-A I 0 I N/A I 0 I N/A I 0 I N/A I I Formerly B-F(l) I B5.130 & Piping welds Volumetric 6 N/A N/A See Cat R-A 0 N/A 0 N/A I 0 N/A B5.140( 2l Category Total 28 0\LJ 0 N/A 0 N/A I 0 N/A Note 1: Inspection requirements for this Category have been superseded by RI-ISi requirements based on Code Case N-716-1.

Notes for Cat. I Note 2: These welds are included in the RI-ISi Program. These dissimilar welds were B5.130 and B5.140 under the 3 rd interval.

Note 3: Examination method is only volumetric per the CNS RI-ISi Program.

(5-3) Revision 2 I

Cooper Station 5th ISi &

3 rd Interval CISI Program B-G-1( 1l I 86.10 I Reactor Vessel Closure I Visual, VT-1 I 52 I 100% I 52 I 52 I 27 I 52% I 25 I 100% I 0 I 100%

Head Nuts B-G-1( 1l I 86.20 I Reactor Vessel Closure I Volumetric I 52 I 100% I 52 I 52 I 0 I 0% I 52 I 100% I 0 I 100%

Studs 8-G-l(ll I 86.40 I Threads in Reactor I Volumetric I 52 I 100% I 52 I 52 I 0 I 0% I 0 I 0% I 52 I 100%

Vessel Flange 8-G-l(ll I 86.50 I Reactor Vessel Closure Visual, VT-1 104 53.84% 56(7 ) 56 27 I 48% I 25 I 93% I 4 I 100%

Washers, Bushings 8-G-l(ll I 86.180 I Bolts and Studs in Pumps Volumetric 2(2) 50%( 6 ) 1(2) 1(2) 1(5)

I 100% I 0 I 0% I 0 I 0%

8-G-1 (ll I 86.190 I Flange Surface, When I Visual, VT-1 I 2(3)

I 50%(3) I 1(3)

I 1(3)

I 1(3)

I 100%(3) I 0(3)

I 0%(3) I o(3l I 0%(3)

Disassembled, in Pumps 8-G-1 (ll I 86.200 I Nuts, Bushings, and I Visual, VT-1 4(4) 50%( 6 ) 2(4) 2(4) 2 100% 0 0% 0 0%

Washers in Pumps Category Total 268 216( 7 ) 216(7)) 58 27% 102 75% 56 100%

Note 1: Table IWB-2411-1 percentages do not apply as examinations may be deferred to end of interval or are only required under certain circumstances such as disassembly of a flange, pump, or valve.

Note 2: 1 set of 16 bolts per pump, 2 pumps total.

Note 3: 1 flange per pump, 2 reactor recirc. pumps total, examine if disassembled (includes 1 inch annular surface around each stud) (See Technical Position TP-4).

Notes for Cat. I Note 4: 1 set of 16 nuts and 16 washers per pump ..

Note 5: Studs will be examined in place under tension if not disassembled. Scheduled examination (See Technical Position TP-1).

Note 6: Per Table IWB-2500-1, Category B-G-1 Note 3, examination can be limited to one bolted connection of a group of similar pumps resulting in 1 of the 2 reactor recirc pumps to be examined. Examination is not required unless connection is disassembled (see Table IWB-2500-1, Category B-G-1 Note 4) (See Technical Position TP-5)

Note 7: Bushing ex~~s~dused_to__()11ly the 4 where the studs are removed. (Footnote 2 (See Technical Position JP-7_3J (5-4) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program B-G-2( 1) I B7.10 I Bolts, Studs, and Nuts in I Visual, 3 Sets( 2l N/A 1 1 1 100% 0 N/A 0 N/A Reactor Vessel VT-1 B-G-2(l,4) I B7.50 I Bolts, Studs, and Nuts in I Visual, 13 Sets N/A 0 0 0 N/A 0 N/A 0 N/A Piping VT-1 B-G-2(1,5) I B7.70 I Bolts, Studs, and Nuts in I Visual, 32 Sets N/A 0 0 0 N/A 0 N/A 0 N/A Valves VT-1 Categ~!'~ Total I 185 I I 1 I 1 I 1 I 100% I O I N/A I O I N/A Note 1: Table IWB-2411-1 percentages do not apply as bolting is only required to be examined if connection is disassembled, Reference Note 1 to Table IWB-2500-1, Cat B-G-2.

Note 2: The reactor vessel has three top head flanges, 2 have blind flanges and 1 flange is disconnected each refueling outage (See Technical Position TP-74).

Note 3: Deleted Note Note 4: Table IWB-2411-1 percentages do not apply as bolting is only required to be examined if connection is disassembled and can be limited to one connection among a group of bolted connections of similar design, size, function, and service. Reference Note 3 to Table IWB-2500-1, Cat B-G-2. CNS has 3 Groups: Group F (3 sets) (Technical Notes for Cat. Position TP-6), Group G (8 sets) (See Technical Position TP-7), and Group N/A (2 sets)(See Technical Position TP-8).

Note 5: Table IWB-2411-1 percentages do not apply as bolting is only required to be examined if connection is disassembled and can be limited to one connection among a group of bolted connections of similar design, size, function, and service. Reference Note 2 to Table IWB-2500-1, Cat B-G-2. CNS has 8 Groups: Group B (2 sets)(See Technical Position TP-11), Group D (4 sets)(See Technical Position TP-12), Group F (3 sets)(See Technical Position TP-13), Group G (8 sets)(See Technical Position TP-14), Group H (8 sets)(See Technical Position TP-15), Group J (1 set)(See Technical Position TP-16), Group M(2 sets)(See Technical Position TP-17), and Group Q (4 sets)(See Technical Position TP-18).

(5-5) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program I Formerly Circumferential Welds in I Volumetric I See B-Pl 89.11 Piping, NPS 4 or Larger and Surface 366 I N/A I 0 I Cat R-A I 0 I N/A I 0 I N/A I 0 I N/A I Formerly Circumferential Welds in See B-P 1 89.21 Piping, Less than NPS 4 I Surface I 47 I N/A I 0 I Cat R-A I 0 I N/A I 0 I N/A I 0 I N/A I Formerly Branch Pipe Connection I Volumetric I See B-P 1 I I I I I I 89.31 Welds, NPS 4 or Larger and Surface 16 I N/A I 0 I Cat R-A 0 N/A 0 N/A 0 N/A B-P 1 I Formerly 89.32 Branch Pipe Connection Welds, Less than NPS 4 Surface 23 N/A 0 See Cat R-A I 0 I N/A I 0 I N/A I 0 I N/A B-P 1 I Formerly Socket Welds Surface 169 N/A 0 See 0 N/A 0 N/A 0 N/A 89.40 Cat R-A Category Total 621 0 0 N/A 0 N/A 0 N/A 1

Note 1: Table IWB-2411-1 percentages do not apply. Inspection requirements for this Category has been superseded by RI-ISi requirements based on Code Case N-716-1.

Notes for Cat.

(5-6) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program Integrally Welded B-K(l) I B10.10 I Attachments to Pressure Surface 5 20%( 2) 1 1 0 0% 1 100% 0 100%

Vessels 8-K(l) I B10.20 I Integrally Welded Surface 66 3.03%( 3) 2 2 1 58% 0 86% 1 100%

Attachments to Piping B-K(l) I B10.30 I Integrally Welded Surface 6 16.60%(3) 1 1 0 0% 0 0% 1 100%

Attachments to Pumps Category Total I 77 I I 4 I 4 I 1 I 25% I 1 I 50% I 2 I 100%

Note 1: Table IWB-2411-1 percentages apply.

Note 2: Percentage based on performing 1 of the 5 attachments per Note 4 of Table IWB-2500-1, Category B-K- I (See Technical Position TP-2)

Notes for Cat. Note 3: Percentage based on Footnote 5 of Table IWB-2500-1, Category B-K. For piping and pumps, a sample of 10% of the welded attachments associated with the component supports selected for examination under IWF-2510 shall be examined. This ten percent sample is equivalent to 3.03% of all piping attachments (See Technical Position TP-3) and 16.60~ of all pump attachments (See Technical Position TP-31). ______ _

Visual B-L-2(ll B12.20 Pump Casing 2 50%( 3) 1(2) 1(2) 1 100% 0 0% 0 0%

VT-3 Category Total I 2 I I l11 L I 11' 1 I 1 I 100% 0 0% 0 100%

Note 1: Table IWB-2411-1 percentages do not apply.

Notes for Cat. Note 2: Examination limited to one of the two Reactor Recirc. pumps and only when disassembled (See Technical Position TP-32).

Note 3: The Recirculation Pump (RR-P-A) ~rn the A Loop is scheduled in RE29.

{5-7) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program B-M-2(ll Valve Body exceeding N/A(2)(3l d2)(3) 812.50 Visual, VT-3 50 0 0 N/A 0 N/A 0 N/A NPS 4 Category Total I SO I I O I O I O I N/A I O I N/A I O I N/A Note 1: Table IWB-2411-1 percentages do not apply.

Note 2: Examinations are only required if valves are disassembled for maintenance or repair.

Note 3: Examinations are limited to at least one valve within each group of similar valves that perform similar functions. CNS has 14 Groups: Group A (4 valves)(See Technical Position TP-33), Group B (2 Valves)(See Technical Position TP-34), Group C {3 Valves)(See Technical Position TP-35), Group D (4 Valves)(See Technical Position TP-36),

Notes for Cat.

Group E (2 Valves){See Technical Position TP-37), Group F {3 Valves){See Technical Position TP-38), Group G (8 Valves){See Technical Position TP-38), Group H (8 Valves){See Technical Position TP-40), Group I {2 Valves){See Technical Position TP-41), Group J { 1 Valve)(See Technical Position TP-42), Group K {3 Valves){See Technical Position TP-43), Group L (4 Valves)(See Technical Position TP-44), Group M (2 Valves)(See Technical Position TP-45), and Group Q (4 Valves)(See Technical Position TP-46). .

4 I N/NLJ I 0 I N/A I 0 I N/A I 0 I N/A I 0

~a_!egory Total I 4 I I O I N/A I O I N/A I O I N/A I O I N/A Note 1: Table IWB-2411-1 percentages do not apply.

Notes for Cat. Note 2: Request for Alternative Rl5-02 {approved) uses the BWRVIP Program in lieu of Examination Category B-N-1 {See BWRVIP Program for examination requirements and scheduling)

(5-8} Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program I Interior Attachments I Visual, VT-1 I B-N-2(ll I B13.20 within Beltline Region 13 I *N/A(2l I 0 I N/A I 0 I N/A I 0 I N/A I 0 I N/A 8-N-2l 1l 813.30 Interior Attachments beyond Beltline Region I Visual, VT-3 I 29 I N/Al 2l I 0 I N/A I 0 I N/A I 0 I N/A I 0 I N/A B-N-2( 1l 813.40 Core Support Structure Visual, VT-3 141 N/A( 2l 0 N/A 0 N/A 0 N/A 0 N/A Category Total 183 0 N/A 0 N/A 0 N/A 0 N/A Note 1: Table IWB-2411-1 percentages do not apply.

Notes for Cat. I Note 2: Request for Alternative RIS-02 (approved) uses the BWRVIP Program in lieu of Examination Category B-N-2 (See BWRVIP Program for examination requirements and scheduling) 36 peripheral B-o'l) I B14.10 I Welds in CRD housing I Surface I CRDs, 72 upper and I 10%(2 ) I 8(2) I 8 I 2 I 25% I 2 I 50% I 4 I 100%

lower welds C:atego!'{ Total I 274 I I 8(2) I 8 I 2 I 28% I 2 I 56% I 4 I 100%

Note 1: Table IWB-2411-1 percentages do not apply. Deferral to end of interval is permissible.

Notes for Cat.

Note 2: Code requires 10% of the peripheral upper and lower CRD welds to be examined either by volumetric or surface on 4 CRDs each interval. Upper welds are inaccessible and will require a relief request after the attempted examination in RE29.

(5-9) Revision 2 I

Cooper Station 5th ISI &

3 rd Interval CISI Program I I Pressure Retaining 100% each I I B-P(l) B15.10 Components Visual, VT-2 2(2) outage 8 8 I 4 I 50% I 4(3)

I 50% I 0 0%

I Pressure Retaining 2(2) 100% each B-P I B15.20 Visual, VT-2 I 2 I 2 I 0 I 0% I 0 I 0% I 2 100%

Components interval Category Total I 4 I I 10 I 10 I 4 I 40% I 4 1~ 1 I 80% I 2 1~ 1 I 100%

Note 1: Table IWB-2411-1 percentages do not apply. Required every outage.

Note 2: Number is based on vessel and Class 1 piping along with vessel leak detection line as the second component {Code Case N-805 provides the alternative for end of Notes for Cat.

interval).

rd Note 3: leakage tests conduct~d per 6.MISC.502 f~r 8 of the 10 tests. The fi~al system leakage test {Item No_._B_lS.20) is performed per 6.MISC.504 in the 3 period ..

Shell Circumferential 0%(1)

C-A Cl.10 Welds Volumetric 8 0 0 0 0% b 0% 0 0%

Head Circumferential 0%(1)

C-A Cl.20 Volumetric 2 0 0 0 0% 0 0% 0 0%

Welds C_ategory Total I 10 I I o I o I o I 0% I o I 0% I o I 0%

Note 1: Evaluation performed under Code Case N-716-1 determined the RHR Heat Exchangers to be Low Safety Significant {LSS) and therefore no examinations are required {See Notes for Cat. Technical Positions TP-55 and TP-56).

(5-10} Revision 2 I

Cooper Station 5th ISI &

3 rd Interval CISI Program Nozzle-to-Shell (or Head)

C-B I C2.21 I Weld without Reinforcing Plates in I Volumetric I 2 I 0%(1) I 0 I 0 I 0 I 0% I 0 I 0% I 0 I 0%

and Surface Vessels> 1/2" Nominal Thickness C-B C2.22 Nozzle Inner Radius 0%(1) I I I I I Volumetric 2 0 0 0 0% 0 0% 0 I 0%

Reinforcing Plate Welds I to Nozzle & Vessel for C-B I C2.31 Nozzles in Vessels > 1/2" I Surface I 4 I 0%(1) I 0 I 0 I 0 I 0% I 0 I 0% I 0 I 0%

Nominal Thickness Nozzle-to-Shell (or Head or nozzle-to-nozzle)

Welds when Inside of C-B I C2.33 I Vessel is Inaccessible, for I Visual, VT-2 I 2 I 0%(1) I 0 I 0 I 0 I 0% I 0(4)

I 0% I 0 I 0%

Vessels> 1/2" Nominal Thickness with Reinforcing Plates I

Category I Total : 10 I I 0 I 0 I 0 I 0% I 0 I 0% I 0 I 0%

Note 1: Evaluation performed under Code Case N-716-1 determined the RHR Heat Exchangers to be Low Safety Significant (LSS) and therefore no examinations are required (See Notes for Cat. I Technical Positions TP-57, TP-58, TP-75 and TP-76).

(5-11} Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program c-d 1l I C3.10 I TP ! TP-59 I Weld- I 2 I so.oo%(3) I 113 ) I 113 ) I 1 I 0I 0.00% I 1 I 100.00% I o I 100.00%

SUR c-d l 1

I C3.20 I TP I TP-60 I Weld- I 139 I 2.88% 12 ) I 4( 2) I 412 i I 41 2 I 50.00% I 1 I 75.00% I 1 I 100.00%

SUR c-ctii I C3.30 I TP J TP-61 I Weld- 6 I 33.33% 12 ) I 212 i I 212 i I 2 I OI 0.00% I OI 0.00% I 2 I 100.00%

SUR Note 1: Table IWC-2411-1 percentages apply.

Note 2: Sample includes 10% of the welded attachments associated with the component supports selected for examination under IWF-2510. Only 4 piping welded attachments are required to be examined (See Technical Position TP-60). Only 2 pump welded attachments are required to be examined {See Technical Position TP-61).

Notes for Cat.

Note 3: Number of components limited to one of the two RHR Hx's (each RHR HX. has 1 welded attachment consisting of two circumferential welds on the reinforcing band (dwg. M82704)) per Note 4 ofTable IWC-2500-1, Cat C-C that permits only one component be examined for multiple vessels of similar design, function, and service (See Technical Position TP-59).

(5-12) Revision 2 I

Cooper Station 5th ISi &

3rd Interval CISI Program Circumferential Welds in C-F-2( 1l I CS.51 I Piping~ 3/8" Nominal I Volumetric I 794 I N/A I 0 I 0 I 0 I N/A I 0 I N/A I 0 I N/A Wall Thickness for Piping and Surface

> NPS 4 Circumferential Welds in C-F-2( 1l I CS.81 I Pipe Branch Connections I Surface I 4 I N/A I 0 I 0 I 0 I N/A I 0 I N/A I 0 I N/A of Branch Piping~ NPS 2 Welds not subject to I ---- I examination based on I C-F-2( 1l Table IWC-2500-1 criteria N/A I 136 I N/A I 0 I 0 I 0 I N/A I 0 I N/A I 0 I N/A (e.g., <3/8")

~ategory Total I 934 I I 0 I 0 I 0 I N/A I 0 I N/A I 0 I N/A Notes for Cat. I Note 1: Table IWC-21+/-!_-1 percentages do not_i![>ply._ln_spection requirements for this Category have been superseded by RI-_ISI requirements based on Code Case N-716-1.

Pressure Pressure Retaining 100% per C-H(l) C7.10 Visual, VT-2( 2! 8 24 retaining 8 100% 8 100% 8 100%

components Period boundary Category Total I 8 24 8 100% 8 100% 8 100%

Note 1: Table IWC-2411-1 percentages do not apply.

Note 2: Visual examination per IWA-5240.

Notes for Cat.

Note 3: Systems include CRD, CS (A/B), HPCI, RCIC, REC, and RHR (A/B).

(5-13) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program Notes for Cat. Note 1: Table IWD-2411-1 percentages apply.

Note 2: Welded integral attachments examined at same time as F-A component typically to the extent practical. However, in some cases, there may be multiple welded integral attachment ID's for a single F-A support component (e.g., ECST tank has one F-A support component ID with six integral attachment ID's).

Note 3: Per TP-77, only 4 required.

D-B(l) 100% per D2.10 components Visual, VT-2 5 15 5 100% 5 100% 5 100%

Period Category Total I 5 1" 1 I I 15 5 100% 5 100% 5 100%

Note 1: Table IWD-2411-1 percentages do not apply.

Notes for Cat.

Note 2_: Systems in_clude Emergency Condensate storage, NBI, REC, and SW (A/B).

(5-14) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program General 100% per E-A I El.11 I Accessible Surface Areas 6 I 18 I 18 I 6 I 100% I 6 I 100% I 6 I 100%

Visual Period Wetted Surfaces or o(ll E-A I El.12 1 Submerged Surfaces Visual, VT-3 N/A I N/A I N/A I N/A I N/A I N/A I N/A I N/A I N/A I BWR Vent System; E-A I El.20 Accessible Surface Areas Visual, VT-3 I 80 I 100% I 80 I 80 I 24 I 30% I 24 I 60% I 32 I 100%

General E-A I El.30 I Moisture Barriers i12i 50% 3 3 1 100% 1 100% 1 100%

Visual Category Total 88 101 101 31 31% 31 61% 39 100%

Note 1: All areas for Item Number El.12 have been considered susceptible to accelerated corrosion per IWE-1240 and therefore placed in Category E-C, Item Number E4.11.

Notes for Cat. I Note 2: The Drywell Exterior Moisture Barrier is inaccessible (Ref. TP-1 of CISI Program).

100% every E-C I E4.11 I Visible Surfaces I Visual, VT-1 I 48 I other I 144 I 144 I 48 I 100% I 48 I 100% I 48 I 100%

Outage(ll Volumetric, 100% per E-C I E4.12 I Test Area Locations 4 18( 2) 18 6 100% 8 100% 4 100%

UT Outage Ca~gory Total 52 162 162 54 100% 56 *100% 52 100%

Note 1: Visual examination is required every other outage (maximum of 4 years) and UT is required every outage based on License Renewal Commitment NLS2010050-02, Rev 1.

Notes for Cat.

Note 2: CNS committed to performing UT's of torus shell (4 locations) after RE29 when only 2 locations were UT'd, hence the total scheduled examinations are 18 vs. 20.

(5-15) Revision 2

Cooper Station 5th ISI &

3 rd Interval CISI Program Category_ Total I 22 I 22 I 22 I 4 I N/A111 I O I N/A1 1 I 18 J_ I 100%

Note 1: Table IWE-2411-1 percentages do not apply.

Note 2: Examination may be performed with the connection assembled and bolting in place under tension, provided the connection is not disassembled during the interval. If the Notes for Cat.

bolted connection is disassembled for any reason during the interval, the examination shall be performed with the connection disassembled.

(5-16) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program F-A(l) Fl.10.A MS SupportVIS 3 25.00% I o.75 I 1 I 1 I 100.00% I 01 0.00% I 1 I 133.33% I 01 133.33%

F-A(l) Fl.10.A NBDR SupportVIS 2 25.00% I o.5 I 1 I 1 I 100.00% I ol 0.00% I 1 I 200.00% I al 200.00%

I I I 1 I 100.00% I I I F-A(l) Fl.10.A RF SupportVIS 4 25.00% 1 1 01 0.00% 1 100.00% I 0I 100.00%

F-A(l) Fl.10.A RHR SupportVIS 2 25.00% I o.5 I 1 I 1 I 100.00% I ol 0.00% I ol 0.00% I 1 I 200.00%

F-A(l) I Fl.10.A RWCU SupportVIS 6 25.00% 1.5 I 2 I 2 I 100.00% I 0I 0.00% I o I 0.00% I 2 I 133.33%

F-A(l) I I Fl.10.A SLC SupportVIS 19 25.00% 4.75 5 I 5 I 100.00% I 0I 0.00% I 41 84.21% I 1 I 105.26%

F-A(l) MS I I Fl.10.B SupportVIS 4 25.00% 1 1 I 1 I 100.00% I 1 I 100.00% I 0I 100.00% I 0I 100.00%

F-A(l) Fl.10.B RR SupportVIS I 2 I 25.00% I o.5 I 1 I 1 I 100.00% I 01 0.00% I 1 I 200.00% I 0I 200.00%

F-A(l) Fl.10.C cs SupportVIS I 6 I 25.00% I 1.5 I 2 I 2 I 100.00% I 1 I 66.67% I 1 I 133.33% I 0I 133.33%

F-A(l) Fl.10.C MS SupportVIS I 37 I 25.00% I 9.25 I 10 I 10 I 100.00% I 41 43.24% I 3 I 75.68% I 3 I 108.11%

F-A(l) Fl.10.C MSDR SupportyIs I 2 I 25.00% I o.5 I 1 I 1 I 100.00% I 0I 0.00% I 1 I 200.00% I 0I 200.00%

F-A(l) Fl.10.C RF SupportVIS I 27 I 25.00% I 6.75 I 7 I 7 I 100.00% I 5 I 74.07% I 1 I 88.89% I 1 I 103.70%

F-A(l) Fl.10.C RHR SupportVIS I 39 I 25.00% I 9.75 I 10 I 10 I 100.00% I 3 I 30.77% I 3 I 61.54% I 41 102.56%

F-A(l) I I Fl.10.C RR SupportVIS 13 25.00% 3.25 41 41 100.00% I 2 I 61.54% I 0I 61.54% I 2 I 123.08%

F-A(l) Fl.10.C RWCU SupportVIS 6 25.00% 1.5 2 2 100.00% 0 0.00% I 2 I 133.33% I 01 133.33%

F-A(l) Fl.20.A cs SupportVIS 18 15.00% 2.7 3 3 100.00% 1 37.04% I 2 I 111.11% I 0I 111.11%

F-A(l) Fl.20.A HPCI SupportVIS 16 15.00% 2.4 3 3 100.00% 1 41.67% I 1 I 83.33% I 1 I 125.00%

F-A(l) MS Fl.20.A SupportVIS 32 15.00% 4.8 5 5 100.00% I 1 I 20.83% I 1 I 41.67% I 3 I 104.17%

F-A(l) Fl.20.A PC SupportVIS 9 15.00% 1.35 2 2 100.00% 0 0.00% 2 148.15% I 01 148.15%

F-A(l) Fl.20.A RCIC SupportVIS 11 15.00% 1.65 2 2 100.00% 1 60.61% 0 60.61% I 1 I 121.21%

F-A(l) Fl.20.A RHR SupportVIS 48 15.00% 7.2 8 8 100.00% 2 27.78% 2 55.56% I 41 111.11%

F-A(l) Fl.20.A SDV SupportVIS 32 15.00% I 4.8 I 5 5 I 100.00% I 2 I 41.67% I 1 I 62.50% I 2 I 104.17%

(5-17) Revision 2

Cooper Station 5th ISi &

3 rd Interval CISI Program F-A(l) Fl.20.B cs SupportVIS 12 15.00% 1.8 2 2 100.00% 0 0.00% 1 55.56% 1 111.11%

F-A(l) Fl.20.B HPCI SupportVIS 8 15.00% 1.2 2 2 100.00% 1 83.33% 1 166.67% 0 166.67%

F-A(l) Fl.20.B MS SupportVIS 4 15.00% 0.6 1 1 100.00% 0 0.00% 0 0.00% 1 166.67%

F-A(l) Fl.20.B RCIC SupportVIS 5 15.00% 0.75 1 1 100.00% 0 0.00% 0 0.00% 1 133.33%

F-A(l) Fl.20.B RHR SupportVIS 25 15.00% 3.75 4 4 100.00% 1 26.67% 1 53.33% 2 106.67%

F-A(l) Fl.20.B SDV SupportVIS 6 15.00% 0.9 1 1 100.00% 1 111.11% 0 111.11% 0 111.11%

F-A(l) Fl.20.C cs SupportVIS 18 15.00% 2.7 3 3 100.00% 1 37.04% 1 74.07% 1 111.11%

F-A(l) Fl.20.C HPCI SupportVIS 5 15.00% 0.75 1 1 100.00% 0 0.00% 0 0.00% 1 133.33%

F-A(l) Fl.20.C MS SupportVIS 34 15.00% 5.1 6 6 100.00% 2 - 39.22% 2 78.43% 2 117.65%

F-A(l) Fl.20.C PC SupportVIS 2 15.00% 0.3 1 1 100.00% 0 0.00% 1 333.33% 0 333.33%

F-A(l) Fl.20.C RCIC SupportVIS 2 15.00% 0.3 1 1 100.00% 0 0.00% 1 333.33% 0 333.33%

F-A(l) Fl.20.C RHR SupportVIS 97 15.00% 14.55 15 16 106.67% 5 34.36% 7 82.47% 4 109.97%

F-A(l) Fl.30.A CM SupportVIS 1 10.00% 0.1 1 1 100.00% 0 0.00% 1 1000.00% 0 1000.00%

F-A(l) Fl.30.A HPCI SupportVIS 23 10.00% 2.3 3 3 100.00% 0 0.00% 3 130.43% 0 130.43%

F-A(l) Fl.30.A MSRV SupportVIS 9 10.00% 0.9 *1 1 100.00% 0 0.00% 0 0.00% 1 111.11%

F-A(l) Fl.30.A REC SupportVIS 32 10.00% 3.2 4 4 100.00% 1 31.25% 1 62.50% 2 125.00%

F-A(l) Fl.30.A SW SupportVIS 161 10.00% 16.1 17 17 100.00% 5 31.06% 6 68.32% 6 105.59%

F-A(l) Fl.30.B CM SupportVIS 1 10.00% 0.1 1 1 100.00% 0 0.00% 1 1000.00% 0 1000.00%

F-A(l) Fl.30.B HPCI SupportVIS 6 10.00% 0.6 1 1 100.00% 1 166.67% 0 166.67% 0 166.67%

F-A(l) Fl.30.B MSRV SupportVIS 6 10.00% 0.6 1 1 100.00% 0 0.00% 0 0.00% 1 166.67%

F-A(l) Fl.30.B REC SupportVIS 7 10.00% 0.7 1 2 200.00% 1 142.86% 0 142.86% 1 285.71%

F-A(l) Fl.30.B SW SupportVIS 50 10.00% 5 5 5 100.00% 1 20.00% 2 60.00% 2 100.00%

F-A(l) Fl.30.C HPCI SupportVIS 1 10.00% 0.1 1 1 100.00% 0 0.00% 0 0.00% 1 1000.00%

F-A(l) Fl.30.C MSRV SupportVIS 87 10.00% 8.7 9 10 111.11% 5 57.47% 2 80.46% 3 114.94%

F-A(l) Fl.30.C REC SupportVIS 10 10.00% 1 1 1 100.00% 1 100.00% 0 100.00% 0 100.00%

F-A(l) Fl.30.C SW SupportVIS 11 10.00% 1.1 2 2 100.00% 1 90.91% 1 181.82% 0 181.82%

F-A(l) Fl.40.A CM SupportVIS 2 50.00% 1 1 1 100.00% 0 0.00% 1 100.00% 0 100.00%

(5-18) Revision 2 I

Cooper Station 5th ISi &

3 rd Interval CISI Program F-A(l) Fl.40.A NB SupportVIS 5 100.00% 5 5 5 100.00% 2 40.00% I 1 I 60.00% I 2 I 100.00%

F-A(l) Fl.40.A PC SupportVIS 56 100.00% 56 56 56 100.00% 15 26.79% 26 73.21% 15 100.00%

F-A(l) Fl.40.A REC SupportVIS 7 71.40% 5 5 5 100.00% 1 20.00% 0 20.00% 4 100.00%

F-A(l) Fl.40.A RHR SupportVIS 8 50.00% 4 4 4 100.00% 0 0.00% 4 100.00% 0 100.00%

F-A(l) Fl.40.B cs SupportVIS 2 50.00% I 1 I 1 I 1 I 100.00% I 0I 0.00% I 0I 0.00% I 1 I 100.00%

F-A(l) Fl.40.B HPCI SupportVIS 2 100.00% I 2 I 2 I 2 I 100.00% I 2 I 100.00% I oI 100.00% I oI 100.00%

F-A(l) Fl.40.B PC SupportVIS 72 100.00% 72 72 72 100.00% 20 27.78% 31 70.83% 21 100.00%

F-A(l) Fl.40.B RCIC SupportVIS 1 100.00% 1 1 1 100.00% 1 100.00% 0 100.00% 0 100.00%

F-A(l) Fl.40.B REC SupportVIS 4 25.00% 1 1 1 100.00% 0 0.00% 1 100.00% 100.00%

0 F-A(l) Fl.40.B RHR SupportVIS 4 25.00% 1 1 1 100.00% 0 0.00% 01 0.00% I 1 I 100.00%

F-A(l) Fl.40.B SW SupportVIS 10 30.00% I 3 I 3 I 3 I 100.00% I 2 I 66.67% I 0I 66.67% I 1 I 100.00%

F-A(l) Fl.40.C RR SupportVIS 12 50.00% I 6 I 6 I 6 I 100.00% I 6 I 100.00% I 0I 100.00% I 0I 100.00%

Note 1: Table IWF-2410-1 percentages apply.

Note 2: Summary Numbers that include F1.10D, F1.20D, F1.30D, and F1.40D denote snubbers governed under the OM Code, Subsection ISTD. However percentages are based on total number of supports for each Class. Snubber supports (pin to building and pin to component) are included in totals for Type C supports based on function and system. Reference 2007 Edition through the 2008 Addenda of ASME Section XI, Figure IWF-1300(f) for break between OM Code and Section XI.

Note 3: Class MC components required to be examined per License Renewal Commitment NLS2008071-12.

Note 4: Table IWF-2500-1 requires 100% of Fl.40 supports to be examined with the exception per Note 3 where only one support is required to be examined for multiple components of similar design, function and service. Consequently, the percentage required for examination is based on the particular breakdown of similar components. The total required examinations for F1.40A, Band C component supports is based on following:

Notes for Cat.

Fl.40A - Number of components based on 1 (ECST A)+ 4(REC HX A)+ 1 (REC tank)+ 4 (RHR HX A)+ 1 (RPV Skirt)+ 4 (RPV Stabilizers)+ 56 (Torus Downcomer and Vent Header)= 71 F1.40B - Number of components based on 1 (CSP B) + 1 (HPCI BP)+ 1 (HPCI MP)+ 1 (RCIC MP)+ 1 (REC Pump A)+ 1 (RHR Pump A)+ 1 (SW BP A)+ 1 (SW PA)+ 1 (SW Strainers A) + 60 (Torus Downcomer Pair Support, Earthquake Ties, and Saddle Supports)+ 12 Vacuum Breaker Supports= 81.

F1.40C (including D's) - Number of components based on 3 (RR PA constants)+ 3 (RR PA snubbers) + 3 (RR P B constants) + 3 (RR P B snubbers) = 12. Only the RR P A Pump is scheduled which results in 6 supports examined.

(5-19) Revision 2 I

Cooper Station 5th ISI &

3rd Interval CISI Program R-A I Rl.16 I NB I STD I R-ARl.16 I Weld-VOL 1 100.00% 1 1 0 0.00% I 1 I 100.00% I 01 100.00%

R-A I Rl.20 I cs I TP I TP-88 I Weld-VOL 32 12.25% 3.92 5 3 76.53% I ol 76.53% I 2I 127.55%

R-A I Rl.20 I NBI I TP I TP-88 I Weld-VOL 10 12.25% 1.22 1 0 0.00% 0 0.00% 1 81.97%

R-A I Rl.20 I RR I TP I TP-88 I Weld-VOL 84 12.25% 10.29 9 4 38.87% 4 77.75% 1 87.46%

R-A I Rl.20 NBDR TP TP-88 Weld-VOL 12 12.25% 1.47 2 0 0.00% 2 136.05% 0 136.05%

R-A Rl.20 SLC TP TP-88 Weld-VOL 4 12.25% 0.49 1 0 0.00% 0 0.00% 1 204.08%

R-A Rl.20 MS TP TP-88 Weld-VOL 149 12.25% 18.25 15 7 38.36% 6 71.23% 2 82.19%

R-A Rl.20 NB TP TP-88 Weld-VOL 3 12.25% 0.37 0 0 0.00% 0 0.00% 0 0.00%

R-A I Rl.20 RF TP TP-88 Weld-VOL 89 12.25% 10.9 9 2 18.35% 1 27.52% 6 82.57%

R-A I Rl.20 RHR TP TP-88 Weld-VOL 53 12.25% 6.49 10 2 30.82% 2 61.63% 6 154.08%

R-A I Rl.20 I RWCU I TP I TP-88 I Weld-VOL 14 12.25% 1.72 3 0 0.00% I 2 I 116.28% I 1 I 174.42%

R-A I Rl.20 I MSDR I TP I TP-88 I Weld-VOL 7 12.25% 0.86 1 0 0.00% I 1 j 116.28% I oI 116.28%

• -* "t.

Category Subtotal 458 R-A I I I I VT-2 I (VOL( 6 l) 191(3 )( 6 ) 5.7%(2) I 11(4) 55( 4) 22( 4) N/A( 4l N/A( 4l N/A(4 l I

Rl.20 I

Note 7 TP I

TP-89 I

22(4)

I I 11(4)

I R-A I Rl.00 I LSS I TP I Note 5 I N/A 934 0%(5) I N/A I N/A I N/A I N/A I N/A I N/A I N/A I N/A Category Total 1583 Note 1: Table IWB-2411-1 percentages used as guidance for distribution of examinations over the interval.

Note 2: Percentage based on number of selected welds divided by the number of welds in the R-A assigned Item (See Technical Positions TP-88 and TP-89).

Note 3: These welds are addressed by Technical Position TP-89 Note 4: The Visual VT-2 examination is performed each Refueling outage per 6.MISC.502 and per 6.MISC.504 for the last outage of the interval, therefore the percentage requirements do not apply.

Notes for Cat. I Note 5: These welds were evaluated as Low Safety Significant (LSS) and therefore exempt per 4(c) of Code Case N-716-1.

Note 6: RVD-BJ-10, SLC-BJ-8, and SLC-BJ-9 welds are included in the License Renewal Commitment NLS2010044-01 which requires a volumetric examination every interval in addition to the VT-2 examinations performed.

Note 7: Welds Not Subject to a Degradation Mechanism {Socket Welds and NPS 2 and less Branch Connections)

TP-88: Circumferential Welds Not Subject to a Degradation Mechanism {457 total welds, i.e., 458-1 for Rl.16). Implementation of Code Case N-716-1 results in perfo!_ming volum~_!ric examinations on 56 of the 457 which equals 12.25%. Element Selection results in 56 welds selected for examination meeting the criteria

{S-20) Revision 2 I

Cooper Station 5th ISi &

3rd Interval CISI Program contained in Section 4 "lnservice Inspection Requirement" of Code Case N-716-1.

TP-89: Socket welds - Implementation of Code Case N-716-1 resulted in 191 total welds within the Class 1 boundary subject to VT-2 examination. Element Selection results in 11 welds being selected out of the 191 total welds or 5.7 meeting the criteria contained in Section 4 "lnservice Inspection Requirement" of Code Case N-716-1.

{5-21) Revision 2 I

Cooper Station 5th ISi &

3rd Interval CISI Program I Feedwater Nozzle Inner B-D I B3.100 I Volumetric I 4 I 100% I 4 I 4 I 0 I 0% I 0 I 0% I 4 I 100%

Radii XMll.l I NR. 0619 _8 I Fee~water Nozzle Bore Volumetric 4 100% 4 4 0 0% 0 0% 4 100%

Region 3 Category Total 8 8 8 0 0% 0 0% 8 100%

Notes for I None NUREG-0619 (5-22) Revision 2 I

Cooper Station 5th ISi &

3rd lnteval CISI Program 6.0 INSERVICE INSPECTION TECHNICAL APPROACH AND POSITION INDEX/SUMMARIES II Position CT-01 Summary Pipe Calibration Blocks used for Examination of Fittings I

CT-02 Weld Reference System (6-1) Revision 0

Cooper Station 5th ISi &

3rd lnteval CISI Program TECHNICAL APPROACH AND POSITION NUMBER: CT-01 COMPONENT IDENTIFICATION Code Classes: 1 and 2

References:

ASME Section XI, 111-3400 Examination Category: Not Applicable Item Number: Not Applicable

Description:

Pipe Calibration Blocks Used for Examination of Fittings CODE REQUIREMENT ASME Section XI, 111-3410, states that basic calibration blocks shall be made from material of the same wall thickness (within 25%) as the component to be examined.

POSITION The Code does not specifically address the examination of pipe to fitting welds, pipe to valve welds, pipe to pump welds, fitting to valve welds, fitting to pump welds, or fitting to fitting welds. Pumps, valves, and fittings generally see higher stresses than pipe and are normally fabricated with a heavier wall for the same service conditions. The pump, valve, or fitting is then counterbored or tapered to the mating pipe wall thickness.

Ultrasonic examinations of pipe to fitting welds, pipe to valve welds, and pipe to pump welds, will be performed from both sides of the weld when geometry and access conditions permit.

The calibration will be performed on the basic calibration block for the pipe material. For carbon steel and wrought stainless steel fittings, the pipe and fitting material are acoustically similar. Cast stainless steel fittings, valves, and pumps cannot be ultrasonically examined with the currently available technology. The examination of the weld from the fitting, valve, or pump side is performed using the same pipe calibration block since the area of interest is the weld and the heat affected zone. The calibration will have an adequate metal path for the thicknesses being examined.

The examination of fitting to fitting welds, fitting to valve welds, and fitting to pump welds will also be performed using the basic calibration block for the pipe material. The geometry of these welds usually limits the examination. Furthermore, there are very few of these kinds of welds selected for ISi to justify procuring a special calibration block. If one of these kinds of welds is required to be examined for 151, a best effort will be made to examine the area of interest (the inner third of the weld and the heat-affected zone).

(6-2) Revision 0

Cooper Station 5th ISi &

3rd lnteval CISI Program CNS wrn use the basic caHbration block for the pipe material of the same wall thickness within 25% to calibrate and examine pipe to fitting welds, pipe to valve welds, pipe to pump welds, fitting to fitting welds, fitting to valve welds, and fitting to pump welds for similar materials (6-3) Revision 0

Cooper Station 5th ISi &

3rd lnteval CISI Program TECHNICAL APPROACH AND POSITION NUMBER: CT-02 COMPONENT IDENTIFICATION Code Classes: 1 and 2

References:

ASME Section XI, IWA-2600 Examination Category: Not Applicable Item Number: Not Applicable

==

Description:==

Weld Reference System CODE REQUIREMENT ASME Section XI, IWA-2610, states that a reference system shall be established for all welds and areas subject to surface and volumetric examination. Each such weld and area shall be located and identified by a system of reference points. The system shall permit identification of each weld, location of each weld centerline, and designation of regular intervals along the weld length.

ASME Section XI, IWA-2640 states a reference system for component welds is given in IWA-2641. A different system may be used provided it meets the requirements of IWA-2610.

POSITION At the time of construction of CNS, neither datum reference markings nor a reference system was required by Code. Application of such physical markings to each and every item subject to surface and volumetric examination at an operating plant would require significant expenditure of resources and would result in additional, unnecessary personnel radiation exposure. ln many instances, limited or no physical access is available to permit such markings.

In accordance with IWA-2640, CNS has adopted a different system for weld referencing in lieu of physically marking all applicable ISi welds installed during original construction. This position is consistent with ASME Section XI Code requirements and Interpretation Xl-1-95-05 which states:

Interpretation: Xl-1-95-05

Subject:

Section XI, IWA-2600; Weld Reference System - Identification of (Winter 1981 Addenda and Later Editions and Addenda Through 1992 Edition)

Date Issued: October 13, 1994 (6-4) Revision 0

Cooper Station 5th ISi &

3rd lnteval CISi Program File Number: IN93-035 Related Documents:

Question: Is it the intent of IWA-2610 to physically mark piping with reference points designating regular intervals along the weld length?

Reply: No It is CNS's position to continue using the present weld identification method employed during the previous 10-year inspection intervals. This is accomplished by procedurally describing datum or reference points such that subsequent relocation of the examination area can be repeatedly achieved.

During the course of performing examinations for the fifth inspection interval, in accordance with the requirements of the ISi Program, reference points will be physically applied to welds where flaw indications are detected and are determined to be relevant.

Where new welds are installed as a result of repair or replacement activities and a preservice inspection is performed, the requirements of IWA-2600 will be met.

Interpretation: Xl-1-92-06

Subject:

Section XI, IWA-2600 and IWA-4130; Weld Reference System -

Recording (1980 Edition With Winter 1981 Addenda, and Later Editions and Addenda Through the 1989 Edition)

Date Issued: September 13, 1991 File Number: IN91-019 Related Documents:

Question: Is it the intent of Section XI, IWA-4130{a)(2) to require recording of dimensions for reference points of a repair only when required by IWA-2600?

Reply:Yes (6-5) Revision 0

Cooper Station 5th ISi &

3rd Interval CISI Program INSERVICE INSPECTION RELIEF REQUESTS 7.0 RELIEF REQUESTS Throughout this program, the term "relief request is used interchangeably referring to 11 submittals to the NRC requesting permission to deviate from either an ASME Section XI requirement, a 10 CFR 50.SSa rule, or to use provisions from Editions or Addenda of Section XI not approved by the NRC as referenced in 10 CFR 50.SSa(l)(ii). However, when communicating with the NRC and in written requests to deviate, the terms as defined below must be used for clarity and to satisfy 10 CFR 50.SSa. Submittals to the NRC must clearly identify which of the below rules are being used to request the deviation.

Table 7.0-1 contains an index of Relief Requests written in accordance with 10 CFR 50.SSa(z) and (g)(S)(iii). The applicable NPPD submittal and NRC Safety Evaluation Report (SER) correspondence numbers are also included for each request.

7.1 Request for Alternatives When seeking an alternative to the rules contained in 10 CFR 50.SSa(b), (c), (d),

(e), (f), (g), or (h) the request is submitted under the provision of 10 CFR 50.SSa(z). Once approved by the Director, Office of Nuclear Reactor Regulation, the alternative may be incorporated into the ISi program. These types of requests are typically used to request use of Code Cases, Code Edition, or Addenda not yet approved by the NRC. Request for Alternatives must be approved by the NRC prior to their implementation or use. Within the provisions of 10 CFR 50.SSa(z) there are two specific methods of submittal:

7.1.1 10 CFR 50.SSa(a)(z)(l) allows alternatives when authorized by the NRC, if the proposed alternatives would provide an acceptable level of quality and safety. Requests submitted under these provisions are not required to demonstrate hardship or burden.

7.1.2 10 CFR 50.55a(z)(2) also allows alternatives when authorized by the NRC, if compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. When submitted under this provision, there must be evidence of unusual hardship or difficulty. Typically, this hardship will be dose or excessive disassembly.

7.2 Relief Request Required due to Impracticality or Limited Examinations 10 CFR 50.SS(a)(g)(S)(iii) and (iv) allows relief to be requested in instances when a Code requirement is deemed impractical with (iv) being specific to examination requirements that are determined to be impractical. The provisions of these two paragraphs are typically used to address impracticalities like limited examination*

coverage. Under 10 CFR 50.SS(a)(g)(S)(iv), relief requests for examination (7-1) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program impracticalities must be submitted for NRC review and approval not later than 12 months after the expiration of the initial or subsequent 120-month inspection interval for which relief is sought.

In cases where the ASME Section XI requirements for inservice inspection are considered impractical, NPPD will notify the NRC and submit information to support the determination, as required by 10 CFR 50.SSa(g)(S)(iii). The submittal of this information will be referred to as a Request for Relief.

In the event that the entire examination volume or surface (as defined in the ASME Code) cannot be examined due to interference by another component or part geometry, then in accordance with IWA-2200(c) (incorporation of Code Case N-460), a reduction in examination volume or area is acceptable if the reduction is less than 10%. In the event that the reduction in examination volume or area is 10% or greater, a request for relief will be submitted. NRC Information Notice 98-42 provides additional guidance that all ASME Section XI examinations should meet the examination coverage criteria established in Code Case N-460.

Therefore, the guidance included in NRC Information Notice 98-42 will be followed by NPPD when determining whether to prepare a relief request or apply the criteria of IWA-2200 for examinations where less than 100% coverage of any Section XI examination is obtained.

7.3 Requests to use Later Edition and Addenda of ASME Section XI On July 28, 2004, the NRC published Regulatory Issue Summary (RIS) 2004-12, "Clarification on Use of Later Editions and Addenda to ASME OM Code and Section XI". This RIS clarifies the NRC position on using Editions and Addenda of Section XI, in whole or in part, later than those specified in the ISi program. If the desired Edition or Addenda are referenced in 10 CFR 50.SSa(l)(ii), the request is submitted following the guidance of the RIS. These types of request are not required to demonstrate hardship, difficulty, or provide evidence of quality and safety. They do need to ensure that all related requirements are also used. Requests to use edition and/or addenda of ASME Section XI that are referenced in 10 CFR 50.SSa(l)(ii) that are later than the initial Code of Record established for the ISi program shall be submitted under the provisions of 10 CFR 50.55a(g)(4)(iv).

(7-2) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Table 1 summarizes each NRC approved relief request. Table 2 summarizes outstandi ng Relief Requests currently pending approval by the NRC. Relief requests are numbers are the same as those used in Interval 3 to maintain continuity . Table 3 summarizes Relief Requests in preparatio n for submittal (or resubmitt al) to the NRC. Percentages are tentativel y adjusted assuming approval will be granted prior to end of the applicable Period as required to ensure Code percentage requireme nts are maintaine d.

Table 1 NRC Approved Relief Rev Description NPPD Correspondence NRC Request # Correspondence 0 NLS2017071 N RC Approved -

Implemen tation of BWRVIP-05 (GL dated 8/15/2017 7/31/2018 Rl5-01 98-05) NRC2018024 (ML18183A325) 2 Rev 1 - N LS2017071 Rev 1- NRC dated 8/15/2017 Approve d-Rev 2 - NLS2019034 7/31/2018 Implemen tation of BWRVIP in lieu of dated 6/28/2019 NRC2018024 Rl5-02 B-N-1 and B-N-2. (ML18183A325)

Rev2-NR C Approve d-3/19/2020 NRC2020002 0 NLS2017071 N RC Approved -

dated 8/15/2017 7/31/2018 NLS2018012 NRC2018024 RIS-03 Implemen tation of Code Case N-702 (revised RIS-03) (ML18183A325) dated 3/14/2018 NLS2018025 dated 4/26/2018 (addressed N-648-1)

Alignmen t and Synchronization of NLS201502 Approved -

the Containm ent lnservice Inspection dated 6/9/2015 NRC2016002 RC3-01 0 {CISI) Program Third Ten-Year dated 2/12/2016 Interval with the lnservice Inspection (ISi) Program Fifth Ten-Year Interval.

Alternativ e Weld Overlay Repair for NLS201502 Approved (for the Dissimilar Metal Weld on the dated 6/9/2015 RE29 only) -

RR5-01 0 Nozzle-to-Control Rod Drive End Cap. NRC2016006 dated 2/24/2016 (7-3) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Table 1 NRC Approved Relief Rev Description NPPD Correspondence NRC Request # Correspondence NLS2017071 N RC Approved -

0 dated 8/15/2017 7/31/2018 RR5-02 Use Code Case N-513-4 NLS2018011 NRC2018024 (revised RRS-02) (ML18183A325) dated 3/8/2018 NLS2017071 N RC Approved -

0 dated 8/15/2017 7/31/2018 Use Code Case N-513-4 at a Higher NLS2018029 NRC2018024 RR5-03 System Operating Pressure (revised RRS-03) (ML18183A325) dated 5/16/2018 Proposed Use of Subsequent ASME NLS20200053 NRC Approved -

0 Code Edition and Addenda in dated 8/27/2020 9/15/20 RRS-04 Accordance with (ML20255A217) 10 CFR 50.55a(g)(4)(iv)

(7-4) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Table 2 Pending NRC Approval Relief Rev# Description NPPD NRC Request Correspondence Correspondence None Table 3 Pending NPPD Submittal Relief Rev# Description NPPD NRC Request Correspondence Correspondence None -------- ----------

(7-5) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Acronyms ALARA As Low as Reasonably Achievable ART Adjusted Reference Temperature ASME American Society of Mechanical Engineers BWR Boiling Water Reactor BWRVIP Boiling Water Reactor Vessel Internals Project CFR Code of Federal Regulation CISI Containment lnservice Inspection CRD Control Rod Drive EPRI Electric Power Research Institute EVT-1 Enhanced Visual (VT-1) Testing FN Ferrite Number GTAW Gas Tungsten Arc Weld HAZ Heat Affected Zone l&E Inspection and Evaluation ID Inner Diameter or Identification IGSCC lntergranular Stress Corrosion Cracking ISi In-Service Inspection LLC Limited Liability Corporation LRA License Renewal Application No. Number NP Non Proprietary NPPD Nebraska Public Power District NRC Nuclear Regulatory Commission NUREG US Nuclear Regulatory Commission Regulation PDI Performance Demonstration Initiative PSI Pre-service Inspection PWHT Post-Weld Heat Treat PWR Pressurized Water Reactor Rev Revision RG Regulatory Guide RPV Reactor Pressure Vessel RTNoT Reference Temperature for Nil Ductility Transition sec Stress Corrosion Cracking SDC Shut Down Cooling SER Safety Evaluation Report us United States UT Ultrasonic Testing VT Visual Testing VT-1 Detailed inspection VT-3 General condition inspection (7-6) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program 10 CFR 50.SSa Request No. RIS-01 Implementation of BWRVIP-05 (GL 98-05)

Proposed Alternative in Accordance with 10 CFR 50.SSa(z)(l)

Acceptable Level of Quality and Safety ASME Code Component(s) Affected Code Class: ASME Section XI Code Class 1 Component Numbers: RPV Circumferential Shell Welds (VCB-BB-1, VCB-BA-2, VCB-BB-3, VCB-BB-4)

Code

References:

ASME Section XI, 2007 Edition with 2008 Addenda Examination Category: B-A Item Number(s): B1.11 Unit/Inspection Interval: Cooper/Fifth 10-year interval April 1, 2016 - February 28, 2026

Applicable Code Edition and Addenda

ASME Section XI, 2007 Edition through the 2008 Addenda Applicable ASME Code Requirements Table IWB-2500-1, Examination Category B-A, Item No. B1.11, requires a volumetric examination of the circumferential shell welds each interval.

Reason for Request

NPPD is requesting an alternative in accordance with 10 CFR 50.SSa(z)(l) on the basis that this alternative provides an acceptable level of quality and safety. This request for alternative would provide relief from circumferential weld examinations required by the ASME Section XI Code for the extended period of operation.

CNS was previously granted this relief for the remainder of the original 40-year license term (Reference 6).

During the staff's review of the CNS LRA (Reference 1), the staff concluded that CNS had demonstrated, in accordance with 10 CFR 54.21(c)(l)(ii), that for RPV circumferential weld examination relief, the analysis had been projected to the end of the period of extended operation. The staff also concluded that the USAR Supplement contained an appropriate summary description of the TLAA evaluation in accordance with 10 CFR 54.21(d) and therefore, was acceptable (Reference 2).

(7-7) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Proposed Alternative and Basis for Use Proposed Alternative CNS requests the use of BWRVIP-05 with supporting information described herein as the bases for excluding the RPV shell circumferential welds from the examinations required by ASME Section XI, Examination Category B-A, Item No. B1.11 for the extended license period ending on January 18, 2034.

The axial weld seams (Examination Category B-A, Item No. B1.12) and their intersection with the associated circumferential weld seams will be examined in accordance with ASME Section XI except where specific relief is granted when essentially 100% (>90%) coverage cannot be obtained.

Basis for Use The technical basis supporting the requested alternative is provided by BWRVIP-05, (EPRI TR-105697) "BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Shell Weld Inspection Recommendations" as accepted in the staff's final safety evaluation report enclosed in a July 28, 1998, letter (Reference 4). In this letter, the staff concluded that because the failure frequency for circumferential welds in BWR plants is significantly below the criterion specified in RG 1.154, "Format and Content of Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water Reactors," and below the core damage frequency of any BWR plant, continued inspection would result in a negligible decrease in an already acceptably low RPV failure probability. Therefore elimination of the ISi requirements for RPV circumferential welds is justified.

The staff's letter indicated that BWR applicants may request relief from ASME Code Section XI requirements for volumetric examination of circumferential RPV welds by demonstrating that (1) the failure frequency for circumferential welds in BWR plants must be significantly below the criterion specified in RG 1.154 and below the core damage frequency of any BWR plant, therefore, the failure frequency for RPV circumferential welds; and (2) the applicants must implement operator training and operating procedures that limit the frequency of cold over-pressure events to the amount specified in the July 28, 1998, SER for the BWRVIP-05 report.

The letter also indicated that the requirements for inspection of RPV circumferential welds during an additional 20-year license renewal period would need plant-specific reassessment as part of any BWR LRA. The applicant also must request relief from the ASME Code Section XI requirements for volumetric examination of circumferential welds for the extended license term in accordance with 10 CFR 50.55a(z).

LRA Section 4.2.5 provided a comparison of the plant-specific information with the generic analysis information in BWRVIP-05 SER to support the conclusion that the CNS RPV beltline circumferential weld parameters at 54 EFPY remained within the bounding parameters for CE RPVs at 64 EFPY from the BWRVIP-05 SER. Since the 54 EFPY mean ART value for CNS is less (7-8) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program than the 64 EFPY value from the BWRVIP-05 SER, the staff review concluded that the RPV conditional failure probability for CNS at 54 EFPY was bounded by the staff's generic analysis in the BWRVIP-05 SER. Therefore, the staff determined that CNS's RPV circumferential welds satisfy the limiting conditional failure probability for circumferential welds at the end of the period of extended operation (the first condition established in the BWRVIP-05 SER).

Table 1 compares the CNS reactor vessel limiting circumferential weld parameters to those used in the NRC analysis. The data in the second column is from Table 2.6-5 of the NRC SER for BWRVIP-05. The data in the third column is from Table 4.2-6 of the LRA (Reference 1). The data in the last column is the projected 54 EFPY data for CNS and has been updated to include the changes contained in the PTLR Revision 1 (Reference 3). Consistent with previous submittals, this table uses surface fluence rather than 1/4t fluence and no margin for RTNoTto be comparable with NRC assessment data, hence the reported ART is lower than that reported in the PTLR (Reference 3).

Table 1 CNS Circumferential Weld Evaluation for 54 EFPY Parameter Description CE(VIP)'ll 64 EFPY CNS 54 EFPY Beltline CNS 54 EFPY Beltline Bounding Circumferential Circumferential Weld Parameters Weld (LRA Values) (Updated P/T Values)

[Ref. 1] [Ref. 3]

Initial reference 0 -50 -50 temperature (RTNoT), °F Neutron fluence at the end of the requested 4.0E+18 1.48E+18 1.75E+18 relief period, n/cm 2 Weld copper content, % 0.13 0.183 0.183 Weld nickel content, % 0.71 0.704 0.704 Weld chemistry factor 151.7 172.22 172.22 (CF)

Increase in reference 113.2 86.1 92.6 temperature (RTNoT), °F Mean adjusted reference temperature (ART), °F 113.2 36.1 42.6 (Initial RT NOT+ rnRT NoT)

(1) Based on chemistry report by BWRVIP For the second condition, the staff review of the original request for the 4th Interval, concluded that the CNS implementation of operator training and establishment of procedures, limiting the frequency of code over-pressure events to the frequency specified in BWRVIP-05 SER for the remaining initial licensed period of operation described in the letter dated February 6, 2008, was acceptable. In LRA Section 4.2.5, CNS stated that the same procedures and training will be used for the period of extended operation. Based on this the staff determined that continued (7-9) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program implementation of operator training and establishment of procedures limiting the frequency of cold over-pressure events would be satisfied during the period of extended operation (the second criterion established in the BWRVIP-05 SER).

In addition to the above criterion, in the BWRVIP-05 SER (Reference 4), the staff concludes that the failure probability of the RPV circumferential shell welds is substantially less than that of the RPV axial shell welds. In the LRA Table 4.2-7, CNS summarized the effects of irradiation on the limiting axial weld at CNS and compared its properties to the NRC limiting plant-specific data used in the July 28, 1998, SER for BWRVIP-05. The higher copper content and chemistry factor for the CNS weld is offset by the CNS weld's lower initial RTNDT. Consequently, the CNS axial welds are less susceptible to irradiation damage than the NRC limiting plant-specific case.

During the staff's review of the LRA, a comparison of the mean ART values of CNS weld data in Table 4.2-6 and Table 4.2-7 of the LRA and concluded that the mean ART for the axial welds at CNS is higher than the mean ART for the circumferential weld, indicating that the axial welds are more susceptible to radiation embrittlement than the circumferential welds.

Table 2 compares the CNS reactor vessel limiting axial weld parameters to those used by the NRC analysis in BWRVIP-05. The data in the second column is from Table 2.6-5 of the NRC SER for BWRVIP-05 (Reference 4) and Table 1 of the NRC SER for BWRVIP-74 (Reference 5). The data in the third column is from Table 4.2-7 of the LRA (Reference 1). The data in the last column is the projected 54 EFPY data for CNS and has been adjusted to include the changes contained in the PTLR (Reference 3). Consistent with previous submittals, this table uses surface fluence rather than 1/4t fluence and no margin for RTNDT to be comparable with NRC assessment data hence the reported ART is lower than that reported in the PTLR (Reference 3).

Table 2 Effects of irradiation on CNS RPV Axial Weld Properties Parameter Description NRC Limiting Plant- CNS Data for Weld CNS Data for Weld Specific Data 2-233-B [Ref. 1] 2-233-B [Ref. 3]

(LRA Values) (Updated P/TValues)

EFPY 64 54 54 Initial (unirradiated) reference temperature -2* -50 -50 (RTNoT), °F Neutron fluence, n/cm 2 0.40E+19** 1.46E+18 1.72E+18 Fluence factor (FF)

N/A 0.497 0.534 (calculated per RG 1.99)

Weld copper content,%

0.219 0.27 0.27 Weld nickel content, %

0.996 1.035 1.035 Weld chemistry factor (CF) (calculated per RG 231.1 ** 254.43 254.4 1.99)

(7-10) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Increase in reference temperature (L\RTNor ), 116.0 126.5 135.8

~F (FF X CF)

Mean adjusted reference temperature 114.0* 76.5 85.8 (ART), °F (RTNDT + L\RTNDT)

• NRC SER to BWRVIP-74[Ref. 5]

• • NRC SER to BWRVIP-05[Ref. 4]

To summarize, the additional analysis described in Section 4.2.5 of the LRA as modified by the changes contained in the PTLR (Reference 3} shows that the parameters projected to 54 EFPY for the CNS RPV are bounded by the staff's (64 EFPY} bounding parameters for a CE vessel in the BWRVIP-05 SER. Additionally, the CNS RPV axial welds are less susceptible to irradiation damage than the NRC limiting plant-specific case, but are more susceptible than the CNS circumferential welds. Therefore, continuation of ISi for axial welds provides additional assurance that the structural integrity of the circumferential welds is adequate.

The procedures and training used to limit low temperature over-pressure events will be the same as those in use when CNS requested approval of the BWRVIP-05 technical alternative for the initial license term. The TLAA associated with reactor vessel circumferential weld inspection relief has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c}(l}(ii}.

Based on the information presented in this request, the referenced LRA with the corresponding NRC SER, and the information provided in the PTLR, the circumferential welds will continue to satisfy the limiting conditional failure probability for circumferential welds in the staff's July 28, 1998, safety evaluation.

Duration of Proposed Alternative The duration of this request is for the extended license period ending January 18, 2034.

Precedents "Peach Bottom Atomic Power Station, Units 2 and 3 - Requests for Relief 14R-51 and 15R-52,"

dated January 24, 2012 (ADAMS Accession Number ML112770217}.

"Browns Ferry Nuclear Plant, Units 2 and 3 - Request for ASME Code,Section XI, Alternatives 2-ISl-30 and 3-151-27 for the Periods of Extended Operation Regarding Reactor Pressure Vessel Circumferential Shell Weld Examinations," dated March 14, 2017 (ADAMS Accession Number M Ll 7045A772}.

(7-11) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program References

1. NPPD letter to the U.S. NRC, "Cooper Nuclear Station, License Renewal Application, Preface through Chapter 4, References," dated September 24, 2008 (ADAMS Accession No. ML083030239).

2. US NRC letter to NPPD, "Safety Evaluation Report Related to the License Renewal of Cooper Nuclear Station," dated September 1, 2010 (ADAMS Accession No. ML102000270).

3.NPPD letter to the U.S. NRC, "Pressure and Temperature Limits Report, Revision 1," dated January 9, 2017 (ADAMS Accession No. ML17018A151 and ML17018A152).

4.J. Strosnider (NRC), to C. Terry (BWRVIP Chairman), "Final Safety Evaluation of the BWR Vessel and Internals Project BWRVIP-05 Report (TAC NO. M93925)," letter dated July 28, 1998.

5.C. Grimes (NRC), to C. Terry (BWRVIP Chairman), "Acceptance for Referencing of EPRI Proprietary Report TR-113596, 'BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines (BWRVIP-74)' and Appendix A, 'Demonstration of Compliance with the Technical Information Requirements of the License Renewal Rule {10 CFR 54.21)' "dated October 18, 2001 (ADAMS Accession No. ML012920549).

6. US NRC letter to NPPD, "Cooper Nuclear Station - Request for Relief No. Rl-29 for Fourth 10-Year lnservice Inspection Interval Regarding Volumetric Examination of Reactor Pressure Vessel Circumferential Shell Welds (TAC No. MD5260)," dated February 6, 2008 (ADAMS Accession No. ML080230288).

(7-12) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 July 31, 2018 Mr. John Dent, Jr.

Vice President-Nuclear and CNO Nebraska Public Power District 72676 648A Avenue Brownville, NE 68321

SUBJECT:

COOPER NUCLEAR STATION - REQUESTS FOR RELIEF ASSOClATED WITH THE FIFTH 10-YEAR INSERVICE INSPECTION INTERVAL PROGRAM (CAC NOS. MG0175 THROUGH MG0179; EPIDS L-2017-LLR-0062 THROUGH L-2017-LLR-0066)

Dear Mr. Dent:

By letter dated August 17, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17241A048), as supplemented by letters dated March 8, 2018, March 14, 2018, April 26, 2018, and May 16, 2018 (ADAMS Accession Nos. ML18078A264, ML18082A563, ML18131A159, and ML18143B464, respectively), Nebraska Public Power District (the licensee) submitted Relief Requests Rl5-01, RIS-02, Revision 1, RIS-03, RRS-02, and RR5-03, to the U.S. Nuclear Regulatory Commission (NRC). The licensee proposed alternatives to or requested relief from certain inservice inspection (ISi) test requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),

Section XI, "Rules for lnservice Inspection (ISi) of Nuclear Power Plant Components," at Cooper Nuclear Station (CNS), for the fifth 10-year ISi interval program, which commenced on April 1, 2016, and will end on February 28, 2026.

Specificaiiy, pursuant to Titie 10 of the Code of Federal Regulations ('10 CFR),

Section 50.55a(z)(1 ), the licensee requested to use the proposed alternatives in Relief Requests R15-01; RIS-02, Revision 1; and Rl5-03, on the basis that the alternatives provide an acceptable level of quality and safety. Pursuant to 10 CFR 50.55a(z)(2), the licensee requested to use the proposed alternatives in RRS-02 and RR5-03 on the basis that the proposed alternatives will provide reasonable assurance of quality and safety of the subject components and compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

The NRC staff has reviewed the subject requests and concludes as set forth in the enclosed safety evaluations, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1) for requests Rl5-01, Rl5-02, Revision 1, and R15-03, and in 10 CFR 50.55a(z)(2) for requests RR5-02 and RR5-03, and is in compliance with the ASME Code requirements. Therefore, the NRC staff authorizes alternative requests Rl5-01, RIS-02, Revision 1, Rl5-03, RRS-02, and RR5-03 at CNS for the fifth 10-year ISi interval program.

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Cooper Station 5th ISi &

3rd Interval GISI Program J. Dent, Jr. All other ASME Code,Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third party review by the Authorized Nuclear lnservice Inspector.

If you have any questions, please contact the Project Manager, Thomas Wengert, at 301-415-4037 or via e-mail at Thomas.Wengert@nrc.gov.

Sincerely, Robert J. Pascarelli, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosures:

1. Safety Evaluation - Relief Request Rl5-01

2. Safety Evaluation - Relief Request R15-02

3. Safety Evaluation - Relief Request Rl5-03

4. Safety Evaluation - Relief Request RR5-02

5. Safety Evaluation - Relief Request RR5-03 cc: Listserv (7-14) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION ALTERNATIVE REQUEST NO. Rl5-01 FOR THE FIFTH 10-YEAR INSERVICE INSPECTION INTERVAL FOR THE PERIOD OF EXTENDED OPERATION REGARDING REACTOR PRESSURE VESSEL CIRCUMFERENTIAL WELD EXAMINATIONS NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated August 17, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17241A048), Nebraska Public Power District (the licensee) submitted a request to the U.S. Nuclear Regulatory Commission (NRC) for the use of alternatives to certain requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI, "Rules for lnservice Inspection (ISi) of Nuclear Power Plant Components," for the reactor pressure vessel (RPV) circumferential shell weld examinations at Cooper Nuclear Station (CNS). The licensee's proposed alternative is identified as request for alternative RIS-01. The licensee's request for the use of this alternative was submitted, pursuant to Title 10 of the Code of Federal Regulations (10 CFR)

Section 50.55a(z)(1 ), on the basis that the alternative would provide an acceptable level of quality and safety.

The ASME Code,Section XI alternative proposed in the licensee's submittal dated August 17, 2017, would eliminate the requirement to inspect the RPV circumferential shell welds, except for the areas of intersection with the axial welds, for the duration of the unit's 20-year extended license term, also referred to as the period of extended operation (PEO). The licensee's proposed alternative addressed the specific guidance provided in the NRC staffs final safety evaluation (SE) dated July 28, 1998, for Boiling Water Reactor (BWR) Vessel and Internals Project (BWRVIP) Topical Report BWRVIP-05, "BWR Reactor Pressure Vessel Shell Weld Inspection Recommendations" (Legacy Library Accession No. 9808040037). This specific guidance provided staff expectations and acceptance criteria for plant-specific applications for Code alternatives to implement the BWRVIP-05 probabilistic fracture mechanics (PFM) methodology in lieu of the subject RPV circumferential shell weld examinations for the original 40-year license term.

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2.0 REGULATORY EVALUATION

The ISi of ASME Code Class 1 , 2, and 3 components is to be performed in accordance with Section XI of the ASME Code and applicable editions and addenda as required by 10 CFR 50.55a(g), "Preservice and inservice inspection requirements," except where specific relief has been granted by the NRC pursuant to 10 CFR 50.55a(g)(6)(i), "Impractical ISi requirements: Granting of relief."

Pursuant to 10 CFR 50.55a(z), "Alternatives to codes and standards requirements," alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC, if (1) the proposed alternatives would provide an acceptable level of quality and safety, or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), "lnservice inspection standards requirements for operating plants," ASME Code Class 1, 2, and 3 components (including supports) must meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year ISi interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(a)(1 )(ii), 12 months prior to the start of the 120-month interval, subject to the conditions listed in 10 CFR 50.55a(b)(2).

CNS is currently in the fifth 10-year ISi interval, which began on April 1, 2016. The applicable ASME Code of record for the fifth 10-year ISi intervals at CNS is the ASME Code,Section XI, 2007 Edition through 2008 Addenda.

2.1 Requirements Related to Neutron Fluence The NRC has established requirements in Appendix G, ' Fracture Toughness Requirements," to 1

10 CFR Part 50, in order to protect the integrity of the reactor coolant pressure boundary (RCPB) in nuclear power plants. The regulations in 10 CFR Part 50, Appendix G, require that the pressure-temperature (P-T) limits for an operating light-water nuclear reactor be at least as conservative as those that would be generated if the methods of Appendix G, "Fracture Toughness Criteria for Protection Against Failure," to Section XI of the ASME Code were used to generate the P-T limits. The regulations in 10 CFR Part 50, Appendix G, also require that applicable surveillance data from RPV material surveillance programs be incorporated into the calculations of plant-specific P-T limits, and that the P-T limits for operating reactors be generated using a method that accounts for the effects of neutron irradiation on the material properties of the RPV beltline materials.

Table 1 of 10 CFR Part 50, Appendix G, provides the NRC staff's criteria for meeting the P-T limit requirements of the ASME Code,Section XI, Appendix G, as well as the minimum temperature requirements of the rule during normal and pressure testing operations.

In addition, the NRC staff's regulatory guidance related to P-T limit curves is found in Regulatory Guide (RG) 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," dated May 1988 (ADAMS Accession No. ML003740284), and NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR [Light-Water (7-16) Rev 3.0

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3rd Interval CISI Program Reactor] Edition," Section 5.3.2, "Pressure-Temperature Limits, Upper-Shelf Energy, and Pressurized Thermal Shock" (ADAMS Accession No. ML070380185).

The P-T limit curve calculations are based, in part, on the reference nil-ductility temperature (RTNor) for the material, as specified in the ASME Code,Section XI, Appendix G. The regulations in 10 CFR Part 50, Appendix G, require that RTNDT values for materials in the RPV beltline region be adjusted to account for the effects of neutron radiation. The guidance in RG 1.99, Revision 2, contains methodologies for calculating the adjusted RTNDT (ART) due to neutron irradiation. The ART is defined as the sum of the initial (unirradiated) reference temperature (initial RTNor), the mean value of the adjustment in reference temperature caused by irradiation (ARTNOT), and a margin tenn.

The ART NOT is a product of a chemistry factor (CF) and a fluence factor. The CF is dependent upon the amount of copper and nickel in the material and may be determined from tables in RG 1.99, Revision 2, or from surveillance data. The fluence factor is dependent upon the neutron fluence at the maximum postulated flaw depth. The margin term is dependent upon whether the initial RTNDT is a plant-specific or a generic value and whether the CF was detennined using the tables in RG 1.99, Revision 2, or surveillance data. The margin term is used to account for uncertainties in the values of the initial RTNDT, the copper and nickel contents, the neutron fluence, and the calculational procedures. The guidance in RG 1.99, Revision 2, describes the methodology to be used in calculating the margin term.

Appendix H, "Reactor Vessel Material Surveillance Program Requirements," to 10 CFR Part 50, provides the NRC staff's criteria for the design and implementation of RPV material surveillance programs for operating LWRs.

In March 2001, the NRC staff issued RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence" (ADAMS Accession No. ML010890301 ).

Fluence calculations for use in ART and P-T limit curve analyses are acceptable if they are performed with approved methodologies or with methods that are shown to conform to the guidance in RG 1.190.

The guidance in RG 1.190 describes methods and assumptions acceptabie to the NRC staff for determining the pressure vessel neutron fluence with respect to the General Design Criteria (GDC) contained in Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50. In consideration of the guidance set forth in RG 1.190; GDC 14, "Reactor coolant pressure boundary"; GDC 30, "Quality of reactor coolant pressure boundary"; and GDC 31, "Fracture prevention of reactor coolant pressure boundary," are applicable. GDC 14 requires the design, fabrication, erection, and testing of the RCPB so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture.

GDC 30 requires, among other things, that components comprising the RCPB be designed, fabricated, erected, and tested to the highest quality standards practical. GDC 31 pertains to the design of the RCPB, which states:

The reactor coolant pressure boundary shall be designed with sufficient margin to assure that when stressed under operating, maintenance, testing, and postulated accident conditions (1) the boundary behaves in a nonbrittle manner and (2) the probability of rapidly propagating fracture is minimized. The design shall reflect consideration of service temperatures and other conditions of the boundary material under operating, maintenance, testing, and postulated accident conditions and the uncertainties in determining (1) material properties, (7-17) Rev 3.0

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3rd Interval CISI Program (2) the effects of irradiation on material properties, (3) residual, steady state and transient stresses, and (4) size of flaws.

3.0 TECHNICAL EVALUATION

3.1 ASME Code Requirement to which the Alternatives are Requested The ASME Code,Section XI, 2007 Edition through 2008 Addenda, Table IWB-2500-1, Examination Category B-A, Item B 1.11 requires a volumetric examination of all the RPV circumferential shell welds each ISi interval, to include volumetric examination of "essentially 100 percent" {i.e., greater than 90 percent) of the length of the welds.

3.2 Component(s) for which the Alternatives are Requested Code Class: 1 Examination Category: B-A Item Number: B1 .11, Circumferential Shell Welds Weld Nos.: VCB-BB-1, VCB-BA-2, VCB-BB-3, VCB-BB-4 Examination Method: Volumetric 3.3 Licensee's Proposed Alternatives to the ASME Code Section XI The licensee's application dated August 17, 2017, identified that CNS was operating with NRC-authorized Code alternatives that allowed plant-specific implementation of the BWRVIP-05 PFM methods in lieu of the subject RPV circumferential shell weld examination requirements for the remainder of the 40-year license term. This 40-year Code alternative was authorized for CNS in an NRC letter dated February 6, 2008 {ADAMS Accession No. ML080230288).

The 40-year license term ended on January 18, 2014, for CNS. Therefore, request for alternative Rl5-01 was submitted to implement the BWRVIP-05 PFM methods in lieu of the subject RPV circumferential shell weld examination requirements for the duration of the 20-year extended license term.

3.4 Licensee's Basis for the Proposed Alternatives The licensee submitted request for alternative Rl5-01 in accordance with 10 CFR 50.55a{z){1 ),

on the basis that the proposed alternatives would provide an acceptable level of quality and safety. The licensee's technical basis for determining an acceptable level of quality and safety included plant-specific evaluations for demonstrating that the limiting RPV circumferential shell weld at CNS has conditional failure probabilities that are bounded by {i.e., less than) the NRC statrs acceptance criteria for the weld failure probabilities, considering projected RPV weld neutron embrittlement through the end of the PEO. The NRC staffs specific acceptance criteria for these circumferential shell weld failure probabilities were established in its SE dated July 28, 1998, for the BWRVIP-05 report.

The licensee determined that these RPV circumferential shell weld evaluations demonstrate that implementation of the proposed Code alternative for the duration of the 20-year extended license term would provide an acceptable level of quality and safety at CNS.

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3rd Interval CISI Program 3.5 NRC Staff Evaluation By letter dated February 6, 2008, the NRC staff authorized an alternative to the volumetric examination requirements of the ASME Code,Section XI, for the subject RPV circumferential shell welds at CNS, pursuant to 10 CFR 50.55a(a)(3)(i), which is now 10 CFR 50.55a(z)(1).

This NRG-authorized alternative allowed for plant-specific implementation of the BWRVIP-05 RPV PFM analyses, as approved by the NRC staff in its BWRVIP-05 SE, in lieu of the subject ASME Code,Section XI examination requirements, for the duration of the unit's 40-year license term. The subject Code alternative expired when CNS entered the 20-year extended license term on January 18, 2014. Therefore, plant-specific implementation of the BWRVIP-05 PFM methods in lieu of the subject ASME Code,Section XI requirements during the PEO requires the submittal of a new request for a Code alternative, pursuant to 10 CFR 50.55a(z)(1).

The licensee's application dated August 17, 2017, requested alternatives to the subject circumferential weld examination requirements for the PEO at CNS, based on plant-specific implementation of the NRG-approved BWRVIP-05 methods for the limiting circumferential shell weld at CNS, considering projected RPV weld neutron embrittlement through 60 years of facility operation. The proposed 60-year Code alternatives included plant-specific calculations demonstrating that projected neutron emb.rittlement for the CNS limiting RPV circumferential shell weld is less than that used by the NRC staff for calculating an acceptable circumferential shell weld conditional failure probability 1 , as documented in the NRC SE for BWRVIP-05.

To project neutron embrittlement for 60 years, the licensee used calculations based on updated fluence values from its Pressure and Temperature Limits Report (PTLR) dated January 9, 2017 (ADAMS Accession Nos. ML17018A151 and ML17018A152). These updated fluence values were based on 54 effective full power years (EFPY), which is equivalent to 60 years of facility operation at CNS. The NRC staff confirmed that the updated fluence values are the most recent licensing basis and would bound 60 years of facility operation at CNS. The conditional failure probabilities documented in the NRC SE for BWRVIP-05 are based on 64 EFPY, which would bound 60 years of facility operation at CNS.

The NRC staff confirmed that the proposed 60-year Code alternatives continued implementation of certain operator procedures and training needed to limit the frequency of cold overpressure events, per the criteria specified in the staffs SE for BWRVIP-05. The staff had previously endorsed these provisions in Section 4.2.5 of its safety evaluation report for the CNS license renewal application (LRA) (NUREG-1944, dated October 2010 (ADAMS Accession No. ML103070009)). regarding the subject circumferential weld analysis. The operator training and procedures are specifically needed to ensure that the overall plant-specific RPV failure probability per reactor operating year (a product of the weld conditional failure probability and the cold overpressure event frequency) is less than the acceptance criterion specified in the staffs SE for BWRVIP-05.

The specific RPV weld neutron embrittlement parameter used for this evaluation is referred to as the mean RT NDT- The mean RT NDT value for demonstrating an acceptable RPV weld conditional failure probability is calculated based on three inputs:

( 1) The Projected RPV Neutron Fluence: RPV neutron fluence, as determined based on staff-approved calculation methodologies, is the key time-dependent 1 The weld conditional failure probability quantifies the probability of weld failure if the RPV was subjected to a cold overpressure event, as addressed in BWRVIP-05.

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3rd Interval CISI Program parameter for all RPV integrity analyses that consider neutron embrittlement of the RPV beltline materials. The projected neutron ffuence input to the mean RTNOT value, for demonstrating an acceptable RPV weld conditional failure probability at the end of the licensed operating term, shall include the effects of any power uprates that are implemented during the licensed operating term of the unit.

(2) The Weld Chemistry Factor (CF): The CF is determined based on both copper and nickel content, or the application of credible RPV material surveillance data from a 10 CFR Part 50, Appendix H RPV material surveillance program. If the weld is represented in the plant-specific or industry integrated surveillance program, all credible RPV surveillance data shall be used for the CF calculation, per the requirements of 10 CFR Part 50, Appendix G. CF values shall be periodically recalculated based on new credible RPV surveillance data that becomes available when a surveillance capsule is withdrawn from the RPV and tested in accordance with 10 CFR Part 50, Appendix H surveillance program requirements.

(3) The Initial (Unirradiated) RTNor: The initial RTNOT is determined in accordance with the requirements of 10 CFR Part 50, Appendix G, based on the procured RPV material impact test data or the use of NRC-approved methods in NUREG-0800, Branch Technical Position 5-3, uFracture Toughness Requirements (ADAMS Accession No. ML070850035), as applicable to the unit.

This is expected to remain fixed throughout the operating life of the plant.

It should be noted that the LRA mean RTNOT calculations used RPV weld neutron fluence and CFs that were valid at the time of the LRA review. Accordingly, the licensee*s application dated August 17, 2017, for the subject Code alternatives considered that it was necessary to recalculate the limiting circumferential weld mean RTNOT values using updated neutron fluence values from the updated PTLR dated January 9, 2017. Based on increased neutron fluence values, the limiting circumferential weld mean RTNOT values increased as well, but remained below the bounding circumferential weld mean RTNOT values from BWRVIP-05.

The NRC staff reviewed the CF value and initial RT NOT value for the limiting RPV circumferential shell weld at CNS and determined that they are the same as those used for the updated PTLR dated January 9, 2017. The staff also confirmed that the licensee correctly calculated the limiting circumferential shell weld mean RTNDT value for CNS. Therefore, the staff determined that the licensee's mean RTNOT calculation for the proposed 60-year Code alternative adequately demonstrated that the limiting circumferential shell weld at CNS satisfies the mean RTNDT acceptance criteria established in the staffs SE for BWRVIP-05, for ensuring an acceptable circumferential shell weld conditional failure probability. Accordingly, the staff finds that the licensee's analysis of the CNS limiting circumferential shell weld, as provided in its submittal dated August 17, 2017, is acceptable for satisfying the specific circumferential shell weld PFM acceptance criteria established in the NRC staffs BWRVIP-05 SE for the PEO at CNS.

Analysis of RPV Axial Welds for BWR Plants that have Entered the PED (BWRVIP-74-A}

The NRC staffs acceptance of U.S. BWRs 40-year Code alternatives for the RPV circumferential shell welds was based, in part, on having an acceptable generic RPVaxial weld failure probability for the BWR fleet. Notably, the staff's March 7, 2000, supplemental SE (7-20) Rev 3.0

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3rd Interval CISI Program (ADAMS Accession No. ML003690281 ) for BWRVIP-05 specifically addressed the BWRVIP's generic analysis of RPV axial weld failure probability for supporting the plant-specific 40-year Code alternatives for elimination of RPV circumferentia l shell weld exams. In its supplemental SE, the staff stated that based on its review of the BWRVIP's generic axial weld PFM results, the limiting RPV axial weld failure probability for the BWR fleet at the end of the 40-year license term for all BWR units is acceptable, given the assumptions described in the supplemental SE.

The supplemental SE for BWRVIP-05 also stated that licensees would need to perform plant-specific evaluations (referred to as time-limited aging analyses, or TLAAs) of axial weld failure probability in LRAs to support demonstration that the PFM basis for elimination of circumferential shell weld exams remains acceptable for PEOs. These plant-specific axial weld evaluations would need to demonstrate acceptability using the NRC staffs specific acceptance criteria for axial weld failure probabilities from the supplemental SE for BWRVIP-05, dated

• March 7, 2000.

Subsequently, by letter dated October 18, 2001 {ADAMS Accession No. ML012920549), the NRC staff issued its final license renewal safety evaluation report (LR-FSER) for the BWRVIP-7 4-A report, "BWR Vessel and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines," wherein the staff identified that BWR licensee renewal applicants referencing the BWRVIP-74-A for their RPV neutron embrittlement TLAAs must evaluate both the RPV circumferential shell weld and axial shell weld failure probabilities as TLAAs for their proposed PE Os. The LR-FSER for BWRVIP-7 4-A indicates that an acceptable plant-specific evaluation of axial weld failure probability may consist of a plant-specific determination of the mean RTNOT of the most limiting RPV axial beltline weld, based on projected neutron embrittlement at the end of the 60-year license term, and demonstrating that it is less than the values specified in Table 1 of the LR-FSER for BWRVIP-74-A . The LR-FSER Table 1 values correspond to the axial weld acceptance criteria cited above from the March 7, 2000, supplemental SE for BWRVIP-05.

Based on the above acceptance criteria, Section 4.2.5 of the CNS LRA includes TLAAs that determined the 60-year projected mean RTNDT values for the limiting RPV circumferential and axial shell welds. As documented in Sections 4.2.5.4 of NUREG-1944, the NRC staff concluded that these analyses are acceptable for demonstrating compliance with the requirement forTLAAs set forth in 10 CFR 54.21(c}(1)(ii). The staff's finding was based on its determination that the 60-year projected mean RTNOT values for the limiting RPV circumferential and axial welds satisfied the BWRVIP-7 4-A acceptance criteria at the time the staff performed the LRA review.

It should be noted that the LRA mean RTNOT calculations used RPV weld neutron fluence and CFs that were valid at the time of the LRA review. Accordingly, the licensee's application dated August 17, 2017, for the subject Code alternative, considered that it was necessary to recalculate the limiting axial weld mean RTNDT values using updated neutron fluence values from the updated PTLR dated January 9, 2017. Based on increased neutron fluence values, the limiting axial weld mean RTNDT values increased as well, but remained below the bounding axial weld mean RTNDT values from the BWRVIP-05.

The NRC staff independently confirmed that the limiting axial weld mean RT NDT calculation supporting the axial weld TLAA, as documented in Section 4.2.5 of the LRA and approved by the NRC in NUREG-1944, remains bounding for the subject Code alternative, because the projected axial weld mean RTNDT remained below the bounding axial weld mean RTNOT values from the BWRVIP-05. Therefore, the staff determined that the limiting circumferential and axial welds satisfy the PFM acceptance criteria established in the BWRVIP-74-A for the PEO at CNS.

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3rd Interval CISI Program Accordingly, the staff finds that request for alternative Rl5-01, to implement the BWRVIP PFM results in lieu of subject RPV circumferential shell weld examination requirements, will provide an acceptable level of quality and safety, and thus should be authorized pursuant to 10 CFR 50.55a(z)(1).

NRC Staff Evaluation Concerning Neutron Fluence The projected RPV neutron fluence is an input to the determination of the mean RT NDT value needed to demonstrate an acceptable RPV weld conditional failure probability. The RPV neutron fluence, as determined based on NRC staff-approved calculation methodologies, is the key time-dependent parameter for all RPV integrity analyses that consider neutron embrittlement of the RPV beltline materials. The projected neutron fluence input to the mean RTNDT value, for demonstrating an acceptable RPV weld conditional failure probability at the end of the licensed operating term, is expected to be reflective or bounding of the as-operated core design, including major changes like the implementation of power uprates.

On February 22, 2013, the NRC issued Amendment No. 245, authorizing a revision to Technical Specification 3.4.9, "RCS Pressure and Temperature (Pff) Limits," for 32 EFPY (ADAMS Accession No. ML13032A526). In its SE, the NRC staff states: "The primary staff consideration for acceptability is the fact that RAMA [Radiation Analysis Modeling Application] has been found adherent to RG 1.190, and in particular for calculating vessel fluence values for BWR/4 vessel geometries such as [CNS]. .. the NRC staff concludes that the neutron fluence calculation supporting the proposed 32 EFPY P-T limits is acceptable," which demonstrates that the fluence method used at CNS, adheres to the guidance contained in RG 1.190. The same fluence methods were reviewed by the NRC staff and found acceptable for use in support of issuing Amendment No. 256, which allowed the licensee to implement administrative control of its Pff limits via a PTLR (ADAMS Accession No. ML16158A022). In its present review, the NRC staff verified that the same fluence methods were used to support the 10 CFR 50.55a relief request, meaning that the methods are NRC-approved and adhere to the guidance contained in RG 1. 190. The calculations also reflect past and present operational characteristics, and the fluence projection for future cycles is representative of the most recent operating cycles at CNS, based on consistency with the most recent revision of the CNS PTLR submitted to the NRC on january 9, 2017 (ADAMS Accession Nos. ML17018A15i and ML170i8Ai52). Therefore, the NRC staff finds the use of the two fluence values reported in the Attachment to the letter dated August 17, 2017, acceptable for use as inputs to demonstrate an acceptable RPV weld conditional failure probability at the end of the licensed operating term, based on use of fluence values calculated using an NRC-approved fluence methodology, which were used to derive valid fluence projections, as reported using an NRC-approved PTLR methodology.

4.0 CONCLUSION

The NRC staff finds that the information submitted by the licensee demonstrates that the conditional failure probabilities for the CNS limiting RPV circumferential and axial shell welds at the end of the PEO satisfies the NRC staff's acceptance criteria for these evaluations in its SEs for BWRVIP-05 and BWRVIP-74-A. Additionally, the* licensee will continue to implement operator training and procedures to limit the frequency of cold overpressure events in accordance with the staffs SE for the BWRVIP-05 report, consistent with the staffs previous approval of these methods for the PEO, as documented in Section 4.2.5 of NUREG-1944 for the license renewal of CNS. The licensee has therefore satisfied the plant-specific conditions required to obtain NRC authorization for this specific Code alternative.

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3rd Interval CISI Program On this basis, the NRC staff concludes that implementation of the BWRVIP-05 and BWRVIP-74-A methods, in lieu of the specific ASME Code,Section XI, Category B-A, Item No. B 1.11 requirements for volumetric examination of the subject RPV circumferential shell welds, will provide an acceptable level of quality and safety at CNS for the duration of the unit's 20-year extended license term. The NRC staff has reviewed the subject request and concludes as set forth above, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1). Therefore, pursuant to 10 CFR 50.55a(z)(1},

CNS request for alternative Rl5-01 is authorized for the remaining term of the CNS renewed operating license, which ends on January 18, 2034.

All other ASME Code,Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third party review by the Authorized Nuclear lnservice Inspector.

Principal Contributors: J. Jenkins, NRR/DMLR/M VIB A. Patel, NRR/DSS/SNP B Date: July 31, 2018 (7-23) Rev 3.0

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3rd Interval GISI Program 10 CFR 50.SSa Request No. RIS-02, Revision 1 Implementation of BWRVIP Documents in Lieu of B-N-1 and B-N-2 Proposed Alternative in Accordance with 10 CFR 50.SSa{z)(l)

Acceptable Level of Quality and Safety ASME Code Component(s) Affected Code Class: ASM E Section XI Code Class 1 Examination Category: 8-N-1, 8-N-2 Item Number(s): 813.10, 813.20, 813.30, and 813.40 Component Numbers: Various

Applicable Code Edition and Addenda

ASME Section XI, 2007 Edition through the 2008 Addenda Applicable ASME Code Requirements Table IW8-2500-1, Examination Categories "8-N-2, Welded Core Support Structures and Interior Attachments to Reactor Vessels," 11 8-N-3, Removable Core Support Structures" requires examinations based on the following Item Numbers:

813.10 Examine accessible areas of the reactor vessel interior (8-N-1) each period by the VT-3, visual examination method; includes only those spaces above and below the core made accessible by removal of components during normal refueling outages 813.20 Examine accessible interior welded attachments within the beltline region each interval by the VT-1, visual examination method (8-N-2)

B13.30 Examine accessible interior welded attachments beyond the beltline region each interval by the VT-3, visual examination method (8-N-2)

B13.40 Examine the accessible surfaces of welded core support structures each interval by the VT-3, visual examination method (B-N-2)

These examinations are performed to assess the structural integrity of the reactor vessel interior, its welded attachments, and the welded core support structure within the boiling water reactor pressure vessel.

Reason for Request

In accordance with 10 CFR 50.SSa(z)(l), NPPD is requesting NRC approval of a proposed alternative to the Code requirements provided above on the basis that the use of the 8WRVIP guidelines discussed below provide an acceptable level of quality and safety. The 8WRVIP (7-24) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Inspection and Evaluation Guidelines recommend specific inspection by BWR owners to identify material degradation with BWR components. A wealth of inspection data has been gathered during these inspections across the BWR industry. The BWRVIP Inspection and Evaluation Guidelines focus on specific and susceptible components, specify appropriate inspection methods capable of identifying known or potential degradation mechanisms, and require re-examination at appropriate intervals. The scope of the BWRVIP Inspection and Evaluation Guidelines exceed that of ASME Section XI and in most instances include components that are not part of the ASME Section XI jurisdiction.

Use of this proposed alternative will maintain an adequate level of quality and safety and avoid duplicate or unnecessary inspections, while conserving radiological dose.

Revision 1 updates the BWRVIP-18 reference to Revision 2-A and provides an updated inspection history to include the Fall 2016 (RE29) refueling outage. Revision 0 of this Relief was approved by the NRC on February 17, 2016 (Reference 14).

Proposed Alternative and Basis for Use Proposed Alternative NPPD requests authorization to utilize the alternative requirements of the BWRVIP Guidelines in lieu of the requirements of ASME Code Section XI.

NPPD will satisfy the Examination Category B-N-1 and B-N-2 requirements as described in Table 1 on page 15 in accordance with BWRVIP guideline requirements. This relief request proposes to utilize the identified BWRVIP guidelines in lieu of the associated Code requirements, including examination method, examination volume, frequency, training, successive and additional examinations, flaw evaluations, and reporting.

!\Jot al! of the components addressed by these guidelines are Code components. The proposed alternative includes:

For Examination Category B-N-1:

As an alternative to meeting ASME Section XI and performing a VT-3 examination of the RPV interior above and below the core made accessible by a normal refuel outage, NPPD will implement the BWRVIP Guidelines listed below and as outlined in Table 1 on page 15. By this request for alternative the BWRVIP Guidelines will be used as an alternative to the requirements of ASME Section XI.

• BWRVIP-03, Revision 17, "Reactor Pressure Vessel and Internals Examination Guidelines"

• BWRVIP-18, Revision 2-A, BWR Core Spray Internals Inspection and Flaw Evaluation 11 Guidelines" (7-25) Rev 3.0

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• BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines"

• BWRVIP-26-A, "BWR Top Guide Inspection and Flaw Evaluation Guidelines"

• BWRVIP-27-A, 11 BWR Standby Liquid Control System/Core Plate tiP Inspection and Flaw Evaluation Guidelines"

• BWRVIP-41, Revision 3, "BWR Jet Pump Assembly Inspection and Evaluation Guidelines"

• BWRVIP-47-A, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines"

• BWRVIP-138 Revision 1-A, "Updated Jet Pump Beam Inspection and Flaw Evaluation Guidelines" For Examination Category B-N-2:

As an alternative to meeting ASME Section XI and performing a VT-1 or VT-3, as required by ASME Section XI, examination of the RPV welded attachments and welded core support structures, NPPD will implement the BWRVIP Guidelines listed below and as outlined in Table 1 on page 15. By this request for alternative the BWRVIP Guidelines will be used as an alternative to the requirements of ASME Section XI.

• BWRVIP-03, Revision 17, "Reactor Pressure Vessel and Internals Examination Guidelines 11

• BWRVIP-38, BWR Shroud Support Inspection and Flaw Evaluation Guidelines 11 11

• BWRVIP-48-A, Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines" 11

• BWRVIP-76, Revision 1-A, BWR Core Shroud Inspection and Flaw Evaluation Guidelines 11 11

• BWRVIP-100-A, "Updated Assessment of the Fracture Toughness of Irradiated Stainless Steel for BWR Core Shrouds" Note: If flaw evaluations are required for BWRVIP-76, Revision 1-A, examinations, the fracture toughness values of BWRVIP-100-A will be utilized.

When a BWRVIP Guideline refers to ASME Section XI, the technical requirements of ASME Section XI as described by the BWRVIP Guideiine wiii be met, but the examination is under the auspices of the BWRVIP program as defined by BWRVIP-94NP, Revision 2, "BWRVIP Vessel and Internals Project Program Implementation Guide."

The NPPD reactor vessel internals inspection programs have been developed and implemented to satisfy the requirements of BWRVIP-94NP, Revision 2. It is recognized that the BWRVIP executive committee periodically revises the BWRVIP guidelines to address industry operating experience, include enhancements to inspection techniques, and add or adjust flaw evaluation methodologies. BWRVIP-94NP, Revision 2, states that where guidance in existing BWRVIP documents has been supplemented or revised by subsequent correspondence approved by the BWRVIP Executive Committee, the vessel and internals program shall be modified to reflect the new requirements and implement the guidance within two refueling outages, unless a different schedule is specified by the BWRVIP.

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3rd Interval CISI Program However, if new guidance approved by the Executive Committee includes changes to NRC approved BWRVIP guidance that are less conservative than those approved by the NRC, the less conservative guidance shall be implemented only after NRC approves the changes, which generally means publication of a "-A" document or equivalent. Therefore, where the revised version of a BWRVIP inspection guideline continues to also meet the requirements of the version of the BWRVIP inspection guideline approved by the NRC, it may be implemented.

Otherwise, the revised guidelines will only be implemented after NRC approval of the revised BWRVIP guidelines or a plant-specific request for alternative has been approved. Table 1 below only represents the most current comparison.

Any deviations from the referenced BWRVIP Guidelines for the duration of the proposed alternative will be appropriately documented and communicated to the NRC, per the BWRVIP Deviation Disposition Process.

Note that other regulatory commitments (i.e., NUREG-0619) are still being implemented separately from the ASME Section XI Program or this request for alternative.

In the event that conditions are identified that require repair or replacement and the component is within the jurisdiction of ASME Section XI (welded attachments to the RPV or Core Support Structure), the repair or replacement activities will be performed in accordance with ASME Section XI, Article IWA-4000. Subsequent examinations will be in accordance with the applicable BWRVIP Guideline.

Basis for Use As part of the BWRVIP initiative, the BWR reactor internals and attachments were subjected to a safety assessment to identify those components that provide a safety function and to determine if long-term actions were necessary to ensure continued safe operation. The safety functions considered are those associated with (1) maintaining a coolable geometry, (2) maintaining control rod insertion times, (3) maintaining reactivity control, (4) assuring core cooling and (5) assuring instrumentation availability. The results of the safety assessment are documented in BWRVIP-06, Revision 1-A, "BWR Vessel and Internals Project Safety Assessment of BWR Reactor Internals" which has been approved by the NRC. As a result of BWRVIP-06, Revision 1-A, component specific BWRVIP guidelines were developed providing appropriate examination and evaluation requirements to address the specific component safety function and potential degradation mechanism.

Along with the component specific guidelines, the BWRVIP has established a reporting protocol for examination results and deviations. The NRC has agreed with the BWRVIP approach in principal and has issued Safety Evaluations for many of these guidelines (see References).

As additional justification, page 17, "Comparison of ASME Code Section XI Examination Requirements to BWRVIP Examination Requirements," provides specific examples which compare the inspection requirements of ASME Code Section XI Table IWB-2500-1, Item (7-27) Rev 3.0

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3rd Interval GISI Program Numbers 813.10, 813.20, 813.30 and 813.40 to the inspection requirements in the BWRVIP documents. Specific BWRVIP documents are provided as examples. This comparison also includes a discussion of the inspection methods.

Therefore, use of the BWRVIP guidelines as an alternative to ASME Section XI, as shown by the comparison provides an acceptable level of quality and safety.

Duration of Proposed Alternative This proposed alternative will be used for the Fifth Ten-Year Interval of the lnservice Inspection Program for CNS.

Precedents Similar request for alternatives has been previously approved for the following other licensees.

1. US NRC letter to Entergy Operations, "Grand Gulf Nuclear Station, Unit 1 - Request for Relief GG-ISl-017, Alternative to Use Boiling Water Reactor Vessel and Internals Project Guidelines in lieu of Specific ASME Code Requirements (TAC No. MF2357)", dated June 30, 2014 (ML14148A262).

2. US NRC letter to Entergy Operations, "River Bend Station, Unit 1 - Request for Relief No.

RBS-ISl-019, Alternative to Use Boiling Water Reactor Vessel and Internals Project Guidelines in Lieu of ASME Code,Section XI Requirements for the Fourth 10-Year lnservice Inspection Interval (TAC No. MF1867), dated May 30, 2014 (ML14127A327).

3. US NRC letter to Exelon Generation Company, LLC, "Dresden Nuclear Power Station, Units 2 and 3 - Safety Evaluation in Support of Request for Relief Associated With the Fifth 10-Year lnservice Inspection Interval Program (TAC Nos. ME9682, ME9683, ME9684, ME9685, ME9686, !VIE9687, ME9688, ME9689; ME9690; ME9691; ME9692: ME9693, ME9694, ME9695, ME9696, and ME9697), dated September 30, 2013 (ML13260A585).

4. US NRC letter to Exelon Generation Company, LLC, "Quad Cities Nuclear Power Station Units 1 and 2 - Safety Evaluation in Support of Request for Relief Associated With the Fifth 10 Year Interval lnservice Inspection Program (TAC Nos. ME9668, ME9669, ME9670, ME9671, ME9672, ME9674, ME9675, ME9676, ME9677, ME9678, ME9679, ME9680, ME9681), dated September 30, 2013 (ML13267A097).

5. US NRC letter to Exelon Nuclear, "Oyster Creek Nuclear Generating Station - Relief From the Requirements of the ASME Code, Relief Request No. I5R-01 (TAC No. ME9490), dated August 5, 2013 (ML13169A062).

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1. US NRC letter to BWRVIP, "Safety Evaluation by the Office of Nuclear Reactor Regulation Topical Report, BWRVIP-06-A: BWR (Boiling Water Reactor) Vessel and Internals Project (BWRVIP), Safety Assessment of BWR Reactor Internals, Revised Section 4.0: Consideration of Loose Parts" (TAC No. MC7448) dated July 29, 2008 (ML082030758).

2. US NRC letter to BWRVIP, "Final Proprietary Safety Evaluation for Electric Power Research Institute Topical Report, "BWRVIP-18, Revision 2: Boiling Water Reactor Core Spray Internals Inspection and Flaw Evaluation Guidelines (TAC No. MF8809}, dated February 22, 11 2016 (ML16011A199).

3. US NRC letter to BWRVIP, "Final Safety Evaluation of BWRVIP Vessel and Internals Project, BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines (BWRVIP-25), EPRI Report TR-107284, December 1996 (TAC No. M97802),

11 11 dated December 19, 1999.

4. US NRC letter to BWRVIP, NRC Approval Letter of BWRVIP-26-A, BWR Vessel and Internals 11 Project Boiling Water Reactor Top Guide Inspection and Flaw Evaluation Guidelines," dated August 29, 2005 (ML052490550).

5. US NRC letter to BWRVIP, "Non-Proprietary Version of NRC Staff Review of BWRVIP-27-A, BWR Standby Liquid Control System/Core Plate 8P Inspection and Flaw Evaluation 11 Guidelines," dated June 9, 2004 (ML041700446).

6. US NRC letter to BWRVIP, "Final Safety Evaluation of the BWR Vessel and Internals Project, 11 BWR Shroud Support Inspection and Flaw Evaluation Guidelines (BWRVIP-38),1' EPRI Report TR-108823 (TAC No. M99638), dated July 24, 2000 (ML003735498).

11

7. US NRC letter to BWRVIP, "Final Safety Evaluation of the BWR Vessel and Internals Project, 11 BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines (BWRVIP-41), (TAC No.

11

!V!99870),1' dated February 4, 2001 (ML010460111).

8. US NRC letter to BWRVIP, NRC Approval Letter of BWRVIP-47-A, BWR Vessel and Internals 11 11 Project Boiling Water Reactor Lower Plenum Inspection and Flaw Evaluation Guidelines,"

dated September 1, 2005 (ML052490537).

9. US NRC letter to BWRVIP, NRC Approval Letter of BWRVIP-48-A, BWR Vessel and Internals 11 11 Project Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines," dated July 25, 2005 (ML052130284).

10. US NRC letter to BWRVIP, "Final Safety Evaluations of the Boiling Water Reactor Vessel and Internals Project 76, Rev. 1 Topical Report, "Boiling Water Reactor Core Shroud Inspection and Flaw Evaluation Guidelines" (TAC No. ME8317)," dated November 12, 2014.

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11. Letter from Chairman, BWR Vessel and Internals Project to NRC, "Project No. 704 - BWRVIP Program Implementation Guide (BWRVIP-94NP, Revision 2}," dated September 22, 2011 (ML11271A058).

12. US NRC letter to BWRVIP, "NRC Approval Letter with Comment for BWRVIP-100-A, BWR Vessel and Internals Project, Updated Assessment of the Fracture Toughness of Irradiated Stainless Steel for BWR Core Shrouds," dated November 1, 2007 (ML073050135}.

13. US NRC letter to BWRVIP, "Electric Power Research Institute Final Safety Evaluation for Technical Report 1016574 "BWRVIP-138, Revision 1: BWR [Boiling Water Reactor] Vessel and Internals Project 'Updated Jet Pump Beam Inspection and Flaw Evaluation Guidelines' (TAC No. ME2191)," dated May 14, 2012 (ML1208A139).

14. US NRC letter to NPPD, "Cooper Nuclear Station - Request for Relief RIS-02, Alternative to Use Boiling Water Reactor Vessel and Internals Project Guidelines in Lieu of Specific ASME Code Requirements (CAC No. MF6336)," dated February 17, 2016 (ML16034A479).

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Table 1 Comparison of ASME Examination Category B-N-1 and B-N-2 Requirements with BWRVIP Guidance Requirements (Note 1)

ASME Item ASME Applicable BWRVIP No. Table ASME Exam ASME BWRVIP Exam BWRVIP Component Exam BWRVIP Exam IWB-2500- Scope Frequency Scope Frequency Type Document Type 1

B13.10 Reactor Vessel Interior Accessible VT-3 Each Period BWRVIP-18, Overview examinations of components during Areas (Non- 25, 26, 38, BWRVIP examinations are performed to satisfy specific) 41, 47, 48, Code VT-3 inspection requirements.

76, 138 B13.20 Interior Attachments Accessible VT-1 Each 10- BWRVIP-48 Riser Brace EVT-1 100% in first 12 within Beltline - Riser Welds year Table 3-2 Attachment years, 25%

Braces Interval during each subsequent 6 years Lower Surveillance BWRVIP-48, Bracket VT-1 Each 10-Year Specimen Holder Table 3-2 Attachment Interval Brackets B13.30 Interior Attachments Accessible VT-3 Each 10- BWRVIP-48, Bracket VT-3 Each 10-Year beyond Beltline - Welds year Table 3-2 Attachment Interval Steam Dryer Hold- interval down Brackets Guide Rod Brackets BWRVIP-48, Bracket VT-3 Each 10-Year Table 3-2 Attachment Interval Steam Dryer Support BWRVIP-48, Bracket EVT-1 Each 10-Year Brackets Table 3-2 Attachment Interval Feedwater Sparger BWRVIP-48, Bracket EVT-1 Each 10-Year Brackets Table 3-2 Attachment Interval Core Spray Piping BWRVIP-48, Bracket EVT-1 Every 4 Refueling Brackets Table 3-2 Attachment Cycles (7-31) Rev 3.0

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Table 1 Comparison of ASME Examination (',:ategory B-N-1 and B-N-2 Requirements with BWRVIP Guidance Requirements (Note 1)

ASME Item ASME Applicable BWRVIP No. Table ASME Exam ASME BWRVIP Exam BWRVIP Component Exam BWRVIP Exam IWB-2500- Scope Frequency Scope Frequency Type Document Type 1

Upper Surveillance BWRVIP-48, Bracket VT-3 Each 10-Year Specimen Holder Table 3-2 Attachment Interval Brackets Shroud Support (Weld BWRVIP-38, Weld H-9 EVT-1 or Maximum of 6 H9) including gussets 3.1.3.2, including gussets UT years for EVT-1, Figures 3-2 Maximum of 10 and 3-5 years for UT B13.40 Integrally Welded Accessiblie VT-3 Each 10- BWRVIP-38, Shroud support EVT-1 or Based on as-Core Support Surfaces year 3.1.3.2, welds H8 and H9 UT found Structure interval Figures 3-2 including gussets conditions, to a and 3-5 maximum 6 years for one side EVT-1, 10 years for UT where accessible Shroud Horizontal BWRVIP-76, Welds Hl-H7 as UT or Based on as-Welds 2.2 applicable EVT-1 found conditions, to a maximum of 10 years for UT when inspected from both sides of the welds (7-32) Rev 3.0

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Table 1 Comparison of ASME Examination Category B-N-1 and B-N-2 Requirements with BWRVIP Guidance Requirements (Note 1)

ASME Item ASME Applicable BWRVIP No. Table ASME Exam ASME BWRVIP Exam BWRVIP Component Exam BWRVIP Exam IWB-2500- Scope Frequency Scope Frequency Type Document Type 1

Shroud Vertical Welds BWRVIP-76, Vertical Welds as EVT-1 or Maximum 10 2.3 applicable UT years for UT based on inspection of horizontal welds Note:

1. This Table provides only an overview of the requirements. For more details, refer to ASME Section XI, Table IWB-2500-1 and the appropriate BWRVIP document.

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3rd Interval CISI Program Comparison of ASME Code Section XI Examination Requirements to BWRVIP Examination Requirements The following provides a comparison of the examination requirements provided in ASME Code Section XI Table IWB-2500-1, Examination Category B-N-1 and 8-N-2, Item Numbers B13.10, 813.20, 813.30, and 813.40, to the examination requirements in the BWRVIP Guidelines.

Specific BWRVIP Guidelines are provided as examples for comparisons. This comparison also includes a discussion of the examination methods.

Code Requirement - B13.10 - Reactor Vessel Interior Accessible Areas {B-N-1)

The ASME Section XI Code requires a VT-3 examination of reactor vessel accessible areas, which are defined as the spaces above and below the core made accessible during normal refueling outages. The frequency of these examinations is specified as the first refueling outage, and at intervals of approximately 3 years during the first inspection interval, and each period during each successive 10-year Inspection Interval. Typically, these examinations are performed every other refueling outage of the Inspection Interval. This examination requirement is a non-specific requirement that is a departure from the traditional Section XI examinations of welds and surfaces. As such, this requirement has been interpreted and satisfied differently across the licensees, and vendors of this inspection service. Based on the acceptance criteria specified in IWB-3520.2, the examination is to identify relevant conditions such as distortion or displacement of parts, loose, missing, or fractured fasteners, foreign material, corrosion, erosion, or accumulation of corrosion products, wear, and structural degradation.

Portions of the various examinations required by the applicable BWRVIP Guidelines require access to accessible areas of the reactor vessel during each refueling outage. Examination of Core Spray Piping and Spargers (BWRVIP-18-R2-A), Top Guide (BWRVIP-26-A), Jet Pump Welds and Components (BWRVIP-41-R3), Interior Attachments (BWRVIP-48-A), Core Shroud Welds (8WRVIP-76-Rl-A), Shroud Support (BWRVIP-38), and Lower Plenum Components (BWRVIP A) provides such access. Locating and examining specific welds and components within the reactor vessel areas above, below (if accessible), and surrounding the core (annulus area) entails access by remote camera systems that essentially perform equivalent VT-3 examination of these areas or spaces as the specific weld or component examinations are performed. This provides an equivalent method of visual examination on a more frequent basis than that required by the ASME Section XI Code. Evidence of wear, structural degradation, loose, missing, or displaced parts, foreign materials, and corrosion product buildup can be, and has been observed during the course of implementing these BWRVIP examination requirements.

Therefore, the requirements specified by the BWRVIP Guidelines meet or exceed the subject Code requirements for examination method and frequency of the interior of the reactor vessel.

Accordingly, these BWRVIP examination requirements provide an acceptable level of quality and safety as compared to the subject Code requirements.

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3rd Interval CISI Program Code Requirement - B13.20 - Interior Attachments within the Beltline (B-N-2)

The ASME Section XI Code requires a VT-1 examination of accessible reactor interior surface attachment welds within the beltline each 10-year interval. In the BWR, this includes the Jet Pump Riser Brace Weld-to-Vessel Wall and the Lower Surveillance Specimen Support Bracket Welds-to-Vessel Wall. In comparison, the BWRVIP requires the same examination method and frequency for the Lower Surveillance Specimen Support Bracket Welds, and requires an EVT-1 examination on the remaining attachment welds in the beltline region in the first 12 years, and then 25% during each subsequent 6 years.

The Jet Pump Riser Brace examination requirements are provided below to show a comparison between the Code and the BWRVIP examination requirements.

Comparison to BWRVIP Requirements - Jet Pump Riser Braces (BWRVIP-41-R3 and BWRVIP Af

• The ASME Code requires a 100% VT-1 examination of the Jet Pump Riser Brace-to-Reactor Vessel Wall Pad welds each 10-year Interval.

• The BWRVIP requires an EVT-1 baseline examination of 100% of the Jet Pump Riser Brace-to-Reactor Vessel Wall Pad welds in the first 12 years with at least 50% being inspected in the first 6 years. Reinspection consists of 25% during each subsequent 6 year period.

• BWRVIP-48-A specifically defines the susceptible regions of the attachment that are to be examined.

The Code VT-1 examination is conducted to detect discontinuities and imperfections on the surfaces of components, including such conditions as cracks, wear, corrosion, or erosion. The BWRVIP EVT-1 is conducted to detect discontinuities and imperfections on the surface of components and is additionally specified to detect potentially very tight cracks characteristic of fatigue and IGSCC, the relevant degradation mechanisms for these components. General wear, corrosion, or erosion although generally not a concern for inherently tough, corrosion resistant stainless steel material, would also be detected during the process of performing a BWRVIP EVT-1 examination.

The ASME Code visual examination method requires (depending on applicable ASME Edition) that a letter character with a height of 0.044 inches can be read. The BWRVIP EVT-1 visual examination method requires the same 0.044 inch resolution on the examination surface and additionally the performance of a cleaning assessment and cleaning as necessary. While the Jet Pump Riser Brace configuration varies depending on the vessel manufacturer, BWRVIP-48-A includes diagrams for each configuration and prescribes examination for each configuration.

The calibration standards used for BWRVIP EVT-1 examinations utilize the same Code characters, thus assuring at least equivalent resolution compared to the Code. Although the BWRVIP examination may be less frequent, it is a more comprehensive method. Therefore, the BWRVIP guidance provides an acceptable level of quality and safety to that provided by the (7-35) Rev 3.0

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Code Requirement - B13.30 - Interior Attachment Beyond the Beltline Region (B-N-2)

The ASME Section XI Code requires a VT-3 examination of accessible Reactor Interior Surface Attachment Welds beyond the beltline each 10-year Interval. In the Boiling Water Reactor, this includes the Core Spray Piping Primary, the Upper Surveillance Specimen Support Bracket Welds-to-Vessel Wall, the Feedwater Sparger Support Bracket Welds-to-Reactor Vessel Wall, the Steam Dryer Support and Hold-Down Bracket Welds-to-Reactor Vessel Wall, the Guide Rod Support Bracket Weld-to-Reactor Vessel Wall, the Shroud Support Plate-to-Vessel Welds, and Shroud Support Gussets. BWRVIP-48-A requires as a minimum the same VT-3 examination method as the Code for some of the interior attachment welds beyond the beltline region, and in some cases specifies an enhanced visual examination technique EVT-1 for these welds. For those interior attachment welds that have the same VT-3 method of examination, the same scope of examination (accessible welds), the same examination frequency (each 10 year interval) and ASME Section XI flaw evaluation criteria, the level of quality and safety provided by the BWRVIP requirements are equivalent to that provided by the ASME Code.

The Core Spray Piping Bracket-to-Vessel Attachment Weld is used as an example for comparison between the Code and BWRVIP examination requirements as discussed below:

Comparison to BWRVIP Requirements - Core Spray Piping Bracket Welds relative to BWRVIP ~

• The Code examination requirement is a VT-3 examination of each weld every 10 years.

• The BWRVIP examination requirement is an EVT-1 for the Core Spray Piping Bracket Attachment Welds with each weld examined every four cycles (8 years for units with a 2 year fuel cycle)

The B\NRV!P examination method EVT-1 has superior f!av,1 detection and sizing capability than the Code VT-3, the examination frequency is greater than the Code requirements, and the same flaw evaluation criteria are used.

The Code VT-3 examination is conducted to detect component structural integrity by ensuring the component1s general condition is acceptable. An enhanced EVT-1 is conducted to detect discontinuities and imperfections on the examination surfaces, including such conditions as tight cracks caused by IGSCC or fatigue, the relevant degradation mechanisms for BWR internal attachments. Additionally, BWRVIP-48-A guidance requires indications detected by an EVT-1 to be examined by ultrasonics to determine if the indication has propagated into the reactor vessel base material.

Therefore, with the EVT-1 examination method, the same examination scope (accessible welds), an increased examination frequency (8 years instead of 10 years) in some cases, and the same flaw evaluation criteria (ASME Code Section XI), the level of quality and safety provided (7-36) Rev 3.0

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Code Requirement - 813.40 - Integrally Welded Core Support Structures (B-N-2)

The ASME Code requires a VT-3 examination of accessible surfaces of the welded core support structure each 10-year interval. In the boiling water reactor, the welded core support structure has primarily been considered the shroud support structure, including the shroud support plate

{annulus floor), the shroud support ring, the shroud support welds, and the shroud support gussets. In later designs, the shroud itself is considered part of the welded core support structure. Historically, this requirement has been interpreted and satisfied differently across the industry. The proposed alternate examination replaces this ASME requirement with specific BWRVIP guidelines that examine susceptible locations for known relevant degradation mechanisms.

• The Code requires a VT-3 of accessible surfaces each 10-year interval.

• The BWRVIP requires as a minimum the same examination method {VT-3) as the Code for integrally welded Core Support Structures, and for specific areas, requires either an enhanced visual examination technique {EVT-1) or volumetric examination {UT).

BWRVIP recommended examinations of integrally welded core support structures are focused on the known susceptible areas of this structure, including the welds and associated weld heat affected zones. As a minimum, the same or superior visual examination technique is required for examination at the same frequency as the Code examination requirements. In many locations, the BWRVIP guidelines require a volumetric examination of the susceptible welds at a frequency identical to the Code requirement. For other integrally welded core support structure components, the BWRVIP requires an EVT-1 or UT of core support structures. The core shroud is used as an example for comparison between the Code and BWRVIP examination requirements as shown below.

Comparison to BWRVIP Requirements - BWR Core Shroud Examination and Flaw Evaluation Guideline (HWRVIP-76}

• The Code requires a VT-3 examination of accessible surfaces every 10 years.

• The BWRVIP requires an EVT-1 examination from the inside and outside surface where accessible or ultrasonic examination of each core shroud circumferential weld that has not been structurally replaced with a shroud repair at a calculated "end of interval" that will vary depending upon the amount of flaws present, but not to exceed ten years.

The BWRVIP recommended examinations specify locations that are known to be vulnerable to BWR relevant degradation mechanisms rather than "all surfaces." The BWRVIP examination methods (EVT-1 or UT) are superior to the Code required VT-3 for flaw detection and characterization. The BWRVIP examination frequency is equivalent to or more frequent than the examination frequency required by the Code. The superior flaw detection and characterization capability, with an equivalent or more frequent examination frequency and the comparable flaw evaluation criteria, results in the BWRVIP criteria providing a level of quality and safety equivalent to or superior to that provided by the Code requirements.

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3rd Interval GISI Program Reactor Internals Inspection History Plant: Cooper Nuclear Station Dated: Nov 08, 2016 (RE29 outage end)

Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Core Shroud Fall 1995 UT Baseline UT performed on welds Hl (RE15) through H7 per BWRVIP guidelines.

Indications identified in 4 circumferential welds. No examinations on vertical welds. No repair required.

Spring 2005 UT (RE22) UT examinations were performed on welds H-1 through H-4 including a portion of vertical weld V16.

Examination of welds H5-H7 was deferred to fall 2006. Single sided UT examinations were performed on welds H-1 through H-3 with welds H-4 and vertical weld (V-16) receiving dual sided examinations. Percentage of welds examined: Hl (54.9%}, H2 (55.7%), H3 (63.9%}, H4 (58.4%). The previously identified eight (8) flaws in Hl showed a net decrease in length. No new flaws in H2 were identified. The eight (8) flaws in H3 were reexamined with one (1) new flaw identified for a total increased change in flaw length relative to total weld length of 7.5 %. Two (2) new minor flaws were discovered in the HAZ of H4.

In addition, a total of eleven (11) minor indications were identified in the base metal adjacent to H4. Six (6) of the indications exhibited characteristics associated with Stress Corrosion Cracking (SCC) in areas subjected to cold working during the shroud fabrication/installation process. The remaining five (5)

Fall 2006 UT indications did not exhibit characteristics (RE23) of sec but appeared to exhibit characteristics commonly observed from localized attachment removal sites. The (7-38) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections indications were determined to be acceptable by analysis. No indications were observed in the vertical weld.

UT examinations were performed on welds HS, H6a, H6b, and H7 using phased array. Two- (2) sided examinations were performed on all welds except H7 that received a one-sided UT examination.

Coverage was estimated at greater than 72% for welds HS, H6a, and H6b. H7 received greater than 53% coverage. A previously identified indication in HS was VT-3 re-examined with no apparent change. A previously identified indication in H6a was re-examined with no apparent change. A new minor indication was discovered in weld H6b in an area Spring 2008 VT-3 previously scanned in RE16 (1995). Two (RE24) (2) new minor indications were discovered in weld H7, one in a previously scanned location and the Spring 2011 VT-3 other in an area not previously scanned.

(RE26)

VT-3 examination of shroud per ASME Section XI, B-N-2 requirements.

Fall 2014 UT Discovered an indication approximately (RE28) ten (10) inches long behind JP-19.

Analyzed as acceptable.

Performed first ASME B-N-2 VT-3 successive examination of flaw discovered in base metal behind JP-19.

No changes in the indication.

Performed second ASME B-N-2 VT-3 successive examination of flaw discovered in base metal behind JP-19.

No changes in the indication.

UT exams were performed on the Hl thru H7 welds along with the V16 and (7-39) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections base material flaw behind JP-19. The previously identified indications showed no apparent changes in growth and none were through wall.

VT-3 examination of shroud per ASME Section XI, B-N-2 requirements. Also performed third ASME B-N-2 VT-3 successive examination of flaw discovered in base metal behind JP-19.

No changes in the indication.

Shroud Support/ 1993-1995 VT-3 and VT-3 examinations of welds on 50% of Access Hole Covers UT core plate each outage. No indications.

UT of access hole covers (AHC) in 1993.

No indications.

Spring 1997 VT-3 (REl 7) VT-3 examinations on 50% of the core shroud support plate. No indications.

VT-1 VT-1 examinations of AHC in accordance with GE SIL 462. No indications.

Fall 1998 VT-3 (RE18} VT-3 examinations on 50% of the core shroud support plate. No indications.

VT-1 VT-1 of AHC's in accordance with GE SIL 462. No indications. VT-1 of gusset plate welds between 0-180° to B-N-2.

Spring 2000 VT-3 (RE19} VT-3 examinations on 50% of the core shroud support plate. No indications.

VT-1 VT-1 examinations of AHCs in accordance with GE SIL 462. No indications.

Fall 2001 EVT-1 (RE20} EVT-1 examinations on 17% of the H8 and H9 welds. EVT-1 examinations on 6 gusset welds and AHCs. No indications.

UT UT examination of AHCs. No indications.

Spring 2003 EVT-1 (7-40) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections (RE21) EVT-1 examinations on four (4) gusset welds. No indications.

Spring 2005 UT (RE22) UT examinations on 11.7% of the H9 weld length. No indications.

Fall 2006 EVT-1 (RE23) EVT-1 examinations performed on approximately 16% of H8 weld length with no relevant indications. EVT-1 examinations of AHC per SIL 462. No Spring 2008 EVT-1 indications.

(RE24)

EVT-1 examinations performed on accessible lengths of welds on seven (7)

Fall 2012 EVT-1 gussets. No indications.

(RE27)

EVT-1 examinations on 16.7% of the H8 weld. EVT-1 examinations on accessible lengths of welds on two (2) gussets @

Fall 2014 UT/EVT-1 195° and 315°. No indications.

(RE28)

UT performed on H9 with 13.4%

coverage. EVT-1 performed on both AHC's. No indications.

Core Spray Piping l980's to VT-1/VT-3 I EB 80-13 examinations of piping and 1995 welds in annulus. Three(3) indications identified in Fall 1995 outage by EVT-1.

No repair required.

UT Spring 1997 UT examinations of CS P8a and P8b(REl 7) welds. Indications on one P8a and one P8b weld (first discovery). Evaluated as EVT-1 acceptable.

EVT-1 examinations on balance of piping.

UT Fall 1998 (RE18) UT examinations on the P8a and P8b EVT-1 indications were re-examined.

(7-41) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Balance examined by EVT-1. No visual UT indications.

Spring 2000 (RE19) UT examinations on P8a and P8b welds EVT-1 with indications. No repair required.

EVT-1 of P3, P4, PS, P6, and P7 welds. No UT visual indications.

Fall 2001 (RE20) UT examinations on P3's, three (3) P4's, PS's, P6's, P7's, P8a's and P8b's. EVT EVT-1 examinations of thirty-one of the CS piping welds.

EVT-1 examinations on fifteen {15)

UT welds. Indications re-examined on P8a Spring 2003 weld and P8b welds.

(RE21)

UT examinations on all P8a and P8b welds. Identified three (3) flaw EVT-1 indications on one P8b weld and one (1) flaw indication on one P8a weld. No change in length.

EVT-1 examinations on both junction box EVT-1 covers and accessible portions of both Spring 2005 Pl's, 2 - P2's, 4 - P3's, 1-P4a, 1-P4b, 1-(RE22) P4c, 1-P4d. EVT-1 all P8a and P8b welds.

No indications.

EVT-1 examinations of both Pl's. The examination revealed that the Pl weld is not a creviced weld based on the presence of an external weld on the tee UT box near the nozzle thermal sleeve. EVT-Fall 2006 1 examinations were performed on both (RE23) P2 welds, the four (4) P3 welds, the 4a -

EVT-1 4d welds at 190°, the PS's, P6's, and P7's, the four (4) P8a's, and four (4) P8b's.

UT examinations of P8b welds. Previous EVT-1 indications showed no change in size.

(7-42) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Spring 2008 (RE24) EVT-1 examinations of piping welds and bracket attachment welds. No new relevant indications observed.

EVT-1 EVT-1 of indication near Pl at 90°. No Fall 2QQg change. EVT-1 of Pl at 270°. EVT-1 of (RE25) P2's and P3's at 90° and 270°. EVT-1 of P4a, -b, -c, and -d at 170° EVT-1 of PS's, P61 s, and P7's at 10°, 170°,

190°, and 350°.

EVT-1 examinations near Plwelds at 90° and 270°. No change with the indication UT near the Pl at go (Loop A). EVT-1 0

examinations of the four (4) P3, PS, P6 and P7 welds, EVT-1 examinations of downcomer welds P4a, P4b, P4c, and P4d at 10°. EVT-1 examinations of four EVT-1 (4) P8a and P8b welds. No change with Spring 2011 visual indication of P8b at 10°.

(RE26)

UT performed on all four (4) P8a and P8b welds. Previously identified indications on the P8a at 190° (Loop B) and the P8b at 10° (Loop A) did not show any change.

EVT-1 of area and indication adjacent to Plweld at 90° (Loop A). No change to the indication.

EVT-1 Fall 2012 EVT-1 of area adjacent to Pl weld at (RE27) 270°. No indications.

EVT-1 of the P2 welds at 90° and 270°.

EVT-1 of the four (4) P3, PS, P6, and P7 welds. EVT-1 of downcomer welds P4a, P4b, P4c, and P4d at 190°. No indications.

EVT-1 of area and indication adjacent to Pl weld at go on A Loop. No change to 0

(7-43) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections the indication.

EVT-1 of the P2, P3a, & P3b @ 90°. EVT-1 of PS, P6, & P7@ 10° & 170°. No indications.

UT EVT-1 of area adjacent to Pl weld at 270° on B Loop. No indications.

EVT-1 of the P2, P3a, & P3b welds at 270°. EVT-1 of PS, P6, and P7 welds@

190° & 350°. EVT-1 of downcomer welds EVT-1 P4a, P4b, P4c, and P4d @ 350°. No Fall 2014 indications.

(RE28)

Loops A & B, EVT-1 of the bracket attachment welds PB @ 30°, 150°, 210°,

and 330°. No indications.

UT performed on all four (4) P8a and P8b welds. Previously identified indications on the P8a at 190° (Loop B) and the P8b at 10° (Loop A) did not show any change.

Loop A EVT-1 EVT-1 of area and indication adjacent to Fall 2016 Plweld at 90° on A Loop. No change to (RE29) the indication.

EVT-1 of the P2, P3a & P3b welds@ 90°.

EVT-1 of PS, P6, & P7@ 10° & 170°.

EVT-1 of downcomer welds P4a, P4b, P4c, and P4d@ 170°. No indications observed.

Loop B EVT-1 of area adjacent to Pl weld at 270°. EVT-1 of the P2, P3a, & P3b welds at 270°. EVT-1 of PS, P6, and P7 welds@

190° & 350°. No indications observed.

(7-44) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Loop A EVT-1 of area and indication adjacent to Plweld at 90° on A Loop. No change to the indication.

EVT-1 of downcomer welds P4a, P4b, P4c, and P4d at 10°. No indications.

EVT-1 of two (2) P8a and two (2) P8b welds at 10° and 170°. No change with visual indication of P8b at 10°.

Loop B EVT-1 of two (2) P8a and two (2) P8b welds at 190° and 350°. No indications.

Core Spray Sparger 1980's to VT-1/UT IEB 80-13 of welds on sparger. No 1995 indications.

EVT-1 Spring 1997 EVT-1 examinations of sparger welds and (REl 7) brackets per BWRVIP-18. Debris (wire) in C-sparger Nozzle 15C identified. No EVT-1 other indications.

Fall 1998 (RE18) EVT-1 examinations of sparger welds and brackets inspected in accordance with BWRVIP-18. Debris (wire) in C-sparger EVT-1 Nozzle lSC was reconfirmed. No other Spring 2000 indications.

(RE19)

EVT-1 examinations of sparger and VT-1 brackets. Five (5) indications evaluated Fall 2001 as acceptable.

(RE20)

EVT-1 VT-1 of 25% of S3a, S3b, and S3c welds.

No indications.

VT-1 Spring 2003 EVT-1 examinations of all Sl, S2, and S4 (RE21) welds examined with no indications.

EVT-1 VT-1 of 25% of S3a & S3b's and all bracket welds. No indications.

N/A EVT-1 examinations of two Sl's, two (7-45) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Spring 2005 52',s, both XTRW welds near t-boxes, and (RE22) four (4) 54 welds. No indications.

VT-1 Fall 2006 Sparger examinations deferred to fall (RE23) 2006 (RE23).

EVT-1 VT-1 on 50% of the 53a, 53b, and 53c welds and 100% on sparger brackets. No VT-1 indications.

Spring 2008 (RE24} EVT-1 on 100% of Sl's and 52's and 54's.

No indications.

EVT-1 VT-1 on 25% of the 53a, 53b, and 53c welds. VT-1 of SB's at 90°, 92°, 119°,

149°, 210°, 241 ° and 268°.

VT-1 EVT-1 examinations of Sl's and 52's at Fall 2009 170° and 190°. EVT-1 examinations of (RE25) 53a, 53b at 92° to 269°. EVT-1 examinations of 53c at 99°. EVT-1 EVT-1 examinations of 54's at 91 ° and 269°.

VT-1 on 25% of the 53a, 53b, and 53c welds. VT-1 of SB's at 272°, 299°, 30°,

VT-1 329°, 61 °, 88° and 270°.

Spring 2011 (RE26} EVT-1 examinations of 51 and 52 and at 10° and 350°. EVT-1 examinations of EVT-1 two (2) additional welds near the 350° tee-box 52 welds.

VT-1 on 25% of the 53a, 53b, and 53c welds. VT-1 of sparger brackets at 90°,

92°, 119°, 149.5°, 210.5°, 241 ° and 268°.

EVT-1 No indications.

Fall 2012 (RE27) EVT-1 on C Sparger, 51@ 170°, 52@

168° & 172°, 54@ 91 ° & 269°. No indications.

EVT-1 on D Sparger, 51@ 190°, 52@

(7-46) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections 188° & 192°, S4 @ 91 ° & 269°. No VT-1 indications.

EVT-1 on A sparger, Sl@ 10, S2@ 8° &

12°, and S4@ 89° & 271°. No indications.

EVT-1 EVT-1 on B sparger, Sl @ 350°, S2 @

Fall 2014 348° & 352°, XTRW welds near T-box @

(RE28) 346° & 354°, and S4@ 89° & 271 °. No indications.

VT-1 on the B sparger, S3a & S3b@ 271°-

890 and S3c @ 279°. No indications.

VT-1 VT-1 of the sparger brackets at 30.5°,

61 °, 88°, 270°, 272°, 299°, and 329.5°.

No indications.

EVT-1 on C Sparger, Sl@ 170°, S2@

168° & 172°, S4@ 91° & 269°. No indications observed.

EVT-1 on D Sparger, Sl @ 190°, S2 @

188° & 192°, S4's@ 91 ° & 269°. No indications observed.

VT-1 on 25% of the S3a, S3b, and S3c welds. VT-1 of sparger brackets (SB) at 90°, 92°, 119°, 149.5°, 210.5°, 241 ° and 268°. No indications observed.

Top Guide (Rim, 1991-1995 VT VT of top guide beams of fifty {SO) cells etc.) was performed in 1991 per RICSIL 059.

No indications. VT exams of the members in the load path between the top guide and core shroud in 1995 per SIL 588. One {1) indication on the 90° aligner pin keeper was observed and evaluated as acceptable (indication not on load bearing portion of assembly).

Spring 1997 VT-1 (7-47) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections (REl 7) VT-1 re-examination of Top Guide Aligner Pin located at 90° in accordance with SIL 588, Rl. Indication on aligner pin keeper did not appear to change in size.

Spring 2000 VT-1 (RE19) VT-1 of two (2) hold down assemblies.

No indications.

Fall 2001 VT-1 (RE20) VT-1 of two (2) horizontal aligner pins with no new indications. VT-1 of four (4) hold down assemblies.

EVT-1 EVT-1 examinations of accessible areas of the Rim weld.

Fall 2006 VT-1 (RE23) VT-1 on two (2) hold down assemblies and aligner pin assemblies at 90° and 270°. A previous indication identified on the non-load bearing keeper of the aligner pin assembly at the 90° location was observed with no apparent change.

However, two (2) new but similar type indications were also observed on the same keeper. Three (3) new indications were observed on the non-load bearing VT-3 aligner pin keeper at the 270° location.

Indications were evaluated as acceptable.

Spring 2008 VT-1 (RE24) VT-3 examinations performed on accessible areas of top guide per B-N-2.

No indications.

VT-1 examinations performed on hold EVT-1 down and aligner assemblies at O and 180°. One (1) new indication identified on non-structural keeper at 180°. Similar VT-3 to indications in keepers seen at 90° and 270°. Evaluated as acceptable.

Fall 2009 VT-1 EVT-1 examinations of accessible areas (RE25) of rim weld.

{7-48) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections VT-3 examinations performed of EVT-1 accessible top guide hold down assemblies, rim pins per B-N-2.

VT-1 examinations performed on hold down and aligner assemblies at 90°. No VT-3 change in the indication atthe 90° aligner pin keeper.

Spring 2011 VT-3 EVT-1 examinations of 10% or fourteen (RE26) (14) of top guide grid beams per BWRVIP-183. No indications. However, VT-1 only eight (8) were credited as quality examinations.

VT-3 examinations of accessible areas of top guide per B-N-2.

VT-3 of accessible areas of Top Guide per B-N-2. No indications.

VT-1 for BWRVIP-26 credit was performed on the Hold Down assemblies and Aligner Pin assemblies at 270°. An indication not previously reported was observed adjacent to the attachment weld adjoining the Aligner Block to the Top Guide. Indication appears to be a manufacturing remnant that was not completely removed during construction.

Previously identified indications were also observed with no changes.

Scope was expanded to include the remaining other three (3) Aligner Pin assemblies located at 0°, 90°, and 180°.

VT-3 for Sect XI B-N-2 and VT-1 for BWRVIP-26 credit was performed.

Aligner Pin assembly at 0° was found to have seven (7) previously unidentified indications, with four (4) identified in the (7-49) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Aligner Pin Keeper and three (3) identified in the Aligner Block. Review of previous inspection video showed faint presence of indications. Evaluated as acceptable.

Aligner Pin assembly at 90° was found to have one (1) previously unidentified EVT-1 indication located on the Aligner Pin Keeper. Review of previous inspection video showed a faint presence of the indication. Three (3) previously identified indications were also observed with no changes. Evaluated as Fall 2012 VT-1 acceptable.

(RE27)

Aligner Pin assembly at 180° was found VT-1 to have two (2) previously unidentified indications located on the Aligner Pin Keeper. Review of previous inspection video shows presence of indications.

Three (3) previously identified indications were also observed with no changes.

Evaluated as acceptable.

EVT-1 examinations of accessible areas of the Rim we!d.

EVT-1 of two (2) top guide cell locations per BWRVIP-183. No indications.

VT-1 examinations performed on hold down assembly at 180°. No indications.

VT-1 of the aligner pin assembly at 0° was performed to confirm seven (7) flaws identified in RE26. Four (4) of the flaws on the keeper were confirmed and verified to have no changes. One (1) flaw on the aligner pin block was confirmed and verified to have no changes. The two (2) other previously identified flaws (7-50) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections on the block were determined to be non-relevant surface scratches.

VT-1 of the aligner pin assembly at 90° was performed to confirm seven (7) flaws identified on the keeper in RE26. 4 of the flaws were confirmed and verified to have no changes. One (1) additional Fall 2014 EVT-1 flaw on the keeper was also reported.

(RE28) This flaw is similar to flaws seen on the other aligner pin keepers, but could not VT-1 be verified in previous video due to camera positioning.

VT-1 of the aligner pin assembly at 180° was performed to confirm three (3) flaws identified in RE26. All of the flaws on the keeper were confirmed and verified to have no changes.

VT-1 of the aligner pin assembly at 270° was performed to confirm four (4) flaws identified in RE26. Three (3) of the flaws on the keeper were confirmed and verified to have no changes. One (1) previously reported flaw adjacent the aligner block to top guide weld was examined using an improved camera and delivery mechanism and determined to be a non-relevant surface scratch.

EVT-1 examinations of accessible areas of Rim weld. No indications.

VT-1 examinations performed on accessible top portion of the top guide hold down assembly at 0°. No indications.

(7-51) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections VT-1 of the aligner pin assembly at 0° was performed to confirm five (5) previously identified flaws. Four (4) flaws on the keeper were confirmed to have no changes. The identified flaw on the aligner pin block showed slight Fall 2016 EVT-1 increase in length.

(RE29)

VT-1 of the aligner pin assembly at 90° was performed to confirm five (5) previously identified flaws. The 5 flaws on the keeper were confirmed to have no changes. Five (5) unreported flaws on VT-1 the aligner block were detected.

VT-1 of the aligner pin assembly at 180° VT-1/EVT-1 was performed to confirm three (3) previously identified flaws. The three flaws on the Keeper were confirmed to have no change. Five (5) unreported flaws on the aligner block and two (2) on the top guide were detected.

VT-1 of the aligner pin assembly at 270° was performed to confirm three (3) previously identified flaws. The three (3) flaws on the keeper were confirmed and verified to have no changes. One (1) unreported flaw on the aligner block and one (1) on the top guide were detected.

EVT-1 of beams near impact site of dropped control rod blade. (Ref OE 313327). No crack indications identified.

EVT-1 of five (5) of top guide grid beams per BWRVIP-183. No indications.

EVT-1 of beams near impact site of dropped control rod blade. (Ref OE (7-52) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections 313327). No indications identified.

VT-1 of accessible top portion of the TG hold down assembly at 90°. No indications.

VT-1 and EVT-1 of aligner pin assembly at 0° confirmed five (5) previously identified flaws. All flaws showed no changes, except for Flaw 6 on the keeper which appeared longer compared to previous examination but difference was attributed to improved tooling and lighting.

VT-1 and EVT-1 of aligner pin assembly at 90° confirmed ten {10) previously identified flaws on the keeper and block.

All flaws showed no changes except for, Flaw 5 (keeper) and 10 (block) which appeared longer compared to previous exam with difference attributed to improved tooling an lighting.

VT-1 and EVT-1 of aligner pin assembly at 180° confirmed nine (9) previously identified flaws. All flaws showed no changes, except for Flaws 2 and 3 on keeper which appear longer compared to previous exam with difference attributed to improved tooling and lighting. One (1) new flaw was reported on the block to slider weld that was later confirmed to be present in the previous exam. Change attributed to improved tooling and lighting.

VT-1 and EVT-1 of aligner pin assembly at 270° confirmed five (5) previously identified flaws that showed no changes.

One (1) new flaw reported on keeper to washer weld that was later confirmed be present in the previous exam.

(7-53) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Core Plate (Rim, Fall 1995 VT-3 VT-3 examinations of hold down bolts etc.) examined in 1995 per SIL 588. No indications.

Spring 2000 VT-3*

(RE19) VT-3 examinations of 48 bolts examined from top side.

• (Bolts are not accessible for EVT-1)

Fall 2001 to VT-3 Fall 2009 VT-3 examinations performed on (RE20- RE26) accessible areas per B-N-2. No indications.

Fall 2012 VT-3 (RE27)

VT-3 examination of three (3) hold down bolt locations (70, 71, and 72) from the top side. No indications.

Fall 2014 VT-3 VT-3 exam of 36 (50%) hold down bolt locations from the top side. No indications.

SLC 1986-2001 VT-2 VT-2 examinations of SLC penetration during Class 1 RPV pressure test each outage.

Spring 2003 EVT-2 (RE21) Enhanced VT-2 examinations during Class 1 pressure test. No indications.

Spring 2005 EVT-2/UT (RE22) Enhanced VT-2 performed of safe-end and penetration in conjunction with ASME Section XI Class I pressure test.

Manual UT to Appendix VIII performed on nozzle to safe-end weld. No Fall 2006 EVT-2 indications.

(RE23)

Enhanced VT-2 examinations of safe-end and penetration performed in conjunction with ASME Section XI Class I Spring 2008 EVT-2 system leakage test. No indications.

(RE24)

Enhanced VT-2 examinations performed (7-54) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections of safe-end and penetration in conjunction with ASME Section XI Class I system leakage test. No indications.

Fall 2009 EVT-2 (RE25)

Enhanced VT-2 examinations of safe-end and penetration performed in conjunction with ASME Section XI Class I Spring 2011 EVT-2 system leakage test. No indications.

(RE26)

Enhanced VT-2 examinations of safe-end and penetration performed in conjunction with ASME Section XI Class I system leakage test. No indications.

Fall 2012 UT (RE27) UT examination of NlO SLC nozzle to safe-end per Risk-Informed ISi Program and Appendix VIII. No indications.

EVT-2 Enhanced VT-2 examinations of safe-end and penetration performed in conjunction with ASME Section XI Class I system leakage test.

Fall 2014 EVT-2 No indications.

(RE28)

Enhanced VT-2 examinations of safe-end and penetration performed in conjunction with ASME Section XI Class I system leakage test.

No indications.

Jet Pump Assembly 1986-1995 VT-1/VT-3/ VT examinations on ten (10) Jet Pumps UT each outage. Exam includes applicable GE SILS. Jet pump beams replaced in 1985. Jet pump beam UT first performed in 1993.

Spring 1997 VT-1/VT-3 (REl 7) Ten (10) jet pumps VT examined. Exam includes applicable GE Slls. No Fall 1998 VT -1/VT-3 indications.

(RE18)

Ten (10} jet pumps VT examined. Exam (7-55) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Spring 2000 N/A includes applicable GE SILs. No (RE19) indications.

Fall 2001 VT-3 Examinations deferred to Fall 2001.

(RE20)

VT-1 VT-3 examinations on all 20 jet pump nozzle inlets per SIL 465. No indications.

EVT-1 VT-1 examinations on all WD-l's. No indications.

EVT-1 examinations on BB-1 and BB-2 on JP's 1-10. EVT-1 on MX-2's on JP's 1-

10. EVT-1 on RB-l's and RB-2's on JP's 1/2, 3/4, and 5/6. No indications. EVT-1 on RS-l's, RS-2's, and RS-3's on JP's 1-Spring 2003 VT-3 10. EVT-1 on RS-6's on JP's 1, 3, and 5.

(RE21) EVT-1 on RS-7's on JP's 2, 4, and 6. EVT-1 on RS-8's and RS-9's on JP's 1/2, 3/4, and 5/6. No indications.

EVT-1 VT-3 examinations on the JP nozzle inlet mixers on JP's 11 - 20 per SIL 465. VT-3 examinations of set screws, gaps, and tack welds on JP's 1 - 20 per SIL 574. No indications.

EVT-1 examinations on the IN-4 on JP's 5, 6, 11, 12, 13, and 14. EVT-1 examinations on the MX-2 on JP's 11, 12, 13, and 14.

UT EVT-1 examinations on the RB-l's and RB-2's, on JP's 11/12 and 13/14. EVT-1 examinations on RS-1 and RS-2 on JP's Spring 2005 VT-3 11/12, 13/14, 15/16, and 17/18; RS-6 on (RE22) JP's 11 and 13; RS-7's on JP's 12 and 14; RS-8's and RS-9's on JP's 11/12 13/14.

VT-1 No indications.

UT examinations on the BB-l's and BB-2's for JP's 1 - 20. No indications.

EVT-1 (7-56) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections VT-3 on the JP nozzle inlet mixers on JP s 1 - 10 per SIL 465. No indications.

Fall 2006 VT-1 VT-1 examinations on JP set screws, gaps (RE23) and tack welds on JP's 1, 2, 15, and 16 per SIL 574. No indications.

EVT-1 EVT-1 examinations on RS-1, RS-2, and RS-3 welds on JP's 1 and 2 and the IN-4 Spring 2008 EVT-1 welds on JP's 7, 8, 9, and 10. No (RE24) indications.

VT-1 per SIL 574 of adjustment screw and gap and tack welds on JPs 9 10. VT-1 of WD-1 at JP's 9 10. No indications.

EVT-1 of RS-1 and RS-2 on JP's 15/16 and 19/20.

EVT-1 examinations of IN-4's at JP's 19 UT and 20. EVT-1 examinations of RB-la's, -

lb's, -lc's, and -ld's between JP's 9/10 and 19/20. EVT-1 examinations of RB-2a's, -2b's, -2c's, and -2d's between JP's 9/10 and 19/20. EVT-1 examination of Fall 2009 VT-3 RS-3 between JP's 19/20. EVT-1

/DC'lC:\

\r\LLJ/ examinations of RS-6 at JP's 9 and 19.

EVT-1 examination of RS-7 at JP's 10 and VT-1 20. EVT-1 examinations of RS-8 and RS-9 at JP's 19/20 and 9/10. No indications.

UT of BB-1, -2 and -3 on all 20 JP beams.

EVT-1 No indications. UT of MX-2 (and AD-1, AD-2, DF-1, DF-2, DF-3 note in Diffuser Section) on all 20 jet pumps.

VT-3 of JP nozzle inlets per SIL 465 on JP's 15, 16, 17 and 18. No indications.

VT-1 per SIL 574 of adjustment screw and gap and tack welds on JPs 10, 15, 16, 19, and 20. VT-1 of WD-1 atJP's 17 and 18.

(7-57) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections No indications.

Spring 2011 VT-3 (RE26) EVT-1 examinations of IN-4 on JP's 15, 16, 17, and 18. EVT-1 examinations of VT-1 RB-l's and RB-2's on JP's 7/8, 15/16, and 17/18. EVT-1 examinations on RS-l's and RS-2's on JP's 11/12 and 17/18. EVT-1 examinations on RS-3's on JP's 11/12, EVT-1 15/16, and 17/18. EVT-1 examinations on RS-6's on JP's 7, 15, and 17 and RS-7's on JP's 8, 16, and 18. EVT-1 examinations on RS-8's and RS-9's on JP's 7/8, 15/16, and 17/18. No indications.

VT-3 of JP nozzle inlets on JP 9 and 10.

No indications.

VT-1 of the JP Restrainer Wedge (WD-1)

Fall 2012 EVT-1 at JP-1 thru JP-20. No indications of (RE27) movement or wear observed.

EVT-1 of RS-8 and RS-9 on JP-1 thru JP-14, JP-19, and JP-20. No indications.

EVT-1 of JP-9 and JP-lO's IN-4, RB-la, RB-lb, RB-le, RB-ld, RB-2a, RB-2b, RB-2c, J:\/T_1 nf Jp_Q 1c PJL'Jrl I 'U PC_':l pc;:_1 QC_")

L. U / I ,-.., _, / I ,__, i , I ,.._, ,_ * '- V I ..L "-' I J 1* J .J VT-1 RS-6 and JP-l0's RS-7. No indications.

EVT-1 of JP-7 and JP-8 s RS-3. No 1

indications.

EVT-1 of JP-13 and JP-14's IN-4, RB-la, RB-lb, RB-le, RB-ld, RB-2a, RB-2b, RB-2c, RB-2d, RS-1, RS-2, & RS-3. EVT-1 of RS-6 on JP-13 and RS-7 on JP-14. No indications.

EVT-1 of JP-7 and JP-8's RS-3. No indications.

EVT-1 of JP-15 and 16's RS-3. No (7-58) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections indications.

VT-3 VT-1 of the JP Restrainer Wedge (WD-1) at JP-1, 2, 9, 10, 13, 14, 15, 16, 19, & 20.

Fall 2014 EVT-1 No indications of movement or wear (RE28) observed.

VT-1 of the JP-15 set screw gaps and slip joint. Previously identified shroud side gap was found to have an increase of 0.003 11 with no signs of movement.

Vessel side set screw confirmed to have VT-1 partial contact. No indications on slip joint.

VT-1 of the JP-20 set screw gaps and slip joint. Previously identified shroud side gap was found to have an increase of

.004 11 with no signs of movement. Newly reported vessel side set screw gap measured to be .013 No indications on 11 slip joint.

VT-3 of JP nozzle inlets on JP-13 and 14.

VT-3 No indications.

EVT-1 of MX-2 on Jet Pumps 1, 2, 8, 9, &

Fall 2016 EVT-1 10. No Indications.

(RE29)

EVT-1 of JP-1 and JP-2 s IN-4, RB-la, RB-1 lb, RB-le, RB-ld, RB-2a, RB-2b, RB-2c, RB-2d, RS-1, RS-2, RS-3, RS-6 on JP-1 and RS-7 on JP-2. No indications.

VT-1 of the JP Restrainer Wedge (WD-1) at JP-1 thru JP-20. No indications of movement or wear observed.

VT-1 VT-1 of the set screws and auxiliary wedges on Jet Pump 1, 2, 9, &10. JP10 had a previously identified shroud side gap that was found to be 0.011 with no 1 signs of movement. JPs 1, 2, and 9 set (7-59) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections screws and aux wedges were found to be VT-3 in full contact with no signs of wear.

VT-3 of JP nozzle inlets on JP-1 and 2. No indications.

EVT-1 of MX-2 and IN-4 on JP-6. No indications.

EVT-1 of RS-1, RS-2, and RS-3 on JP-3&JP-4 and RS-1 and RS-2 on JP-7&JP-8. No indications.

EVT-1 of JP-S&JP-6 s RB-la, RB-lb, RB-le, 1

RB-ld, RB-2a, RB-2b, RB-2c, RB-2d, RS-1, RS-2, RS-3, RS-6, RS-7, RS-8, and RS-9.

No indications.

VT-1 of set screw gaps and slip joints on JP-15 and JP-20. No indications.

VT-1 of the JP Restrainer Wedge (WD-1) at JP-5 and JP-6. No indications.

VT-3 of JP nozzle inlets on JP-6. No indications.

Jet Pump Diffuser 1986-1998 VT-3 10 Jet Pumps VT-3 examined each outage. No indications. No indications.

Spring 1997 VT-1/VT-3 Ten jet pumps VT examined. Exam (REl 7) includes applicable GE Slls. No indications.

Fall 1998 VT-1/VT-3 (RE18) VT examinations on ten (10) jet pumps.

Exam includes applicable GE SI Ls. No Spring 2000 N/A indications.

(RE19}

Exams deferred to Fall 2001.

Fall 2001 EVT-1 (RE20)

EVT-1 examinations on ten (10) jet (7-60) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections pumps (5 assemblies). Identified an indication thought to be a broken jet Spring 2003 VT-3 pump sensing line upper bracket (RE21) retaining weld. Evaluated as acceptable.

VT-1 VT-3 on JP sensing lines for all jet pumps per SIL 420. No indications.

VT-1 on sensing line brackets for all jet pumps per SIL 420. Previously reported EVT-1 cracked bracket weld was determined not to be cracked. No indications.

Spring 2005 VT-3 EVT-1 examinations of AD-1, AD-2, AD-(RE22) 3a, AD-3b welds on JP's 11 through 20.

No indications.

VT-1 VT-3 on JP sensing lines for JP's 1 - 11 and 14 per SIL 420. No indications.

Fall 2006 EVT-1 (RE23) VT-1 on JP sensing line brackets for JP's 1- 11 and 14. No indications.

EVT- 1 on AD-1 on JP's 1, 2, and 5. EVT-1 examinations on AD-2, AD-3a, AD-3b, DF-Spring 2008 UT 1 on (RE24)

JP-15, 16, 17, 18, 19, and 20 and DF-2 on EVT-1 JP's 15, 16, 19, and 20. No indications.

UT on AD-1, AD-2, DF-1, DF-2, and DF-3 (and MX-2). One (1) indication on DF-1 Fall 2009 EVT-1 at JP-14.

(RE25)

EVT-1 examinations on DF-1 at JP-14 in addition to UT. Appeared to be a defect Spring 2011 EVT-1 from original construction.

(RE26)

EVT-1 examinations of indication to DF-1 on JP-14 identified during the previous Fall 2012 EVT-1 outage. No change.

(RE27)

(7-61) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections EVT-1 re-examination of indication located on the inside surface of JP-14 at Fall 2014 EVT-1 the DF-1 weld. Indication was found to (RE28) have no changes.

EVT-1 re-examination of indication located on the inside surface of JP-14 at the DF-1 weld. Indication did not Fall 2016 EVT-1 change.

(RE29)

EVT-1 of AD-1, AD-2, AD-3a, AD-3b, DF-1, DF-2 on Jet Pumps 1, 2, 8, 9, & 10. No Indications. EVT-1 re-examination of indication located on the inside surface of JP-14 at the DF-1 weld. Indication did not change.

EVT-1 of AD-1, AD-2, AD-3a, AD-3b, DF-2 on Jet Pumps 3, 4, 5, 6, & 7. No indications.

EVT-1 of DF-1 (outside diameter) on Jet Pumps 6 and 14. No indications.

EVT-1 of DF-1 (inside diameter) for re-examination of indication on the inside surface of JP-14. Indication showed no change.

r . . : , . . L..-

rnr.

\-1"\U \:JUIUt:: I UUt:: Fall 1995 \/T VI

-_, VT-3 exams of accessible guide tubes.

No indications.

Spring 1997 VT-3 VT-3 exams of accessible guide tubes.

(REl 7) No indications.

Fall 1998 VT-3 VT-3 exams of accessible guide tubes.

(RE18) No indications.

Spring 2000 VT-3 VT-3 examinations of eighteen (18) anti-(RE19) rotation pins and eleven (11) CRGT-1 welds. No indications.

EVT-1 EVT-1 examinations of four (4) CRGT-2 (7-62) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections and CRGT-3 welds. No indications.

Fall 2001 VT-3 VT-3 examinations of thirteen (13) anti-(RE20) rotation pins and thirteen (13) CRGT-1 welds. No indications.

EVT-1 EVT-1 examinations of five (5) CRGT-2 and CRGT-3 welds. No indications.

Spring 2005 EVT-1 EVT-1 examinations of one (1) CRGT-2 (RE22) weld and one (1) CRGT-3 weld. No indications.

Fall 2006 EVT-1 (RE23) EVT-1 examinations of one (1) CRGT-2 weld and one (1) CRGT-3 weld. No Spring 2008 EVT-1 indications.

(RE24)

EVT-1 examinations of two (2) CRGT-2 Fall 2009 EVT-1 welds and three (3) CRGT-3 welds. No (RE25) indications.

EVT-1 examinations on one (1) CRGT-2 weld and two (2) CRGT-3 welds. No indications.

CRD Stub Tube 1\1 / A l'IJ/ /-\ N/A No record of examination.

In-core Housing NA NA No record of examination back to 1996.

Dry Tube 1989-1991 VT VT exam in 1989, 1990, and 1991 per SIL 409Rl. All dry tubes replaced in 1993.

Spring 2005 VT Replaced one (1) dry tube.

(RE22)

Fall 2012 VT-1 VT-1 was performed on dry tube (RE27) locations at 12-09 and 28-25. No indications.

Fall 2014 VT-1 (RE28) VT-1 performed on IRM dry tube (7-63) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections locations at 20-25 and 36-41. No indication observed. Replaced IRM dry Fall 2016 VT-1 tube at 12-41.

(RE29)

VT-1 on Dry Tube Locations. IRM 28-33

& 36-09 and SRM 12-33, 20-17, & 36-25.

No indications.

Instrument 1986-2000 VT-2 VT-2 examination performed during RPV Penetrations system leakage test each outage for all six (6) instrument nozzle penetrations.

No indications.

Spring 2000 PT (RE19) PT examination of N16A instrument penetration nozzle to safe-end weld.

Fall 2001 VT-2 (RE20) VT-2 examination performed during RPV system leakage test. No indications.

Spring 2003 VT-2 (RE21) VT-2 examination performed during RPV system leakage test. No indications.

Spring 2005 VT-2 (RE22) VT-2 examination performed during RPV system leakage test. No indications.

UT UT examination of N16B nozzle to safe-end per Risk-Informed ISi Program and Appendix VIII. No indications.

Fall 2006 VT-2 (RE23) VT-2 examination performed during RPV system leakage test. No indications.

Spring 2008 VT-2 (RE24) VT-2 examination performed during RPV system leakage test. No indications.

Fall 2009 VT-2 (RE25) VT-2 examination performed during RPV system leakage test. No indications.

Spring 2011 VT-2 (RE26) VT-2 examination performed during RPV system leakage test. No indications.

Fall 2012 VT-2 (RE27) VT-2 examination performed during RPV system leakage test. No indications.

(7-64) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Fall 2014 UT (RE28) UT examination of N16B nozzle to safe-end per Risk-Informed ISi Program and Appendix VIII. No indications.

VT-2 VT-2 examination performed during RPV system leakage test. No indications.

Fall 2016 VT-2 (RE29) VT-2 examination performed during RPV system leakage test. No indications.

Vessel ID Brackets 1986-1995 VT-1/VT-3 ASME XI VT-3 (non-beltline) and VT-1 (beltline examinations) of jet pump riser brace, dryer, FW Sparger, Core Spray, guide rod, and surveillance capsule holder brackets performed once per interval. No indications.

Spring 1997 VT-1/VT-3 (RE17) VT-1/VT-3 ASME Section XI examinations on five (5) jet pump riser brackets, FW brackets and welds examined. No Fall 1998 VT-1/VT-3 indications.

(RE18)

VT-1/VT-3 ASME Section XI examinations on five (5) jet pump riser brackets, FW EVT-1 brackets and welds examined. No indications.

Spring 2000 VT-3 EVT-1 examinations on four (4) CS (RE19) bracket attachment welds. No indications.

VT-1 VT-3 examinations of guide rod EVT-1 attachment welds. No indications.

VT-1 on FW sparger brackets. No Fall 2001 EVT-1 indications.

(RE20)

EVT-1 examinations on CS bracket attachment welds. No indications.

Spring 2003 EVT-1 (RE21) EVT-1 examinations on all FW sparger bracket attachment welds and all dryer (7-65) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections Spring 2005 VT-3 support attachment welds. No (RE22) indications.

Fall 2006 EVT-1 EVT-1 examination of on JP riser brace (RE23) pad attachment weld at 150°. No indications.

Spring 2008 VT-3 VT-3 examination of steam dryer hold (RE24) down brackets.

EVT-1 EVT-1 of eight (8) FW sparger brackets and four (4) CS piping bracket attachment welds. No indications.

VT-3 of guide rod attachment welds. No indications.

Fall 2009 EVT-1 (RE25) EVT-1 examinations of JP riser brace pad attachment welds at 30°, 150°, 210°,

270°, and 330°. EVT-1 examinations of Spring 2011 EVT-1 steam dryer support bracket attachment (RE26) welds at 215° and 325°. No indications.

Fall 2012 EVT-1 EVT-1 examinations of JP riser brace pad (RE27) attachment welds at 60°, 90°, and 120°.

No indications.

EVT-1 of the JP riser brace pad attachment welds, JP-RBPAD-ATTWLDS

@ 30°. No Indications.

EVT-1 of four (4) CS piping bracket attachment welds at 30°, 150°, 210°, and 330°. No indications.

VT-1 EVT-1/VT-1 of JP riser brace pad attachment welds at 270°. No VT-3 indications.

EVT-1/VT-3 of steam dryer support bracket attachment welds at 215° and Fall 2014 EVT-1 325°. No indications.

(7-66) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections (RE28)

VT-1 of surveillance capsule holder EVT-1/VT-3 brackets at 300°. No indications.

VT-3 (direct) examination of steam dryer VT-1 hold down brackets @ 35°, 145°, 215°,

and 325°. No indications.

VT-3 EVT-1 of Riser Brace attachment welds on JP-1 & 2 at 150°. No indications.

EVT-1/VT-3 of steam dryer support Fall 2016 EVT-1 bracket attachment welds at 145° and (RE29) 35°. No indications.

VT-1 of surveillance capsule holder brackets at 30° & 120°. No indications.

VT-3 (direct) examination of steam dryer hold down brackets @ 35°, 145°, 215°,

and 325°. No indications.

EVT-1 of the JP riser brace pad attachment welds, JP-RBPAD-ATTWLDS

@ 90°. No indications.

LPCI Coupling N/A N/A Not applicable to this plant.

Steam Dryer Fall 2001 VT-1 VT-1 of twenty four (24) drain channel (RE20) welds per SIL 474.

Spring 2003 EVT-1 EVT-1 of twenty four (24) drain channel (RE21) welds per SIL 474.

Spring 2005 VT-1 VT-1 of leveling screws per OE 16110.

(RE22)

Fall 2006 VT-1 Performed baseline VT-1 examinations to (RE23) w/Character BWRVIP-139 and SIL 644, Rev 2. Re-Card examined five (5) minor indications previously identified per SIL 474 adjacent to several drain channels. Two (2) new (7-67) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVIP Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections indications were observed in a weld adjacent to a drain channel and both tack welds on one (1) lifting lug were observed. The indications were Fall 2009 VT-1(89) evaluated as acceptable.

{RE25)

VT-1 examinations on seven (7) previously identified indications on dryer.

With additional cleaning, six {6) of the indications disappeared with only one {1) remaining {i.e., the cracked tack welds on Fall 2016 VT-1(89) one {1) lifting lug - no change in the

{RE29) lifting lug).

Performed VT-1 examinations to BWRVIP-139-A. Re-examined one (1) previous indication of cracked tack welds on lifting lug @ 145° with no changes.

The other three (3) lifting lugs were observed to have similar cracked tacks that were not previously reported. Five (5) Tie Rods were reported to be slightly bent with no broken welds. One (1) additional indication was observed on the lower guide bracket weld at 180° that extended into the skirt. The indication was arrested with a 5/8th inch Stop-drill hole. No other dryer indications reported.

Dissimilar metal Spring 2008 UT Automated UT performed on four (4) welds (RE24) CAT A welds per Appendix VIII. Manual UT performed on two (2) CAT A welds.

All welds included in Risk-Informed ISi Program. No indications.

Spring 2011 UT (RE26) Manual UT inspection performed on one (1) CAT D nozzle to cap weld {CRD Return) per Appendix VIII and Risk-Informed ISi Program. No indications.

Fall 2014 UT (RE28) Manual UT inspection performed on three (3). CAT A welds per Appendix VIII.

(7-68) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Component in Date of Inspection Summarize the Following Information:

BWRVI P Scope Frequency of Method Inspection Results, Repairs, Inspection Used Replacements, Re-inspections All welds included in Risk-Informed ISi Program. No indications.

Fall 2016 UT (RE29) Automated Phased Array UT performed on one (1) CAT D weld and manual UT performed on one (1) CAT A weld. Both welds included in Risk-Informed ISi Program. No indications.

(7-69) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C 20555..0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION ALTERNATIVE REQUEST NO. Rl5-02. REVISION 1 FOR THE FIFTH 10-YEAR INTERVAL INSERVICE INSPECTION NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated June 9, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML15167A066), as supplemented by letters dated October 21, 2015 (ADAMS Accession No. ML15301A249) and December 21, 2015 (ADAMS Accession No. ML15364A013), Nebraska Public Power District (the licensee) submitted proposed alternative Request No. Rl5-02 for its fifth 10-year interval inservice inspection (ISi) program plan for its reactor vessel internals (RVI) components at Cooper Nuclear Station (CNS). In this safety evaluation (SE), the term "RVI componentsn includes reactor pressure vessel interior surfaces, attachments, and core support structures. In Request No. Rl5-02, the licensee proposed to use Boiling Water Reactor (BWR) Vessel and Internals Project (BWRVIP) guidelines as an alternative to certain requirements of Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) for ISi of the reactor pressure vessel interior surfaces, attachments, and core support structures. These proposed alternatives were requested for the fifth 10-year ISi interval, which began on April 1, 2016, and will end on February 28, 2026. By letter dated February 17, 2016 (ADAMS Accession No. ML16034A479), the U.S. Nuclear Regulatory Commission (NRC) staff authorized the proposed alternative in Request No. Rl5-02 pursuant to Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.55a(z)(1) on the basis that the alternative provides an acceptable level of quality and safety.

By letter dated August 17, 2017 {ADAMS Accession No. ML17241A048), the licensee submitted proposed alternative Request No. Rl5-02, Revision 1, for its fifth 10-year interval ISi program plan for its RVI components at CNS. Request No. Rl5-02, Revision 1, updates the specified revision of BWRVIP-18 "BWR Core Spray Internals Inspection and Flaw Guidelines, n which was one of the guidelines referenced in Request No. Rl5-02. Request No. Rl5-02, Revision 1, also updated the inspection history to include the fall 2016 refueling outage.

(7-70) Rev 3.0 Enclosure 2

Cooper Station 5th ISi &

3rd Interval CISI Program

2.0 REGULATORY EVALUATION

The ISi of ASME Code Class 1, 2, and 3 components is to be performed in accordance with Section XI of the ASME Code and applicable edition and addenda as required by 10 CFR 50.55a(g ), "Preservice and inservice inspection requirements," except where specific relief has been granted by the NRC pursuant to 10 CFR 50.55a(g)(6)(i), "Impractical ISi requirements: Granting of relief."

Pursuant to 10 CFR 50.55a(z), "Alternatives to codes and standards requirements," alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC if (1) the proposed alternatives would provide an acceptable level of quality and safety or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), "lnservice inspection standards requirements for operating plants," ASME Code Class 1, 2, and 3 components (including supports) must meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI, to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year ISi interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(a)(1 )(ii), 12 months prior to the start of the 120-month interval, subject to the conditions listed in 10 CFR 50.55a(b )(2).

The regulation in 10 CFR 50.55a(g)(4)(iv), "Applicable ISi Code: Use of subsequent Code editions and addenda," states that inservice examination of components and system pressure tests may meet the requirements set forth in subsequent editions and addenda that are incorporated by reference in paragraph 10 CFR 50.55a(a), subject to the limitations and modifications listed in 10 CFR 50.55a(b) and subject to Commission approval. Portions of editions or addenda may be used provided that all related requirements of the respective editions or addenda are met The applicable ASME Code of Record for the fifth 10-year ISi interval for CNS, is the ASME Code,Section XI, 2007 Edition through 2008 Addenda.

3.0 TECHNICAL EVALUATION

3. 1 The Components for Which an Alternative is Requested ASME Code,Section XI, Class 1, Examination Categories B-N-1 and B-N-2, Code Item Nos. B13.10 (Vessel Interior), B13.20 (Interior Attachments within Beltline Region),

B13.30 (Interior Attachments beyond Beltline Region), and B13.40 (Core Support Structure).

3.2 Examination Requirements for Which an Alternative is Requested ASME Code,Section XI, requires the visual examination (VT) of certain RVI components.

These examinations are included in Table IWB-2500-1 , Categories B-N-1 and B-N-2, and identified with the following item numbers:

B13.10 - Examine accessible areas of the reactor vessel interior each period using a technique which meets the requirements for a VT-3 examination, as defined in paragraph IWA-2213 of the ASME Code,Section XI.

(7-71) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program B13.20 - Examine interior attachment welds within the beltline region each interval using a technique which meets the requirements for a VT-1 examination, as defined in paragraph IWA-2211 of the ASME Code,Section XI.

B 13.30 - Examine interior attachment welds beyond the beltline region each interval using a technique which meets the requirements for a VT-3 examination, as defined in paragraph IWA-2213 of the ASME Code,Section XI.

B13.40 - Examine surfaces of the core support structure each interval using a technique which meets the requirements for a VT-3 examination, as defined in paragraph IWA-2213 of the ASME Code,Section XI.

These examinations are performed to assess the structural integrity of the reactor pressure vessel interior surfaces, attachments, and core support structures.

3.3 Licensee's Basis for Requesting an Alternative and Justification for Granting Relief In proposed alternative Request No. Rl5-02, Revision 1, the licensee, in lieu of ASME Code,Section XI requirements, submitted an alternative inspection program per the BWRVIP guidelines for B-N-1 and B-N-2 reactor pressure vessel interior surfaces, attachments, and core support structures at CNS. The licensee stated that implementation of the alternative inspection program will maintain an acceptable level of quality and safety and will avoid duplicate or unnecessary inspections, while conserving radiological dose. The licensee further indicated that the BWRVIP has established reporting protocol for examination results and deviations, and that the NRC has agreed with the BWRVIP approach in principle and has issued SEs for many of these guidelines.

The licensee proposed to examine the CNS RVI components in accordance with the following BWRVIP guidelines:

• BWRVIP-03, Revision 17, "BWR Vessel and Internals Project Reactor Pressure Vessel and !ntema!s Examination Guidelines"

• BWRVIP-18, Revision 2-A, "BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines"

• BWRVIP-25, "BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines"

• BWRVIP-26-A, "BWR Vessel and Internals Project, BWR Top Guide Inspection and Flaw Evaluation Guidelines"

• BWRVIP-27-A, "BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core Plate ~P Inspection and Flaw Evaluation Guidelines"

• BWRVIP-38, "BWR Vessel and Internals Project, BWR Shroud Support Inspection and Flaw Evaluation Guidelines" (7-72) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program

• BWRVIP-41, Revision 3, "BWR Vessel and Internals Project, BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines"

• BWRVIP-47-A, "BWR Vessel and Internals Project, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines"

• BWRVIP-48-A, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines"

• BWRVIP-76, Revision 1-A, "BWR Vessel and Internals Project, BWR Core Shroud Inspection and Flaw Evaluation Guidelines"

• BWRVIP-94NP, Revision 2, "BWRVessel and Internals Project, Program Implementation Guide"

• BWRVIP-100-A, "BWR Vessel and Internals Project, Updated Assessment of the Fracture Toughness of Irradiated Stainless Steel for BWR Core Shrouds"

• BWRVIP-138, Revision 1-A, "BWR Vessel and Internals Project, Updated Jet Pump Beam Inspection and Flaw Evaluation" With the exception of BWRVIP-18, Revision 2-A, the above BWRVIP guidelines were also referenced in the evaluation of proposed alternative Request No. Rl5-02, which was approved by the NRC staff on February 17, 2016.

In Table 1 of proposed alternative Request No. Rl5-02, Revision 1, the licensee provided a comparison of the ASME Code,Section XI, examination requirements for B-N-1 and B-N-2 categories of the reactor pressure vessel interior surfaces, attachments, and core support structures with the above current BWRVIP Inspection and Evaluation Guidelines. In proposed alternative Request No. Rl5-02, Revision 1, the licensee also provided additional information regarding the BWRVIP inspection guidelines for the following components of the reactor pressure vessel interior surfaces, attachments, and core support structures and their subcomponents representing each of the ASME Code, Section Xi, item Nos. 813. i 0, 813.20, B13.30, and B13.40:

• Reactor Vessel Interior (813.1 0)

• Interior Attachments within Beltline (B13.20)

• Jnterior Attachments beyond Beltline (813.30)

• Core Support Structure (B13.40)

The comparison provided by the licensee in proposed alternative Request No. Rl5-02, Revision 1, is identical with the comparison provided by the licensee in proposed alternative Request No. Rl5-02, except that the examination of core spray piping and spargers will be in accordance with BWRVIP-18, Revision 2-A in lieu of BWRVIP-18, Revision 1-A.

3.4 NRC Staff Evaluation The NRC staff reviewed the information provided by the licensee in its submittal dated August 17, 2017, regarding its proposed alternatives to the ASME Code,Section XI, ISi requirements and the technical bases for the licensee's proposed alternatives. The staff found (7-73) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program the referenced BWRVIP reports to be acceptable, with any additional conditions associated with the implementation of the subject BWRVIP reports outlined in the corresponding staff SE for that report.

Examination of Reactor Vessel Interior {Item B13.10)

The ASME Code requires a VT-3 examination of the reactor vessel interior, which is above and below the core beltline, and which is made accessible during normal refueling outages. For the first 10-year inspection interval, the ASME Code requires inspection at the first refueling outage and subsequent refueling outages at approximately 3-year intervals. For the second and successive 10-year inspection intervals, the ASME Code requires inspection once each inspection period.

Except for the core spray piping and spargers, the BWRVIP alternatives proposed by the licensee for Item 813.10 components in its submittal dated August 17, 2017, are identical with the alternatives approved by the NRC staff in its SE dated February 17, 2016, of proposed alternative Request No. RIS-02. For the core spray piping and spargers, the licensee proposes examination in accordance with BWRVIP-18, Revision 2-A. By letter dated May 9, 2012

{ADAMS Accession No. ML12139A153), the Electric Power Research Institute {EPRI) submitted BWRVIP-18, Revision 2, "BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines" to the NRC staff for review. The changes in this revision included a revised operating experience and susceptibility discussions for core spray internals, a revised inspection program for core spray internals, and additional guidance for evaluation of cracking associated with sparger bracket locations. By letter dated February 22, 2016 (ADAMS Accession No. ML16011A199), the NRC staff found that BWRVIP-18, Revision 2 is acceptable for referencing in licensing applications for nuclear power plants. The NRC staff finds that the licensee's proposal in alternative Request No. RIS-02, Revision 1, to use BWRVIP-18, Revision 2-A, for the examination of core spray piping and spargers is acceptable.

The last examination of core spray piping, which occurred during the fall 2016 outage, did not reveal any changes in the existing indications and identified no new indications.

The NRC staff finds that the licensee's proposed alternative Request No. Ri5-02, Revision i, provides an acceptable level of quality and safety for the Item 813.10 components.

Examination of Interior Attachments within Beltline (Item B13.20)

The ASME Code requires a VT-1 examination of accessible reactor vessel interior attachment welds within the beltline during each inspection interval. The BWRVIP alternatives proposed by the licensee for Item B13.20 components in its submittal dated August 17, 2017, are identical with the alternatives approved by the NRC staff in its SE dated February 17, 2016, of proposed alternative Request No. RIS-02.

The NRC staff finds that the licensee's proposed alternative Request No. RIS-02, Revision 1, provides an acceptable level of quality and safety for the Item 813.20 components.

Examination of Interior Attachments beyond Beltline (Item B13.30)

The ASME Code requires a VT-3 examination of accessible reactor vessel interior attachment welds beyond the beltline during each inspection interval. The BWRVIP alternatives proposed by the licensee for Item B13.30 components in its submittal dated August 17, 2017, are identical (7-74) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program with the alternatives approved by the NRC staff in its SE dated February 17, 2016, of proposed alternative Request No. Rl5-02.

The NRC staff finds that the licensee proposed alternative Request No. Rl5-02, Revision 1, provides an acceptable level of quality and safety for the Item 813.30 components.

Examination of Core Support Structure (Item B13.40}

The ASME Code requires a VT-3 examination of accessible surfaces of the core support structure during each inspection interval.

The 8WRVIP alternatives proposed by the licensee for Item 813.40 components in its submittal dated August 17, 2017, are identical with the alternatives approved by the NRC staff in its SE dated February 17, 2016, of proposed alternative Request No. Rl5-02.

The NRC staff finds that the licensee's proposed alternative Request No. Rl5-02, Revision 1, provides an acceptable level of quality and safety for the Item B13.40 components.

4.0 CONCLUSION

Based on the information provided in the licensee's submittal dated August 17, 2017, the NRC staff concludes that the alternative proposed by the licensee will ensure that the integrity of the RVI components is maintained with an acceptable level of quality and safety.

The NRC staff has reviewed the subject request and concludes as set forth above, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1). Therefore, pursuant to 10 CFR 50.55a{z)(1), the licensee's proposed alternative for CNS is authorized for the fifth 10-year ISi interval with the condition that in the event the licensee wishes to take exceptions to, or deviations from, the NRG-approved BWRVIP inspection guidelines authorized as a proposed alternative, the licensee must revise and resubmit its request for authorization to use the proposed alternative under 10 CFR 50.55a.

Any ASME Code, Section Xi, RVi components that are not included in thrs request for alternative will continue to be inspected in accordance with the ASME Code,Section XI requirements. The Inspection and Evaluation guidelines addressed in the relevant BWRVIP reports should be implemented for the non-ASME Code,Section XI, RVI components at CNS.

All other ASME Code,Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third party review by the Authorized Nuclear lnservice Inspector.

Principal Contributor: J. Jenkins, NRR/DMLR/MVIB Date: July 31 *, 201 8 (7-75) Rev 3.0

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3rd Interval GISI Program 10 CFR 50.SSa Relief Request RIS-02, Revision 2 Revision to Relief Request RIS-02, Revision 1 Associated with Implementation of BWRVIP Documents in Lieu of Specific ASME Code Requirements on Reactor Pressure Vessel Internals and Components Inspection In Accordance with 10 CFR 50.SSa(z)(l)

Reason for Request

Pursuant to 10 CFR 50.SSa(z)(l), a revision is requested to the Nuclear Regulatory Commission (NRC) previously approved Cooper Nuclear Station (CNS) relief request RIS-02, Revision 1 (Reference 3) associated with the use of the Boiling Water Reactor Vessel and Internals Project (BWRVIP) guidelines in lieu of specific American Society of Mechanical Engineers (ASME) Code requirements on Reactor Pressure Vessel internals and componer:its inspection. Since the issuance of the NRC Safety Evaluation Report, revisions to BWRVIP documents have occurred.

BWRVIP-41, Revision 4-A (Reference 1) and BWRVIP-94NP, Revision 3 (Reference 2) have been issued. Nebraska Public Power District {NPPD) is requesting approval to use the latest NRC/BWRVIP approved documents in place of the document revisions cited in the Safety Evaluation Report on the basis that these approved BWRVIP documents provide an acceptable level of quality and safety.

The BWRVIP guidelines have recommended aggressive specific inspection by Boiling Water Reactor (BWR) operators to identify material condition issues with BWR components. A wealth of inspection data has been gathered during these inspections across the BWR industry. These guidelines focus on specific and susceptible components, specify appropriate inspection methods capable of identifying anticipated degradation mechanisms, and require re-examination at conservative intervals. In contrast, the code inspection requirements were prepared before the BWRVIP initiative and have not evolved with BWR inspection experience.

Proposed Revision NPPD submitted relief request RIS-02, Revision 1 proposing to use the BWRVIP guidelines as an alternative to the requirements of Section XI of the ASME Code for the inservice inspection of the Reactor Pressure Vessel interior surfaces, attachments, and core support structures. RIS-02, Revision 1 has been approved by the NRC with specific revisions of BWRVIP documents listed. The Safety Evaluation Report restricts the use of the relief request benefits to the BWRVIP document revisions specifically addressed within the relief request submittal. In the time since the staff's approval of NPPD's proposed alternative, BWRVIP-41 has been revised by the BWRVIP and approved by the NRC. BWRVIP-94NP is an administrative document that has also been revised and approved by the BWRVIP Executive Committee. NPPD requests that the latest NRC approved revision of BWRVIP-41 and the latest BWRVIP Executive Committee approved revision of BWRVIP-94 be used as an alternative to the revisions currently listed in the referenced Safety Evaluation Report.

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3rd Interval GISI Program References

1. BWRVIP-41, Revision 4-A: BWR Vessel and Internals Project BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines. EPRI, Palo Alto, California: 3002014254, dated December 2018.

2. BWRVIP-94NP, Revision 3, BWR Vessel and Internals Project Program Implementation Guide. EPRI, Palo Alto, California: 3002013101, dated September 2018.

3. U.S. Nuclear Regulatory Commission letter to Nebraska Public Power District dated July 31, 2018, "Cooper Nuclear Station - Requests for Relief Associated with the Fifth 10-Year lnservice Inspection Interval Program." (Ml18183A325)

Precedents

1. Letter to U.S. Nuclear Regulatory Commission from James Barstow (Exelon Generation Company, LLC) dated February 19, 2019, "Revision to Relief Requests Associated with the Use of the BWRVIP Guidelines in Lieu of Specific ASME Code Requirements on Reactor Pressure Vessel Internals and Components Inspection." (ML19050A363)

2. U.S. Nuclear Regulatory Commission letter to Exelon Generation Company, LLC, dated April 30, 2019, "Clinton Power Station, Unit No. 1; Dresden Nuclear Power Station, Units 2 and 3; James A. Fitzpatrick Nuclear Power Plant; LaSalle County Station, Units 1 and 2; Limerick Generating Station, Units 1 and 2; Peach Bottom Atomic Power Station, Units 2 and 3; and Quad Cities Nuclear Power Station, Units 1 and 2 - Revision to Approved Alternatives to Use Boiling Water Reactor Vessel and Internals Project Guidelines." (ML19098A034)

Table 1 Updated BWRVIP Revisions CNS Safety Evaluation Listed BWRVIP- Requested Listed Requested ADAMS Accession No. 41 Revision BWRVIP-41 BWRVIP-94NP BWRVIP-94NP Revision Revision Revision ML18183A325 3 4-A 2 3 (7-77) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION PREQUEST FOR ALTERNATIVE RIS-02, REVISION 2 FOR FIFTH 10-YEAR INSERVICE INSPECTION INTERVAL NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated August 17, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17241A048), Nebraska Public Power District (the licensee) submitted a proposed alternative, Relief Request (RR) RIS-02, Revision 1, for its reactor vessel internals (RVI) components at Cooper Nuclear Station (CNS). In RR RIS-02, Revision 1, the licensee proposed to use Boiling Water Reactor Vessel and Internals Project (BWRVIP) guidelines as an alternative to certain requirements of Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code (ASME Code) for inservice inspection (ISi) of reactor pressure vessel interior surfaces, interior attachments, and core support structures. This alternative was requested for the fifth 10-year ISi interval at CNS, which began on April 1, 2016, and will end on February 28, 2026. By letter dated July 31, 2018 (ADAMS Accession No. ML18183A325), the U.S. Nuclear Reguiatory Commission (NRC) staff authorized the proposed alternative in RR RIS-02, Revision 1 pursuant to Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.55a(z)(1) on the basis that the alternative provides an acceptable level of quality and safety.

By letter dated June 28, 2019 (ADAMS Accession No. ML19190A092), the licensee submitted a revision to its proposed alternative, RR RIS-02, Revision 2 for its fifth 10-year ISi interval for its RVI components at CNS. Relief Request RIS-02, Revision 2 changes the specified revision of two of the BWRVIP topical reports that are used as a basis for the ASME Code alternative authorized in the NRC staffs letter dated July 31, 2018. The applicable BWRVIP guidelines are BWRVIP-41, "BWR [Boiling Water Reactors] Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," and BWRVIP-94NP, "BWR Vessel and Internals Project, Program Implementation Guide," which are two of the BWRVIP documents referenced in RR RIS-02, Revision 1.

2.0 REGULATORY EVALUATION

The ISi of ASME Code Class 1, 2, and 3 components is to be performed in accordance with Section XI of the ASME Code and applicable edition and addenda as required by Enclosure 2 (7-78) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program 10 CFR 50.55a(g), "Preservice and inservice inspection requirements," except where specific relief has been granted by the NRC pursuant to 10 CFR 50.55a(g)(6)(i), "Impractical ISi requirements: Granting of relief." Pursuant to 10 CFR 50.55a(z), "Alternatives to codes and standards requirements," alternatives to the requirements of paragraph (g) may be used, when authorized by the NRC if (1) the proposed alternatives would provide an acceptable level of quality and safety or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4), "lnservice inspection standards requirement for operating plants," ASME Code Class 1, 2, and 3 components (including supports) must meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code,Section XI to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year interval and subsequent intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.55a(a)(1 )(ii),

"ASME Boiler and Pressure Vessel Code,Section XI," twelve months prior to the start of the 120-month interval, subject to the conditions listed in 10 CFR 50.55a(b)(2), "Conditions on ASME BPV Code,Section XI."

The applicable ASME code of record for the fifth 10-year ISi interval for CNS is the ASME Code,Section XI, 2007 Edition through 2008 Addenda.

3.0 TECHNICAL EVALUATION

3.1 The Components for Which an Alternative is Requested The licensee requested to use alternative inspection criteria for the following components: ASME Code,Section XI, Class 1, Subarticle IWB-2500, "Examination and Pressure Test Requirements,"

Table IWB-2500-1, "Examination Categories," Examination Categories B-N-1 and B-N-2, Code Item Numbers B13.10 (Vessel Interior), B13.20 (Interior Attachments within Beltline Region),

B13.30 (Interior Attachments beyond Beltline Region), and B13.40 (Core Support Structure).

3.2 Examination Requirements for Which an Alternative is Requested The ASME Code,Section XI requires the visual examination (VT) of certain RVI components.

These examinations are included in Table IWB-2500-1, Categories B-N-1 and B-N-2, and identified with the following item numbers:

• B13.10 - Examine accessible areas of the reactor vessel interior each period using a technique, which meets the requirements for a VT-3 examination, as defined in paragraph IWA-2213, "VT-3 Examination," of the ASME Code,Section XI.

• B13.20 - Examine interior attachment welds within the beltline region each interval using a technique which meets the requirements for a VT-1 examination as defined in paragraph IWA-2211, "VT-1 Examination," of the ASME Code,Section XI.

• B13.30 - Examine interior attachment welds beyond the beltline region each interval using a technique which meets the requirements for a VT-3 examination, as defined in paragraph IWA-2213 of the ASME Code,Section XI.

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• 813.40 - Examine surfaces of the core support structure each interval using a technique which meets the requirements for a VT-3 examination, as defined in paragraph IWA-2213 of the ASME Code,Section XI.

These examinations are performed to assess the structural integrity of the reactor pressure vessel interior surfaces, interior attachments, and core support structures.

3.3 Licensee's Basis for Requesting an Alternative and Justification for Granting Relief In RR RIS-02, Revision 2, the licensee proposed to replace BWRVIP-41, Revision 3 with Revision 4-A dated December 2018 (ADAMS Accession No. ML19297G484). The licensee also proposed to replace BWRVIP-94NP, Revision 2 with Revision 3 dated September 2018 (ADAMS Accession No. ML11271A058).

3.4 NRC STAFF EVALUATION The NRC staff reviewed the information provided by the licensee in its submittal dated June 28, 2019, regarding its proposed alternatives to the ASME Code,Section XI ISi requirements and the technical bases for the licensee's proposed alternatives.

3.4.1 BWRVIP-41, Revision 4-A As stated in the publicly available submittal letter dated October 22, 2019 (ADAMS Accession No. ML19297G503), Topical Report BWRVIP-41, Revision 4-A contains inspection and flaw evaluation guidelines for the BWR jet pump assemblies. In its July 2, 2018 safety evaluation (ADAMS Accession No. ML18130A024), the NRC staff found that the topical report, as modified and clarified to incorporate NRC staff conditions, is acceptable for use with respect to the proposed inspections and flaw evaluation guidelines for the BWR jet pump assemblies. Topical Report BWRVIP-41, Revision 4-A incorporates the NRC staff conditions referenced in the July 2, 2018, safety evaluation and is acceptable for use with respect to the proposed inspections and flaw evaluation guidelines for the BWR jet pump assemblies.

3.4.2 BWRVIP-94NP, Revision 3 Topical Report BWRVIP-94NP, Revision 3 is an administrative document intended to incorporate the NRG-endorsed Nuclear Energy Institute (NEI) guidance document NEI 03-08, "Guidelines for the Management of Materials Issues" (ADAMS Accession No. ML19079A253), for the BWRVIP Program, and to ensure consistent application of BWRVIP guidelines by BWRVIP utilities. The NRC staff has not evaluated this BWRVIP topical report for generic use; however, the staff finds that the licensee's reference to Revision 3 is an acceptable way for the licensee to incorporate the guidance of NEI 03-08 for the subject proposed alternative. The NRC staff also confirmed that the licensee's implementation of BWRVIP-94NP, Revision 3 will not impact any of the NRC staffs safety determinations concerning implementation of the applicable BWRVIP guidelines as an alternative to the subject ASME Code,Section XI requirements.

The NRC staff finds that the use of BWRVIP-41, Revision 4-A, dated December 2018 and BWRVIP-94NP, Revision 3, dated September 2018 to be acceptable because BWRVIP-41, Revision 4-A is an NRG-approved topical report and BWRVIP-94NP, Revision 3, will provide reasonable administrative controls for implementation of BWRVIP guidelines for the CNS RVI components.

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4.0 CONCLUSION

As set forth above, the NRC staff determines that the licensee's proposed alternative provides an acceptable level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1 ).

Therefore, the NRC staff authorizes the alternative in RR RIS-02, Revision 2 at CNS for the fifth 10-year ISi interval, which began on April 1, 2016 and will end on February 28, 2026.

All other ASME BPV Code,Section XI, requirements for which an alternative was not specifically requested and approved remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector.

Principal Contributor: J. Jenkins, NRR Date: March 19, 2020 (7-81) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program 10 CFR 50.SSa Request No. RIS-03 Implementation of Code Case N-702 Proposed Alternative in Accordance with 10 CFR 50.SSa(z)(l)

Acceptable Level of Quality and Safety ASME Code Component(s) Affected Code Class: ASME Section XI Code Class 1 Component Numbers: Various (see Table 1 for detailed list of components)

Code

References:

ASME Section XI, 2007 Edition with 2008 Addenda Code Case N-702 Examination Category: B-D Item Number(s): B3.90 and B3.100

Applicable Code Edition and Addenda

ASME Section XI, 2007 Edition through the 2008 Addenda Applicable ASME Code Requirements Table IWB-2500-1, Examination Category B-D, "Full Penetration Welded Nozzles in Vessels" requires a volumetric examination of all nozzles with full penetration welds to the vessel shell (or head) and integrally cast nozzles each 10-year interval. Additionally, for ultrasonic examinations, ASME Section XI, Appendix VIII, "Performance Demonstration for Ultrasonic Examination Systems," is implemented, as required and conditioned by 10 CFR 50.5Sa(b)(2)(xv).

The RPV nozzle-to-vessel welds and inner radii subject to this request are listed below in Table 1:

TABLE 1 Identification Description Total Number Minimum Number Number to be examined Nl Recirculation Outlet 2 1 N2 Recirculation Inlet 10 3 N3 Main Steam Outlet 4 1 NS Core Spray 2 1 N6 Head Instrument 2 1 N7 Head Vent 1 1 N8 Jet Pump Instrumentation 2 1 (7-82) Rev 3.0

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Reason for Request

NRC Regulatory Guide 1.147 Rev. 17 conditionally accepts the use of Code Case N-702. This code case provides an alternative to performing examination of 100% of the Nozzle-to-Vessel Welds and Inner Radii for Examination Category B-D nozzles with the exception of the Feedwater and CRDRL Nozzles. The alternative is to perform examination of a minimum of 25%

of the nozzle inner radii and nozzle-to-shell welds, including at least one nozzle from each system and nominal pipe size, excluding the Feedwater and CRDRL Nozzles.

Proposed Alternative and Basis for Use Proposed Alternative Pursuant to 10 CFR 50.55a(z)(1), NPPD requests approval to implement the alternative of Code Case N-702 in lieu of the code required 100% examination of all nozzles identified in Table 1. As an alternative, for the nozzle-to-shell welds and inner radii identified in Table 1, NPPD proposes to examine a minimum of 25% of the nozzle-to-vessel welds and inner radius sections, including at least one nozzle from each system and nominal pipe size, in accordance with Code Case N-702.

Basis for Use BWRVIP has issued two topical reports:

• BWRVIP-108, "Technical Basis for the Reduction of Inspection Requirements for the Boiling Water Reactor Nozzle-to-Vessel Shell Welds and Nozzle Blend Radii," EPRI Technical Report 1003557, dated October 2002 (ML023330203).

• BWRVIP-241, "Probabilistic Fracture Mechanics Evaluation for the Boiling Water Reactor Nozzle-to-Vessel She!! We!ds and Nozzle Blend Radii," EPRI Technical Report 1021005; dated October 2010 (ML11119A041).

The BWRVIP-108 report contains the technical basis supporting ASME Code Case N-702 "Alternative Requirements for BWR Nozzle Inner Radius and Nozzle-to-Shell Welds" for reducing the inspection of RPV nozzle-to-vessel shell welds and nozzle inner radius areas from 100 percent to 25 percent of the nozzles for each nozzle type during each 10-year interval.

BWRVIP-241 provides supplemental analyses for BWR RPV recirculation inlet and outlet nozzle-to-shell welds and nozzle inner radii. BWRVIP-241 was submitted to address the limitations and conditions specified in the December 19, 2007, safety evaluation for the BWRVIP-108 report, "BWR Vessel and Internals Project, Technical Basis for the Reduction of Inspection Requirements for the Nozzle-to-Vessel Shell Welds and Nozzle Blend Radii."

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3rd Interval CISI Program Based on the two evaluations (BWRVIP-241 and BWRVIP-108), the failure probabilities due to a LTOP event at the nozzle blend radius region and the nozzle-to-vessel shell welds for CNS recirculation inlet and outlet nozzles are very low and meet the NRC safety goal.

Regulatory Guide 1.147, Revision 17 conditionally accepts the use of Code Case N-702 with the following condition 'The applicability of Code Case N-702 must be shown by demonstrating that the criteria in Section 5.0 of NRC Safety Evaluation regarding BWRVIP-108 dated December 18, 2007 (ML073600374) or Section 5.0 of NRC Safety Evaluation regarding BWRVIP-241 dated April 19, 2013 (ML13071A240) are met."

Section 5.0 of the NRC Safety Evaluation for BWRVIP-241 states:

"Licensees who plan to request relief from the ASME Code,Section XI requirements for RPV nozzle-to-vessel shell welds and nozzle inner radius sections may reference the BWRVIP-241 report as the technical basis for use of ASME Code Case N-702 as an alternative. However, each licensee should demonstrate the plant-specific applicability of the BWRVIP-241 report to their units in the relief request by demonstrating all of the following:

(1) The maximum RPV heatup/cooldown rate is limited to less than 115°F/hour CNS Technical Specification 3.4.9.1, Reactor Coolant System heatup and cooldown rates are limited to a maximum of 100°F when averaged over any one hour period and thus meets the requirement of Condition 1.

Note: Inputs used in 2 through 5 representing the CNS configuration are in bold text.

Recirculation inlet nozzles (N2}

(2) (pr/t)/CRPvS 1.15 p = RPV normal operating pressure (psi) (1020 psig per CNS Technical Specifications 3.4.10 for Reactor Steam Dome Pressure) r = RPV inner radius (inch) (110.375) t = RPV wall thickness (inch) (6.875)

CRPV = 19332 (based on the BWRVIP-108 recirculation inlet nozzle/RPV finite element method (FEM) model);

CNS specific calculations for Condition 2 above:

(1020 X 110.375)/6.875)/19332 = 0.85 ~ 1.15 The CNS result is 0.85 and thus meets the requirement of condition 2 to be~ 1.15.

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3rd Interval CISI Program P = RPV normal operating pressure (psi) (1020}

ro = nozzle outer radius (inch) (10.219}

ri = nozzle inner radius (inch) (6.188}

CNozzLE = 1637 based on the BWRVIP-108 recirculation inlet nozzle/RPV FEM model);

CNS specific calculations for Condition 3 above:

[1020(10.219 2 + 6.188 2 )/(10.219 2 - 6.188 2 }]/1637 = 1.34 =5. 1.47 The CNS result is 1.34 and thus meets the requirement of condition 3 to be ~1.47 Recirculation outlet nozzles (Nl)

(4) (pr/t)/CRPV :5_ 1.15 p = RPV normal operating pressure (psi) (1020) r = RPV inner radius (inch) (110.375) t = RPV wall thickness (inch) (6.875}

CRPv = 16171 (based on the BWRVIP-108 recirculation outlet nozzle/RPV FEM model);

CNS specific calculations for Condition 4 above:

(1020 X 110.375)/6.875}/16171 = 1.013 :5_ 1.15 The CNS result is 1.013 and thus meets the requirements of condition 4 to be =5. 1.15 P = RPV normal operating pressure (psi) (1020}

ro = nozzle outer radius (inch) (21.656) ri = nozzle inner radius (inch) (12.875)

CNozzLE = 1977 (based on the BWRVIP-108 recirculation outlet nozzle/RPV FEM model).

CNS specific calculation for Condition 5 above:

[1020(21.656 2 + 12.875 2 )/(21.656 2 - 12.8752 )1/1977 = 1.08 =5.1.59 The CNS result is 1.08 and thus meets the requirements of condition 5 to be =5.1.59 (7-85) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program The analyses for the N2 nozzles in BWRVIP-108 and BWRVIP-241 are based on the assumption that fluence at the nozzles is negligible because the analysis is for the initial 40 years of plant operation and do not address the extended operating period. Based on analysis performed in support of license renewal for CNS, the beltline was re-evaluated for 60 years based on the axial flux profile and the active fuel and nozzle elevations. In 4.2.1 "Reactor Vessel Fluence" of the License Renewal Application, it is documented that fluence at the recirculation inlet nozzles (the closest ferritic nozzles to the beltline) will not exceed 1E+17 n/cm during the period of 2

extended operation. Since the LRA, CNS has updated the fluence values using the NRC approved RAMA fluence method in support of the current Pressure Temperature Limits Report.

As part of that evaluation, the predicted fluence at 54 EFPY was also determined for the N2 nozzles which support the conclusion of the LRA that the fluence at the recirculation inlet nozzles will not exceed 1E+17 n/cm 2

• The plates and welds in the beltline remain the limiting materials for the period of extended operation. Therefore, the fluence assumptions used in BWRVIP-108 and BWRVIP-241 remain valid and are applicable to CNS.

The analyses in BWRVIP-108 and BWRVIP-241 were based on predicted fatigue crack growth over the initial licensed operating period and assumed additional fatigue cycles in evaluating fatigue crack growth. CNS is projected to exceed the total number of thermal cycles used in the BWRVIP analysis during the extended operating period. However, the usage factor for the N2 nozzles is expected to remain below 1.0. Previous BWRVIP documents have demonstrated that sec crack growth represents the majority of the crack growth and that crack growth due to additional mechanical/thermal fatigue cycles introduced by the extended operation time is insignificant compared to hypothetical sec growth. Thus, the amount of thermal cycle driven fatigue crack growth due to the extended operation to 60 years is not a controlling factor in the probability of failure of the BWR reactor vessel nozzles.

CNS performed a plant specific probabilistic fracture mechanics to supplement the criteria of Code Case N-702 and BWRVIP-241 in order to demonstrate that the PoF remains acceptable over the period of extended operation. Conservatively assuming zero inspection for the initial 40 years of operation and examination of 25% for PEO, the evaluation concluded the average PoF for a LTOP event is 1.65 x 10-10 per year (Reference 1) for the nozzle inner (blend) radius,

< 8.33 x 10-13 per year (Reference 1) for the nozzle-to-shell weld, and < 8.33 x 10-10 per year 5

(Reference 1) due to normal operation, all of which are less than the NRC safety goal of 5 x 10-per year.

The examination history for the subject nozzles is included in Table 2.

Duration of Proposed Alternative The duration of this request is for the extended license period ending January 18, 2034.

(7-86) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program Precedents "Pilgrim Nuclear Power Station - Relief Request PRR-50, Use of Alternatives, Implementation of Code Case N-702," dated January 5, 2016 (ADAMS Accession Number ML15338A309).

"Cooper Nuclear Station - Request for Relief No. Rl-04 for the Fourth 10-Year lnservice Inspection Interval Regarding Inspection of Reactor Vessel Nozzle-to-Vessel Shell Welds," dated October 8, 2010 (ADAMS Accession Number ML102220449).

"Cooper Nuclear Station - Relief Request No. Rl-08, Revision O Applicable to Fourth 10-Year lnservice Inspection Interval," dated May 20, 2015 (ADAMS Accession NumberML15134A242).

Reference

1. ER 2017-027, "Review of Structural Integrity Calculations 1400334.301 & 1400334.302 for Code Case N-702 Relief Request," Revision 1, dated March 8, 2018.

(7-87) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C, 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION ALTERNATIVE REQUEST NO. RIS-03 FOR THE FIFTH AND SIXTH 10-YEAR INTERVAL INSERVICE INSPECTIONS NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated August 17, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17241A048), as supplemented by letters dated March 14, 2018, and April 26, 2018 (ADAMS Accession Nos. ML18082A563 and ML18131A159 respectively),

Nebraska Public Power District (the licensee), requested relief from the requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code)

Section XI, Table IWB-2500-1 and instead proposes to use the inspection requirements documented in ASME Code Case N-702, "Alternative Requirements for Boiling Water Reactor (BWR) Inner Nozzle Radius and Nozzle-to-Shell Weld,Section XI, Division 1." For the VT-1 visual examinations allowed by ASME Code Case N-702, the licensee proposes to use ASME Code Case N-648-1, "Alternative Requirements for Inner Radius Examination of Class 1 Reactor Vessel Nozzles,Section XI, Division 1," with associated required conditions specified in Regulatory Guide (RG) 1.147, Revision 17, "lnservice Inspection Code Case Acceptability,Section XI, Division 1," dated August 2014.

Specifically, pursuant to Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.55a(z)(1 ), the licensee requested to use the proposed alternative on the basis that the alternative provides an acceptable level of quality and safety.

2.0 REGULATORY EVALUATION

Adherence to Section XI of the ASME Code is mandated by 10 CFR 50.55a(g)(4), "lnservice inspection standards requirements for operating plants," which states, in part, that ASME Code Class 1, 2, and 3 components will meet the requirements, except the design and access provisions and the pre-service examination requirements, set forth in Section XI of the ASME Code.

(7-88) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program The regulation at 10 CFR 50.55a(z), "Alternatives to codes and standards requirements/' states, in part that, Alternatives to the requirements of paragraphs (b) through (h) of [10 CFR 50.55a]

or portions thereof may be used when authorized by the Director, Office of Nuclear Reactor Regulation .... A proposed alternative must be submitted and authorized prior to implementation. The applicant or licensee must demonstrate that:

( 1 ) Acceptable level of quality and safety. The proposed alternative would provide an acceptable level of quality and safety; or (2) Hardship without a compensating increase in quality and safety. Compliance with the specified requirements of this section would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Based on the above, and subject to the following technical evaluation, the U.S. Nuclear Regulatory Commission (NRC) staff finds that regulatory authority exists for the licensee to request the use of an alternative and the NRC to authorize the proposed alternative.

3.0 TECHNICAL EVALUATION

3. 1 Background For all reactor pressure vessel (RPV) nozzle-to-vessel shell welds and nozzle inner radii, ASME Code,Section XI, requires 100 percent inspection during each 10-year inservice inspection (ISi) interval. However, ASME Code Case N-702 provides an alternative, which reduces the inspection of RPV nozzle-to-vessel shell welds and nozzle inner radii areas from 100 percent to 25 percent of the nozzles for each nozzle type during each 10-year interval. This code case was conditionally approved in RG 1.147, Revision 17. For application of ASME Code Case N-702, the licensee is required to address the conditions specified in RG 1.147, Revision 17 for ASME Code Case N-702. The condition specified in RG 1.147, Re\.4sion 17 states, in part:

The applicability of Code Case N-702 must be shown by demonstrating that the criteria in Section 5.0 of NRC Safety Evaluation regarding [Boiling Water Reactor Vessel and Internals Project] BWRVIP-108 dated December 19, 2007 ([ADAMS Accession No.] ML073600374) or Section 5.0 of NRC Safety Evaluation regarding BWRVIP-241 dated April 19, 2013 ([ADAMS Accession No.]

ML13071A240) are met. The evaluation demonstrating the applicability of the Code Case shall be reviewed and approved by the NRC prior to the application of the Code Case.

BWRVIP-108, "BWR Vessel and Internals Project, Technical Basis for the Reduction of Inspection Requirements for the Boiling Water Reactor Nozzle-to-Vessel Shell Welds and Nozzle Inner Radii" (Not publicly available; proprietary information) and BWRVIP-241, "BWR Vessel and Internals Project, Probabilistic Fracture Mechanics [PFM] Evaluation for the Boiling Water Reactor Nozzle-to-Vessel Shell Welds and Nozzle Blend Radii" (ADAMS Accession No. ML11119A043) contain PFM analysis results supporting ASME Code Case N-702. Both reports are for 40 years of operation. BWRVIP-241 contains additional PFM results supporting (7-89) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program revision of the evaluation criteria under "Conditions and Limitations" in the safety evaluation (SE) for 8WRVIP-108. The SE for 8WRVIP-241 accepted the revised criteria.

Recently, the NRC issued a safety evaluation (SE) dated April 26, 2017 (ADAMS Accession No. ML17114A096), on a supplemental document for license renewal (8WRVIP-241, Appendix A, "8WR Nozzle Radii and Nozzle-to-Vessel Welds Demonstration of Compliance with the Technical Information Requirements of the License Renewal Rule (10 CFR 54.21 ")).

This license renewal Appendix A extends the applicability of the 8WRVIP-108 and 8WRVIP-241 methodologies, and, therefore, ASME Code Case N-702, through the period of extended operation.

ASME Code Case N-702 allows that VT-1 visual examination may be performed in lieu of volumetric examination for Examination Item No. 83. 100 nozzle inner radius sections. ASME Code Case N-648-1, as conditionally accepted by RG 1.147, Revision 17, requires that nozzle inner radius examinations must use the allowable flaw length criteria of ASME Code, Table IW8-3512-1, with limiting assumptions on the flaw aspect ratio.

3.2 ASME Code Components Affected

The affected components belong to Examination Category 8-D, "Full Penetration Welded Nozzles in Vessels" under Examination Item No. 83.90, "Nozzle-to-Vessel Welds" and 83.100, "Nozzle Inside Radius Section."

Table 1 RPV Nozzle-to-Vessel Welds and Inner Radii Subject to this Request Identification Total Number Minimum Number Description Number to be examined N1 Recirculation Outlet 2 1 N2 Recirculation Inlet 10 3 N3 Main Steam Outlet 4 1 NS Core Spray 2 1 N6 Head Spray 2 1 N7 Head Vent 1 1 NB Jet Pump Instrumentation 2 1 3.3 Applicable Code Edition and Addenda This request applies to the fifth and sixth 10-year ISi intervals, in which CNS adopted the 2007 Edition through 2008 Addenda of ASME Code Section XI, as the Code of Record.

3.4 Applicable Code Requirements ASME Code Section XI, Table IW8-2500-1, Examination Category 8-D, requires a volumetric examination of all nozzles with full penetration welds to the vessel shell (or head) and integrally cast nozzles each 10-year interval.

3.5 Licensee's Proposed Alternative The licensee proposed to implement ASME Code Case N-702 and reduce the ASME Code-required volumetric examinations for all RPV nozzle-to-shell welds and inner radii, to a minimum of 25 percent of the nozzle inner radii and nozzle-to-shell welds, including at least one (7-90) Rev 3.0

Cooper Station 5th IS I &

3rd Interval CISI Program nozzle from each system and nominal pipe size during each inspection interval. The required examination volume for the reduced set of nozzles remains at 100 percent of that depicted in Figures IWB-2500-7 (a) through (d), as applicable in the ASME Code.

In addition, the licensee stated it may perform a VT-1 visual examination in lieu of a volumetric examination for Category B-D, Item No. 3.100 consistent with ASME Code Case N-648-1, with associated required conditions specified in RG 1.147, Revision 17.

3.6 Licensee's Bases for Alternative The alternative is based on the PFM results documented in the BWRVIP-241 report. The licensee proposed that it met the evaluation criteria in the SE for BWRVIP-241 as follows:

(1) Maximum RPV Heatup/Cooldown Rate The maximum RPV heatup/cooldown rate is limited to less than 115 °F/hr (degrees Fahrenheit per hour). CNS Technical Specifications Surveillance Requirement 3.4.9.1, Reactor Coolant System heatup and cooldown rates are limited to a maximum of 100 °F when averaged over any one hour period and thus meets the requirement of Condition 1.

(2) Recirculation Inlet (N2) Nozzles (pr/t) /Ci--RPv < 1.15, where p = RPV normal operating pressure (per square inch (psi)),

r = RPV inner radius (inch),

t = RPV wall thickness (inch), and Ci-RPV = 19332.

The CNS result based on the input parameters for this nozzle, per the licensee's submittal, is (pr/t) /Ci-RPv = 0.85 ([(1020)(110.4)/6.875]/19332), thus meeting the requirements of Condition 2.

(3) Recirculation Inlet (N2) Nozzles

[p(rc2+ri2)/(rc2-n 2)]/Ci-NOZZLE s; 1.47, where p = RPV normal operating pressure (psi),

ro = nozzle outer radius (inch),

n = nozzle inner radius (inch), and Ci-NOZZLE = 1637.

The CNS result based on the input parameters for this nozzle, per the licensee's submittal, is [p(rc2+r?)/(rc2-r?)]/Ci-NOZZLE = 1.34 ([1020(10.222 + 6.188 2 )/(10.222 -

6.1882 )]/1637), thus meeting the requirements of Condition 3.

(7-91) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program (4) Recirculation Outlet (N1) Nozzles (pr/t)/Co--RPv s 1.15, where p = RPV normal operating pressure (psi),

r = RPV inner radius (inch),

t = RPV wall thickness (inch), and Co-RPV = 16171.

The CNS result based on the input parameters for this nozzle, per the licensee's submittal, is (pr/t)/Co--RPV 1.013 ([(1020)(110.4)/6.875]/16171), thus meeting the requirements of Condition 4.

(5) Recirculation Outlet (N1} Nozzles

[p(r/ + r?)/(r/ - r?)]/Co-NOZZLE s 1.59, where p = RPV normal operating pressure (psi),

ro = nozzle outer radius (inch),

n = nozzle inner radius (inch), and Co-NOZZLE= 1977.

The CNS result based on the input parameters for this nozzle, per the licensee's submittal, is (p(ri + ri2)/(ri - r?)]/Co-NOZZLE = 1.08 ([1020(21.656 2 + 12.8752 )/(21.656 2

- 12.8752 )]/1977), thus meeting the requirements of Condition 5.

The licensee's application also states that the licensee performed a plant-specific PFM analysis to supplement the criteria of ASME Code Case N-702 and BWRVIP-241 in order to demonstrate that the probability of failure (PoF) remains acceptable over the period of extended operation.

Conservatively, assuming zero inspection for the initial 40 years of operation and examination of 25 percent of the nozzles every interval for the period of extended operation, the evaluation concluded the average PoF for a low temperature overpressure (LTOP) event is 1.675 x 10-10 per year for the nozzle inner radius, and < 8.33 x 10*13 per year for the nozzle-to-shell weld, both of which are less than the NRC safety goal of 5 x 10~ per year. These probabilities were calculated based on the most limiting nozzle (the N2 inlet nozzle) and thus are bounding for all nozzles which are part of the licensee's request.

3.7 Duration of Proposed Alternative The fifth 10-year ISi interval for CNS began on April 1, 2016, and the sixth 10-year ISi interval is scheduled to end concurrent with the end of the extended license period on January 18, 2034.

3.8 NRC Staff Evaluation The licensee proposed an alternative to implement ASME Code Case N-702 for all CNS RPV nozzle-to-vessel shell penetration welds and nozzle inner radii using the criteria in BWRVIP-241.

In general, the applicability of the BWRVIP-241 report to an ASME Code Case N-702 alternative is demonstrated by showing that Criteria 2 through 5 within Section 5.0 of the NRC SE for (7-92) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program BWRVIP-241 are met for the bounding nozzles (recirculation inlet and outlet nozzles), and that Criterion 1 is met for all components included in the proposed alternative.

The NRC staff confirms that Criterion 1 (applicable to all nozzles within the scope of ASME Code Case N-702) is satisfied because CNS Technical Specifications Surveillance Requirement 3.4.9.1 limits the maximum heatup/cooldown rate to less than or equal to 100 °F/hour, well below the 115 °F/hour criterion limit.

For Criteria 2 through 5, the licensee provided plant specific data and its evaluation of the driving force factors, or ratios, using the criteria established in Section 5.0 of the SE for BWRVIP-241. The NRC staff reviewed the licensee's calculations and confirms that they show that Criteria 2 through 5 are satisfied. Therefore, the BWRVIP-241 report applies to CNS, and the basis for using ASME Code Case N-702 is demonstrated for the CNS RPV nozzle-to-vessel welds and inner radii listed in Table 1 above.

The licensee perfonned a plant-specific PFM analysis to supplement the criteria of ASME Code Case N-702 and BWRVIP-241 in order to demonstrate that the PoF remains acceptable over the period of extended operation. Conservatively, assuming zero inspection for the initial 40 years of operation and examination of 25 percent of the nozzles every interval for the period of extended operation, the evaluation concluded the average PoF for a low temperature overpressure event is 1.675 x 10-10 per year for the nozzle inner radius, and <8.33 x 10-13 per year for the nozzle-to-shell weld. The licensee's evaluation also provided the PoF due to normal operation, or <8.33 x 10-10 per year. The NRC staff finds the licensee's evaluation acceptable since the NRC staff has reviewed the PFM analysis provided and has determined that the PoF due to either LTOP or normal operation is less than the NRC safety goal of 5 x 10-6 per year.

For the Examination Item No. 83.100 nozzle inner radius sections, the NRC staff finds the licensee's proposal to perform VT-1 visual examination in lieu of ultrasonic examination to be acceptable because the licensee will comply with ASME Code Case N-648-1, with associated required conditions specified in RG 1.147, Revision 17.

4.0 CONCLUSION

As set forth above, the NRC staff determines that the licensee has demonstrated that the proposed a'ttemative provides an acceptable level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)( 1). Therefore, the NRC staff authorizes the use of Rl5-03 at CNS for the fifth and sixth intervals for ASME Category 8-D, Item Numbers 83.90 and 83.100 until January 18, 2034.

All other ASME Code,Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third party review by the Authorized Nuclear lnservice Inspector.

Principal Contributor: J. Jenkins, NRR/DMLR/MVl8 Da~: July 31, 2018 (7-93) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program 10 CFR 50.SSa Request Number RC3-01 Alignment and Synchronization of the Containment lnservice Inspection (CISI) Program Third Ten-Year Interval with the lnservice Inspection (ISi) Program Fifth Ten-Year Interval Proposed Alternative in Accordance with 10 CFR 50.SSa(z)(l)

Acceptable Level of Quality and Safety ASME Code Component(s) Affected Code Class: MC Examination Categories: E-A, E-C and E-G

Reference:

IWA-2430 Inspection Intervals Item Numbers: Various

==

Description:==

Alignment of the CISI Program Third Ten-Year Interval dates with the ISi Program Fifth Ten-Year Interval dates and including Synchronization of the ASME Code of Record Requirements for each program as required in 10 CFR 50.SSa and its future revisions.

Component Numbers: All Class MC Components

Applicable Code Edition and Addenda

The ASME Code of Record for the CISI Program Third Ten-Year Interval and the ISi Program Fifth Ten-Year Interval will be ASME Code,Section XI, 2007 Edition, 2008 Addenda.

Applicable Code Requirement

The following Code requirements for inspection intervals are from Subarticle IWA-2430, Inspection Intervals of the ASME Code,Section XI, 2001 Edition, 2003 Addenda as applied to the current CIS! Program Second Ten-Year Interval and the corresponding requirements of the ASME Code,Section XI, 2007 Edition, 2008 Addenda for the proposed CISI Third Ten-Year Interval describing the requirements for a 10 year inspection interval. The requirements in 10 CFR 50.SSa use a 120-month interval and it is the same as the 10 year interval used in the ASME Code. For purposes of this request the term Ten-Year Interval is used.

Paragraph IWA-2430(b) - The inspection interval shall be determined by calendar years following placement of the plant into commercial service. (2001 Edition, 2003 Addenda and 2007 Edition, 2008 Addenda)

(7-94) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Subsubarticle IWA-2432 (2001 Edition, 2003 Addenda and IWA-2431 2007 Edition, 2008 Addenda) - The inspection intervals shall comply with the following, except as modified by IWA-2430(d) - (2001 Edition, 2003 Addenda) - IWA-2430(c) - (2007 Edition, 2008 Addenda):

1 st Inspection Interval - 10 years following initial start of plant commercial service Successive Inspection Intervals - 10 years following the previous inspection interval

Reason for Request

Pursuant to 10 CFR 50.SSa, "Codes and Standards,11 paragraph (z)(l), an alternative is requested to allow the CISI Program Third Ten-Year Interval start date to be aligned with the ISi Program Fifth Ten-Year Interval and to synchronize the ASME Code,Section XI, 2007 Edition, 2008 Addenda requirements of these programs on the basis that the proposed alternative would provide an acceptable level of quality and safety.

Specifically, this is an administrative type of request that is being sought to complete the CISI Program Second Ten-Year Interval early on February 29, 2016 in lieu of the currently scheduled end date of May 8, 2018 and to begin the CISI Program Third Ten-year Interval on March 1, 2016 aligning it with the start of the ISi Program Fifth Ten-Year Interval. Additionally, synchronization of the 10 CFR 50.SSa requirements to use the same ASME Code,Section XI, 2007 Edition, 2008 Addenda for both programs will also begin on March 1, 2016 and this alignment and synchronization will continue for successive CISI and ISi Ten-Year Intervals to the end of the extended license period for CNS. The net effect of this request is to establish one common Ten-Year Interval for both the CISI and ISi Programs at the CNS.

This request for alignment and synchronization of these programs will allow NPPD as the licensee for CNS a burden reduction in procedure development and maintenance and to reduce possible errors associated with applying two different ASME Code,Section XI, Editions and Addenda requirements at the same time.

Currently, the CISI Program Second Ten-Year Interval is using the ASME Code,Section XI, 2001 Edition, 2003 Addenda. If this request is not authorized procedures will have to remain in place to support the related Code requirements of the CISI Program using Subsection IWE of the ASME Code,Section XI, 2001 Edition, 2003 Addenda and related requirements in IWA-1000, IWA-2000 and IWA-4000. This means that for the ISi Program Fifth Ten Year Interval that will use ASME Code,Section XI, 2007 Edition, 2008 Addenda and begins March 1, 2016 these same types of procedures will have to be revised to include both sets of Code requirements or separate procedures written for each set of Code requirements. Then again in 2018, because of the current CISI Program Second Ten-Year Interval end date, a later ASME Code,Section XI, Edition or Addenda could be required and more changes would have to be made and CNS is trying to alleviate this situation from occurring with this request.

(7-95) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program The current ASME Code requirement in IWA 2430 described above was not used in the implementation of the CISI Program. In the Final Rule change to 10 CFR 50.SSa that required the implementation of ASME Code, Subsection IWE requirements that was published in the Federal Register (61 FR 41303} dated August 8, 1996, the NRC amended its regulations (Rule) to incorporate by reference the 1992 Edition and 1992 Addenda of Subsections IWE and IWL of Section XI of the ASME Code. Only Subsection IWE for Metal Containments applied to CNS because it is a BWR with a Mark I Containment. The amended rule became effective on September 9, 1996, it required the licensees to incorporate the new requirements into their ISi plans and to complete the first period containment inspections within five years (i.e., no later than September 9, 2001).

CNS proceeded to develop their CISI Program and to complete the first period examinations by September 9, 2001. Thus, the CISI Program First Ten-Year Interval began on September 9, 1996 and ended on May 8, 2008. This is actually about a 12 year interval and was due to the 5 years allowed to complete the first period examinations. This CISI Program First Ten-Year Interval set the start date of May 9, 2008 to the end date of May 8, 2018 for the current CISI Program Second Ten-Year Interval.

In the Federal Register (67 FR 60520) dated September 26, 2002 another Final Rule change to 10 CFR 50.SSa was published and in the Supplementary Information in Section 2.2 Section XI, Pages 60521 and 60522, it contains statements supporting the proposed alternative for modifying the CISI Interval. Specifically, the information pointed out that 10 CFR 50.55a(g)(4)(ii) does not prohibit licensees from updating to a later Edition and Addenda of the ASME Code midway through a Ten-Year IWE and IWL examination interval. Additionally, the information advised that licensees wishing to synchronize their 120-month intervals may submit a request in accordance with Section 50.55a(a)(3), which is currently reflected in a new Section 50.SSa(z).

Using a common interval date for both the CISI Program Third Ten-Year Interval and the ISi Program Fifth Ten-Year Interval based on the current requirement to update the ISi Program Fifth Ten-Year Interval on !\/larch 1, 2016 and using the Code of record for that interval, which is to be set on February 28, 2015 [i.e., 12 months prior to the start of the successive interval in accordance with 10 CFR 50.55a(g)(4)(ii)] currently is ASME Code,Section XI, 2007 Edition, 2008 Addenda. Thus, with authorization of this request CNS intends to use the same start and end dates for the CISI Program Third Ten-Year Interval and the ISi Program Fifth Ten-Year Interval along with the same ASME Code,Section XI, 2007 Edition with the 2008 Addenda requirements.

In conclusion, NPPD has determined that authorizing the proposed alternative as described herein provides and acceptable level of quality and safety and does not adversely impact the health and safety of the public.

Proposed Alternative and Basis for Use As an alternative to the full CISI Program Second Ten-Year Interval duration requirements of IWA-2430{b) and IWA-2432 of the ASME Code,Section XI, 2001 Edition, 2003 Addenda, CNS (7-96) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program proposes to start the new CISI Program Third Ten-Year Interval on March 1, 2016 instead of the current start date which would be May 9, 2018. This will permit the subsequent ISi and CISI Programs to share a common inspection interval and to implement a common ASME Code,Section XI Edition and Addenda. The common Code of record for both the CISI Program Third Ten-Year Interval and the ISi Program Fifth Ten-Year Interval will be the ASME Code,Section XI, 2007 Edition, 2008 Addenda.

Since this alternative will shorten the current CISI Program Second Ten-Year Interval by approximately two years CNS has completed all the required CISI examinations for the CISI Second Ten-Year Interval during the last refueling outage RE28 in October 2014 in preparation for the submittal of this request. Examinations performed to date have satisfied the acceptance standards contained in Article IWE-3000. Based on these completed examinations and the regulatory information that has been described above it is concluded that this request has the necessary information to support authorization for its use.

Duration of Proposed Alternative This proposed alternative when authorized will be used at the start of the CISI Program Third Ten-Year Interval and will continue until the end of the extended license period for CNS.

Precedents

1. Limerick Generating Station, 10 CFR 50.55a(a)(3)(i) Alternative Request 13R-01 includes a similar request and was authorized for use on January 24, 2007 under (TAC NOS. MD2727 and MD2728) and (ADAMS Accession No. ML063390103).

(7-97) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 February 12, 2016 Mr. Oscar A. Limpias Vice President-Nuclear and CNO Nebraska Public Power District 72676 648A Avenue Brownville, NE 68321

SUBJECT:

COOPER NUCLEAR STATION - REQUEST FOR RELIEF RC3-01 FOR ALIGNMENT OF INSERVICE INSPECTION AND CONTAINMENT INSERVICE INSPECTION (CAC NO. MF6333)

Dear Mr. Limpias:

By letter dated June 9, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML15167A066), Nebraska Public Power District (NPPD, the licensee) submitted Relief Request RC3-01, to the U.S. Nuclear Regulatory Commission (NRC), for the use of an alternative to the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI, "Rules for lnservice Inspection of Nucl~ar Power Plant Components" for Cooper Nuclear Station (CNS).

• Specifically, pursuant to Title 1O of the Code of Federal Regulations ( 10 CFR) Part 50, paragraph 50.55a(z)(1 ), the licensee is requesting relief to reduce the duration of the CNS second containment inservice inspection (CISI) interval in order to create a common inservice inspection (ISi) interval for CNS, on the basis that the alternative provides an acceptable level of quality and safety. This relief will permit subsequent CISI interval dates to be synchronized with the future ISi intervals. The net effect of this request is to establish one common interval for both the ISi and CISI programs at CNS. The CNS conversion to the common ISi interval start date would commence on March 1, 2016.

• Based on the NRC staff's evaluation of the information provided in the licensee's submittal, the _

staff concludes, as set forth in the enclosed safety evaluation, that the licensee's proposed alternative to the requirements of ASME Code,Section XI, Subarticle IWA-2430, is acceptable

-because it will provide an acceptable level of quality and safety. Accordingly, the staff concludes that the licensee has adequately addressed t~e regulatory requirements set forth in 10 CFR 50.55a(z)(1) and is in compliance with t~e requirements of the ASME Code for which relief was not requested. Therefore, the staff authorizes the licensee to en9 the second CISI program interval early and commence the use of the 2007 Edition with the 2008 Addenda of the ASME Code,Section XI, for ISi of ASME Code Class MC Components as the common Code of record for the CISI program_ third 10-year interval commencing on March 1, 2016.

All other ASME Code,Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC $taff remain applicable, including third party review by the Authorized Nuclear tnservice Inspector.

(7-98) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program

0. limpias If you have any questions, please contact Thomas Wengert at 301-415-4037 or via e-mail at Thomas.Wengert@nrc.gov.

Sincerely,

~/WJ2_~

Meena K. Khanna, Chief Plant Licensing IV-2 and Decommissioning Transition Branch Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosure:

Safety Evaluation cc w/encl: Distribution via Listserv (7-99) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY. COMMISSION WASHINGTON, O.C. 20555--0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REQUEST FOR RELIEF RC3-01 ALIGNMENT OF INSERVICE INSPECTION AND CONTAINMENT INSERVICE INSPECTION NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated June 9, 2015 (Agencywide Document_Access and Management System *

(ADAMS) Accession No. ML15167A066), Nebraska Public Power District (NPPD. the licensee),

requested an alternative to the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI. "Rules for lnservice Inspection of Nuclear Power Plant Components," for the Cooper Nuclear Station (CNS).

Specifically, pursuant to Title 1O of the Code of Federal Regulations (1 O CFR) Part 50, paragraph 50.55a(z)(1 ), the licensee is requesting relief to reduce the duration of the CNS second containment inservice inspection (CISI) interval in order to create a common inservice inspection (ISi) interval for CNS, on the basis that the alternative provides an acceptable level of quality and safety. This relief will permit subsequent GISI interval dates to be synchronized with the future ISi intervals. The net effect of this request is to establish one common interval for both the ISi and GISI programs at CNS. The CNS conversion to the common iSi intervai start date would commence on fv:larch 1, 2016. *

2.0 REGULATORY EVALUATION

Title 1O of the Code of Federal Regulations (1 O CFR) Section 50.SSa(g) specifies that ISi of nuclear power plant components shall be performed in accordance with the requirements of the ASME Code,Section XI.* Section 50.55a(z) of 10 CFR states, in part, that alternatives to the requirements of paragraph (g) may be used, when authorized by the Nuclear Regulatory Commission (NRG), if (1) the proposed alternative would provide an acceptable level of quality and safety, or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

Pursuant to 10 CFR 50.55a(g)(4). components that are classified as Class MC and Class CC pressure retaining components and their integral attachments, must meet the requirements, except the design and access provisions and preservice examination requirements, set forth in Enclosure (7-100) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program

0. Limpias the ASME Code,Section XI, to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations in 10 CFR 50.55a(g)(4) require that inservice examination of components and system pressure tests conducted during successive 120-month inspection intervals must comply with the requirements of the latest edition and addenda of Section XI of the ASME Code, incorporated by reference in Paragraph (a) of 10 CFR 50.55a, 12 months before the start of th.e 120-month inspection interval, subject to the limitations and modifications listed therein.

3.0 TECHNICAL EVALUATION

3.1 ASME Code Components Affected

ASME Section XI, Code Class MC Components.

3.2 Applicable Code Edition and Addenda The licensee stated that the current Code of record for the GISI Program Second 10-Year Interval is the ASME Code,Section XI, 2001 Edition, 2003 Addenda. However, if the requested alternative is approved, the GISI program third 10-year interval start date will be aligned with the ISi program fifth 10-year interva, and synchronized with the ASME Code,Section XI, 2007 Edition, 2008 Addenda requirements of these programs.

3.3 Applicable ASME Code Requirement ASME Code,Section XI, Subarticle IWA*2432 (2001 Edition, 2003 Addenda; IWA-2431, 2007 Edition, 2008 Addenda) requires that each inspection interval consist of a 10-year duration and permits the inspection interval to be reduced or extended by as much as 1 year, provided that successive intervals are not altered by more than 1 year from the original pattern of intervals, except as modified by IWA-2430(d), and IWA-2430(c) for the 2007 Edition, 2008 Addenda.

3.4 Licensee Proposed Alternative and Basis for Use Currently, the CNS fifth 10-year ISi program interval is scheduled to begin on March 1, 2016, while the GISI third 10-year program interval is scheduled to begin on May 9, 2018. CNS proposes to reduce the duration of the GISI third 10-year program interval to coincide with the start of the ISi fifth .10-year program interval. This proposed alternative will permit the subsequent ISi and GISI programs to share a common inspection interval and to implement a common ASME Code Section XI Edition and Addenda (2007 Edition, 2008 Addenda). The licensee stated that since this proposed alternative will shorten the current CISI program second 10-year interval by approximately 2 years, CNS has completed all the required GISI examinations for the GISI second 10-year interval during the last refueling outage (RE28 in October 2014) in preparation for this submittal. The licensee further stated that the examinations performed, to date, have satisfied the acceptance standards contained in Article IWE-3000.

The licensee stated that 10 CFR 50.55a(g)(4)(ii) does not prohibit licensees from updating to a .

later Edition and Addenda of the ASME Code midway through a 10-year IWE and IWL examination interval. The licensee further stated that using the common interv~I date justified above and based on the current ISi program, the ASME Code of record for the fifth 10-year (7-101) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program

0. limpias interval ISi and third 10-year interval CISI programs, is to be set on March 1, 2016. The latest edition and addenda of the ASME Code incorporated by reference in 10 CFA 50.55(a)(1)(ii) of the regulation is the 2007 Edition, 2008 Addenda. Currently, the CISI program second 10-year interval is using the ASME Code,Section XI, 2001 Edition, 2003 Addenda. Thus, CNS will utilize the 2007 Edition, 2008 Addenda of Section XI to develop the ISi program update for the fifth 10-year ISi interval and third 10-year GISI interval. The licensee asserts that the proposed alternative, as described above, provides an acceptable level of quality and safety and does not adversely impact the health and safety of the public.

3.5 NRC Staff Evaluation In the supplementary information contained in Section 2.2 of the Finat Rule (67 FA 60520),

dated September 26, 2002, the NRC staff stated, in part, that 1o CFR 50.55a(g)(4)(ii) does not prohibit licensees from updating to a later edition and addenda of the ASME Code midway through a 10-Year IWE or 5-Year IWL examination interval. Additionally, the staff advised .that licensees wishing to synchronize their 120-month intervals may submit a request in accordance with 10 CFR 50.55a(a)(3), currently reflected in 10 CFR 50.55a(z), to obtain authorization to extend or reduce 120-month intervals.

In the subject alternative request, the licensee proposed an alternative to the requirements of the ASME Code,Section XI, IWA-2430(b) and IWA-2432 requirements. The proposed alternative will reduce the duration of the second 10-year CISI program interval by approximately 26 months (March 1, 2016 versus May 9, 2018). However, ASME Code,Section XI, IWA-2432(d) allows only a 1-year change to the original pattern of the 10-year ISi interval. Therefore, to determine whether the proposed alternative will provide an acceptable level of quality and safety, the NRC staff's review focused on its effect on.the implementation of the ASME Code-required GISI program.

The proposed alternative will align the 10-year GISI interval with the ISi interval starting on March 1, 2016. This will establish a common 10-year interval for both the GISI and the ISi programs at CNS and allow the use of a common ASME Code of record. The common Code of record for this interval, which was set on February 28, 2015 (i.e., 12 months prior to the start of the successive interval in accordance with 10 CFR 50.55a(g)(4)(ii)), currently is ASME Code,Section XI, 2007 Edition, 2008 Addenda.

CNS has different 10-year GISI and ISi program interval dates, which -may re~ult in implementation of different governing code editions and requirements in subsequent \SI program intervals. The 10-year program interval dates are different because the CISI program was not implemented until the NRC's amended rule became effective on September 9, 1996.

The proposed alternative will align and synchronize both 10-year programs and establish the use of the ASME Code,Section XI, 2007 Edition, 2008 Addenda, as the common Code of record. The licensee stated that there are distinct advantages in implementing the same Code requirements in a common interval, such as the reduction of administrative burden in developing and maintaining different sets of procedures and requirements, thus reducing possible errors associated with applying two different ASME Code Editions and Addenda.requirements at the same time. The licensee also stated that any GISI examinations unique to and specifically required for the remainder of the second 10-year interval ha":e already been performed and not def erred to the end of the interval. The licensee stated that it has completed all of the required CISI examinations for the second 10-year interval during the last refueling outage (RE28 in (7-102) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program

0. Limpias October 2014) in preparation of this request, and that the completed examinations performed to date have satisfied the acceptance standards of Article IWE-3000. The licensee stated that upon authorization by the NRC staff of this proposed alternative, CNS intends to use the same start and end dates for the CISI program third 10-year interval and the ISi program fifth 10-year interval along with the same ASME Code,Section XI, 2007 Edition with the 2008 Addenda requirements.

The 2007 Edition, 2008 Addenda, is the latest edition and addenda available and have been previousry reviewed by the NRC staff and incorporated by reference into 10 CFR 50.55a for use by licensees. Since the licensee did not request relief from any of the conditions applicable to the 2007 Edition, 2008 Addenda, any applicable conditions will remain in effect. Since the licensee completed all of the examinations applicable to the second 10-year CISI interval, implementation of this request would not result in any fewer examinations.

The NRC staff review addressed the ability of the licensee to maintain an acceptable level of quality and safety after altering its ISi programs and to ensure integrity of the containment.

Based on these considerations, the staff has determined that the licensee's proposed alternative to allow the CISI program third 10-year interval start date to be aligned with the ISi program fifth 10-year interval and to synchronize the ASME Code,Section XI, 2007 Edition, 2008 Addenda, requirements of these programs (e.g., use of a common ASME Code of record),

with no change to the inspection frequency of examinations, provides reasonable assurance of quality and safety.

4.0 CONCLUSION

Based on the NRC staff's evaluation of the information provided in the licensee's submittal, the staff concludes that the licensee's proposed alternative to the requirements of ASME Code,Section XI, Subarticle IWA-2430, is acceptable because it will provide an acceptable level of quality and safety. Accordingly, the staff concludes that the licensee has adequately addressed the regulatory requirements set forth in 10 CFR 50.55a(z)(1) and is in compliance with the requirements of the ASME Code for which relief was not requested. Therefore, the staff authorizes the licensee to end the second CISI program interval early and commence the use of the 2007 Edition with the 2008 Addenda of the ASME Code. Section Xi, for inservice inspection of ASME Code Class MC Components as the common Code of record for the CISI program third 10-year interval at Cooper Nuclear Station, commencing on March 1, 2016.

All other ASME Code,Section XI, requirements for which relief was not specifically requested and authorized herein by the staff remain applicable, including third party review by the Authorized Nuclear lnservice Inspector.

Principal Contributor: R. Pettis Date: February 12, 2016 (7-103) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program

0. Limpias If you have any questions, please contact Thomas Wengert at 301-415-4037 or via e-mail at Thomas.Wengert@nre.gov.

Sincerely,

/RA/

Meena K. Khanna, Chief Plant Licensing IV-2 and Decommissioning Transition Branch Division of Operating Reactor licensing Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosure:

Safety Evaluation cc w/encl: Distribution via Listserv DISTRIBUTION:

PUBLIC RidsNrr0or!Lpl4-2 Resource RPettis, Nrr/De/Emcb LPL4-2 Reading RidsNrrLAPBlechman Resource Rlyengar, E0O RIV RidsACRS_MailCTR Resource RidsNrrPMCooper Resource RidsNrrDeEmcb Resource RidsRgn4MailCenter Resource ADAMS AccessIon No.: ML16034A303 *b,yemaI*1 d ate d OFFICE NRR/LPL4-2/PM NRR/LPL4-2/LA NRR/DE/EMCB/BC" NRR//LPL4-2/BC NAME TWengert PBlechman Tlupold MKhanna DATE 02/09/16 02/08/16 01/29/16 02/12/16 OFFfCIAL RECORD COPY (7-104) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program 10 CFR 50.SSa Request No. RRS-01 Alternative Weld Overlay Repair for a Dissimilar Metal Weld Joining Nozzle to Control Rod Drive End Cap Proposed Alternative in Accordance with 10 CFR 50.SSa{z)(l)

Acceptable Level of Quality and Safety ASME Code Component(s) Affected Code Class: 1 Examination Categories: B-F Item Number: B5.10 Component Numbers: RCA-BF-1, 5 inch Control Rod Drive Return Cap to Nozzle N9 Weld

Applicable Code Edition and Addenda

ASME Code,Section XI, 2007 Edition, 2008 Addenda.

Applicable Code Requirement

American Society of Mechanical Engineers (ASME)Section XI, IWA-4411 requires repair/replacement activities to be performed in accordance with the Owner's Requirements and the original Construction Code of the component or item. Alternatively, IWA-4411 (a) and (b) allows use of later Editions/Addenda of the Construction Code either in its entirety or portions thereof, Code Cases, and revised Owner Requirements.

IWA-4190(a) requires Code Cases used for repair/replacement activities to be applicable to the Edition and Addenda of Section XI specified for the activity.

IWA-4411(e) permits the use of IWA-4600(b) when welding is to be performed without postwe!d heat treatment required by the Construction Code. !WA-4600{b) provides temper bead welding requirements as an alternative to the welding and postweld heat treatment requirements of the Construction Code. And as an alternative to IWA-4600(b), the requirements of Code Case N-638-4, "Similar and Dissimilar Metal Welding Using Ambient Temperature Machine GTAW Temper Bead Technique", as approved by the NRC, may be used.

IWA-4411(h) permits the use on Non mandatory Appendix Q for the installation of welded overlays for the repair of stress corrosion cracking (SCC) in Class 1, 2 or 3 austenitic stainless steel pipe weldments.

Mandatory Appendix VIII, Supplement 11 provides procedure and personnel qualification requirements for examination of full structural overlaid wrought austenitic piping welds and is required by Nonmandatory Appendix Q.

(7-105) Rev 3.0

Cooper Station 5th ISi &

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Reason for Request

The control rod drive return line cap to nozzle weld is considered susceptible to stress corrosion cracking and is classified as Category Din BWRVIP-75A. Previous ultrasonic examinations of this nozzle weld have not identified any relevant indications. In the event an examination identifies conditions requiring repair, the methods currently available within ASME Section XI do not provide techniques to support a repair without draining the reactor vessel.

Because ASME Section XI, Nonmandatory Appendix Q does not specifically apply to the overlay of dissimilar metal welds and the requirements of IWA-4600(b) or Code Case N-638-4 do not specifically apply to the welding of overlays, an alternative is required to combine the requirements of Nonmandatory Appendix Q and Code Case N-638-4 to provide a complete set of requirements for a full structural weld overlay of the control rod drive return line cap to nozzle weld.

Pursuant to 10 CFR 50.SSa, "Codes and Standards," Paragraph (z)(l), relief is requested from the requirements of ASME Code Section XI as described below:

Non mandatory Appendix Q Historically, similar requests for relief have been based, in part, on Code Case N-504 (various revisions). However, Code Case N-504 was incorporated into ASME Section XI as Nonmandatory Appendix Qin the 2004 Edition with the 2005 Addenda. Nonmandatory Appendix Q, as part of ASME Section XI, is approved by the NRC, by reference, without condition in 10 CFR 50.55a(b)(2).

Like Code Case N-504, Nonmandatory Appendix Q is applicable to weld overlay of austenitic stainless steel material. However an alternative is required because the configuration subject to this request includes the overlay of an SA 508 Class 2 nozzle, Alloy 82 and 182 weld materials, and an SB-166 cap.

Nonmandatory Appendix Q, paragraph Q-2000(a), requires the reinforcement weld metal to be low carbon (0.035 percent maximum) austenitic stainless steel. An alternative is required since a nickel-based weld material (Alloy 52M) will be used.

Non mandatory Appendix Q, paragraph Q-2000(d), requires the first two layers of the weld overlay to have a ferrite content of at least 7.5 FN (Ferrite Number). An alternative is required because the overlay weld material is a nickel based alloy (Alloy 52M) which is fully austenitic.

Nonmandatory Appendix Q, Article Q-4000, requires ultrasonic examination (UT) personnel and procedures to be qualified in accordance with Mandatory Appendix VIII. Mandatory Appendix VIII, Supplement 11 provides requirements for the qualification of procedures and personnel for examination of full structural overlaid wrought austenitic piping welds. The overlay configuration subject to this request is a dissimilar metal weld and not within the scope of (7-106) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Supplement 11. An alternative is required to accept the use of personnel and procedures qualified by the Electric Power Research (EPRI) Performance Demonstration Initiative (PDI) which is based on Code Case N-653-1 with modifications.

Code Case N-638-4 As an alternative to IWA-4600(b), Code Case N-638-4, will be used.

Code Case N-638-4 is listed in Regulatory Guide 1.147, Revision 17, Table 2 as approved by the NRC with two conditions:

(1) Demonstration for ultrasonic examination of the repaired volume is required using representative samples which contain construction type flaws.

(2) The provisions of 3(e)(2) or 3(e)(3) may only be used when it is impractical to use the interpass temperature measurement methods described in 3(e)(1), such as in situations where the weldment area is inaccessible (e.g., internal bore welding) or when there are extenuating radiological conditions.

ASME Section XI, IWA-4190(a) requires Code Cases used for repair/replacement activities to be applicable to the Edition and Addenda specified for the repair/replacement activity. The applicability of Code Case N-638-4 (latest approved by the NRC) is limited to the 2004 Edition of ASME Section XI and the ASME Section XI that is specified for this repair/replacement activity is the 2007 Edition with the 2008 Addenda. An alternative to IWA-4190(a) is required to permit use of Code Case N-638-4 with the 2007 Edition through the 2008 Addenda of ASME Section XI as described in this request.

Code Case N-638-4, paragraphs 4(a), and 4(a)(4) state that all welds (including repair welds) shall be volumetrically examined in accordance with the requirements and acceptance criteria of the Construction Code or ASME Section Ill. An alternative is required to use the examination requirements of paragraph Q-4100 of ASME Section XI, Nonmandatory Appendix Q.

Proposed Alternative and Basis for Use Proposed Alternative The component subject to repair using the requirements described in the request for alternative is described in Table 1. The repair would consist of a full structural welded overlay to replace the original pressure boundary of the dissimilar metal weld identified in Table 1.

(7-107) Rev 3.0

Cooper Station 5th ISi &

3rd Interval CISI Program Table 1 Component Component Description Material 1 Material 2 Maximum Surface Area of Weld Identification Overlay (Ferritic side, in 2)

RCA-BF-1 5 inch Control Rod Drive Nozzle: A-508 SB-166 260 Return Cap to Nozzle N9 Class 2 Weld Nonmandatory Appendix Q applies specifically to austenitic stainless steel piping and weldments. As an alternative CNS proposes the use of Code Case N-638-4 and Nonmandatory Appendix Q to install a weld overlay on a configuration that consists of an A-508, Class 2 low alloy steel nozzle, Alloy 182/82 weld materials, and an SB-166, Alloy 600 nickel alloy cap using ERNiCrFe-7A (Alloy 52M) filler metal.

Appendix Q, paragraph Q-2000(a) requires weld metal used to fabricate weld overlays be low carbon steel (0.035%) austenitic stainless steel. As an alternative, NPPD proposes to perform the weld overlay using ERNiCrFe-7A (Alloy 52M). Therefore, this requirement does not apply.

Appendix Q, paragraph Q-2000(d) requires the weld overlay to consist of at least two austenitic stainless steel weld layers, each layer having an as-deposited delta ferrite content of at least 7.5 FN or 5 FN under certain conditions. As an alternative, NPPD proposes to perform the weld overly using ERNiCrFe-7 A (Alloy 52M) which is purely austenitic. Therefore, the delta ferrite requirement does not apply.

Code Case N-638-4 is included in the latest Revision of Regulatory Guide 1.147 Rev. 17 with the following conditions:

1. Demonstration for ultrasonic examination of the repaired volume is required using representative samples which contain construction type flaws.

• CNS will implement this condition.

2. The provisions of 3(e)(2) and 3(e)(3) may only be used when it is impractical to use the interpass temperature measurement methods described in 3(e)(l), such as in situations where the weldment area is inaccessible (e.g., internal bore welding) or when there are extenuating radiological conditions.

• CNS is not using the provisions of 3(e)(2) or 3(e)(3). In monitoring preheat and interpass temperatures during the application of the overlay, CNS will comply 3(e)(l) of the code case as described below:

"Preheat and interpass temperatures will be measured using a contact pyrometer. In the first three layers, the interpass temperature will be measured every three to five passes. After the first three layers, interpass temperature measurements will be taken every six to ten passes for the subsequent layers. Contact pyrometers will be calibrated in accordance with approved calibration and control program documents."

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Cooper Station 5th ISi &

3rd Interval GISI Program The reason N-638-4 is not applicable to the 2007 Edition through the 2008 Addenda is due to a change in ASME Section XI references that occurred in the 2005 Addenda. To remedy this situation, the ASME Section XI committees created a "Guideline for Cross-Referencing Section XI Cases" which includes "Cross Reference List for Section XI Cases." This was added in the front of the Nuclear Code Case Book. Code Case N-638 has been added to this table showing the correct references for using the Code Case with Editions/Addenda of Section XI later than the 2004 Edition. Using the corrected references in Table 2 ensures N-638-4 is correctly used with the 2007 Edition through the 2008 Addenda of ASME Section XI.

Table 2 References for Alternative Editions and Addenda for Section Xl 1 2008 2007 2006 2005 1989 Edition with 1986 1983 1980 Addenda Edition Addenda Addenda 1991 Addenda Edition Edition Edition through 2004 with with with Edition 1998 1983 1981 Addenda Addenda Winter through through Addenda 1989 1986 through Edition Edition 1983 with with the Edition 1990 1987 with Addenda Addenda 1983 Summer Addenda

/WA- /WA- /WA- /WA- IWA-2210 Visual IWA- IWA- IWA-2200 2200 2200 2200 Examinations 2210 2210 2210

/WA- /WA- /WA- /WA- IWA-2300 Personnel IWA- IWA- IWA-2300 2300 2300 2300 Qualifications 2300 2300 2300 ivVA- lvVA- IIAl/1

/VVM- lvVA- IWA-4000 IWA- !VI./A-  !\A/A-4000 4000 4000 4000 Repair/Replacement 4000& 4000& 4000&

Activities IWA- IWA- IWA-7000 7000 7000

/WA- /WA- /WA- /WA- IWA-4400 Welding, IWA- IWA- IWA-4410 4410 4410 4410 Brazing, Metal 4400 4300 4300

/WA- /WA- /WA- /WA- Removal and 4411 4411 4411 4411 Installation

/WA- /WA- /WA- /WA-4420 4420 4420 4420

/WA- /WA- /WA- /WA-4440 4440 4440 4440 This shows that the applicability of Code Case N-638-4 can be extended to the 2007 Edition 1 The italicized text has been added to the existing Table 1 from Code Case N-638-4.

(7-109) Rev 3.0

Cooper Station 5th ISi &

3rd Interval GISI Program through the 2008 Addenda with the corrected references.

This proposed alternative provides an acceptable methodology for installing and examining a full structural overlay that will provide structural integrity for the life of the plant.

The full structural weld overlay will be designed consistent with the requirements of the following:

1. Nonmandatory Appendix Q "Weld Overlay Repair of Class 1, 2, and 3 Austenitic Stainless Steel Piping Weldments", and

2. IWB-3640, ASME Section XI 2007 through the 2008 Addenda as referenced by Nonmandatory Appendix Q.

The use of an overlay filler material that provides excellent resistance to sec creates an effective barrier to flaw extension. Also, temper bead welding techniques produce excellent toughness and ductility in the weld heat-affected zone (HAZ) of low alloy steel materials and in this case results in compressive residual stresses on the inside surface that help to inhibit further sec of the original weldment. The design of the overlay for the nozzle to end cap weldment uses methods that are standard in the industry. There are no new or different approaches in this overlay design which would be considered either a first-of-a-kind or inconsistent with previous approaches.

The overlay will be designed as a full structural weld overlay in accordance with Nonmandatory Appendix Q. The temper bead welding technique to be implemented in accordance with Code Case N-638-4 will produce a tough, ductile, corrosion-resistant overlay.

Welder Qualification and Welding Procedures - Use of Alloy 52M All 'vvelders, 'vvelding operators, and weld procedures will be qualified in accordance with ASME Section IX and any special requirements of Nonmandatory Appendix Q or Code Case N-638-4.

Qualified personnel under the vendor's welding program will perform the weld overlay repair.

A welding procedure specification utilizing machine GTAW (with cold wire feed) for welding SFA-5.14, ERNiCrFe-7A, UNS N06054, F-No. 43 (commercially known as Alloy 52M) will be used.

This alloy has nominally 30% chromium, which is significantly greater than lnconel 82 (which nominally contains 20% chromium), and has been accepted by the NRC in NUREG-0313, Revision 2, as a resistant material against intergranular stress corrosion cracking (IGSCC) in the boiling water reactor (BWR).

If repairs to the overlay are required, manual GTAW for welding SFA-5.14, ERNiCrFe-7A, UNS N06054, F-No. 43 (commercially known as Alloy 52M) will be used. In the unlikely event of a through-wall defect, UNS W86152, F No. 43 manual shield metal arc weld rod (commercially known as Alloy 152) will be used to seal any defect if it is greater than 0.125 inch from the P-3 nozzle material before beginning the structural weld overlay using GTAW.

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Cooper Station 5th ISi &

3rd Interval GISI Program Welding Wire and Electrodes A consumable nickel based welding wire, highly resistant to sec, is selected as the weld overlay material. This material is Alloy 52M, contains a nominal 30% Cr level that imparts excellent resistance to sec. Where localized repairs are required, Alloy 52M will also be used.

Weld Overlay Design The weld overlay will extend around the full circumference of the end cap to nozzle weldment location in accordance with Nonmandatory Appendix Q. The overlay length will extend across the projected flaw intersection with the outer surface beyond the extreme axial boundaries of the flaw. The design thickness and length will be determined in accordance with the guidance provided in Nonmandatory Appendix Q (paragraph Q-3000(a and ASME Section XI, paragraph IWB-3640, 2007 Edition through the 2008 Addenda for the evaluation methodology for flawed pipe. The overlay will completely cover the area of the flaw and other Alloy 182 or susceptible austenitic stainless steel material with the highly resistant Alloy 52M weld filler material. The overlay length will conform to Nonmandatory Appendix Q, paragraph Q-3000(a}, which satisfies the stress and load transfer requirements .. In order to apply the necessary weld overlay geometry, it will be necessary to weld on the low alloy steel nozzle base material. A temper bead welding approach will be used for this purpose following ASM E Section XI Code Case N-638-4 as described herein. This code case provides for fabricating machine GTAW temper bead weld repairs to P-No. 3 Group No. 3 nozzle base materials at ambient temperature. The temper bead approach was selected because temper bead welding is an acceptable alternative to the requirement for post-weld heat treatment (PWHT} of the HAZ in welds on low alloy steel material. Also, the temper bead welding technique produces excellent toughness and ductility as demonstrated by welding procedure qualification in the HAZ of welds on low alloy steel materials and, in this case, results in compressive residual stresses on the inside surface, which assists in inhibiting SCC. This approach provides a comprehensive weld overlay repair and increases the volume under the overlay that can be examined. Pressure Testing The completed repair shall be pressure tested in accordance with ASME Section XI Nonmandatory Appendix Q, Q-4400. Basis for Use Code Case N-638-4 is approved (with two conditions} for generic use in Regulatory Guide 1.147 Revision 17 and was developed for both similar and dissimilar metal welding using ambient temperature machine GTAW temper bead technique. The welding methodology of Code Case N-638-4 will be followed for the overlay, whenever welding within the 0.125-minimum distance (7-111) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program from the low alloy steel nozzle base material. Nonmandatory Appendix Q is approved in 10 CFR 50.SSa with no conditions and was developed for welding on and using austenitic stainless steel material. An alternative application for nickel-based and low alloy steel materials is proposed due to the specific configuration of this weldment. The weld overlay proposed is austenitic material having a mechanical behavior similar to austenitic stainless steel. It is also compatible with the existing weld and base materials. The methodology of Nonmandatory Appendix Q will be followed with the following exceptions: Alternative to Appendix Q, Requirement Q-2000(a) Q-2000(a) requires the weld overlay to be low carbon (0.35% maximum) austenitic stainless steel. A consumable welding wire highly resistant to sec was selected for the overlay material. This material, designated as UNS N06054, FN 43, is a nickel based alloy weld filler material, commonly referred to as Alloy 52M, and will be deposited using the machine GTAW process with cold wire feed. Alloy 52M contains about 30% chromium, which imparts excellent corrosion resistance to the material. By comparison, lnconel 82 is identified as an sec resistant material in NUREG-0313, Revision 2, and contains nominally 20% chromium, while Alloy 182 has a nominal chromium content of 15%. With its significantly higher chromium content than lnconel 82, Alloy 52M provides and even a higher level of resistance to sec consistent with the requirements of the code case. Therefore, this alternative provides an acceptable level of quality and safety. Alternative to Appendix Q Requirement Q-2000(d) Q-2000(d) requires the first two layers of the weld overlay to have a ferrite content of at least 7.5 FN. The composition of nickel-based Alloy 52M is such that delta ferrite does not form during welding, because Alloy 52M welds are 100% austenitic and contain no delta ferrite due to the high nickel composition (approximately 60% nickel). Consequently, de!ta ferrite measurements will not be performed for this overlay. Therefore, this alternative provides an acceptable level of quality and safety. Alternative to Code Case N-638-4, Paragraph 4(a) and 4(a)(4) Code Case N-638-4, Paragraph 4(a) and 4(a)(4), state that all welds (including repair welds) shall be examined in accordance with the requirements and acceptance criteria of the Construction Code or ASME Section Ill. As an alternative, CNS proposes to examine the weld overlay in accordance with the requirements and acceptance criteria of Nonmandatory Appendix Q, Article Q-4000 of ASME Section XI. The examination requirements and acceptance standards in Non mandatory Appendix Q, paragraph Q-4100 were developed specifically for weld overlays unlike those in Code Case N-638-4. However, the examinations required by Nonmandatory Appendix Q will not be performed until after the three tempering layers have been in place for at least 48 hours as required by 4(a)(2) of Code Case N-638-4. (7-112) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program Nonmandatory Appendix Q, Article Q-4000, requires UT examination procedures and personnel to be qualified in accordance with Appendix VIII of ASME Section XI. Supplement 11 of Appendix VIII addresses qualification requirements for weld overlays, but is limited to full structural overlaid wrought austenitic piping welds. Alternative to 2007 Edition with 2008 Addenda of ASME Section XI, Appendix VIII, Supplement 1L The PDI qualification program for structural overlays does not implement Mandatory Appendix VIII, Supplement 11, but is based on Code Case N-653-1 with modifications. The attached Table 1 provides a comparison of Supplement 11 requirements and the alternate requirements contained within EPRI PDI guidance documents, written in accordance with Code Case N-653-1. Based on the attached Table and as described below, use of the EPRI PDI qualification program for qualification of procedures and personnel as an alternative to ASME Section XI, Mandatory Appendix VIII, Supplement 11 will provide an acceptable level of quality and safety.

• The scope was changed to broaden the applicability of Supplement 11 o The title of ASME Section XI, Supplement 11 in the 2007 Edition with Addenda through 2008 is "Qualification Requirements for Full Structural Overlaid Wrought Austenitic Piping Welds". When originally written, this was accurate for the extent of usage of weld overlay repairs. However, the use of weld overlays has broadened. Weld overlays are now being designed that are not intended as full-structural replacements to the original weld and base material. In addition, weld overlays are now being applied over cast austenitic stainless steel piping welds, as well as wrought. Therefore, the alternatives proposed within this relief request are required broaden the applicability of Supplement 11 as written in the 2007 Edition with Addenda through 2008 of the ASME Section XI Code.
• The names of the grading units \AJere changed from base meta! and overlay fabrication to inservice (ISi) and preservice (PSI) respectively.

o Originally, Supplement 11 was written to cover the examination of weld overlay repairs of BWR recirculation piping welds, which were applied due to sec cracking. At the time, sec cracking was only occurring in the base metal adjacent to the weld (in the heat affected zone). Therefore, for qualification purposes, it was appropriate to refer to the grading units intended to contain cracking in the original pipe as "base metal" grading units. Subsequently, mechanisms have been discovered that cause cracking not only in the base metal, but also in the weld and buttering of these types of welds. And overlays are being applied to welds in PWRs, as well, where the cracking is primarily found in the weld and buttering material. Therefore, it is now more appropriate to call the grading unit for the original piping as an "inservice" grading unit, which is a broad enough term to encompass flaws in the base material or weld material. And since the term for grading units in the original piping was being changed to "inservice", it seemed (7-113) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program appropriate to change the term for grading units intended to contain fabrication related discontinuities in the weld overlay (i.e. bonding and weld cleanliness) to preservice It 11 11 is during the preservice inspection that these indications are expected to be discovered. o The term base metal flaws was changed to service-induced flaws and the term overlay fabrication flaws was changed to fabrication-induced flaws in this revision. o This relief request proposes using "service-induced flaws" as an alternative to the term "base metal flaws" and "fabrication-induced flaws" as an alternative to "overlay fabrication flaws" to describe the flaw types to make them broad enough to encompass all currently recognized degradation mechanisms.

• Provisions have been added for qualification of 11 optimized 11 weld overlays.

o The qualification requirements provided in ASME Section XI, Appendix VIII, Supplement 11 were written strictly for weld overlay repairs designed as full structural replacements for the original weld and base material beneath them. The volumetric examination coverage required for full structural weld overlays was the thickness of the overlay, plus the outer 25% of the original weld and base material. Since that time, the industry has begun to use overlay repairs on larger piping systems, for which full structural overlays are not practical, due to the weight they would add to the piping system and the time it would take to install them. These new 11 optimized 11 weld overlays are thinner and are designed as a partial structural replacement to the original piping. They are only designed as a repair for up to a 75% through-wall circumferential crack, instead of a 100% through-wall crack. Because of this, the volumetric examination requirements can be increased to greater than the outer 25% of the original base material. The proposed alternatives contain provisions to allow for qualification of this extended examination volume.

• Qualification for width sizing of laminar flaws is now addressed.

o The acceptance criteria for laminar flaws in a weld overlay repair are based upon, among other things, the total area of the flaw. However, Supplement 11 only contains provisions for length sizing and is silent on qualification for width sizing. The common technique for both length sizing and width sizing of laminar flaws is to map the edges of the flaw using a 0° (straight beam) transducer. There is virtually no difference in these measurements in terms of axial versus circumferential directions. Therefore, this relief request includes a clarifying sentence for the qualification for both length and width sizing of laminar flaws. Additional NDE Information (7-114) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program The length, surface finish, and flatness of the weld overlay will comply with Q-4100(a) to facilitate examination in accordance with ASME Section XI, Appendix Q. Figure Q-4100-1 describes the examination volume for acceptance examination while Figure Q-4300-1 does the same for preservice and inservice examinations. Preservice and inservice examination requirements are specified in Q-4200 and Q-4300 of Appendix Q. The examinations required by Nonmandatory Appendix Q as described by this request for alternative will provide adequate assurance that the integrity of the proposed weld overlay is consistent with the structural integrity assumptions of the design. Duration of Proposed Alternative This proposed alternative will be used for the Fifth Ten-Year Interval of the lnservice Inspection Program for CNS. Precedents Similar Request for Alternatives previously approved by the NRC.

1. This request is consistent with Rl-35, Revision 1, approved by the NRC for CNS for the 4th Interval, however limited to only RE24 (Fall 2008) (Adams Accession ML080370464, TAC MD8025)

2. Palisades Nuclear Plant- Relief Request Number RR-4-19, Proposed Alternative to the Requirements of ASME Code Case N-638-4 (Adams Accession NO. ML14199A557, TAC NO.

MF3517)

3. Millstone Unit 3 was approved by the NRC in a letter dated May 3, 2007 (Adams Accession ML071210024, TAC MD3379)

AtbrhmPnt tn thic; Relief Request The following attachment is a two column Table providing the ASME Section XI, Appendix VIII, Supplement 11, 2007 Edition with 2008 Addenda requirements as compared with requirements contained within EPRI PDI Supplement 11 demonstration documents, written in accordance with Code Case N-653-1. (7-115) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program This alternative provides qualification requirements for detection and length and depth sizing for both service-induced and fabrication-induced flaws. It is applicable for wrought austenitic. ferritic. or dissimilar metal welds. overlaid with austenitic weld material. 1.0 SPECIMEN REQUIREMENTS SPECIMEN REQUIREMENTS Qualification test specimens shall meet the requirements listed herein, Qualification test specimens shall meet the requirements listed in this unless a set of specimens is designed to accommodate specific limitations document, unless a set of specimens is designed to accommodate specific stated in the scope of the examination procedure (e.g., pipe size, weld limitations stated in the scope of the examination procedure (e.g., pipe joint configuration, access limitations). The same specimens may be used size, weld joint configuration, access limitations). The same specimens to demonstrate both detection and sizing qualification. may be used to demonstrate both detection and sizing qualification. 1.1 General. The specimen set shall conform to the following General - The specimen set shall conform to the following requirements. requirements. Specimens shall have sufficient volume to minimize spurious reflections (a) Specimens shall have sufficient volume to minimize spurious that may interfere with the interpretation process. reflections that may interfere with the interpretation process. (b) The specimen set shall consist of at least three specimens having The specimen set shall consist of at least three specimens having different different nominal pipe diameters and overlay thicknesses. They shall nominal pipe diameters and overlay thicknesses. They shall include the include the minimum and maximum nominal pipe diameters for which minimum and maximum nominal pipe diameters for which the the examination procedure is applicable. Pipe diameters within a range of examination procedure is applicable. Pipe diameters within a range of 0.9 0.9 to 1.5 times a nominal diameter shall be considered equivalent. If the to 1.5 times the nominal diameter shall be considered equivalent. If the procedure is applicable to pipe diameters of 24 in. (600 mm) or larger, the procedure is applicable to pipe diameters of 24 in. {610 mm) or larger, the . specimen set must include at least one specimen 24 in. (600 mm) or specimen set must include at least one specimen 24 in. (610 mm) or larger larger but need not include the maximum diameter. The specimen set but need not include the maximum diameter. The specimen set must shall include at least one specimen with overlay not thicker than 0.1 in. include specimens with overlay not thicker than 0.1 in. {2.5 mm) more (2.5 mm) more than the minimum thickness, and at least one specimen than the minimum thickness, and at least one specimen with overlay not with overlay not thinner than 0.25 in. (6 mm) less than the maximum for thinner than 0.25 in. {6 mm) less than the maximum thickness for which which the examination procedure is applicable. the examination procedure is applicable. (c) The surface condition of at least two specimens shall approximate the The surface condition of at !east two specimens sha!! approximate the roughest surface condition for which the examination procedure is roughest surface condition for which the examination procedure is applicable. applicable." (d) Flaw Conditions Service-induced Flaws (1) Base metal flaws. All flaws must be in or near the butt weld heat- All flaws must be in or near the butt weld heat-affected zone, open to the affected zone, open to the inside surface, and extending at least 75% inside surface. The examination procedure shall specify the examination through the base metal wall. Intentional overlay fabrication flaws shall volume. If the examination procedure specifies an examination volume not interfere with ultrasonic detection or characterization of the base greater than the outer 25% of the base metal wall thickness the metal flaws. At least 70% of the flaws in the detection and sizing tests detection and sizing test sets shall include at least five representative shall be actual cracks. Specimens containing IGSCC shall be used if they flaws suitable to demonstrate the procedure capability in this extended are available. If implantation of actual cracks produces spurious volume. Intentional overlay fabrication flaws shall not interfere with reflectors that are not characteristic of actual flaws, alternative flaws may ultrasonic detection or characterization of the base metal flaws. be used but shall comprise not more than 30% of the total of base Specimens containing IGSCC shall be used when available. material flaws. Alternative flaws, if used, shall provide crack-like reflective characteristics and shall be semielliptical. The tip width of the At least 70% of the flaws in the detection and sizing tests shall be actual alternative flaws shall not exceed 0.002 in. cracks. If implantation of actual cracks produces spurious reflectors that are not characteristic of actual flaws; alternative flaws may be used but shall comprise not more than 30% of the total of base material flaws. (7-116) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Alternative flaws, if used, shall provide crack-like reflective characteristics. The shape of the alternative flaw is intended to simulate the growth pattern of actual flaws and may be semielliptical. The tip width of the alternative flaws shall not exceed 0.002 inches. (2) Overlay fabrication flaws. At least 40% of the flaws shall be noncrack Fabrication-induced Flaws fabrication flaws (e.g., sidewall lack offusion or laminar lack of bond) in the overlay or the pipe-to-overlay interface. At least 20% of the flaws At least 40% of the flaws shall be non-crack fabrication flaws (e.g., shall be cracks. The balance of the flaws shall be of either type. sidewall lack of fusion or laminar lack of bond) in the overlay or the pipe-to-overlay interface. At least 20% of the flaws shall be cracks wholly contained in the overlay. The balance of the flaws shall be of either type. (e) Detection Specimens Detection Specimens (1) At least 20% but less than 40% of the base metal flaws shall be At least 20% but less than 40% of the base metal flaws shall be oriented oriented within +/-20 deg of the pipe axial direction. The remainder shall within +/-20 deg. of the pipe axial direction. The remainder shall be oriented be oriented circumferentially. Flaws shall not be open to any surface to circumferentially. Flaws shall not be open to any surface to which the which the candidate has physical or visual access. candidate has physical or visual access. {2} Specimens shall be divided into base metal and overlay fabrication Specimens shall be divided into base metal fil!l_and overlay fabrication grading units. Each specimen shall contain one or both types of grading 15.!l grading units. Each specimen shall contain one or both types of units. Flaws shall not interfere with ultrasonic detection or grading units. Flaws shall not interfere with ultrasonic detection or characterization of other flaws. characterization of other flaws. ISi Grading Unit. A grading unit designed to include a portion of the original weld and base material and the weld overlay material above it and designed to contain service-induced flaws (cracks) PSI Grading Unit. A grading unit designed to include a portion of the weld overlay, including the interface between the weld overlay and the original weld and base material, and designed to contain fabrication-induced flaw types (e.g. interbead lack of fusion laminar lack of bond, cracks). Each specimen shall contain one or both types of grading units. Flaws shall not interfere with ultrasonic detection or characterization of other flaws. (a)(1) A base metal grading unit includes the overlay material and the ill grading units include the overlay material and the examination volume outer 25% of the original overlaid weld. The base metal grading unit specified in the examination procedure. ill grading units shall extend shall extend circumferentially for at least 1 in. (25 mm) and shall start at circumferentially for at least 1 inch (25 mm) and shall start at the weld the weld centerline and be wide enough in the axial direction to centerline and shall be wide enough in the axial direction to encompass encompass one half of the original weld crown and at least 1/2 in. (13 1/2 of the original weld crown and at least 1/2 inch {13 mm) of the mm) of the adjacent base material. For axially-oriented discontinuities, adjacent base material. The grading units shall be of various sizes. For an the axial dimension of the base metal grading unit may encompass the axially oriented discontinuity, the axial dimension of the base metal original weld crown and at least 1/2 in. (13 mm) of the adjacent base grading unit may encompass the original weld crown and at least 1/2inch materials. (13 mm) of both adjacent base materials. The base metal grading unit shall not include the inner 75% of the overlaid weld and base metal. or base metal-to-overlay interface. For axially-oriented discontinuities, the axial dimension of the base metal grading unit may encompass the original weld crown and at least 1/2 in. (13 mm) of the adjacent base metal. (2) When base metal flaws penetrate into the overlay material, the base If service-induced flaws penetrate into the overlay material, the base metal grading unit shall not be used as part of any overlay grading unit. metal grading unit fil!1 shall not be used as part of any~ grading unit. (3) Sufficient unflawed overlaid weld and base metal shall exist on all Sufficient unflawed overlaid weld and base metal shall exist on all sides of (7-117) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program sides of the grading unit to preclude interfering reflections from adjacent the grading unit to preclude interfering reflections from adjacent flaws. flaws. (b}(l) An overlay fabrication grading unit shall include the overlay PSI grading unit shall include the overlay material and the overlay-to-material and the base metal-to-overlay interface for a length of at least 1 component interface for a length of at least 1 inch (25 mm). in. (25 mm). (2) Overlay fabrication grading units designed to be unflawed shall be PSI grading units designed to be unflawed shall be separated by unflawed separated by unflawed overlay material and unflawed base metal-to- overlay material and unflawed overlay-to-component interface for at overlay interface for at least 1 in. (25 mm) at both ends. Sufficient least 1 inch (25 mm) at both ends. Sufficient unflawed overlaid weld and unflawed overlaid weld and base metal shall exist on both sides of the base metal shall exist on both sides of the PSI grading unit to preclude overlay fabrication grading unit to preclude interfering reflections from interfering reflections from adjacent flaws. The specific area used in one adjacent flaws. The specific area used in one overlay fabrication grading PSI grading unit shall not be used in another overlay ~fabrication unit shall not be used in another overlay fabrication grading unit. grading unit. PSI grading units need not be spaced uniformly about the Overlay fabrication grading units need not be spaced uniformly about specimen. the specimen. (3) Detection sets shall be selected from Table VIII-S2-1. The minimum Detection sets shall be selected from Table VIII-S2-1. The detection detection sample set is five flawed base metal grading units, ten unflawed sample sets shall contain at least ten flawed ISi grading units and five base metal grading units, five flawed overlay fabrication grading units, flawed PSI grading units. Additionally. for each type of grading unit, the and ten unflawed overlay fabrication grading units. For each type of sets shall contain at least twice as many unflawed as flawed grading grading unit, the set shall contain at least twice as many unflawed as units. For initial procedure qualification, detection sets shall include the flawed grading units. For initial procedure qualification, detection sets equivalent of three personnel qualification sets. To qualify new values of shall include the equivalent of three personnel qualification sets. To essential variables, at least one personnel qualification set is required. qualify new values of essential variables, at least one personnel qualification set is required. (f) Sizing Specimen [1.l(f}} Section 6.4 (1) The minimum number of flaws shall be ten. At least 30% of the flaws Sizing sample sets shall contain at least ten flaws. At least 30% of the shall be overlay fabrication flaws. At least 40% of the flaws shall be open flaws shall be overlay fabrication-induced flaws. At least 40% of the flaws to the inside surface. To assess sizing capabilities, sizing sets shall shall be service-induced flaws and shall be open to the inside surface. contain a representative distribution of flaw dimensions. For initial Sizing sets shall contain a representative distribution of flaw dimensions procedure qualification, sizing sets shall include the equivalent of three that cover the examination volume specified in the examination personnel qualification sets. To qualify new values of essential variables, procedure. For initial procedure qualification, sizing sets shall include the at !east one personnel qualification set is required. equivalent of three personnel qualification sets. To qual~fy new values of essential variables, at least one personnel qualification set is required. (2) At least 20% but less than 40% of the flaws shall be oriented axially. At least 20% but less than 40% of the flaws shall be oriented axially. The The remainder shall be oriented circumferentially. Flaws shall not be open remainder shall be oriented circumferentially. Flaws shall not be open to to any surface to which the candidate has physical or visual access. any surface to which the candidate has physical or visual access. (3) Base metal flaws used for length sizing demonstrations shall be Service-induced flaws used for length sizing demonstrations shall be oriented circumferentially. oriented circumferentially. (4) Depth sizing specimen sets shall include at least two distinct locations Depth sizing specimen sets shall include at least two distinct locations where a base metal flaw extends into the overlay material by at least 0.1 where a service-induced flaw extends into the overlay material by at least in. (2.5 mm) in the through-wall direction. 0.1 inches (2.5 mm) in the through-wall direction. 2.0 CONDUCT OF PERFORMANCE DEMONSTRATIONS The specimen inside surface and identification shall be concealed from The specimen inside surface and identification shall be concealed from the the candidate. All examinations shall be completed prior to grading the candidate. All examinations shall be completed prior to grading the results results and presenting the results to the candidate. Divulgence of and presenting the results to the candidate. Divulgence of particular particular specimen results or candidate viewing of unmasked specimens specimen results or candidate viewing of unmasked specimens after the after the performance demonstration is prohibited. The overlay performance demonstration is prohibited. fabrication flaw test and the base metal flaw test may be performed (7-118) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program separately. The PSI test and the §1. test may be performed separately. 2.1 Detection Test. Flawed and unflawed grading units shall be randomly Flawed and unflawed grading units shall be randomly mixed. Although mixed. Although the boundaries of specific grading units shall not be the boundaries of specific grading units shall not be revealed to the revealed to the candidate, the candidate shall be made aware of the type ca~~~~~~~~~~~~~~M~~ or types of grading units (base or overlay fabrication) that are present for grading units (§1. orfg) that are present for each specimen. each specimen. 2.2 Length Sizing Test Length Sizing Test (a) The length sizing test may be conducted separately or in conjunction Length sizing tests may be conducted separately or in conjunction with the with the detection test. detection test. (b) If the length sizing test is conducted in conjunction with the detection If the length sizing test is conducted in conjunction with the detection test test and the detected flaws do not satisfy the requirements of 1.l(f), and the detected flaws do not satisfy the requirements for the sizing additional specimens shall be provided to the candidate. The regions specimens detailed above. additional specimens shall be provided to the containing a flaw to be sized shall be identified to the candidate. The candidate. The regions containing a flaw to be sized shall be identified to candidate shall determine the length of the flaw in each region. the candidate. The candidate shall determine the length of the flaw in each region. (c) For a separate length sizing test, the regions of each specimen For a separate length sizing test, the regions of each specimen containing containing a flaw to be sized shall be identified to the candidate. The a flaw to be sized shall be identified to the candidate. The candidate shall candidate shall determine the length of the flaw in each region. determine the length of the flaw in each region. (d) For flaws in base metal grading units, the candidate shall estimate the For flaws in §1. grading units, the candidate shall estimate the length of length of that part of the flaw that is in the outer 25% of the base metal that part of the flaw that part of the flaw that is in the examination wall thickness. volume specified in the examination procedure. 2.3 Depth Sizing Test Depth Sizing Test (a) Depth sizing consists of measuring the metal thickness above the flaw Depth sizing consists of measuring the metal thickness above the flaw (i.e., remaining ligament), and may be conducted separately or in (i.e., remaining ligament) and may be conducted separately or in conjunction with the detection test. conjunction with the detection test. (b) If the depth sizing test is conducted in conjunction with the detection If the depth sizing test is conducted in conjunction with the detection test test and the detected flaws do not satisfy the requirements of 1.l(f), and the detected flaws do not satisfy the requirements for the sizing additional specimens shall be provided to the candidate. The regions specimens above, additional specimens shall be provided to the candidate. containing a flaw to be sized shall be identified to the candidate. The The regions containing a flaw to be sized shall be identified to the candidate shall determine the maximum depth of the flaw in each region. candidate. The candidate shall determine the maximum depth of the flaw in each region. (c) For a separate depth sizing test, the regions of each specimen For a separate depth sizing test, the regions of each specimen containing containing a flaw to be sized shall be identified to the candidate. The a flaw to be sized shall be identified to the candidate. The candidate shall candidate shall determine the maximum depth of the flaw in each region. determine the maximum depth of the flaw in each region. 3.0 ACCEPTANCE CRITERIA ACCEPTANCE CRITERIA 3.1 Detection Acceptance Criteria. Procedure Qualification (a) Examination procedures shall be qualified as follows: In addition to the specimen and performance demonstration requirements, procedure qualification shall satisfy the following: (1) All flaws within the scope of the procedure shall be detected, and the results of the performance demonstration shall satisfy the acceptance The specimen set shall include the equivalent of at least three personnel (7-119) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program demonstrations may be combined to satisfy these requirements. (2) At least one successful personnel demonstration shall be performed meeting the acceptance criteria defined in 3.l(b). At least one successful personnel demonstration shall be performed Delectability of all flaws in the procedure qualification test set within the scope of the procedure shall be demonstrated. Length and depth sizing shall meet the requirements of the below paragraphs. (b) Examination equipment and personnel shall be considered qualified Examination equipment and personnel shall be considered qualified for for detection if the results of the performance demonstration satisfy the detection if the results of the performance demonstration satisfy the acceptance criteria of Table VIII-S2-1 for both detection and false calls. acceptance criteria of Table VIII-S2-1 for both detection and false coils. If the procedure is intended to be used to examine greater than the upper 25% of the original pipe volume. a candidate for personnel qualification shall not fail to detect more than one of the flaws located in the extended volume (c) The criteria in 3.l(a) and 3.l(b) shall be satisfied separately by the The detection test. length sizing test and depth sizing test criteria shall be demonstration results for base metal grading units and by those for satisfied separately by the demonstration results for j2J_grading units and overlay fabrication grading units. by those for 51..grading units. 3.2 Sizing Acceptance Criteria. Examination procedures, equipment, and Examination procedures, equipment, and personnel are qualified for personnel are qualified for sizing when the results ofthe performance ~ sizing demonstration satisfy the following criteria. lf.the RMS error of the circu mferentia I flaw length measurements, (a) The RMS error of the flaw length measurements, as compared to the compared ta the true circumferential flaw lengths, is not more than 0. 75 true flaw lengths, is less than or equal to 0.75 in. (19 mm). The length of in.{19mm). The length of a service-induced.flaw is measured lD. a base metal flaw is measured at the 75% through-base-metal position. accordance with the length sizing test requirements. Examination procedures, equipment, and personnel qualified for length sizing in accordance with the criteria above are considered qualified for both length and width sizing of laminar flaws. (b} The RMS error of the flaw depth measurements; as compared to the Examination orocedures. equioment and oersonnel are oualified for true flaw depths, is less than or equal to 0.125 in. (3.2 mm). depth sizing if the RMS error of the flaw depth measurements, as compared to the true flaw depths, is less than or equal to 0.125 in {3.2 mm). Note (1) The "bolded" words contained within the ASME Section XI, Appendix VIII, Supplement 11 requirements are used to highlight the differences between the Supplement 11 and EPRI PDI requirements. Note (2) The "italicized" words contained within the EPRI POI Program PDI alternative requirements, are the same as found in Section XI, 2007 Edition with 2008 Addenda, Appendix VIII, Supplement 11 requirements. The "non-italicized/underlined" words are alternate to the wording/requirements of Section XI, 2007 Edition with 2008 Addenda, Appendix VIII, Supplement 11. (7-120) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 February 24, 2016 Mr. Oscar A Umpias Vice President-Nuclear and CNO Nebraska Public Power District 72676 648A Avenue Brownville, NE 68321

SUBJECT:

COOPER NUCLEAR STATION - REQUEST FOR RELIEF RR5-01, ALTERNATIVE WELD OVERLAY REPAIR FOR A DISSIMILAR METAL WELD JOINING NOZZLE TO CONTROL ROD DRIVE END CAP IN LIEU OF SPECIFIC AMERICAN SOCIETY OF MECHANICAL ENGINEERS BOILER AND PRESSURE VESSEL CODE REQUIREMENTS {CAC NO. MF6332)

Dear Mr. Umpias:

By letter dated June 9, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML15167A066), as supplemented by letter dated October 29, 2015 (ADAMS Accession Number ML15310A059), Nebraska Public Power District (NPPD, the licensee) requested an alternative to the requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code), Section XI, IWA-4000, "Repair/Replacement Activities," and Nonmandatory Appendix Q, "Weld Overlay Repair of Classes 1, 2, and 3 Austenitic Stainless Steel Piping Weldments," at Cooper Nuclear Station (CNS). Pursuant to Title 10 of the Code of Federal Regulations (1 O CFR) 50.55a{z){1 ), the licensee proposed an alternative to codes and standards requirements on the basis that the alternative would provide an acceptable level of quality and safety. Specifically, Relief Request RR5-01 proposes an lnservice Inspection (ISi} alternative to install a full structural weld overlay (FSWOL) on the control rod drive nozzle to cap weld at CNS during Refueling Outage 29, which is projected to occur during the fifth 10-year ISi interval. The licensee intends to use the ISi alternative only as a contingency in the event that a flaw is discovered in the control rod drive nozzle to cap weld resulting in the need for a FSWOL. The U.S. Nuclear Regulatory Commission (NRC) staff has reviewed the subject relief request and concludes, as set forth in the enclosed safety evaluation, that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z){1) and is in compliance with the requirements of the ASME Code, Section XI for which relief was not requested. Therefore, the NRC staff authorizes the use of Relief Request RR5-01 at CNS as a contingency, if a flaw is discovered during Refueling Outage 29. The proposed alternative is authorized for the fifth 10-Year IS I interval. AU other requirements of the ASME Code, Section XI, for which relief has not been specifically requested and authorized by NRC staff remain applicable, including a third party review by the Authorized Nuclear lnservice Inspector. (7-121) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program

0. Limpias If you have any questions, please contact Thomas Wengert at 301-415-4037 or via e-mail at Thomas.Wengert@nrc.gov.

Sincerely, Meena K. Khanna, Chief Plant Licensing IV-2 and Decommissioning Transition Branch Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-298

Enclosure:

Safety Evaluation cc w/encl: Distribution via Listserv (7-122) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REQUEST FOR RELIEF RR5-01 ALTERNATIVE WELD OVERLAY REPAIR FOR A DISSIMILAR METAL WELD JOINING NOZZLE TO CONTROL ROD DRIVE END CAP NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By fetter dated June 9, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML15167A066), as supplemented by letter dated October 29, 2015 (ADAMS Accession Number ML15310A059), Nebraska Public Power District (NPPD, the licensee) requested an alternative to the requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code), Section XI, IWA-4000, "Repair/Replacement Activities." and Nonmandatory Appendix Q, "Weld Overlay Repair of Classes 1, 2, and 3 Austenitic Stainless Steel Piping Weldments," at Cooper Nuclear Station (CNS). Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z)(1 ), the licensee proposed an alternative to codes and standards requirements on the basis that the alternative would provide an acceptable level of quality and safety. Specifically, Relief Request RRS-01 proposes an inservice Inspection (ISi) alternative to install a full structural weld overlay (FSWOL) on the control rod drive nozzle to cap weld at CNS during Refueling Outage 29, which is projected to occur during the fifth 10-year ISi interval. The licensee intends to use the ISi alternative only as a contingency in the event that a flaw is discovered in the control rod drive nozzle to cap weld resulting in the need for an FSWOL. CNS currently has no weld overlays installed.

2.0 REGULATORY EVALUATION

The licensee requested authorization of an alternative to the requirements of Article IWA-4000 of the ASME Code, Section XI, pursuant to 10 CFR 50.55a(z)(1). Adherence to Section XI of the ASME Code is mandated by 10 CFR 50.55a(g)(4), which states, in part, that ASME Code crass 1, 2, and 3 components (including supports) will meet the Enclosure (7-123) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program requirements, except the design and access provisions and the pre-service examination requirements, set forth in the ASME Code, Section XI. The regulation in 10 CFR 50.55a(z) states, in part, that alternatives to the requirements of paragraph (g) of 10 CFR 50.55a may be used, when authorized by the U.S. Nuclear Regulatory Commission (NRC), if the licensee demonstrates that: (1) the proposed alternative provides an acceptable level of quality and safety, or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. The proposed alternative must be submitted and authorized prior to implementation. Based on the above, and subject to the following technical evaluation, the NRC staff finds that regulatory authority exists for the licensee to request the use of an alternative and the NRC to authorize the proposed alternative.

3.0 TECHNICAL EVALUATION

3.1 ASME Code Components Affected

Code Class: ASME Section XI Code Class 1 Examination Categories: B-F Item Number: B5.10 Component Numbers: RCA-BF-1, 5 inch Control Rod Drive Return Cap to Nozzle N9 Weld 3.2 Applicable Code Edition and Addenda ASME Code, Section XI, 2007 Edition through 2008 Addenda. 3.3 Applicable Code Requirements ASME Section XI, Article lWA-4000, "Repair/Replacement Activities" provides requirements for repair or replacement of Class 1, 2 or 3 components. Article IWA-4400, "Welding, Brazing, Metal Removal, Fabrication. and Installation" provides requirements for repair/replacement of Class 1, 2 or 3 components by welding. ASME Section XI, IWA-4411 requires repair/replacement activities to be performed in accordance with the Owner's Requirements and the original Construction Code of the component or item. Alternatively, IWA-4411(a) and (b) allows use of later Editions and Addenda of the Construction Code either in its entirety or portions thereof, Code Cases, and revised Owner Requirements. IWA-4411(e) permits the use of IWA-4600(b) when welding is to be performed without postweld heat treatment (PWHT) required by the Construction Code. IWA-4411 (h) permits the use of Nonmandatory Appendix Q for the installation of welded overlays for the repair of stress corrosion cracking (SCC) in Class 1, 2 or 3 austenitic stainless steel pipe weldments. ASME Section XI, IWA-4190(a) requires Code Cases used for repair/replacement activities to be applicable to the Edition and Addenda of Section XI specified for the activity. (7-124) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program IWA-4600(b) provides te.mper bead welding requirements in accordance with IWA-4620, IWA-4630 and IWA-4640 as an alternative to the welding and postweld heat treatment requirements of the Construction Code. NRC-approved Code Cases may also be used as an alternative to the welding and postweld heat treatment requirements of the Construction Code. ASME Section XI, Code Case N-638-4, "Similar and Dissimilar Metal Welding Using Ambient Temperature Machine GTAW [Gas Tungsten Arc Welding] Temper Bead Technique," may be used as an alternative to following the preheat and PWHT requirements of IWA-4400. Code Case N-638-4 is the latest version of this Code Case approved by the NRC, but is not applicable for editions of the Code later than 2004. Paragraph 2.1 of Code Case N-638-4 provides the requirements for qualifying procedures used to perform temper bead welding of similar and dissimilar metal weld joints using the ambient temperature machine GTAW technique. Paragraph 2.1.c of Code Case N-638-4 requires that consideration shall be given to the effects of irradiation on the properties of material for applications in the core belt line region of the reactor vessel. Paragraphs 2.1.g, 2.1.h, 2.1.i and 2.1.j of Code Case N-638-4 contain the requirements for performing Charpy V-notch impact testing of procedure qualification test assemblies of ferritic materials. ASME Section XI Mandatory Appendix VIII provides procedure and personnel qualification requirements for ultrasonic examination and is required by Nonmandatory Appendix Q. Appendix VI 11, Supplement 11 is applicable to full structural overlaid wrought austenitic piping welds. Appendix VIII, Supplement 11 is not applicable to overlays of dissimilar metal welds. ASME Section XI Nonmandatory Appendix Q, "Weld Overlay Repair of Classes 1, 2, and 3 Austenitic Stainless Steel Piping Weldments" provides guidance for the weld overlay repair of austenitic stainless steel pipe weldments. Appendix Q is not applicable to the repair of weldments involving alloy steel and/or austenitic nickel-based alloys. 3.4 Reason for Request The licensee stated that the control rod drive return line cap to nozzle weld (which is a dissimilar metal vveld) is considered susceptible to SCC and is classified as Category Din BWRV!P-75A "BWR [Boiling-Water Reactor] Vessel and Internals Project Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules." Category D welds are defined in BWRVIP-75A as welds that are susceptible to intergranular stress corrosion cracking (IGSCC), a subset of sec, which have not been treated with an IGSCC remedy, but for which cracks have not been reported. The licensee stated that previous ultrasonic examinations of this component weld have not identified any relevant indications. In the event an examination during Refueling Outage 29 identifies conditions requiring repair, such as SCC, the methods currently available within ASME Section XI do not provide techniques to support a repair without draining the reactor vessel. The licensee proposes to perform a FSWOL, as specified by Nonmandatory Appendix Q, for the repair of Class 1 austenitic stainless steel pipe weldments in the event that SCC is found in the subject component weld during Refueling Outage 29. The licensee proposes to use weld material Alloy 52M to perform this FSWOL. The licensee further stated that, because ASME Section XI, Nonmandatory Appendix Q does not specifically apply to the overlay of dissimilar metal welds, or materials other than austenitic stainless steel, and because the requirements of IWA-4600(b) or Code Case N-638-4 do not specifically apply to the welding of overlays, an alternative is required to combine the (7-125) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program requirements of Nonmandatory Appendix Q and Code Case N-638-4 to provide a complete set of requirements for a FSWOL of the control rod drive return line cap to nozzle weld. Also, the following requirements of Nonmandatory Appendix Q cannot be applied to the subject dissimilar metal weld because they were not intended for dissimilar metal welds made with Alloy 52M weld material:

• Nonmandatory Appendix Q, paragraph Q-2000(a), requires the reinforcement weld metal to be low carbon (0.035 percent maximum) austenitic stainless steel.
• Nonmandatory Appendix Q, paragraph Q-2000(d), requires the first two layers of the weld overlay to have a ferrite content of at least 7.5 Ferrite Number (FN).

ASME Section XI, IWA-4190(a) requires Code Cases used for repair/replacement activities to be applicable to the Edition and Addenda specified for the repair/replacement activity. The applicability of Code Case N-638-4 (latest approved by the NRC) is limited to the 2004 Edition of ASME Section XI but the ASME Section XI edition that is specified for this repair/replacement activity is the 2007 Edition with the 2008 Addenda. The limitation of Code Case N-638-4 applicability to the 2004 Edition of Section XI is not due to any technical limitations of Code Case N-638-4, but rather due to a change in Section XI numbering that occurred in the 2005 Addendum. An alternative to IWA-4190(a) is required to permit use of Code Case N-638-4 with the 2007 Edition through the 2008 Addenda of ASME Section XI as described in this request. The licensee noted that Code Case N-638-4, paragraphs 4(a), and 4(a)(4) state that all welds (including repair welds) shall be volumetrically examined in accordance with the requirements and acceptance criteria of the Construction Code or ASME Section Ill. An alternative is required to use the examination requirements of Article Q-4100 of ASME Section XI, Nonmandatory Appendix Q. 35 Proposed Alternative The licensee proposes to repair the following component at CNS, as needed, to correct any relevant indications identified by ISi during Refueling Outage 29. The repair, if needed, would consist of a FSWOL to replace the original pressure boundary of the dissimilar metal weld identified below. Component Component Nozzle End Cap Maximum Identification Description Material Material Surface Area Of Overlay RCA-BF-1 5 inch Control A-508, Class 2 SB-166 260 square Rod Drive (low alloy steel) (lnconel Alloy inches on the Return Line 600) f erritic side End Cap to Nozzle N9 Weld (7-126) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program In its letter dated June 9, 2015, the licensee stated, in part, that: The weld overlay [if needed], will extend around the full circumference of the end cap to nozzle weldment location in accordance with Nonmandatory Appendix Q. The overlay length will extend across the projected flaw intersection with the outer surface beyond the extreme axial boundaries of the flaw. The design thickness and length will be determined in accordance with the guidance provided in Nonmandatory Appendix Q (paragraph Q-3000(a)) and ASME Section XI, paragraph IWB-3640, 2007 Edition through the 2008 Addenda for the evaluation methodology for flawed pipe. The overlay will completely cover the area of the flaw and other Alloy 182 or susceptible austenitic stainless steel material with the highly resistant Alloy 52M weld filler material. The overlay length will conform to Nonmandatory Appendix Q, paragraph Q-3000(a), which satisfies the stress and load transfer requirements. The licensee further states that Nonmandatory Appendix Q applies specifically to austenitic stainless steel piping and weldments. As an alternative, the licensee proposes to use Code Case N-638-4 and Nonmandatory Appendix Q to install a weld overlay on a configuration that consists of an A-508, Class 2 low alloy steel nozzle, Alloy 182/82 weld materials, and an S8-166, Alloy 600 nickel alloy cap using ERNiCrFe-7 A (Alloy 52M) filler metal. As needed for welding within 0.125 inch from the low alloy steel nozzle material, the licensee proposes to use Code Case N-638-4 with the condition that demonstration for ultrasonic examination of the repaired volume is required using representative samples, which contain construction type flaws. In monitoring preheat and interpass temperatures during the application of the overlay, the licensee proposes to comply with 3(e)(1) of the Code Case, which means that the interpass temperature will be directly measured during the welding process. The conditions proposed by the licensee for the use of Code Case N-638-4 are consistent with the conditions imposed by the NRC in Regulatory Guide (RG) 1.147, Revision 17, "lnservice Inspection Code Case Acceptability ASME Section XI, Division 1 (ADAMS Accession No. ML13339A689). Appendix Q, Article Q-2000(a) requires weld metal used to fabricate weld overlays be low carbon steel (0.035%) austenitic stainless steel. As an alternative, the licensee proposes to perform the weld overlay using ERNiCrFe-7 A (Alloy 52M) which is an austenitic nickel based alloy. The licensee stated that Appendix Q, Article Q-2000(d) requires the weld overlay to consist of at least two austenitic stainless steel weld layers, each layer having an as-deposited delta ferrite content of at least 7.5 FN, or 5 FN under certain conditions. As an alternative, the licensee proposes to perform the weld overlay using ERNiCrFe-7A (Alloy 52M), which is purely austenitic. Since the alternative weld deposits are purely austenitic, the licensee maintains that the delta ferrite requirements of Appendix Qare not applicable. In its letter dated June 9, 2015, the licensee further states, in part: Code Case N-638-4, Paragraphs 4(a) and 4(a)(4), state that all welds (including repair welds) shall be examined in accordance with the requirements and acceptance criteria of the Construction Code or ASME Section Ill. As an alternative, CNS proposes to examine the weld overlay in accordance with the requirements and acceptance criteria of Nonmandatory Appendix Q, (7-127) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Article Q-4000 of ASME Section XI. The examination requirements and acceptance standards in Nonmandatory Appendix Q, [Article] Q-4100 were developed specifically for weld overlays unlike those in Code Case N-638-4. However, the examinations required by Nonmandatory Appendix Q will not be performed until after the three tempering layers have been in place for at least 48 hours as required by [paragraph] 4(a)(2) of Code Case N-638-4. ASME Section XI Mandatory Appendix VIII with Supplement 11, is applicable to full structural overlaid wrought austenitic piping welds. As an alternative, the licensee proposes to use the Electric Power Research Institute (EPRI) Performance Demonstration Initiative (POI) qualification program, as described in the licensee's submittal dated June 9, 2015. ASME Section XI Nonmandatory Appendix Q, "Weld Overlay Repair of Classes 1, 2, and 3 Austenitic Stainless Steel Piping Weldments," provides guidance for the weld overlay repair of austenitic stainless steel pipe weldments. As an alternative, the licensee proposes to use Nonmandatory Appendix Q for the FSWOL of the subject dissimilar metal weld. 3.6 Basis for Use Code Case N-638-4 is approved (with Conditions) for generic use in RG 1.147, Revision 17, and was developed for both similar and dissimilar metal welding using ambient temperature machine GTAW temper bead technique. The licensee proposes to follow the approved welding methodology of this Code Case (consistent with the conditions imposed by RG 1.147) for the overlay, whenever welding within the 0.125-minimum distance from the low alloy steel nozzle base material. The licensee stated that nonmandatory Appendix Q is approved in 10 CFR 50.55a with no . conditions and was developed for welding on and using austenitic stainless steel material. The weld overlay proposed is austenitic nickel-based material having a mechanical behavior similar to austenitic stainless steel. It is also compatible with the existing weld and base materials.

 ~7 v.,     Duration of Proposed Alternative This proposed alternative will be used for the Fifth 10-Year Interval of the ISi Program for CNS.

4.0 NRC STAFF EVALUATION 4.1 Weld Description The licensee stated that the control rod drive return line cap to nozzle weld is classified as Category Din BWRVIP-75A. Per BWRVIP-75A, Category D welds are classified as not resistant to IGSCC, with no mitigating stress improvement performed, but with no reported cracking. The licensee proposes to apply Alloy 52M FSWOL to this weld if SCC is found during the Refueling Outage 29 inspection of the weld. In nickel-based alloys, increasing levels of chromium are associated with increasing level of corrosion resistance. Alloy 52M contains nominally 28 percent chromium, which imparts excellent corrosion resistance to the material. By comparison, Alloy 82 contains nominally 20 percent chromium, while Alloy 182 has a nominal chromium content of 15 percent. Alloy 82 is considered resistant to SCC, but (7-128) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program Alloy 182, with its lower chromium content, is considered to be less resistant to sec. Operating experience indicates that alloy 182 welds are not immune to SCC. The control rod drive return line cap to nozzle weld is a dissimilar metal weld, which joins a low alloy steel (SA 508, Cl 2) nozzle to a nickel-based alloy (Alloy 600) end cap. The licensee stated in its submittals that the existing weld consists of both nickel-based Alloys 82 and 182. In its response to Request for Information (RAl)-3, dated October 29, 2015, the licensee clarified that, although Alloy 82 weld metal was used to weld the cap to the nozzle, Alloy 182 is still present in the weld joint from a previous weld that was not completely removed when that weld joint was cut. Also, as discussed in the licensee's response to RAl-3, the profile of the existing weld joint is as follows: a low alloy steel nozzle is joined to Alloy 182 weld metal (fufl penetration); the Alloy 182 weld metal (full penetration) is joined to Alloy 82 weld metal (full penetration); and, the Alloy 82 weld metal (full penetration) is joined to the nickel-based alloy end cap. The licensee proposes to use Alloy 52M austenitic nickel-based alloy weld material for the overlay. Based on the weld joint description provided by the licensee, the overlay would cover the following materials: alloy steel (SA 508, Cl 2) base material, Alloy 182 weld material, Alloy 82 weld material, and Alloy 600 base material. Although there is no Code section or NRC-approved Code Case with specific requirements for performing FSWOL with this material combination, it is generally accepted that Alloy 52M is compatible with this material combination and the Code would allow this overlay, provided the welding procedure is properly qualified. 4.2 Code Welding Requirements The application of this FSWOL falls under the requirements of Article IWA-4400 for welding repairs. When performing weld repairs, a licensee may opt to follow the temper bead welding requirements of Article IWA-4600(b) or the NRC-approved Code Case as an alternative to the welding and postweld heat treatment requirements of the Construction Code. In this request, the licensee has proposed to follow the temper bead welding requirement of Code Case N-638-4, which was approved by the NRC staff in RG 1.147. Although a licensee may opt to perform welding repairs in accordance with the temper bead welding requirements of NRC-approved Code Case N-638-4, NPPD must request NRC-approval for the proposed FSWOL since this Code Case in not applicable to the Edition and Addenda specified for the repair/replacement activity. As stated previously in this safety evaluation (SE), the limitation of Code Case N-638-4 applicability to the 2004 Edition of Section XI is not due to any technical limitation of Code Case N-638-4, but rather due to a change in Section XI numbering that occurred in the 2005 Addendum. In the proposed alternative, the licensee included a cross-reference that will allow the use of Code Case N-638-4 with later editions and addenda of the Code. The NRC staff has reviewed this cross-reference and determined it to be an acceptable method to apply Code Case N-638-4 to the Code Edition and Addenda applicable to the welding repairs proposed by the licensee. In RG 1.147,.the NRC staff approved Code Case N*638-4 with the following Conditions:

1. Demonstration for ultrasonic examination of the repaired volume is required using representative samples which contain structural type flaws (7-129) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program

2. The provisions of [paragraphs] 3(e)(2) and 3(e)(3) may only be used when it is impractical to use the interpass temperature measurement methods described in [paragraph] 3(e)(1), such as in situations where the weldment area is inaccessible ... or when there are extenuating radiological circumstances.

As stated previously in this SE, the licensee proposes to comply with Condition 1 and also to measure interpass temperature directly in accordance with paragraph 3(e)(1). Therefore, the licensee proposes to use Code Case N-638-4 in accordance with the Conditions imposed by the NRC staff in RG 1.147. The staff finds the licensee's request to use Code Case N-638-4, rather than the later revision of this Code Case applicable to the Code of Record, acceptable, because Code Case N-638-4, which is conditionally approved by NRC staff in RG 1.147, is compatible with the proposed alternative, and the licensee has submitted an acceptable cross-reference, which will allow the use of this Code Case with the 2007 Edition through 2008 Addenda of the Code. 4.3 Irradiation Effects Code Case N-638-4 requires that the welding procedure and welding operators shall be qualified in accordance with Section IX and the requirements of paragraphs 2.1 and 2.2 of the Code Case. Paragraph 2.1.c of Code Case N-638-4 requires that consideration shall be given to the effects of irradiation on the properties of material "for applications in the core belt line region of the reactor vessel." Because irradiation effects were not discussed in the licensee's submittal, the NRC staff issued RAl-2 to request the licensee to identify whether the proposed FSWOL will be in the core belt Jine region discussed in Code Case N-638-4, and if so, to discuss how consideration was given to the effects of irradiation. In RAl-2, the NRC staff clarified the core belt line to be that region of reactor vessel ferritic materials with a fluence projected to be greater than 1 x 10 17 neutrons per square centimeter (n/cm2 ) for Energy greater than 1 million electron volts (E> 1MeV). In the licensee's response to RAl-2 dated October 29, 2015, the licensee stated that the weld subject to the proposed FSWOL is physically located outside the core belt line region, and does not identify any consideration given to the effect of irradiation on the properties of the material. The NRC staff finds the licensee response to RAl-2 acceptable because, based on its location outside the core belt line region, the proposed FSWOL would be in a region with a projected fluence of less than 1 x 10 17 n/cm 2 (E>1 MeV) and Code Case N-638-4 would not require that any consideration be given to the effects of irradiation on the properties of the material. 4.4 Impact Testing Requirements Paragraph 2. 1.j of Code Case N-638-4 states, in part, that for weld procedures qualified for use with Code Case N-638-4: The average lateral expansion value of the three HAZ Charpy V-notch specimens shall be no less than the average lateral expansion value of the three unaffected base metal specimens. However, if the average fateral expansion value of the HAZ Charpy V-notch specimens is less than the average value for the unaffected base metal specimens and the procedure qualification meets all the other requirements of this Case, either of the following shall be performed: (7-130) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program (1) The welding procedure shall be requalified. (2) An Adjustment Temperature for the procedure qualification shall be determined in accordance with the applicable provisions of NB-4335.2 of Section Ill, 2001 Edition with the 2002 Addenda. The RT NDT [Reference Temperature for Nil Ductility Transition] or lowest service temperature of the materials for which the welding procedure will be used shall be increased by a temperature equivalent to that of the Adjustment Temperature. Because paragraph 2.1.j, option 2, has the potential to affect reactor vessel integrity analyses, the NRC staff issued RAl-1, requesting the licensee to identify whether option 1 or option 2 was used to qualify the subject weld repair overlay. In the licensee's response to RAl-1 dated October 29, 2015, the licensee clarified that a vendor has not yet been chosen to perform the overlay and therefore, the procedure qualification records have not yet been reviewed. The licensee also clarified that option 2 would only be chosen after option 1 had been attempted and it was determined that option 2 is the only available solution. The licensee also stated, in part, in its response to AAl-1 : If option 2 is determined to be the only available solution, the effects of the Adjusted Temperature would be determined before the Full Structural Weld Overlay (FSWOL) is installed. If the new Adjusted Temperature is determined to affect the pressure-temperature curves, the curves would be revised before plant startup from refuel outage 29. However, because the location of the FSWOL is outside of the beltline region (fluence values greater than 1 x 10 17 n/cm 2 (E> 1 MeV)], it is not expected that minor changes to the Adjusted Temperature would affect the pressure-temperature curves. The NAC staff finds the licensee's response to RAl-1 acceptable, because the licensee clarified how the welding procedure would be qualified and, because the welding procedure would be qualified in accordance with the requirements of the Code as specified in Code Case N-638~4. The NAC staff finds the licensee's statement that, "If the new Adjusted Temperature is determined to affect the pressure-temperature curves, the curves would be revised before plant startup from refuel outage 29," to be acceptable, because the licensee will evaluate the effect on the pressure-temperature (P-T) limits if an adjustment temperature must be determined as a result of the weld procedure qualification. The licensee also indicated in its response to AAl-1 that it does not expect a change to the P-T limits to be necessary due to the low fluence at the location of the FSWOL. However, the NAC staff notes that, as clarified in Regulatory Issue Summary (RIS) 2014-11, "Information on Licensing Applications for Fracture Toughness Requirements for Ferritic Reactor Coolant Pressure Boundary Components," 1O CFA 50, Appendix G requires that all ferritic materials within the entire reactor vessel be considered in the development of the P-T limits, not just those with fluence greater than 1 x 1017 n/cm 2 (E> 1MeV). This is because the effects of structural discontinuities tor a material with a lower reference temperature, such as a nozzle with a lower fluence, may result in more restrictive allowable P-T limits than those for the vessel shell material with a higher reference temperature. (7-131) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program 4.5 Design and Ultrasonic Examination Requirements The licensee proposes to use a modified version of ASME Section XI, Nonmandatory Appendix Q for this potential repair. Nonmandatory Appendix Q is applicable to the FSWOL of austenitic stainless steel material (per Article Q-1000) using austenitic stainless steel weld material (per Article Q-2000(a) & (d)) and contains design considerations (Article Q-3000) and ultrasonic examination requirements (Article Q-4000). As stated previously in this SE, the licensee's proposed alternative is applicable to the FSWOL of a dissimilar metal weld using austenitic nickel-base material. The NRC staff agrees that, despite the material differences, the design consideration and ultrasonic examination requirements of Appendix Q can be used for the proposed alternative with the following two exceptions:

• Appendix Q (Article Q-2000(a)) requires the weld overlay to be fabricated from low carbon austenitic stainless steel weld metal. The proposed alternative will fabricate the weld overlay from ERNiCrFe-7 A (Alloy 52M) filler metal which is an austenitic nickel-based alloy.
• Appendix Q (Article-O-2000(d)) imposes minimum delta ferrite requirements on the weld overlay. This requirement is appropriate for overlays made with austenitic stainless steel weld metal which as deposited contain both austenite and delta ferrite phases. The proposed alternative will not impose minimum delta ferrite requirements on the weld overlay since the proposed alternative will use nickel-based alloy, which will be deposited without any delta ferrite phase.

The NRC staff finds the licensee's request to use Appendix Q with the above exceptions for the proposed alternative to be acceptable because the design considerations and the ultrasonic examination requirements of Appendix Q can be applied to the dissimilar metal weld combination of the proposed alternative, and will result in a FSWOL with sufficient structural integrity to mitigate the detrimental impact of sec, if found. ASME Section XI, Mandatory Appendix VIII provides procedure and personnel qualification requirements for ultrasonic examination and is required by Nonmandatory Appendix Q. Supplement 11 to Mandatory Appendix VIII is applicable to full structural overlaid wrought austenitic piping welds, but is not applicable to overlays of dissimilar metal welds. As an alternate to Mandatory Appendix VIII with Supplement 11, the licensee proposes to use the EPRI PDI qualification program as described in the licensee's submittal. The NRG staff performed a comprehensive review of the proposed PDI qualification program and Mandatory Appendix VIII, Supplement 11. An NRC staff review of the two programs has determined that the PDI Program for qualifying procedures, equipment, and personnel, as described in the relief request, is very similar to Mandatory Appendix VIII, Supplement 11. For the qualification of full structural weld overlays, the primary differences between the Appendix VIII requirements and the PDI Program are administrative or semantic in nature, such as changing "base metal flaws" to "service-induced flaws." The staff finds the licensee's request acceptable because the PDI qualification program, as described in the licensee's submittal, is applicable to overlays of dissimilar metal welds and is similar to the Mandatory Appendix VIII requirements except for administrative or semantic differences. (7-132) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 4.7 Summary The licensee's proposed alternative FSWOL, which follows the design requirements of Nonmandatory Appendix Q with the exceptions noted previously, will provide an acceptable repair tor any sec defects found during ISi, as discussed in Section 4.5 (of this SE). Alloy 52M with its high chromium content will provide superior corrosion resistance to the Alloy 82 and 182 weld materials used in the existing weld, as discussed in Section 4.1. The temper bead welding Code Case N-638-4 is acceptable for welding to alloy steel when post weld heat treatment of the weld joint is not performed, as discussed in Section 4.2. The welding for the proposed alternative will be performed and qualified in accordance with Code requirements, as discussed in Section 4.4. Because the projected neutron fluence is less than 1 x 10 17 n/cm 2 (E> 1 MeV), the Code Case requirement that irradiation effects be considered for applications in the core belt line does not apply here, as discussed in Section 4.3. The POI Program is acceptable for qualifying ultrasonic examination procedures, equipment, and personnel to be used for the proposed alternative, as discussed in Section 4.5. Therefore, the NRC staff finds that the proposed alternative provides an acceptable level of quality and safety and structural integrity.

5.0 CONCLUSION

As set forth above, the NRC staff determines that the proposed alternative demonstrates an acceptable level of quality and safety and provides a reasonable assurance of structural integrity for the subject weld. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(1) and is in compliance with the requirements of the ASME Code, Section XI for which relief was not requested. Therefore, the NRC staff authorizes the use of Relief Request RR5-01 at CNS as a contingency, if a flaw is discovered during Refueling Outage 29. The proposed alternative is authorized for the fifth 10-Year ISI interval. All other requirements of the ASME Code, Section XI, for which relief has not been specifically requested and authorized by NRC staff remain applicable, including a third party review by the Authorized Nuclear lnservice Inspector. Principal Contributor: J. Jenkins Da~: February 24, 2016 (7-133) Rev 3.0

ML16042A326 *by email dated OFFICE NRR/DORL/LPL4-2/PM NRR/DORULPL4-2/LA NRR/DE/EVIB/BC* NRR/DORULPL4-2/BC NAME TvVengert PB/echman JMcHale MKhanna DATE 2/22/16 2/17/16 02/05/16 2/24/16 Cooper Station 5th ISi & 3rd Interval CISI Program 10CFRS0.SSa Request No. RRS-02 Cooper Nuclear Station Request to Use Code Case N-513-4 Proposed Alternative in Accordance with 10 CFR S0.55a{z)(2) Hardship Without a Compensating Increase in Quality and Safety ASME Code Component(s) Affected All ASME, Section XI, Class 2 and 3 piping components that meet the operational and configuration limitations of Code Case N-513-4, paragraphs l(a), l(b), l(c), and l(d) at CNS.

Applicable Code Edition and Addenda

CNS applicable Code for the fifth IO-year ISi interval and the ISi program is the 2007 Edition of Section XI with the 2008 Addenda. CNS fifth interval started April 1, 2016 and ends February 28, 2026. Applicable ASME Code Requirements ASME Code, Section XI, IWC-3120 and IWC-3130 require that flaws exceeding the defined acceptance criteria be corrected by repair/replacement activities or evaluated and accepted by analytical evaluation. ASME Code, Section XI, IWD-3120(b) requires that components exceeding the acceptance standards oflWD-3400 be subject to supplemental examination, or to a repair/replacement activity.

Reason for Request

In accordance with 10 CFR S0.5Sa(z)(2), NPPD is requesting a proposed alternative from the requirement to perform repair/replacement activities for degraded Class 2 and 3 piping whose maximum operating temperature does not exceed 200° and whose maximum operating pressure does not exceed 275 psig. Moderately degraded piping could require a plant shutdown within the required action statement time-frames to repair observed degradation. Plant shutdm,vn activities result in additional dose and plant risk that would be inappropriate when a degraded condition is demonstrated to retain adequate margin to complete the component's function. The use of an acceptable alternative analysis method in lieu of immediate action for a degraded condition will allow NPPD to perform additional extent of condition examinations on the affected systems while allowing time for safe and orderly long term repair actions if necessary. Actions to remove degraded piping from service could have a detrimental overall risk impact by requiring a plant shutdown, thus requiring use of a system that is in standby during normal operation. Accordingly, compliance with the current code requirements results in a hardship without a compensating increase in the level of quality and safety. ASME Code Case N-513-3 does not allow evaluation of flaws located away from attaching circumferential piping welds that are in elbows, bent pipe, reducers, expanders, and branch tees. ASME Code Case N-513-3 also does not allow evaluation of flaws located in heat exchanger external tubing or piping. ASME Code Case N-513-4 provides guidance for evaluation of flaws in these locations. (7-135) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Proposed Alternative and Basis for Use NPPD is requesting approval to apply ASME Code Case N-513-4, "Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping Section XI, Division 1," to the SW System piping that meets the operational and configuration limitations of Code Case N-513-4, paragraphs l(a), l(b), l(c), and l(d). Application of the Code Case will avoid accruing additional personnel radiation exposure and increased plant risk associated with a plant shutdown to comply with the cited Code requirements. The NRC issued GL 90-05 (Reference 1), "Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping (Generic Letter 90-05)," to address the acceptability of limited degradation in moderate energy piping. The generic letter defines conditions that would be acceptable to utilize temporary non-code repairs with NRC approval. The ASME recognized that relatively small flaws could remain in service without risk to the structural integrity of a piping system and developed Code Case N-513. NRC approval of Code Case N-513 versions in RG 1.147, 11 lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1 (Reference 3)," allows temporary acceptance of partial through-wall or through-wall flaws provided all conditions of the Code Case and NRC conditions are met. The temporary acceptance period has historically been the time to the next scheduled refueling outage. The Code Case also requires the Owner to demonstrate system operability due to leakage. The ASME recognized that the limitations in Code Case N-513-3 were preventing needed use in piping components such as elbows, bent pipe, reducers, expanders, and branch tees and external tubing or piping attached to heat exchangers. Code Case N-513-4 was approved by the ASME to expand use on these locations and to revise several other areas of the Code Case. , Attachment 1 provides a marked-up N-513-3 version of the Code Case to highlight the changes compared to the NRC approved N-513-3 version. The following provides a high level overview of the Code Case N-513-4 changes:

• Revised the maximum allowed time of use from no longer than 26 months to the next scheduled refueling outage.
• Added applicability to piping elbows, bent pipe, reducers, expanders, and branch tees where the flaw is located more than (Rot) 112 from the centerline of the attaching circumferential piping weld.
• Expanded use to external tubing or piping attached to heat exchangers.
• Revised to limit the use to liquid systems.
• Revised to clarify treatment of Service Level load combinations.
• Revised to address treatment of flaws in austenitic pipe flux welds.

(7-136) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program

• Revised to require minimum wall thickness acceptance criteria to consider longitudinal stress in addition to hoop stress.
• Other minor editorial changes to improve the clarity of the Code Case.

The technical basis for changes in Code Case N-513-4 when compared to NRC approved Code Case N-513-3 is provided in Enclosure 1, Attachment 2. Enclosure 1, Attachment 3 provides additional technical justification for the use of Code Case N-513-4 at CNS. The design basis is considered for each leak and evaluated using the NPPD Operability Evaluation process. The evaluation process must consider requirements or commitments established for the system, continued degradation and potential consequences, operating experience, and engineering judgment. As required by the Code Case, the evaluation process considers but is not limited to system make-up capacity, containment integrity with the leak not isolated, effects on adjacent equipment, and the potential for room flooding. Leakage rate is not typically a good indicator of overall structural stability in moderate energy systems, where the allowable through-wall flaw sizes are often on the order of inches. The periodic inspection interval defined using paragraph 2(e} of Code Case N-513-4 provides evidence that a leaking flaw continues to meet the flaw acceptance criteria and that the flaw growth rate is such that the flaw will not grow to an unacceptable size. The effects ofleakage may impact the operability determination or the plant flooding analyses specified in paragraph l(f}. For a leaking flaw, the allowable leakage rate will be determined by dividing the critical leakage rate by a safety factor of four (4). The critical leakage rate is determined as the lowest leakage rate that can be tolerated and may be based on the allowable loss of inventory or the maximum leakage that can be tolerated relative to room flooding, among others. The safety factor of four (4} on leakage is based upon Code Case N-705 (Reference 2), which is accepted without condition in RG 1.147, Revision 17. Paragraph 2.2(e) ofN-705 requires a safety factor of tvJo {2) on f!aw size when estimating the f!avv size from the leakage rate. This corresponds to a safety factor of four (4} on leakage for non planar flaws. Although the use of a safety factor for determination of an unknown flaw is considered conservative when the actual flaw size is known, this approach is deemed acceptable based upon the precedent of Code Case N-705. Note that the alternative herein does not propose to use any portion of Code Case N-705 and that citation of N-705 is intended only to provide technical basis for the safety factor on leakage. During the temporary acceptance period, leaking flaws will be monitored daily as required by paragraph 2(f) of Code Case N-513-4 to confirm the analysis conditions used in the evaluation remain valid. Significant change in the leakage rate is reason to question that the analysis conditions remain valid, and would require re-inspection per paragraph 2(f) of the Code Case. Any re-inspection must be performed in accordance with paragraph 2(a) of the Code Case. The leakage limit provides quantitative measurable limits which ensure the operability of the system and early identification of issues that could erode defense-in-depth and lead to adverse consequences. (7-137) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program In summary, NPPD will apply ASME Code Case N-513-4 in its entirety for evaluation of Class 2 and 3 piping flaws at CNS if Code repairs cannot reasonably be completed within the Technical Specifications required time limit. Code Case N-513-4 utilizes technical evaluation approaches that are based on principals that are accepted in other Code documents already acceptable to the NRC. The application of this Code Case will maintain acceptable structural and leakage integrity while minimizing plant risk and personnel exposure by minimizing the number of plant transients that could be incurred if degradation is required to be repaired based on ASME Section XI acceptance criteria only. Duration of Proposed Alternative The proposed alternative is for use of Code Case N-513-4 for Class 2 and 3 piping and components within the scope of the Code Case and the request herein. A Section XI compliant repair/replacement will be completed prior to exceeding the next scheduled refueling outage or allowable flaw size, whichever comes first. This relief request will be applied for the duration of the fifth 10-year inservice inspection interval. If a flaw is evaluated near the end of the interval and the next refueling outage is in the subsequent interval, the flaw may remain in service under this relief request until the next refueling outage. Precedent US NRC letter to Exelon Generation Company Nuclear Fleet - " ... Proposed Alternative to Use ASME Code Case N-513-4," NRC Safety Evaluation dated September 6, 2016 (ML16230A237). References

1. NRC Generic Letter 90-05, "Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping (Generic Letter 90-05)," dated June 15, 1990.

2. AS!V!E Boiler and Pressure Vessel Code, Code Case N-705, "Evaluation Criteria for Temporary Acceptance of Degradation in Moderate Energy Class 2 or 3 Vessels and Tanks Section XI, Division 1," dated October 12, 2006.

3. NRC Regulatory Guide 1.147, "lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, Revision 17," dated August 2014.

(7-138) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION FOR THE FIFTH 10-YEAR INSERVICE INSPECTION INTERVAL RELIEF REQUEST NO. RR5-02 PROPOSED ALTERNATIVE TO UTILIZE ASME CODE CASE N-513-4 NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO 50-298

1.0 INTRODUCTION

By letter dated August 17, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17241A048), as supplemented by letter dated March 8, 2018 (ADAMS Accession No. ML18078A264), Nebraska Public Power District (NPPD the licensee), submitted a request in accordance with paragraph 50.55a(zX2) of Title 10 of the Code of Federal Regulations (10 CFR) for a proposed alternative to the requirements of Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) for the Cooper Nuclear Station (CNS). The proposed alternative, Relief Request RR5-02, would allow the licensee to use ASME Code Case N-513-4, "Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping Section XI, Division 1," for the evaluation and temporary acceptance of flaws in moderate energy Class 2 and 3 piping in lieu of specified ASME Code requirements for the fifth 10-year inservice inspection (ISi) Interval which began on April 1, 2016, and is scheduled to end on February 28, 2026. Specifically, pursuant to 10 CFR 50.55a(z)(2), the licensee requested to use the alternative on the basis that complying with the specified requirement would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

2.0 REGULATORY EVALUATION

The licensee proposes an alternative to the requirement of ASME Code, Section XI, Articles IWC-3000 and IWD-3000. Adherence to Section XI of the ASME Code is mandated by 10 CFR 50.55a(g)(4), "lnservice inspection standards requirements for operating plants," which states, in part, that ASME Code Class 1, 2, and 3 components (including supports) will meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in Section XI of the ASME Code. (7-139) Rev 3.0 Enclosure 4

Cooper Station 5th ISi & 3rd Interval CISI Program The regulation 10 CFR 50.55a(z), "Alternatives to codes and standards requirements," states, in part, that alternatives to the requirements of paragraph (g) of 10 CFR 50.55a may be used when authorized by the NRC, if the licensee demonstrates that: (1) the proposed alternative provides an acceptable level of quality and safety, or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Based on the above, and subject to the following technical evaluation, the U.S. Nuclear Regulatory Commission (NRC) staff finds that regulatory authority exists for the licensee to request the use of an alternative and the NRC to authorize the proposed alternative.

3.0 TECHNICAL EVALUATION

3.1 ASME Code Component(s) Affected The affected components are ASME Code Class 2 and 3 moderate energy piping systems, as described in ASME Code Case N-513-4, Section 1 "Scope," whose maximum operating temperature does not exceed 200 degrees Fahrenheit (°F) and whose operating pressure does not exceed 275 pounds per square inch gauge (psig). 3.2 Applicable Code Edition and Addenda The Code of Record for the fifth 10-year ISi interval at CNS is the ASME Code, Section XI, 2007 Edition, through 2008 Addenda. The fifth 10-year ISi at CNS began on April 1, 2016, and is scheduled to end on February 28, 2026. 3.3 Applicable Code Requirement ASME Code, Section XI, Subarticles IWC-3120 and IWC-3130, require that flaws exceeding the defined acceptance criteria be corrected by repair/replacement activities or evaluated and accepted by analytical evaluation. ASME Code. Section XI, subparagraph IWD-3120(b), requires that components exceeding the acceptance standards of Article IWD-3400 be subject to supplemental examination, or to a repair/replacement activity. 3.4 Reason for Request The licensee stated that ASME Code Case N-513-3 does not allow evaluation of flaws located away from attaching circumferential piping welds that are in elbows, bent pipe, reducers, expanders, and branch tees. ASME Code Case N-513-3 does not allow evaluation of flaws located in heat exchanger external tubing or piping. ASME Code Case N-513-4 provides guidance for evaluation of flaws in these locations. Moderately degraded piping could require a plant shutdown within the required action statement timeframes to repair observed degradation. The licensee stated, in part, in its letter dated August 17, 2017, that "[p]lant shutdown activities result in additional dose and plant risk that would be inappropriate when a degraded condition is demonstrated to retain adequate margin to complete the component's function." 3.5 Licensee s Proposed Alternative and Basis for Use 1 The licensee's proposed alternative is to use ASME Code Case N-513-4 for the evaluation and temporary acceptance of flaws in moderate energy Class 2 and 3 piping in lieu of specified ASME Code, Section XI, requirements. In addition, the licensee's proposed alternative includes (7-140) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program the determination of an allowable leakage rate by dividing the critical leakage rate by a safety factor of four. The licensee stated that it will apply ASME Code Case N-513-4 in its entirety for the evaluation of Class 2 and 3 piping flaws at CNS if Code repairs cannot reasonably be completed within the technical specification required time limit. The licensee stated that limitations in ASME Code Case N-513-3, related to its use on piping components such as elbows, bent pipe, reducers, expanders, and branch tees and external tubing or piping attached to heat exchangers, have been addressed in ASME Code Case N-513-4. The licensee provided a high level overview of the differences between Code Case N-513-3 and Code Case N-513-4 as listed below:

1. Revised the maximum allowable time of use from no longer than 26 months to the next refueling outage.

2. Added applicability to piping elbows, bent pipe, reducers, expanders, and branch tees where the flaw is located more than (Rot) 112 [where Ro is the outside pipe radius and tis the evaluation wall thickness] from the centerline of the attaching circumferential piping weld.

3. Expanded use to external tubing or piping attached to heat exchangers.

4. Revised to limit the use to liquid systems.

5. Revised to clarify treatment of Service Level load combinations.

6. Revised to address treatment of flaws in austenitic pipe flux welds.

7. Revised to require minimum wall thickness acceptance criteria to consider longitudinal stress in addition to hoop stress.

8. Other minor editorial changes to improve the clarity of the Code Case.

Enclosure 1, Attachment 2 of the licensee's letter dated August 17, 2017, includes a technical basis document for the fourth revision to N-513, Proceedings of the ASME 2014 Pressure 11 Vessels & Piping Conference, PVP2014, July 20-24, 2014, Anaheim, California, USA, PVP2014-28355, Technical Basis for Proposed Fourth Revision to ASME Code Case N-513." The licensee stated that the effects of leakage may impact the operability determination or the plant flooding analyses specified in paragraph 1(f) of ASME Code Case N-513-4. For a leaking flaw, the licensee stated that the allowable leakage rate will be determined by dividing the critical leakage rate by a safety factor of four. The critical leakage rate is determined as the limiting leakage rate that can be tolerated and may be based on the allowable loss of inventory or the maximum leakage that can be tolerated relative to room flooding, among others. The licensee contends that applying a safety factor of four to the critical leakage rate provides quantitative measurable limits, which ensure the operability of the system and early identification of issues that could erode defense-in-depth and lead to adverse consequences. (7-141) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program The licensee stated that ASME Code Case N-513-4 utilizes technical evaluation approaches that are based on principles that are accepted in other Code documents already acceptable to the NRC. The licensee also stated that application of this code case, in concert with safety factors on leakage limits, will maintain acceptable structural and leakage integrity while minimizing plant risk and personnel exposure by minimizing the number of plant transients that could be incurred if degradation is required to be repaired based on ASME Code, Section XI, acceptance criteria only. 3.6 Hardship Justification As stated, in part, by the licensee in its letter dated August 17, 2017, Moderately degraded piping could require a plant shutdown within the required action statement timeframes to repair observed degradation. Plant shutdown activities result in additional dose and plant risk that would be inappropriate when a degraded condition is demonstrated to retain adequate margin to complete the component's function. The use of an acceptable alternative analysis method in lieu of immediate action for a degraded condition will allow NPPD to perform additional extent of condition examinations on the affected systems while allowing time for safe and orderly long term repair actions if necessary. Actions to remove degraded piping from service could have a detrimental overall risk impact by requiring a plant shutdown, thus requiring use of a system that is in standby during normal operation. Accordingly, compliance with the current code requirements results in a hardship without a compensating increase in the level of quality and safety. 3.7 Duration of Proposed Alternative The licensee stated that the duration of the proposed alternative is the fifth 10-year ISi interval which began on April 1, 2016, and is scheduled to end on February 28, 2026. The licensee stated that if a flaw is evaluated near the end of the interval, and the next refueling outage is in the subsequent interval, the flaw may remain in service until the next refueling outage. 3.8 NRC Staff Evaluation The NRC staff evaluated the adequacy of the proposed alternative in maintaining the structural integrity of piping components identified in ASME Code Case N-513-4. ASME Code Case N-513-3, which is conditionally approved for use in RG 1.147, Revision 17, provides alternative evaluation criteria for temporary acceptance of flaws, including through-wall flaws, in moderate energy Class 2 and 3 piping. However, ASME Code Case N-513-3 contains limitations that the licensee considers restrictive and could result in an unnecessary plant shutdown. ASME Code Case N-513-3 is limited to straight pipe with provisions for flaws that extend for a short distance, at the pipe to fitting weld, into the fitting. Evaluation criteria for flaws in elbows, bent pipe, reducers, expanders, branch tees and heat exchangers are not included within the scope of ASME Code Case N-513-3. Code Case N-513-4 addresses these aforementioned limitations. Given that the previous revision of this code case (Code Case N-513-3) is conditionally approved for use in RG 1.147, Revision 17, the staff focused its review on the differences between ASME Code Cases N-513-3 and N-513-4. The significant changes in ASME Code Case N-513-4 include: (1) revised temporary acceptance period; (2) added flaw evaluation criteria for elbows, bent pipe, reducers/expanders and branch tees, (3) expanded applicability to heat exchanger tubing or piping, (4) limited use to liquid systems, (7-142) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program {5) clarified treatment of service load combinations. (6) revised treatment of flaws in austenitic pipe flux welds, {7) revised minimum wall thickness acceptance criteria to consider longitudinal stress in addition to hoop stress, and {8) revised leakage monitoring requirements. The NRC staff also evaluated the licensee's proposed limitation on the leakage rate and its hardship justification. The NRC staff notes that many requirements specified in ASME Code Case N-513-4 are not discussed in this SE, but they should not be considered as less important. As part of the NRC-approved proposed alternative, all requirements in the code case must be followed. Any exceptions or restrictions to the code case that are approved in this SE also need to be followed. Temporary Acceptance Period ASME Code Case N-513-3 specifies a temporary acceptance period of a maximum of 26 months. Code Case N-513-3 is accepted for use in RG 1 .14 7, Revision 17, with the following condition, "The repair or replacement activity temporarily deferred under the provisions of this Code Case shall be performed during the next scheduled outage." ASME Code Case N-513-4 includes wording that limits the use of the code case to the next refueling outage. The NRC staff finds that Code Case N-513-4 appropriately addresses the NRC condition on Code Case N-513-3, and, is therefore, acceptable. Flaw Evaluation Criteria for Elbows, Bent Pipe, Reducers/Expanders and Branch Tees. Evaluation and acceptance criteria have been added to ASME Code Case N-513-4 for flaws in elbows, bent pipe, reducers, expanders, and branch tees using a simplified approach, which is based on the Second International Piping Integrity Research Group {IPIRG-2) program reported in NUREG/CR-6444 BMl-2192, "Fracture Behavior of Circumferentially Surface-Cracked Elbows," March 1996. The flaw evaluation methodology in ASME Code Case N-513-4 for piping elbows, bends, reducers and tees, is conducted as if the flaws in these components are in straight pipe by scaiing hoop and axiai stresses using ASME Code piping design code stress indiees and stress intensification factors to account for the stress variations caused by the geometric differences. Equations used in the code case are consistent with the piping design by rule approach in ASME Code, Section 111, NC/ND-3600. NUREG/CR-6444 shows that this approach is conservative for calculating stresses used in flaw evaluations in piping elbows and bent pipe. The code case also applies this methodology to reducers, expanders, and branch tees. The NRC staff finds that the flaw evaluation and acceptance criteria in ASME Code Case N-513-4 for elbows, bent pipe, reducers, expanders, and branch tees is acceptable because the flaw evaluation methods in the code case are consistent with ASME Code, Section XI, ASME Code Section 111, design by rule approach and provides a conservative approach as confirmed by comparing the failure moments predicted using this approach to the measured failure moments from the elbow tests for through-wall circumferential flaws conducted as part of the IPIRG-2 program. Flaw Evaluation in Heat Exchanger Tubing or Piping ASME Code Case N-513-4 has been revised to include heat exchanger external tubing or piping provided that the flaw is characterized in accordance with Section 2{a) of the code case (7-143) Rev 3.0

CooperS~tion5~1S1& 3rd Interval CISI Program and leakage is monitored. Section 2(a) requires that the flaw geometry be characterized by volumetric inspection or physical measurement. The NRC staff determined that the flaw evaluation criteria in ASME Code Case N-513-4 for straight or bent piping, as appropriate, can be applied to heat exchanger external tubing or piping. The staff determined the methods for evaluating flaws in straight pipe are acceptable since they are currently allowed in ASME Code Case N-513-3. For bent pipe, the acceptability is described in Section 3.2.2 above. Therefore, the NRC staff finds inclusion of heat exchanger external tubing or piping in the code case to be acceptable because only heat exchanger tubing flaws that are accessible for characterization and leakage monitoring may be evaluated in accordance with the code case and the code case provides acceptable methods for the evaluation of flaws. Limit Use to Uquid Systems Use of ASME Code Case N-513-4 is specifically limited to liquid systems. The NRC staff finds this change acceptable since ASME Code Case N-513 is not intended to apply to air or other compressible fluid systems. Treatment of Service Load Combinations Modifications in ASME Code Case N-513-4 now make clear that all service load combinations must be considered in flaw evaluations to determine the most limiting condition, although previously implied in ASME Code Cases N-513-3 (N-513-4 makes this requirement clear). Therefore, the NRC staff finds this change acceptable. Treatment of Flaws in Austenitic Pipe Flux Welds Paragraph 3.1{b) of ASME Code Case N-513-4 contains modifications which include a reference to ASME Code Section XI, Appendix C, C-6320, to address flaws in austenitic stainless steel pipe flux welds. The ASME Code, Section XI, Appendix C, C-6000 permits the use of elastic plastic fracture mechanics criteria in lieu of limit load criteria to analyze flaws in stainless steel pipe flux welds. Equation 1 of the code case was aiso revised to be consistent with ASME Code, Section XI, Appendix C, C-6320, so the equation can be used for flaws in austenitic stainless steel pipe flux welds. The NRC staff finds this acceptable because the modification to the code case now includes the appropriate methods for the evaluation of stainless steel pipe flux welds in accordance with ASME Code, Section XI. Minimum Wall Thickness Acceptance Criteria to Consider Longitudinal Stress Although it is unlikely that a minimum wall thickness calculated based on the longitudinal stress would be limiting when compared to a minimum wall thickness calculated based on hoop stress, ASME Code Case N-513-4 includes revisions that require consideration of longitudinal stress in the calculation of minimum wall thickness. Previous versions of the code case only required the use of hoop stress. The NRC staff finds this acceptable because it will ensure that the more limiting of the longitudinal or hoop stress is used to determine minimum wall thickness. Leakage Monitoring for Through-Wall Flaws ASME Code Case N-513-3 required through-wall leakage to be observed by daily walkdowns to confirm the analysis conditions used in the evaluation remain valid. ASME Code Case N-513-4 (7-144) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program modifies this requirement by continuing to require that leakage be monitored daily but now allows other techniques to be used to monitor leakage such as using visual equipment or leakage detection systems to determine if leakage rates are changing. The NRC staff finds this change acceptable because the code case continues to require through-wall leaks to be monitored daily and the expanded allowable monitoring methods should have no adverse impact. Leakage Rate ASME Code Case N-513-3, paragraph 1(d), states, "The provisions of this Case demonstrate the integrity of the item and not the consequences of leakage. It is the responsibility of the Owner to demonstrate system operability considering effects of leakage." ASME Code Case N-513-4 modified the last sentence, now located in paragraph {f), to state, "It is the responsibility of the Owner to consider effects of leakage in demonstrating system operability and performing plant flooding analyses." The licensee stated that the allowable leakage rate will be determined by dividing the critical leakage rate by a safety factor of four. The critical leakage rate is determined as the limiting leakage rate that can be tolerated and may be based on the allowable loss of inventory or the maximum leakage that can be tolerated relative to room flooding, among others. The licensee contends that applying a safety factor of four to the critical leakage rate, provides quantitative measurable limits which ensure the operability of the system and early identification of issues that could erode defense-in-depth and lead to adverse consequences. ASME Code Cases N-513-3 and N-513-4 do not contain leakage limits for components with through-wall flaws. The NRC staff finds that the licensee's approach of applying a safety factor of four to the critical leakage rate is acceptable because it will provide sufficient time for corrective measures to be taken before significant increases in leakage erodes defense-in-depth which could lead to adverse consequences. Hardship Justification The NRC staff finds that performing a plant shutdown.to repair the subject piping would cycle the unit and increase the potential of an unnecessary transient resulting in undue hardship. Additionally, performing certain ASME Code repairs during normal operation would challenge the technical specification "Completion Time" and place the plant at higher safety risk than warranted. Therefore, the NRC staff determined that compliance with the specified ASME Code repair requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. 3.9 Technical Evaluation Summary The NRC staff finds that the proposed alternative will provide reasonable assurance of the structural integrity because: (1) ASME Code Case N-513-4 addresses the NRC condition in RG 1.147 for Revision 3, (2) flaw evaluations in component types added to Revision 4 of the code case are based on acceptable methodologies, and (3) the method for determining the allowable leakage rate is adequate to provide early identification of a significant increase in leakage. In addition, complying with ASME Code, Section XI requirements would result in in hardship or unusual difficulty without a compensating increase in the level of quality and safety. (7-145) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program

4.0 CONCLUSION

As set forth above, the NRC staff determined that the proposed alternative, Request No. RRS-02, provides reasonable assurance of structural integrity of the subject components and that complying with IWC-3120, IWC-3130, IWD-3120{b), and IWD-3400, of the ASME Code, Section XI, would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a{z){2). Therefore, the NRC staff authorizes the use of the licensee's proposed alternative as described in Request No. RR5-02, to use ASME Code Case N-513-4, at CNS, for the fifth 10-year ISi interval which began on April 1, 2016, and is scheduled to end on February 28, 2026. If the proposed alternative is applied to a flaw near the end of the authorized 10-year ISi interval, and the next refueling outage is in the subsequent interval, the licensee is authorized to continue to apply the proposed alternative to the flaw until the next refueling outage. The NRC staff notes that approval of this alternative does not imply NRC approval of ASME Code Case N-513-4. All other ASME Code, Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third party review by the Authorized Nuclear lnservice Inspector. Principal Contributor: R. Davis, NRR/DMLR/MPHB Da~: July 31, 2018 (7-146) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 10CFRS0.SSa Request No. RRS-03 Cooper Nuclear Station Request to Use Code Case N-513-4 at a Higher System Operating Pressure Proposed Alternative in Accordance with 10 CFR S0.5Sa(z)(2) Hardship Without a Compensating Increase in Quality and Safety ASME Code Component(s) Affected All ASME, Section XI, Class 3 RHRSWB system piping with a maximum operating pressure less than or equal to 490 psig and a maximum operating temperature less than 200°F at the Cooper Nuclear Station (CNS). The RHR and RHRSWB Systems are designed such that RHRSWB operates at a higher pressure than RHR. The RHR and RHRSWB Systems are standby systems that typically operate during testing or plant shutdown. Under this design, if there is an internal leak within a RHR heat exchanger, RHRSWB water, which is raw water from the Missouri River, will leak into the RHR System. The safety objective of the RHRSWB System is to provide cooling to the RHR System without an uncontrolled release of radioactive material to the environment. The RHRSWB System is designed to provide an adequate supply of cooling water to the RHR heat exchangers during postulated accident and transient conditions to remove the design RHR System heat load and at adequate pressure to prevent uncontrolled release of fission products to the environment due to a RHR heat exchanger tube failure. RHRSWB System at CNS has exhibited a history of degradation similar to raw fresh water systems throughout the nuclear industry. Degradation requiring immediate action to address leakage or observed thinning in the system is generally due to localized corrosion mechanisms.

Applicable Code Edition and Addenda

CNS' applicable Code for the fifth 10-year ISi interval and the ISi program is the 2007 Edition of Section XI with the 2008 Addenda. CNS' fifth interval started April 1, 2016 and ends February 28, 2026. Applicable ASME Code Requirements ASME Code, Section XI, IWD-3120(b) requires that components exceeding the acceptance standards of IWD-3400 be subject to supplemental examination, or to a repair/replacement activity.

Reason for Request

In accordance with 10 CFR 50.55a(z)(2), NPPD is requesting a proposed alternative from the requirement to perform repair/replacement activities for degraded RHRSWB piping which has a maximum operating pressure in excess of 275 psig. Moderately degraded piping could require a plant shutdown within the required action statement timeframes to repair observed degradation. Plant shutdown activities result in additional dose and plant risk that would be inappropriate when a (7-147) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program degraded condition is demonstrated to retain adequate margin to complete the component's function. The use of an acceptable alternative analysis method in lieu of immediate action for a degraded condition will allow NPPD to perform additional extent of condition examinations on the affected systems while allowing time for safe and orderly long term repair actions if necessary. Actions to remove degraded piping from service could have a detrimental overall risk impact by requiring a plant shutdown, thus requiring use of a system that is in standby during normal operation. Accordingly, compliance with the current code requirements results in a hardship without a compensating increase in the level of quality and safety. ASME Code Case N-513-3 does not allow evaluation of flaws located away from attaching circumferential piping welds that are in elbows, bent pipe, reducers, expanders, and branch tees. ASME Code Case N-513-3 also does not allow evaluation of flaws located in heat exchanger external tubing or piping. ASME Code Case N-513-4 provides guidance for evaluation of flaws in these locations. Proposed Alternative and Basis for Use NPPD is requesting approval to apply ASME Code Case N-513-4, "Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping Section XI, Division 1," to the RHRSWB System piping having a maximum operating pressure of 490 psig. The operational and configuration limitations of Code Case N-513-4, paragraphs l(a), l(b), and l(d), shall apply. The maximum operating temperature of 200°F in paragraph l(c) shall also apply. Application of the Code Case will avoid accruing additional personnel radiation exposure and increased plant risk associated with a plant shutdown to comply with the cited Code requirements. The NRC issued Generic Letter 90-05 (Reference 1), "Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping (Generic Letter 90-05)," to address the acceptability of limited degradation in moderate energy piping. The generic letter defines conditions that would be acceptable to utilize temporary non-code repairs with NRC approval. The ASME recognized that relatively small flaws could remain in service without risk to the structural integrity of a piping system and developed Code Case N-513. NRC approval of Code Case N-513 versions in Regulatory Guide 1.147, "lnservice Inspection Code Case Acceptability, ASME Section X!, Division 1 (Reference 3)/' allows temporary acceptance of partial through-wall or through-wall flaws provided all conditions of the Code Case and NRC conditions are met. The temporary acceptance period has historically been the time to the next scheduled refueling outage. The Code Case also requires the Owner to demonstrate system operability due to leakage. The ASME recognized that the limitations in Code Case N-513-3 were preventing needed use in piping components such as elbows, bent pipe, reducers, expanders, and branch tees and external tubing or piping attached to heat exchangers. Code Case N-513-4 was approved by the ASME to expand use on these locations and to revise several other areas of the Code Case. Enclosure 2, Attachment 1 provides a marked-up N-513-3 version of the Code Case to highlight the changes compared to the NRC approved N-513-3 version. The following provides a high level overview of the Code Case N-513-4 changes:

• Revised the maximum allowed time of use from no longer than 26 months to the next scheduled refueling outage.

(7-148) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program

• Added applicability to piping elbows, bent pipe, reducers, expanders, and branch tees where the flaw is located more than (Rot) 112 from the centerline of the attaching circumferential piping weld.
• Expanded use to external tubing or piping attached to heat exchangers.
• Revised to limit the use to liquid systems.
• Revised to clarify treatment of Service Level load combinations.
• Revised to address treatment of flaws in austenitic pipe flux welds.
• Revised to require minimum wall thickness acceptance criteria to consider longitudinal stress in addition to hoop stress.
• Other minor editorial changes to improve the clarity of the Code Case.

The technical basis for changes in Code Case N-513-4 when compared to NRC approved Code Case N-513-3 is provided in Enclosure 2, Attachment 2 (See original submittal). The design basis is considered for each leak and evaluated using the NPPD Operability Evaluation process. The evaluation process must consider requirements or commitments established for the system, continued degradation and potential consequences, operating experience, and engineering judgment. As required by the Code Case, the evaluation process considers but is not limited to system make-up capacity, containment integrity with the leak not isolated, effects on adjacent equipment, and the potential for room flooding. Leakage rate is not typically a good indicator of overall structural stability, where the allowable through-wall flaw sizes are often on the order of inches. The periodic inspection interval defined using paragraph 2(e) of Code Case N-513-4 provides evidence that a leaking flaw continues to meet the flaw acceptance criteria and that the flaw growth rate is such that the flaw will not grow to an unacceptable size. The effects of leakage may impact the operability determination or the plant flooding analyses specified in paragraph l(f). For a leaking flaw, the allowable leakage rate will be limited to 5 gpm to limit effects of jet thrust force even though a structural evaluation of the subject piping and leakage effects would allow a much higher leakage rate than 5 gpm. Any leakage, if present, will be limited to the leakage allowed by the evaluation or 5 gpm, whichever is lower. During the temporary acceptance period, leaking flaws will be monitored daily as required by paragraph 2(f) of Code Case N-513-4 to confirm the analysis conditions used in the evaluation remain valid. Significant change in the leakage rate is reason to question that the analysis conditions remain valid, and would require re-inspection per paragraph 2(f) of the Code Case. Any re-inspection must be performed in accordance with paragraph 2(a) of the Code Case. (7-149) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program The design pressure of the Class 3 RHRSWB system is 490 psig with a maximum operating pressure of approximately 420 psig. The background, history, and effects of using Code Case N-513-4 at a conservative pressure value of 490 psig in lieu of the current 275 psig limitation provided in the Code Case are contained in Enclosure 2, Attachment 3. A review of previous NRC submittals identified that the NRC has previously granted specific relief for leaks on high energy systems (see Enclosure 2, ). NPPD is seeking relief for general application for limited degradation in the RHRSWB System raw water piping for a maximum operating pressure of 490 psig (conservative). Raw water piping degradation is a well understood phenomenon and the evaluation methods in Code Case N-513-4 are widely applied by the industry in raw water piping systems that operate at a pressure less than or equal to 275 psig without incident. The structural aspects of raising the allowable operating pressure to 490 psig were evaluated as discussed in Enclosure 2, Attachment 3. It was determined that Code Case allowable flaw sizes by both the Linear Elastic Fracture Mechanics and branch reinforcement methods used in Code Case N-513-4 were smaller as would be expected. The effects of jet thrust force were evaluated and it was determined there was little difference in force for a 0.50" diameter flaw size at 275 psig versus 490 psig. The study also determined that jet thrust force increases with increasing leakage rate and that it is appropriate to limit the application of this relief request to 490 psig. , Attachment 3 provides (See original submittal):

1) A review of relevant NRC approved relief requests

2) A structural integrity evaluation that includes:

• Design minimum wall thickness comparison
• Code Case N-513-4 allowable flaw size comparison
• Code Case N-513-4 cover thickness requirement comparison

3) A jet thrust force evaluation CNS will follow all requirements of Code Case N-513-4. With regard to augmented examination process as described in Section 5 of the Code Case, a sample size of at least five of the most susceptibie and accessible locations wiii be examined within 30 days of detecting the original flaw.

In summary, NPPD will apply ASME Code Case N-513-4 and RG 1.147, Revision 17 (or later NRC defined revision as applicable) for evaluation of RHRSWB piping flaws at CNS if Code repairs cannot reasonably be completed within the Technical Specifications required time limit. NPPD will apply a 490 psig maximum operating pressure in lieu of the 275 psig maximum operating pressure defined in paragraph l(c) of the Code Case. Code Case N-513-4 utilizes technical evaluation approaches that are based on principals that are accepted in other Code documents already acceptable to the NRC. In order to bolster defense-in-depth and avoid adverse consequences as a result of increasing the maximum operating pressure to 490 psig, NPPD is making one additional commitment to apply a 5 gpm leakage limit or lower as allowed by the engineering evaluation. This Relief Request is no longer valid for leakages greater than 5 gpm. The application of this Code Case, along with the additional commitment above, will maintain acceptable structural and leakage integrity while minimizing plant risk and personnel exposure by (7-150) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program minimizing the number of plant transients that could be incurred if degradation is required to be repaired based on ASME Section XI acceptance criteria only. Duration Of Proposed Alternative The proposed alternative is for use of Code Case N-513-4 for Class 3 RHRSWB piping and components within the scope of the Code Case and the request herein. A Section XI compliant repair/replacement will be completed prior to exceeding the next scheduled refueling outage, or allowable flaw size, or leakage in excess of 5 gpm, whichever comes first. This relief request will be applied for the duration of the fifth 10-year ISi interval. If a flaw is evaluated near the end of the interval and the next refueling outage is in the subsequent interval, the flaw may remain in service under this relief request until the next refueling outage. Precedents US NRC letter to Exelon Generation Company Nuclear Fleet- " ... Proposed Alternative to Use ASME Code Case N-513-4, dated September 6, 2016 (ML16230A237). 11 US NRC letter to "Peach Bottom Atomic Power Station, Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2 - Relief from the Requirements of the ASME Code," dated March 19, 2015 (ML15043A496). References

1. NRC Generic Letter 90-05, "Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2, and 3 Piping (Generic Letter 90-05), dated June 15, 1990.

11

2. NRC Regulatory Guide 1.147, "lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1, Revision 17," dated August 2014.

(7-151) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE NUCLEAR REGULATION FOR THE FIFTH 10-YEAR INSERVICE INSPECTION INTERVAL RELIEF REQUEST NO. RR5-03 ALTERNATE REPAIR FOR RESIDUAL HEAT REMOVAL (RHR) AND RHR SERVICE WATER BOOSTER PIPING NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated August 17, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17241A048), supplemented by letter dated May 16, 2018 (ADAMS Accession No, ML181438464), Nebraska Public Power District (NPPD, the licensee) requested relief from the requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code), Section XI, IWA-3120(b), at Cooper Nuclear Station (CNS). The licensee submitted Relief Request RR5-03 for the U.S. Nuclear Regulatory Commission's (NRCj review and approval for the repair of residual heat removal (RHR) service water booster (RHRSWB) piping using ASME Code Case N-513-4, "Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping Section XI, Division I," with exceptions. Specifically, pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z)(2), the licensee submitted Relief Request RR5-03 on the basis that compliance with the specified ASME Code repair would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. The NRC staff notes that the licensee revised the original Relief Request RRS-03 as part of a response to the NRC's request for additional information. Therefore, the NRC's evaluation below is for Relief Request RRS-03, as documented in the licensee's letter dated May 16, 2018. The NRC staff further notes that this is a contingency relief request. The licensee postulated degradation in the RHRSWB piping as part of analyses and technical basis to support the relief request. (7-152) Rev 3.0 Enclosure 5

Cooper Station 5th ISi & 3rd Interval CISI Program

2.0 REGULATORY EVALUATION

Adherence to Section XI of the ASME Code is mandated by 10 CFR 50.55a{g){4), "lnservice inspection standards requirements for operating plants," which states, in part, that ASME Code Class 1, 2, and 3 components will meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in ASME Code, Section XI. The regulation at 10 CFR 50.55a{z), "Alternatives to codes and standards requirements," states, in part, that: Alternatives to the requirements of paragraphs {b) through {h) of [10 CFR 50.55a] or portions thereof may be used when authorized by the Director, Office of Nuclear Reactor Regulation .... A proposed alternative must be submitted and authorized prior to implementation. The applicant or licensee must demonstrate that: . ( 1) Acceptable level of quality and safety. The proposed alternative would provide an acceptable level of quality and safety; or {2) Hardship without a compensating increase in quality and safety. Compliance with the specified requirements of this section would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Based on the above, and subject to the following technical evaluation, the NRC staff finds that regulatory authority exists for the licensee to request the use of an alternative and the NRC to authorize the proposed alternative.

3.0 TECHNICAL EVALUATION

3.1 ASME Code Component(s) Affected The affected components are the ASME Code Class 3 RHRSWB piping with a maximum operating pressure of less than or equal to 490 per square inch gauge {psig) and a maximum operating temperature less than 200 degrees Fahrenheit (°F). The RHR and RHRSWB systems are standby systems that typically operate during testing or plant shutdown. The licensee stated that the systems are designed such that RHRSWB operates at a higher pressure than RHR. Under this design, if there is an internal leak within a RHR heat exchanger, RHRSWB water, which is raw water from the Missouri River, will leak into the RHR system. As stated in the licensee's letter dated May 16, 2018, "The RHRSWB System is designed to provide an adequate supply of cooling water to the RHR heat exchangers during postulated accident and transient conditions to remove the design RHR System heat load and at adequate pressure to prevent uncontrolled release of fission products to the environment due to a RHR heat exchanger tube failure." As stated in the licensee's letter dated May 16, 2018, "RHRSWB System at CNS has exhibited a history of degradation similar to raw fresh water systems throughout the nuclear industry. Degradation requiring immediate action to address leakage or observed thinning in the system is generally due to localized corrosion mechanisms." (7-153) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 3.2 Applicable Code Edition and Addenda The applicable Code of Record for the fifth 10-year inservice inspection (ISi) interval and the ISi program is the 2007 Edition through 2008 Addenda of the ASME Code, Section XI. The fifth ISi interval started on April 1, 2016, and will end on February 28, 2026. 3.3 Applicable ASME Code Requirements As stated in the licensee's letter dated May 16, 2018, "ASME Code, Section XI, IWD-3120(b) requires that components exceeding the acceptance standards of IWD-3400 be subject to supplemental examination or to a repair/replacement activity. 3.4 Reason for Request The licensee proposed to use ASME Code Case N-513-4 to perform repair/replacement activities for degraded RHRSWB piping, which has a maximum operating pressure in excess of 275 psig and is the maximum allowed pressure in the code case. The licensee stated that a plant shutdown would be required within the action statement timeframes, as specified in the plant Technical Specifications, if the degraded RHRSWB piping is repaired in accordance with the ASME Code, Section XI. The licensee noted that plant shutdown activities result in additional radiation dose and plant risk that would be inappropriate when a degraded pipe condition is demonstrated to retain adequate margin to complete the component's function. The licensee noted that the use of an acceptable alternative analysis method in lieu of the immediate repair of the degraded RHRSWB piping will permit additional extent of condition examinations on the affected systems while allowing time for safe and orderly long term repair actions if necessary. ASME Code Case N-513-3 does not allow evaluation of flaws located away from attaching circumferential piping welds that are in elbows, bent pipe, reducers, expanders, and branch tees. Code Case N-513-3 also does not allow evaluation of flaws located in heat

• exchanger external tubing or piping. Code Case N-513-4 provides guidance for evaluation of flaws in these locations.

3.5 Proposed Aiternative The licensee proposed to apply ASME Code Case N-513-4 to disposition the degraded RHRSWB piping having a maximum operating pressure of 490 psig in lieu of repair/replacement activities in accordance with the ASME Code, Section XI.. 3.6 Basis for Use The licensee stated that the ASME recognized that relatively small flaws could remain in service without risk to the structural integrity of a piping system and developed ASME Code Case N-513. NRC approval of ASME Code Case N-513-3 in Regulatory Guide (RG) 1.147, Revision 17, "lnservice Inspection Code Case Acceptability, ASME Section XI, Division 1," allows temporary acceptance of partial through-wall or through-wall flaws provided that all NRG-imposed conditions on the code case are met. The temporary acceptance period is the time to the next scheduled refueling outage. ASME Code Case N-513-3 requires the Owner to demonstrate system operability due to leakage. ASME Code Case N-513-3 is not applicable to piping components such as elbows, bent pipe, reducers, expanders, and branch tees and external tubing or piping attached to heat exchangers. The ASME approved Code (7-154) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Case N-513-4 to expand use on these pipe locations and to revise several other areas of the code case. The licensee stated that it will follow all requirements of the ASME Code Case N-513-4 with a few exceptions as discussed below. The NRC staff notes that the discussion below follows the organizational structure of the ASME Code Case N-513-4. The licensee also provided hardship justification as discussed below. ASME Code Case N-513-4, Section 1, "Scope," limits its application to certain pipe components and operating conditions. Paragraph 1(c) of Section 1 limits the application to piping with a maximum operating pressure not exceeding 275 psig. The maximum operating pressure of the RHRSWB system is 490 psig. Therefore, the licensee requested relief from the pressure limits of paragraph 1(c). The licensee stated that it will evaluate each leak using the plant operability evaluation process in order to satisfy paragraph 1(f) of Section 1. The licensee's evaluation will consider requirements or commitments established for the piping system, continued degradation and potential consequences, operating experience, and engineering judgment. The licensee will consider but is not limited to system makeup capacity, containment integrity with the leak not isolated, effects on adjacent equipment, and the potential for room flooding. The licensee explained that the effects of leakage may impact the operability determination or the plant flooding analyses specified in paragraph 1(f) of ASME Code Case N-513-4. The licensee will determine the allowable leakage rate for a leaking flaw by dividing the critical leakage rate by a safety factor of four. The critical leakage rate is determined as the lowest leakage rate that can be tolerated and may be based on the allowable loss of inventory or the maximum leakage that can be tolerated relative to room flooding. The licensee noted that the safety factor of four on leakage is based upon ASME Code Case N-705, "Evaluation Criteria for Temporary Acceptance of Degradation in Moderate Energy Class 2 or 3 Vessels and Tanks Section XI, Division 1," dated October 12, 2006, which the NRC has accepted without condition in RG 1.147, Revision 17. Paragraph 2.2(e) of ASME Code Case N-705 requiies a safety factor of two on flaw size when estimating the flaw size from the leakage rate. This corresponds to a safety factor of four on leakage for nonplanar flaws. The licensee contended that although the use of a safety factor to determine an unknown flaw is considered conservative when the actual flaw size is known, this approach is deemed acceptable based upon the precedent of ASME Code Case N-705. The licensee noted that the subject alternative does not propose to use any portion of ASME Code Case N-705 and that its citation is intended only to provide technical basis for the safety factor on leakage. In the submittal dated May 16, 2018, the licensee stated that if ASME Code Case N-513-4 is applied to a leaking flaw in the RHRSWB system for leakage greater than 5 gallons per minute (gpm), the leakage shall be stopped throughout the temporary acceptance period by the use of engineered mechanical clamping. The licensee further stated that the engineered mechanical clamping shall be sufficient to withstand the maximum operating pressure and removable such that the frequent periodic inspections defined in paragraph 2(e) of ASME Code Case N-513-4 may be performed. (7-155) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Procedure ASME Code Case N-513-4, Section 2, "Procedure," provides provisions for flaw characterization and periodic inspections. The licensee stated that its proposed alternative does not take exception to Section 2 of ASME Code Case N-513-4. The licensee further stated that the periodic inspection interval per paragraph 2(e) of ASME Code Case N-513-4 will demonstrate that a leaking flaw continues to meet the flaw acceptance criteria and that the flaw will not grow to an unacceptable size. The licensee reported that during the temporary acceptance period, leaking flaws will be monitored daily, as required by paragraph 2(f) of ASME Code Case N-513-4, to confinn the analysis conditions used in the flaw evaluation remain valid. The licensee noted that significant change in the leakage rate would require reinspection, per paragraph 2(f) of the code case, and the licensee will perform any required reinspection. Flaw Evaluation ASME Code Case N-513-4, Section 3, "Flaw Evaluation," provides provisions for the evaluation of detected flaws. The proposed alternative does not take exception to Section 3 of ASME Code Case N-513-4. The licensee stated that allowable flaw sizes calculated by both the linear elastic fracture mechanics and branch reinforcement methods used in the code case were smaller than would be expected. The licensee evaluated the effects of jet thrust force and found that there was little difference in jet thrust force for a 0.50-inch diameter flaw size at an operating pressure of 275 psig versus 490 psig. Acceptance Criteria ASME Code Case N-513-4, Section 4, "Acceptance Criteria," provides provisions for the acceptance of flaws. The proposed alternative does not take exception to Section 4 of ASME Code Case N-513-4. Augmented Examination ASME Code Case N-513-4, Section 5, "Augmented Examination," provides provisions for the extent of condition examinations. In the submittal dated May 16, 2018, the licensee stated that with regard to augmented examination process as described in Section 5 of the code case, a sample size of at least five of the most susceptible and accessible locations will be examined within 30 days of detecting the original flaw, as required by paragraph 5(a) of ASME Code Case N-513-4. The licensee further stated that it will examine additional locations as specified in the requirements of paragraph 5(b) as it applies to paragraph 5(a). Mandatory Appendix I ASME Code Case N-513-4, Mandatory Appendix I, "Relations for Fm, Fb, and F for Through-Wall Flaws," provides provisions for the flaw evaluation. The proposed alternative does not take exception to Mandatory Appendix I of ASME Code Case N-513-4. Hardship The licensee stated that performing an ASME Code repair could have a detrimental impact on the overall risk by requiring a plant shutdown, thus requiring use of a piping system that is in (7-156) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program standby during normal operation. The application of ASME Code Case N-513-4, along with the additional commitments associated with this relief request, will maintain acceptable structural and leakage integrity while minimizing plant risk and personnel exposure by minimizing the number of plant transients that could be incurred if degradation is required to be repaired based on the requirements of the ASME Code, Section XI. The licensee concluded that compliance with the current ASME Code requirements results in a hardship without a compensating increase in the level of quality and safety. 3.7 Duration of Proposed Alternative The licensee stated in its submittal dated May 16, 2018, that an ASME Code, "Section XI. compliant repair/replacement will be completed prior to exceeding the next scheduled refueling outage, or allowable flaw size, or leakage in excess of 5 gpm, whichever comes first. This relief request will be applied for the duration of the fifth 10-year ISi interval. If a flaw is evaluated near the end of the interval and the next refueling outage is in the subsequent interval, the flaw may remain in service under this relief request until the next refueling outage." 3.8 NRC Staff Evaluation The NRC staff evaluated the licensee's proposed alternative with respect to the provisions of ASME Code Case N-513-4, which has not been approved for use by the NRC. For clarity, the NRC staff's evaluation of the proposed alternative will follow the organizational structure of ASME Code Case N-513-4. The NRC staff's evaluation is limited to CNS only and does not constitute a generic review of the code case. In its submittal dated May 16, 2018, the licensee provided the isometric drawings showing pipe support locations, pipe routing, nominal pipe size, outside diameter, pipe schedule, and wall thickness of various RHRSWB pipe segments. Based on the review of the information provided, the NRC staff determined that the scope of the subject piping is appropriately defined and identified. Therefore, the NRC staff finds that the subject piping satisfies paragraph 1{a) of ASME Code Case N-5i 3-4. Paragraph 1{c) of ASME Code Case N-513-4 limits the maximum operating pressure to 275 psig. To justify the use of this code case on the RHRSWB piping with a maximum operating pressure of 490 psig, the licensee demonstrated in Enclosure 2 of the May 16, 2018, submittal that {1) the structural integrity of the RHRSWB piping is achieved by a flaw evaluation, {2) the structural integrity of the subject piping will be maintained by periodically inspecting and monitoring, and {3} the leaking flaw and/or leak rate are limited to within the allowable value. Based on the flaw evaluation, periodic inspections and monitoring, and the leakage limit, the NRC staff finds the proposed alternative is acceptable with respect to paragraph 1{c). Paragraph 1{f) of ASME Code Case N-513-4 requires that "the Owner consider the effects of leakage in demonstrating system operability and performing plant flooding analyses." To address the NRC staff's question regarding what action will be taken before the leakage limit of 5 gpm is reached, the licensee explained that identified leaks will be quantified and entered into the CNS Corrective Action Program and assessed for system operability. The licensee will evaluate the leakage based on its plant-specific operability evaluation process as discussed above. The NRC staff finds it acceptable because the licensee's operability evaluation will (7-157) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program consider system makeup capacity, containment integrity with the leak not isolated, effects on adjacent equipment, and the potential for room flooding. The NRC staff notes that the licensee's flooding analysis showed that during normal operation, sump pumps in the four reactor building quad rooms are sized to handle leakage from the reactor building structure, which includes the torus area. The licensee stated that two 50 gpm sump pumps in each quad room have the capacity to pump a total of 100 gpm of leakage from each quad room of the reactor building structure. The sump pumps in the Emergency Condensate Storage Room in the control building basement have a total pumping capacity of 100 gpm. The NRC staff finds that the sump pumps in the reactor building have sufficient capacity to manage a 5-gpm leak. The NRC staff noted that as a part of the flooding analysis, the licensee identified the corresponding coolant flow from postulated pipe breaks in each of the above equipment areas, based on system pressure (adjusting for head loss and elevation difference), break area, and discharge coefficient. The NRC staff finds that all the licensee's analyzed breaks are adequately derived based on equipment available to safely shutdown and maintain the reactor in a safe shutdown condition. The NRC staff verified that the allowable break flows evaluated in the licensee's flooding analysis are significantly greater than the leakage limit of 5 gpm. The NRC staff finds that the proposed 5 gpm leakage limit is acceptable because a margin exists between the 5 gpm limit and the allowable break flow in the equipment areas. The NRC staff asked for the minimum leak rate and the flow rate that would cause the RHRSWB to not perform its intended function, and the average normal flow rate in the subject pipe. The licensee stated that each RHRSWB pump is verified to produce a flow rate of up to 4000 gpm as part of quarterly inservice testing and biennial performance testing. The RHRSWB System flow assumed in the analyses is 4000 gpm per pump with one pump operating in one loop. The NRC staff notes that, according to the licensee, RHR heat exchanger thermal performance is based on reduced tube side flow of 3500 gpm. The NRC staff determined that there is a margin of 500 gpm (4000 gpm - 3500 gpm) exists between the 4000 gpm that the RHRSWB system can deliver and a required coolant flow of 3500 gpm at the RHR heat exchanger tube side. The NRC staff finds that a RHRSWB piping leakage of 5 gpm is much less than the maigin of 500 gpm. Therefore, a leak of 5 gpm has a minimal impact to RHR heat exchanger performance. The NRC staff also recognizes that the leakage limit of 5 gpm is within the uncertainty of the flow instrumentation and within the capacity of RHRSWB system to provide the required flow. The NRC staff asked the licensee how the leakage in the RHRSWB piping can be detected and how the operators in the control room are notified. The licensee explained that a leak in the RHRSWB piping can be detected and communicated to the control room in many ways. The CNS Operations department conducts operator tours that vary from once per week (full torus floor area) to twice daily in the reactor building RHR heat exchanger room and control building basement. In addition to operator tours, plant walkdowns conducted by various departments, such as Radiation Protection, Maintenance, System Engineering, and management observations, provide additional opportunities for a leak to be detected and reported. The licensee noted that the minimum detectable leakage can vary from a small weep to a steady stream, depending on the size of the leak opening. Generally, leaks from the RHRSWB piping would be expected to be observed at a low point below the leak such as on the floor in these locations. The RHRSWB system is operated on an intermittent basis (minimum quarterly) so the probability of detecting a leak would be greatest when the RHRSWB system is in (7-158) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program operation. Other times, the piping is continuously pressurized at the service water operating pressure of approximately 30 to 50 psig. Larger leaks could be detected by the radwaste operators by observing changes in the floor drain and/or equipment drain collector tank revels. The licensee stated that engagement by CNS personnel provides reasonable assurance that a leak would be visually identified and reported to the control room in a timely manner. The NRC staff finds that the licensee does have adequate means and reasonable intervals to monitor the subject piping and report the leak before reaching the limit of 5 gpm. The NRC staff reviewed the pipe support locations on the piping isometric drawings and the jet force loads provided in Enclosure 2 of Attachment 3 to the submittal dated May 16, 2018. The NRC staff confirmed that, should the leakage occur, the existing pipe supports will be able to support the jet force loads from the allowable flaw size. The NRC staff determined that the licensee provided reasonable assurance that leakage from the RHRSWB piping will be detected early based on various indications, so that the operators can take appropriate corrective actions. The NRC staff finds that the licensee has satisfied paragraph 1(f) because it has considered effects of leakage and will implement a leakage limit of 5 gpm in demonstrating system operability. Based on above evaluation, the NRC staff finds that the proposed alternative satisfies the requirements of Section 1 of ASME Code Case N-513-4, except paragraph 1(c). However, the licensee has provided adequate justifications for the deviation from paragraph 1(c). Procedure The NRC staff determines that the proposed alternative will follow and does not take exception to Section 2 of ASME Code Case N-513-4. Therefore, the NRC staff finds that the proposed alternative is acceptable with respect to Section 2 of ASME Code Case N-513-4. Flaw Evaluation The NRC staff notes that Table 4 in Enclosure 2 of Attachment 3 to the submittal dated May 16, 2018, provides generic aiiowabie fiaw sizes, not specific to CNS. The iicensee expiained that Table 4 is meant to illustrate the effect of pressure on the allowable through-wall flaw size. The licensee stated that the plant-specific allowable flaw size is a function of the applied loading at the specific location for which this code case will be applied. The licensee noted that the exact location for which the code case will be applied cannot be known at the time of submittal. The licensee further stated that the size of a flaw will be limited to a size that does not exceed the acceptance criteria of the flaw evaluation or a flaw size resulting in a leakage rate of greater than 5 gpm, whichever is less. Therefore, the NRC staff finds that it is acceptable for the licensee to provide generic allowable flaw sizes as a reference for comparison purposes. The NRC staff notes that with a higher operating pressure of 490 psig, the allowable flaw size based on structural consideration will be smaller than those at the code case limit of 275 psig. On the other hand, the allowable minimum pipe wall thickness will be higher for the 490 psig than for the 275 psig case. The NRC staff finds that the smaller allowable flaw size and higher minimum wall thickness are conservative and it is appropriate to compensate for the higher operating pressure. However, the NRC staff notes that the final allowable flaw size will be appropriately limited to a size that does not exceed the acceptance criteria of the flaw evaluation or a flaw size resulting in a leakage rate of greater than 5 gpm, whichever is less. (7-159) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program In addition, the licensee stated that if leakage does occur in the future, it will follow the requirements in the code case to analyze the flaw based on plant-specific parameters. Based on the above, the NRC staff finds that the proposed alternative will follow and does not take exception to Section 3 of ASME Code Case N-513-4. Therefore, the proposed alternative is acceptable with respect to Section 3 of ASME Code Case N-513-4. Acceptance Criteria The NRC staff finds that the proposed alternative will follow and does not take exception to Section 4 of ASME Code Case N-513-4. Therefore, the proposed alternative is acceptable with respect to Section 4 of ASME Code Case N-513-4. Augmented Examination ASME Code Case N-513-4, Paragraph 5(a) requires, in part, that: A sample size of at least five of the most susceptible and accessible locations, or, if fewer than five, all susceptible and accessible locations shall be examined within 30 days of detecting the flaw. Paragraph 5(b) requires that: When a flaw is detected, an additional sample of the same size as defined in [paragraph 5](a) shall be examined In the submittal dated May 16, 2018, the licensee stated that it will examine the same number of pipe locations as required by paragraph 5(a) of ASME Code Case N-513-4. In addition, the licensee stated that it will examine additional locations as specified in the requirements of paragraph 5(b) as it applies to 5(a). The NRC staff finds that the licensee has satisfied the provisions of Section 5 of ASME Code Case N-513-4 and, therefore, the proposed augmented examination is acceptabie. Mandatory Appendix I The NRC staff finds that the proposed alternative will follow and does not take exception to the Mandatory Appendix I of ASME Code Case N-513-4. Therefore, the proposed alternative is acceptable with respect to Mandatory Appendix I of ASME Code Case N-513-4. Hardship Justification The NRC staff evaluated the technical basis of this request against the criteria contained in 10 CFR 50.55a(z)(2). The. NRC staff notes that performing the specified ASME Code compliant repairs will require a plant shutdown, which will lead to unnecessary plant transients and additional radiation dose. The plant shutdown is undesirable in terms of plant safety because it increases loads on the systems and components. In addition, the ASME Code compliant repair of the subject piping would not significantly increase plant quality or safety. The NRC staff, therefore, finds that requiring an ASME Code compliant repair is a hardship or unusual difficulty without a compensating increase in plant quality or safety. (7-160) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program In summary, the NRC staff finds that the proposed alternative will provide reasonable assurance of the structural integrity of the RHRSWB piping because ( 1) the licensee will follow the requirements of N-513-4 with exceptions for which the licensee has provided appropriate justifications, (2) the licensee will perform flaw evaluations in combination with periodic inspections to ensure that the flaw will not exceed the allowable per the code case, and (3) the licensee will implement a leakage limit of five gpm.

4.0 CONCLUSION

As set forth above, the NRC staff determines that the proposed alternative as documented in the submittal dated May 16, 2018, provides reasonable assurance of structural integrity of the RHRSWB piping. The NRC staff concludes that complying with the specified ASME Code requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(2). Therefore, the NRC staff authorizes the use of Relief Request RR5-03, as documented in the submittal dated May 16, 2018, for the fifth 10-year ISi interval on the basis that an ASME Code, Section XI compliant repair/replacement will be completed prior to exceeding the next scheduled refueling outage, or allowable flaw size, or leakage in excess of 5 gpm, whichever comes first. The NRC staff further concludes that if a flaw is evaluated near the end of the interval and the next refueling outage is in the subsequent interval, the flaw may remain in service under this relief request until the next refueling outage. The NRC staff notes that the authorization of Relief Request RR5-03 does not imply NRC approval of ASME Code Case N-513-4. All other ASME Code, Section XI, requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third party review by the Authorized Nuclear lnservice Inspector. Principai Contributor: j_ Tsao, NRRiDMLRiMPHB Date of issuance: July 31 , 2018 (7-161) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program J. Dent, Jr.

SUBJECT:

COOPER NUCLEAR STATION - REQUESTS FOR RELIEF ASSOCIATED WITH THE FIFTH 10-YEAR INSERVICE INSPECTION INTERVAL PROGRAM (CAC NOS. MG0175 THROUGH MG0179; EPIDS L-2017-LLR-0062 THROUGH L-2017-LLR-0066) DATED JULY 31, 2018 DISTRIBUTION: PUBLIC RidsNrrDssSnpb Resource PM File Copy RidsNrrDssSrxb Resource RidsACRS MailCTR Resource JJenkins, NRR RidsNrrDorlLp14 Resource RDavis, NRR RidsNrrPMCooper Resource JTsao, NRR RidsNrrLAPBlechman Resource APatel, NRR RidsRgn4Mai1Center Resource J8owen, OEDO RidsNrrDmlrMvib Resource LBurkhart, OEDO RidsNrrDmlrMphb Resource ADAMS Accession No. ML18183A325 '"b e-mail OFFICE NRR/DORULPL4/PM NRR/DORULPL4/LA NRR/DMLR/MVIB/BC* NRR/DMLR/MPHB/BC* NAME TWengert PBlechman w/comments SRuffin/DAlley DAlley/SRuffin 7/17/18 7/11/18 4/24/18 3/25/18 DATE 4/28/18 5/24/18 5/24/18 OFFICE NRR/DSS/SNPB* NRR/DORL/LPL4/BC NAME Rlukes RPascarelli DATE 5/1/18 7/31/18 (7-162) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 10CFRSO.SSa Request No. RRS-04 Proposed Use of Subsequent ASME Code Edition and Addenda in Accordance with 10 CFR 50.55a(g)(4)(iv) In accordance with 10 CFR 50.55a, "Codes and standards," paragraph (g)(4)(iv) and the guidance provided in Reference 1, Nebraska Public Power District (NPPD) requests NRG approval to use specific provisions of a later edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section XI, for Cooper Nuclear Station (CNS). Specifically, NPPD requests approval to use IWA-4540(b) of the 2017 Edition of the ASME B&PV Code.

1. ASME Code Component(s) Affected:

All Class 1, 2, and 3 items located in the ASME Section XI boundaries.

2. Requested Date for Approval:

Approval requested by September 23, 2020, to support the Cooper Nuclear Station refueling outage scheduled for September 2020.

3. Applicable Code Edition and Addenda

INTERVAL INTERVAL ISi INTERVAL EDITION SCHEDULED PLANT START END Cooper 2007 Edition, Nuclear 5 through 2008 04/01/2016 2/28/2026 Station Addenda

4. Proposed Subsequent Code Edition and Addenda (or Portion):

CNS performs Repair/Replacement activities in accordance with a site program based on an Edition of ASME Section XI which, at present, is the 2007 Edition through the 2008 Addenda. Pursuant to 10 CFR 50.55a(g)( 4 )(iv), NPPD requests permission to utilize IWA-4540(b) from the 2017 Edition. This subparagraph outlines items that are exempt from pressure testing after repair/replacement activities.

5. Related Requirements:

10 CFR 50.55a(g)( 4 )(iv) states:

   "lnservice examination of components and system pressure tests may meet the requirements set forth in subsequent editions and addenda that are incorporated by reference in paragraph (a) of this section, subject to the conditions listed in paragraph (b) of this section, and subject to Commission approval. Portions of editions or addenda may be used, provided that all related requirements of the respective editions or addenda are met."

Enclosure to NL-20-TBD 10 CFR 50.55a(b )(2) incorporates by reference Section XI, Division 1, of the ASME B&PV (7-163) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Code 2017 Edition as approved in Reference 3. NPPD is requesting to use of IWA-4540(b) of the 2017 Edition of ASME Section XI to utilize the exemptions listed. There are no related requirements or applicable conditions associated with this subparagraph, IWA-4540(b ).

6. Duration of Proposed Request:

The duration of this request will continue for the remainder of the site's current lnservice Inspection interval.

7.

References:

1. NRC Regulatory Issue Summary 2004-12, "Clarification on Use of Later Editions and Addenda to the ASME OM Code and Section XI," dated July 28, 2004

2. U.S. Nuclear Regulatory Commission Memorandum from D. Rudland (Senior Level Advisor, Division of New and Renewed Licenses) to Anna H. Bradford (Director, Division of New and Renewed Licenses), "Summary of the June 25, 2020, Public Meeting with the Nuclear Industry to Discuss Title 10 of the Code of Federal Regulations Section 50.55a(b)(2)(xxvi) Condition on the Pressure Testing of Class 1, 2, and 3 Mechanical Joints," dated July 8, 2020 (ML20189A286)

3. Federal Register, 85 FR 26540, dated May 4, 2020

8. Precedents

1. NL-20-0919 Vogtle Electric Generating Plant Units 1&2, VEGP-ISI-ALT-04-06, Request to use a Provision of a Later Edition of the ASME Boiler and Pressure Vessel Code, Section XI.

(7-164) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, O.C. 20555-0001 September 15, 2020 Mr. John Dent, Jr. Vice President and Chief Nuclear Officer Nebraska Public Power District 72676 648A Avenue P.O. Box 98 Brownville, NE 68321

SUBJECT:

COOPER NUCLEAR STATION - REQUEST TO USE A PROVISION OF A LATER EDITION OF THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS BOILER AND PRESSURE VESSEL CODE, SECTION XI (EPID L-2020-LLR-0123)

Dear Mr. Dent:

The U.S. Nuclear Regulatory Commission (NRC) has approved your request to use a provision of a later edition of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code, Section XI, for Cooper Nuclear Station (Cooper). This action is in response to your request dated August 26, 2020 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML20248H484). Specifically, pursuant to Title 10 of the Code of Federal Regulations (10 CFR) Section 50.55a(g)(4)(iv), Nebraska Public Power District proposed to use subparagraph IWA-4540(b) of the 2017 Edition of the ASME BPV Code, Section XI, in place of the of the corresponding subparagraph from the Code of Record. The NRC staff approves the use of subparagraph iWA-4540(b) of the 2017 Edition of ASME BPV Code, Section XI, foi Cooper for the duration of the fifth insen;ice inspection interval that started on April 1, 2016, and is scheduled to end on February 28, 2026. All other ASME BPV Code, Section XI, requirements which are not modified by the NRC staff's approval of the licensee's request remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector. Enclosed is the NRC staff's safety evaluation. (7-165) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program J. Dent, Jr. If you have any questions, please contact the Project Manager, Thomas Wengert at 301-415-4037 or by e-mail at Thomas.Wengert@nrc.gov. Sincerely, Jennifer Dixon-Herrity, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-298 cc: Listserv (7-166) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555--0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION b4 re"' q. 1-,~

                                                   . tP REQUEST RR5-a$-  ;,;

REQUEST TO USE A PROVISION OF A LATER EDITION OF THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS BOILER AND PRESSURE VESSEL CODE NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated August 26, 2020 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML20248H484), Nebraska Public Power District (the licensee) submitted proposal RR5-04 to use a portion of a later edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code for Cooper Nuclear Station (Cooper). Specifically, pursuant to Title 10 of the Code of Federal Regulations ( 10 CFR) Section 50.55a(g)(4)(iv), "Applicable ISi [lnservice Inspection] Code: Use of subsequent Code editions and addenda," the licensee proposed to use subparagraph IWA-4540(b) of the 2017 Edition of the ASME BPV Code, Section XI, instead of the corresponding subparagraph from the current Code of Record. The time period appiicabie for the use of the requested subsequent ASME BPV Code edition and addenda foi Coopei Nuclear Station is the fifth ISi interval. The licensee stated that there are no related requirements or applicable conditions associated with this subparagraph, IWA-4540(b). 2.0 PROPOSED USE OF SUBSEQUENT CODE EDITION AND ADDENDA 2.1 Components for Which the Subsequent Code Edition is Requested All Class 1, 2, and 3 items located in the ASME BPV Code, Section XI, boundaries. 2.2 Current Code Requirement Subparagraph IWA-4540(b) provides items that are exempt from pressure testing after repair/replacement activities. Enclosure (7-167) Rev 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program 2.3 Current Code Edition and Addenda of Record The ISi Code of Record for the current 10-year ISi interval at Cooper is the ASME BPV Code, Section XI, 2007 Edition through the 2008 Addenda. 2.4 Proposed Subsequent Code Edition and Addenda The proposed subsequent Code edition and addenda to be used is subparagraph IWA-4540(b) of the 2017 Edition of the ASME BPV Code, Section XI. 2.5 Duration of the Use of the Later Code Edition and Addenda The duration of this request for Cooper is for the fifth ISi interval that started on April 1, 2016, and is scheduled to end on February 28, 2026.

3.0 REGULATORY EVALUATION

The licensee is proposing to use a section of a later edition and addenda of the ASME BPV Code, Section XI, in accordance with 10 CFR 50.55a(g)(4)(iv), which states: lnservice examination of components and system pressure tests may meet the requirements set forth in subsequent editions and addenda that are incorporated by reference in paragraph (a) of this section, subject to the conditions listed in paragraph (b) of this section, and subject to Commission approval. Portions of editions or addenda may be used, provided that all related requirements of the respective editions or addenda are met. Given that 10 CFR 50.55(g)(4)(iv) permits the U.S. Nuclear Regulatory Commission (NRC) staff to approve the use of subsequent ASME BPV Code edition and addenda, the NRC staff finds that, subject to the following technical evaluation, the licensee may propose to use a section of a later edition and addenda of the ASME BPV Code, Section XI, and the NRC staff has the regulatory authority to approve the later edition and addenda of the ASME BPV Code, Section XI. 4.0 NRC TECHNICAL EVALUATION As previously stated in Section 3.0 of this safety evaluation, prior to approving the use of a subsequent edition and addenda of the ASME BPV Code under 10 CFR 50.55a(g)(4)(iv), the NRC staff must find that (1) the proposed subsequent edition and addenda are incorporated by reference in 10 CFR 50.55a(a), "Documents approved for incorporation by reference"; (2) the licensee has identified any conditions listed in 10 CFR 50.55a(b), "Use and conditions on the use of standards," appropriate to the request and will comply with those conditions; (3) the licensee has requested approval to use the subsequent edition and addenda; and (4) if only portions of edition or addenda are to be used, all related requirements of the respective edition or addenda are met. If these criteria are met, the NRC staff finds the use of the subsequent edition and addenda of the ASME BPV Code, Section XI, to be acceptable. 4.1 Incorporation by Reference In evaluating the first criterion, 10 CFR 50.55a(a) incorporates by reference the ASME BPV Code, Section XI, from the 1970 Edition through the 1976 Winter Addenda, and the (7-168) Rev 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 1977 Edition through the 2017 Edition. The licensee proposed to use the 2017 Edition, which is included in the list of editions and addenda incorporated by reference in the current edition of 10 CFR 50.55a(a). Therefore, the NRC finds that the first criterion has been satisfied. 4.2 Subject to Conditions Listed in 10 CFR 50.55a(b) In evaluating the second criterion, the NRC staff finds that 10 CFR 50.55a(b) contains no conditions relevant to this request. Therefore, the NRC staff finds that the second criterion has been satisfied. 4.3 Requesting Commission Approval In evaluating the third criterion, the licensee's request dated August 26, 2020, constitutes a request to the Commission for approval to use a subsequent edition/addendum of the ASME BPV Code. Therefore, the NRC staff finds that the third criterion has been satisfied. 4.4 All Related Requirements In evaluating the fourth criterion, the NRC staff finds that there are no related requirements relevant to this request. Therefore, the NRC staff finds that the fourth criterion has been satisfied. 4.5 Summary Based on the review above, the NRC staff finds that the licensee has adequately addressed all regulatory requirements set forth in 10 CFR 50.55a(g)(4)(iv).

5.0 CONCLUSION

As set forth above, NRC staff finds that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(g)(4 )(iv). Therefore, the NRC staff concludes that the use of subparagraph IWA-4540(b) the 2017 Edition of the ASME BPV Code, Section XI, is acceptable. The NRC staff approves the use of subparagraph IWA-4540(b) of the 2017 Edition of the ASME BPV Code, Section XI, at Cooper Nuclear Station for the duration of the fifth ISi interval. All other ASME BPV Code, Section XI, requirements which are not modified by the NRC staffs approval of the licensee's request remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector. Principal Contributor: T. Wengert, NRR Date: September 15, 2020 (7-169) Rev 3.0

ML20255A217

• via email OFFICE NRR/DORULPL4/PM* NRR/DORULPL4/LA* NRR/DNRUNPHP/BC* NRR/DORULPL4/BC*

NAME TWengert PBlechman MMitchell JDixon-Herrity DATE 9/14/2020 9/11/2020 9/14/2020 9/15/2020 Cooper Station 5th ISi & 3rd Interval CISI Program 8.0 PRESSURE TESTING System pressure tests shall be conducted in accordance with the rules of ASME Section XI as modified by 10CFR50.55a to the maximum extent practicable. Where such impracticalities exist, relief has been requested and alternative test requirements have been proposed. Relief requests are outlined in this program, Section 10. Pressure tests are implemented in accordance with CNS administrative procedures. System pressure tests of Class 1, 2, and 3 systems will be performed as specified in the Pressure Test Summary Tables on the following pages. (8-1) Revision 0

Cooper Station 5th IS 3rd Interval CISI Progra1. Freq. P&ID System Class Exam Category Item No. Test Type Relief Request Technical Position (Period) sheet# 1 2026, 2027, 1 B-P B15.10 IWB-5220 2038, 2039, NSSS Each 2040, 2041, RPS-01 Refueling (Leakage) Outage 2042-1, 2043, 2 C-H (7.10 IWC-5220 2044 2045-1, 2045-2 2026, 2027, 2038, 2039, Once Per 2040, 2041, RPS-01 1 NSSS (Leakage) 1 B-P B15.20 IWB-5220 Interval 2042-1, 2043, 2044 2045-1, 2045-2 PT-01, cs Each 2 C-H (7.10 IWC-5220 2045-1 PT-02, LOOP A Period PT-03 PT-01, cs Each 2 C-H (7.10 IWC-5220 2045-1 PT-02, LOOP B Period PT-03 PT-01, 2 C-H C7.10 IWC-5220 Each PT-02, HPCI 2044 Period PT-03, 3 D-B D2.10 IWD-5220 PT-04 (8-2) Revision O

Cooper Station 5th I, 3rd lnteNal CISI Progra,., Freq. P&ID System Class Exam Category Item No. Test Type Relief Request (Period) Technical Position sheet# 2031-1 2 C-H C7.10 IWC-5220 REC Each 2031-2 3 D-8 02.10 IWD-5220 Period 2036-1 PT-01, Each 2041 PT-02, RCIC 2 C-H C7.10 IWC-5220 Period 2043 PT-03, PT-04 PT-01, RHR (2.33 Each 2 C-H IWC-5220 2040 PT-02, LOOP A (7.10 Period PT-03 PT-01, RHR C2.33 IWC-5220 Each 2 C-H 2040 PT-02, LOOP B C7.10 Period PT-03 Each NBI 3 D-B D2.10 IWD-5220 2026,2027,2041 Period Note 1. Per IWB-5222(b), The Class 1 pressure retaining boundary which is not pressurized when the system valves are in the position required for normal reactor startup shall be pressurized and examined at or near the end of the inspection interval. This boundary may be tested in its entirety or in portions and testing may be performed during the testing of the boundary of IWB-5222(a) .. SW 2006-1, 2006-2, 2006-Each 3 D-B 02.10 IWD-5220 3, 2006-4, 2036-1, LOOP A Period 2077 SW 2006-1, 2006-2, 2006-Each 3 D-B D2.10 IWD-5220 3, 2006-4, 2036-1, LOOP B Period 2077 MSRV DISCHARGE Each 3 D-B D2.10 IWD-5220 2028 PT-03 Period (8-3) Revision 0

Cooper Station 5th IS 3rd lnteNal GISI Progran, Freq. P&ID System Class Exam Category Item No. Test Type Relief Request Technical Position (Period) sheet# Each TIP 2 C-H (7.10 IWC-5220 2083 Period Each SERVICE AIR 2 C-H C7.10 IWC-5220 2010-3 Period Each H202 2 C-H C7.10 IWC-5220 2022 Period Each DEMIN WATER 2 C-H C7.10 IWC-5220 2027 Period Each DRAINS 2 C-H C7.10 IWC-5220 2028 Period Each REACTOR RECIRC. 2 C-H (7.10 IWC-5220 2027 Period Each INST AIR 2 C-H C7.10 IWC-5220 2010-2 Period Each PCC, NI, and SBNI 2 C-H C7.10 IWC-5220 2022,2084 Period Each RPVINST 2 C-H C7.10 IWC-5220 2026 Period (8-4) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program 9.0 SYSTEM PRESSURE TESTING TECHNICAL APPROACH AND POSITION INDEX/SUMMARIES I I Summary I Position PT-01 Valve Seats as Pressurization Boundaries PT-02 Leakage through mechanical connections PT-03 Open ended discharge piping PT-04 Buried Components (9-1) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program TECHNICAL APPROACH AND POSITION NUMBER: PT-01 COMPONENT IDENTIFICATION Code Classes: 1, 2, and 3 Examination Categories: B-P, C-H, and D-8 Items: 815.10, C7.10, D2.10

== Description:== Valve Seats as Pressurization Boundaries. CODE REQUIREMENT ASME Section XI requires that the pressurization boundary for the system leakage test extend to the components containing pressurized reactor coolant under the plant mode of normal reactor startup (IWB-5222) and components required to operate or support the safety function of the system (IWC-5222 and IWD-5222). Hydrostatic test boundaries, IWA-5222(a), shall be defined by the system boundaries within which the components have the same minimum required classification and are designed to the same pressure rating as governed by the system function and the internal fluid operating conditions, respectively. POSITION CNS's position is that regardless of the type of pressure test performed (i.e. system leakage or hydrostatic), the pressurization boundary extends up to the seat of the valve used for isolation. For example, in order to hydrostatically test the Class 1 components, the valve that provides the Class break would be used as the isolation point. In this case, the true pressurization boundary, and class break, is actually at the valve seat. Any requirement to test beyond the valve seat is dependent only on whether or not the piping on the other side of the valve seat is ISi Class 1, 2, or 3. The extension of the pressurization boundary during a system leakage test would require an abnormal valve line-up. Extending the boundary for a hydrostatic test could result in over pressurization of low pressure piping at systems that have a high/low pressure interface (such as RHR and Core Spray). In order to simplify preparation of the walkdown checklists, CNS will perform a VT-2 visual examination of the entire boundary valve body and bonnet (during pressurization up to the valve seat). REFERENCES

1. ASME Section XI, 2007 Edition, 2008 Addenda, IWA-5221, IWA-5222, IWB-5222, IWC-5222, IWD-5222 (9-2) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program TECHNICAL APPROACH AND POStTION NUMBER: PT-02 COMPONENT IDENTIFICATION Code Classes: 1, 2, and 3 Examination Categories: B-P, C-H, and D-B Items: 815.10, C7.10, D2.10

== Description:== Leakage through mechanical connections. CODE REQUIREMENT ASME Section XI requires that the pressurization boundary for the system leakage test extend to the components containing pressurized reactor coolant under the plant mode of normal reactor startup (IWB-5222) and components required to operate or support the safety function of the system (IWC-5222 and IWD-5222). Hydrostatic test boundaries, IWA-5222(a), shall be defined by the system boundaries within which the components have the same minimum required classification and are designed to the same pressure rating as governed by the system function and the internal fluid operating conditions, respectively. POSITION The CNS position is that leakage through mechanical connections, such as valve packing or gaskets, is not considered to be a failure of the pressure test, provided that the test pressure is maintained for the duration of the test. Leakage through mechanical connections will be noted and evaluated in accordance with plant administrative procedures. Excessive leakage will be repaired; however, a subsequent pressure test is not required. Similarly, leakage past a valve seat is not considered to be a failure. If the valve is required to pass a seat leakage test, then leakage in excess of the allowable limit will be evaluated and appropriate corrective action taken. A subsequent seat leakage test may be required, but another pressure test is not required. REFERENCES

1. ASME Section XI, 2007 Edition, 2008 Addenda, IWA-5221, IWA-5222, IWB-5222, IWC-5222, IWD-5222 (9-3) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program TECHNICAL APPROACH AND POSITION NUMBER: PT-03 COMPONENT IDENTIFICATION Code Classes: 2 and 3 Examination Categories: C-H and D-B Items: C7.10 and D2.10

Description:

Open ended discharge piping CODE REQUIREMENT ASME Section XI requires that the pressure test boundary for the system leakage test includes only those portions of the system required to operate or support the safety function up to and including the first normaUy closed valve (including a safety or relief valve} or valve capable of automatic closure when the safety function is required (IWC-5222(a) and IWD-5222(a)}. items outside the boundaries described above, and open ended discharge piping, are excluded from the examination requirements (IWC-5222(b} and IWD-5222(b)). Interpretation: Xl-1-98-13

Subject:

IWC-2500-1; Category C-H (Winter 1979 Addenda through 1990 Addenda), Table IWD-2500-1; Categories D-A, D-B, and O-C (Winter 1977 Addenda through 1990 Addenda}, IWC-5240 (1991 Addenda Through 1992 Addenda), IWC-5222 (1993 Addenda Through 1996 Addenda), and IWD-5240 (1991 Addenda Through 1996 Addenda) Date Issued: November 21, 1997 File Number: IN97-007 Question: Is it the intent of Section XI that open-ended portions of Class 2 and 3 systems are exempted from system pressure tests and associated VT-2 visual examination? Reply: Yes. POSITION The CNS position is that test return lines on Class 2 systems (e.g., HPCI, RCIC, Core Spray) that discharge to the suppression pool are not required for the safety function of the parent system (they may have a passive safety function as extensions of primary containment) are therefore excluded from the examination requirements. They will be verified for unobstructed flow in conjunction with the satisfactory performance of the applicable 1ST pump test. Containment spray lines in the RHR System beyond the injection valves are also considered open ended Class 2 piping and are similarly excluded from examination. An open flow test is not required for this piping. The MS relief valve discharge piping in containment is considered open ended Class 3 piping. The Class 1 relief valve is the isolation boundary. This discharge piping is not included in any (9-4) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program periodic pressure test because it is not periodically pressurized as described in IWD-5221. References

1. ASME Section XI, 2007 Edition, 2008 Addenda IWC-5222(b), IWD-5222(b)

2. ASME Section XI Interpretation Xl-1-98-13 (9-5) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program TECHNICAL APPROACH AND POSITION NUMBER: PT-04 COMPONENT IDENTIFICATION Code Classes: 3 Examination Categories: D-B Item: 02.10

== Description:== Buried Components CODE REQUIREMENT Table IWD-2500-1, Item No. D2.10 requires system leakage tests for the pressure retaining boundary of Class 3 piping. IWA-5244(b)(1) states for buried components where a VT-2 visual examination cannot be performed and the line is isolable by means of valves, a test that determines the rate of pressure loss is required. Alternatively, the test may determine the change in flow between the ends of the buried components. POSITION The HPCI and RCIC Class 3 suction piping (18" HP-5 common suction) leading from the Emergency Condensate storage tanks contain a portion of piping that is buried between the Control Building and Reactor Building and is inaccessible for VT-2 examination. Per 6.HPCl.501, verification that tank levels do not decrease provides verification, per Paragraph 1WA-5244(b)(1), that no side stream leakage in the buried portion of the piping is occurring. REFERENCES

1. ASME Section XI, 2007 Edition, 2008 Addenda, IWA-5244

2. Burns and Roe drawing 4179, STRUCTURAL CONTROL BUILDING SECTIONS & DETAILS

3. Burns and Roe drawing 4171, STRUCTURAL CONTROL BUILDING FOUNDATION PLAN & SECTIONS (9-6) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program 10.0 PRESSURE TESTING RELIEF REQUESTS AND REQUESTS FOR ALTERNATIVES 10.0 RELIEF REQUESTS Throughout this program, the term "relief request" is used interchangeably referring to submittals to the NRC requesting permission to deviate from either an ASME Section XI requirement, a 10 CFR 50.SSa rule, or to use provisions from Editions or Addenda of Section XI not approved by the NRC as referenced in 10 CFR 50.SSa(l)(ii). However, when communicating with the NRC and in written requests to deviate, the terms as defined below must be used for clarity and to satisfy 10 CFR 50.SSa. Submittals to the NRC must clearly identify which of the below rules are being used to request the deviation. Table 10.0-1 contains an index of Relief Requests written in accordance with 10 CFR 50.SSa(z) and (g)(S). The applicable NPPD submittal and NRC Safety Evaluation Report (SER) correspondence numbers are also included for each request. 10.1 Request for Alternatives When seeking an alternative to the rules contained in 10 CFR 50.SSa(b), (c), (d), (e), (f), (g), or (h) the request is submitted under the provision of 10 CFR 50.SSa(z). Once approved by the Director, Office of Nuclear Reactor Regulation, the alternative may be incorporated into the ISi program. These types of requests are typically used to request use of Code Cases, Code Edition, or Addenda not yet approved by the NRC. Request for Alternatives must be approved by the NRC prior to their implementation or use. Within the provisions of 10 CFR 50.SSa(z) there are two specific methods of submittal: 10.1.1 10 CFR 50.SSa(a)(z)(l) allows alternatives when aut~orized by the NRC, if the proposed alternatives would provide an acceptable level of quality and safety. Requests submitted under these provisions are not required to demonstrate hardship or burden. 10.1.2 10 CFR 50.55a(z)(2) also allows alternatives when authorized by the NRC, if compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. When submitted under this provision, there must be evidence of unusual hardship or difficulty. Typically this hardship will be dose or excessive disassembly. 10.2 Relief Request Required due to Impracticality or Limited Examinations 10 CFR 50.SS(a)(g)(S)(iii) and (iv) allows relief to be requested in instances when a Code requirement is deemed impractical with (iv) being specific to examination requirements that are determined to be impractical. The provisions of these two paragraphs are typically used to address impracticalities like limited examination coverage. Under 10 CFR 50.SS(a)(g)(S)(iv), relief requests for examination impracticalities must be provided to the NRC no later than 12 months after the end of the active 120-month interval. In cases where the ASME Section XI requirements for inservice inspection are considered impractical, NPPD will notify the NRC and submit information to support the determination, (10-1) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program as required by 10 CFR 50.55a(g)(5). The submittal of this information will be referred to as a Request for Relief. 10.3 Requests to use Later Edition and Addenda of ASME Section XI On July 28, 2004, the NRC published Regulatory Issue Summary (RIS) 2004-12, "Clarification on Use of Later Editions and Addenda to ASME OM Code and Section XI". This RIS clarifies the NRC position on using Editions and Addenda of Section XI, in whole or in part, later than those specified in the ISi program. If the desired Edition or Addenda are referenced in 10 CFR 50.55a(l)(ii), the request is submitted following the guidance of the RIS. These types of request are not required to demonstrate hardship, difficulty, or provide evidence of quality and safety. They do need to ensure that all related requirements are also used. Requests to use edition and/or addenda of ASME Section XI that are referenced in 10 CFR 50.55a(l)(ii) that are later than the initial Code of Record established for the ISi program shall be submitted under the provisions of 10 CFR 50.55a(g)(4)(iv). RP5-01 0 Implementation of Code NLS2015025 NRC2016005 Case N-795 (For information dated 6/18/15 dated 2/24/16 only, Case N-795 has been {CAC No. MF6335) approved for use by the NRC via RG 1.147, Rev 19) PRS-02 0 Definition of Pressure NLS2018061 NRC2018027 Retaining Boundary for dated 11/5/18 dated 11/6/18 System Leakage Test (Superseded by RPS-02, Rev NLS2018063 0). dated 11/8/18 RPS-02 0 Definition of Pressure NLS2019034 NRC2020002 Retaining Boundary for dated 6/28/2019 dated 3/19/2020 System Leakage Test (10-2) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program 10 CFR 50.SSa Request No. RPS-01 (Info Only) Implementation of Code Case N-795 Propose Alternative in Accordance with 10 CFR 50.55a(z)(2) Hardship without a Compensating Increase in Quality and Safety ASME Code Component(s) Affected Code Class: ASM E Section XI Code Class 1 Component Numbers: Not Applicable Code

References:

ASME Section XI, 2007 Edition with 2008 Addenda, IWB-5221(a) Examination Category: Not Applicable Item Number(s): Not Applicable Applicable ASME Code Requirements 10 CFR 50.55a(b)(2)(xxvi) requires the use of the 1998 Edition, IWA-4540(c) for pressure testing of Class 1, 2, & 3 mechanical joints The 1998 Edition of ASME Section XI, IWA-4540(c) states: "Mechanical joints made in installation of pressure retaining items shall be pressure tested in accordance with IWA-5211(a). Mechanical joints for component connections, piping, tubing (except heat exchanger tubing), valves, and fittings, NPS-1 and smaller, are exempt from the pressure test." NPPD understands that this means a pressure test is required for a mechanical joint when a new valve or flange greater than NPS-1 is installed as part of the repair/replacement activity, and does not include those items covered by IWA-4132 "Items Rotated From Stock." Note that the 1998 Edition, IWA-5211(a) states "a system leakage test conducted during operation at nominal operating pressure, or when pressurized to nominal operating pressure and temperature." NPPD has defined this to be a minimum of 1005 psig for components within the Reactor Coolant Pressure Boundary (RCPB). The applicability for Code Case N-795 begins with the 1998 Edition with the 1999 Addenda and includes applicability to the 2007 Edition with the 2008 Addenda; although the 1998 Edition specified in 10 CFR 50.5Sa(b)(2)(xxvi) is not included in the published applicability, NPPD believes that the comparison of IWB-5211(a) from the 1998 Edition and IWB-5221(a) of the 2007 Edition with the 2008 Addenda is compatible when the pressure has been defined specifically as described above. Therefore, N PPD concludes that Code Case N-795 may be used for the 1998 Edition specified by the NRC condition found in 10 CFR 50.SSa. Welded or Brazed Joints ASME Section XI, 2007 Edition with the 2008 Addenda IWA-4540(a) states: "Unless exempted by IWA-4540(b), repair/replacement activities performed by welding or brazing on pressure-retaining boundary shall include a hydrostatic or system leakage test in accordance with IWA-5000, prior to, or as part of, returning to service. Only (10-3) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program brazed joints and welds made in the course of a repair/replacement activity require pressurization and VT-2 visual examination during the test." Pressure Testing Requirements ASME Section XI, 2007 Edition with the 2008 Addenda IWB-5221(a) states: "The system leakage test shall be conducted at a pressure not less than the pressure corresponding to 100% rated reactor power."

Reason for Request

At the Cooper Nuclear Station (CNS), Class 1 pressure tests for repair/replacement activities in accordance with IWA-4540 at pressure corresponding to 100% rated reactor power when performed after Table IWB-2500-1, Category B-P testing has been completed, requires abnormal plant conditions/alignments. Testing at these abnormal plant conditions/alignments results in additional risks and delays while providing little added benefit beyond tests which could be performed at slightly reduced pressures under normal plant conditions. Code Case N-795 is intended to provide alternative test pressure for certain Class 1 pressure tests. The code case would be used following repair/replacement activities (excluding those on the reactor vessel) which occur subsequent to the periodic Class 1 pressure test required by Table IWB-2500-1, Category B-P and prior to the next refueling outage on those components that cannot be isolated. Components which can be isolated will be pressure tested at a pressure in accordance with IWB-5221(a). Performance of the Category B-P pressure test each refueling outage, places CNS in a position of significantly reduced margin, approaching the fracture toughness limits defined in the Technical Specification Pressure Temperature (P-T) Curves. To violate these curves would place the vessel in a low temperature over pressure (LTOP) condition. With strict operational control procedures, specific component alignment and operations staff training regarding LTOP this may be considered acceptable to be at this reduced margin condition for the purpose of verifying the leakage status/integrity of the primary system in order to meet the ASME Section XI, Category B-P requirements prior to startup from a refueling outage, however to perform this evolution more frequently would increase the overall risks to the plant. Proposed Alternative and Basis for Use Proposed Alternative Pursuant to 10 CFR S0.55a(z)(2), relief is requested on the basis that the proposed alternative provides an acceptable level of quality and safety. NPPD proposes to perform the system leakage testing and associated VT-2 examination following repair/replacement activities on those components that cannot be isolated in accordance with Code Case N-795, however using a longer hold times than specified in the code case. The system leakage test will be performed during the normal operational start-up sequence at a minimum of 900 psig (10-4) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program (~90% of the pressure required by IWB-5221(a)) following a one hour hold time (for uninsulated components) and an eight hour hold time (for insulated components) in lieu of the nominal operating pressure associated with 100% reactor power of approximately 1005 psig. Note that this code case is not applicable to Class 1 pressure tests performed to satisfy the periodic requirement of Table IWB-2500-1, Category B-P and is not applicable to pressure tests required following repair/replacement activities on the reactor vessel. NPPD will continue to conduct the periodic system leakage tests required by IWB-2500-1, Category B-P at the end of each refueling outage at a pressure corresponding to 100% rated reactor power. Basis for Use By the end of a normal refueling outage the core decay heat has had time to decrease and some spent fuel has been removed and some new fuel has been added. The result is a much lower decay heat load and much lower heatup rates. At the end of a normal refueling outage, the rate of temperature increase is able to be tolerated during the system leakage test. During normal performance of this system leakage test, the pressurization phase of the test is taken at a slow and very controlled pace. The pressurization phase normally takes several hours to reach test conditions. However, following a maintenance or forced outage, there is a much larger decay heat load from the reactor core. That heat load is difficult to control once SDC has been removed from service. Once SDC is removed from service, heatup starts immediately. During a short term mid-cycle shutdown, the projected heatup rate could be in the order of 0.4°F per minute depending on how quickly SDC is secured. Under those conditions, the time available to pressurize up to test conditions, perform the VT-2 exam and return to SDC will be greatly reduced. The hurried time frames may create a more error-likely environment. During short mid-cycle outages, the core does have a larger decay heat load. Considering only the actions of isolating SDC from the vessel under high decay heat loads, there is some inherent risk. There would be some probability that once isolated, mechanical, control or operational problems could occur which could delay return to SDC. The required VT-2 examinations performed following repair/replacement activities are limited to the areas affected by the work thereby allowing for a focused exam. The VT-2 exams, therefore, have a much smaller examination boundary than the periodic test. However, during normal startup with normal power ascension, nominal operating pressure of 1005 psig is reached at a reactor power level of approximately 85%. If access to containment were permitted at this power level, personnel would be exposed to excessive radiation levels, including significant exposure to neutron radiation field, which is contrary to Station ALARA practices. Indication of leakage identified through the VT-2 examinations during a test at a pressure correlating to either the 100% rated reactor power level or at ~go% of that value will not be significantly different between the two tests. Higher pressure under the otherwise same conditions will produce a higher flow rate but the difference is not significant. Code Case N-795 proposes increased hold times, as compared to a test performed at normal operating pressure, to allow for more leakage from the pressure boundary if a through-wall or mechanical joint leakage condition exists; Further, NPPD proposes to implement longer hold times than specifierl (10-5) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program by the Code Case. NPPD believes these longer hold times are justified to allow for additional leakage to accumulate at the area of interest so as to be more evident during the VT-2 examination, should a through-wall or mechanical joint leakage condition exist. This alternate test pressure, when combined with longer hold times, is still adequate to provide evidence of leakage, should a leak exist. With respect to using the alternative requirements of Code Case N-795 to welded repair/replacement activities, the ASME concluded during the development of Code Case N-416 "Alternative Pressure Test Requirements for Welded or Brazed Repair, Fabrication Welds or Brazed Joints for Replacement Parts and Piping Subassemblies, or Installation of Replacement Items by Welding or Brazing, Classes 1, 2, and 3" and Code Case N-498, "Alternative Requirements for 10-Year System Hydrostatic Testing for Class 1, 2, and 3 Systems", that the hydrostatic test (a test using pressure higher than a system leakage test) was not a structural integrity test, but a leakage test. The fact that the hydrostatic test does not verify structural integrity served as the basis for replacing it with a system leakage test. Both code cases are approved by the NRC in Regulatory Guide 1.147. It is the requirements of the construction code including the construction code nondestructive examinations used for the repair/replacement activity that ensures structural integrity of the pressure boundary and its welded or brazed connections. Based on research performed by ASME, the effect of testing at a pressure that corresponds with 90% of rated power verses 100% of rated power is not reduced validation of structural integrity, but a potential in leakage rate reduction. Therefore, NPPD believes that the alternative requirements of Code Case N-795 on welded or brazed repair/replacement activities are acceptable. Research described in the White Paper performed by Argonne National Laboratory, as commissioned by the NRC, indicates that the relationship of leakage and pressure is relatively linear. Therefore, leakage rates associated with pressure at 90% of normal operating pressure would be approximately 10% less than a leakage rate at 100% of normal operating pressure. However, any reduction in leakage rate is more than compensated for by the increase in hold time (600% for noninsu!ated and 200% for insulated). Other research cited in the White Paper supports the conclusions of Argonne National Laboratory. While NPPD does not expect that leakage will occur, any leakage will be related to the differential pressure at the point of leakage, or across the connection. A 10% reduction in the test pressure is not expected to result in the arrest of a leak that would occur at nominal operating pressure. In the unlikely event that leakage would occur subsequent to the VT-2 examination, at higher pressures associated with 100% rated reactor power, leakage would be detected by the drywell monitoring systems, which include drywell pressure monitoring, the containment atmosphere monitoring system (CAM), and the drywell floor drain sumps. Leakage monitoring is required by Technical Specifications. Code Case N-795 and the NPPD proposed hold times allows for an adequate pressure test to be performed; ensuring the safety margin is not reduced due to VT-2 examination being performed at the slightly reduced pressure. There is no physical benefit withheld by testing at the slightly reduced pressure. The affected pressure boundary will be tested and will be otherwise fully capable of performing its intended safety function as part of the Reactor Coolant Pressure Boundary. 3.0 (10-6) Rev.

                                                                                   'Cooper Station 5th ISi &

3rd Interval GISI Program The use of Code Case N-795 will only be applied if the System Leakage Test required by IWB-2500-1, Category 8-P has been completed for the cycle on components that cannot be isolated and will not be implemented for any repair/replacement activity performed on the reactor pressure vessel. In summary, the proposed alternative is to perform the system leakage test and VT-2 examination in accordance with Code Case N-795 at 900 psig with a minimum hold time of one hour for uninsulated components and an eight hour hold time for insulated components during maintenance, forced outages, or following the performance of the periodic pressure test required by Table IWB-2500-1, Category 8-P during refueling outages. The provisions of this alternative are not applicable to the Examination Category 8-P pressure test performed during refueling outages or to pressure tests of repair/replacement activities of the reactor pressure vessel or components that can be isolated. Considering the discussion above, NPPD believes that this alternative will provide an acceptable verification of the leak integrity of the locations having repair/replacement activities performed without putting the plant in a non-conservative operational condition and without unnecessary radiation exposure and safety challenges to personnel. Duration of Proposed Alternative This proposed alternative will be used for the entire Fifth Ten-Year Interval of the lnservice Inspection Program for CNS. (Note, this Relief has been superseded by use of ASME Section XI Code Case N-795, approved per Regulation Guide 1.147, lnservice Inspection Code Case Acceptability, Revision 19, October 2019, See Section 3 of this program for NRC conditions on use of CC N-795.) Precedents

1. 10 CFR 50.55a(a)(3)(ii) request was approved for Susquehanna Steam Electric Station, Units 1 and 2 Relief Request for the Fourth 10-Year lnservice Inspection Interval (TAC NOS. MF2705 through MF-2714) dated June 9, 2014 and (ADAMS Accession No. ML14141A073).

2. 10 CFR 50.55a(a)(3)(ii) request was approved for Columbia Generating Station Relief Request 3ISl-12 proposed alternative using Code Case N-795 (TAC NO. MF0319) dated August 9, 2013 and (ADAMS Accession No. ML13191A054).

3. 10 CFR 50.55a(a)(3)(ii) request was approved for Monticello Nuclear Generating Plant relief from the requirements of the American Society of Mechanical Engineers code for the Fifth 10-Year lnservice Inspection Program Interval (TAC NOS. ME8068, ME8070, and ME8701) dated February 26, 2013 and (ADAMS Accession No. ML13035A158).

4. 10 CFR 50.55a(a)(3)(ii) request was approved for the MNGP during their Fourth 10-Year lnservice Inspection Interval as a one-time relief by NRC letter "Monticello Nuclear Generating Plant - One Time lnservice Inspection Program Plan Relief Request No. 8 for Leak Testing the "B" and "G" Main Steam Safety Relief Valves (TAC No. MB9538)", dated June 13, 2003 and (ADAMS Accession No. ML031640464).

(10-7) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISStON WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REQUEST FOR ALTERNATIVE RP5-01 IMPLEMENTATION OF CODE CASE N-795 FOR FIFTH 10-YEAR INSERVICE INSPECTION PROGRAM INTERVAL NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated June 9, 2015, as supplemented by letter dated November 9, 2015 (Agencywide Documents Access and Management System (ADAMS) Accession Nos. ML15167A066 and ML15321A012, respectively), Nebraska Public Power District (NPPD, the licensee) submitted request for alternative RPS-01, "Implementation of Code Case N-795," to the U.S. Nuclear Regulatory Commission (NRC) for review and authorization. Specifically, the licensee proposes to use provisions similar to those of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code) Case N-795, "Alternative Requirements for BWR [Boiling Water Reactor] Class 1 System Leakage Test Pressure Following Repair/Replacement Activities, Section XI, Division 1," to perform the leakage testing and associated visual examination for leakage (VT-2) following repair/replacement activities at Cooper Nuclear Station (CNS) during the fifth 10-year inservice inspection (ISi) interval. ASME Code Case N-795 has not been approved for use in Regulatory Guide 1.147, "lnservice Inspection Code Case Acceptability ASME Section XI, Division 1," Revision 17 (ADAMS Accession No. ML13339A689). The licensee requested to use the proposed alternative on the basis that compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety.

2.0 REGULATORY EVALUATION

Pursuant to Title 10 of the Code of Federal Regulations (10 CFR), Part 50, paragraph 50.55a(g)(4), 'lnservice inspection standards requirements for operating plants," ASME Code 1 Class 1, 2, and 3 components (including supports) shall meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the Enclosure (10-8) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program ASME Code, Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," to the extent practical within the limitations of design, geometry, and materials of construction of the components. The regulations require that inservice examination of components and system pressure tests conducted during the first 10-year inspection interval and subsequent 10-year inspection intervals comply with the requirements in the latest edition and addenda of Section XI of the ASME Code incorporated by reference in 10 CFR 50.SSa{b) 12 months prior to the start of the 120-month inspection interval, subject to the limitations and modifications listed therein. The regulations in 10 CFR 50.55a(z) state, in part, that alternatives to the requirements of 10 CFR 50.55a(g) may be used, when authorized by the NRC, if (1) the proposed alternatives would provide an acceptable level of quality and safety, or (2) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Based on analysis of the regulatory requirements, the NRC staff concludes that the regulatory authority exists to authorize the licensee's proposed alternative to the ASME Code requirement on the basis that compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the staff has reviewed and evaluated the licensee's request pursuant to 10 CFR 50.55a(z)(2).

3.0 TECHNICAL EVALUATION

3.1 The Licensee's Request for Alternative The licensee is requesting relief from the pressure requirement of ASME Code, Section XI, required system leakage testing of ASME Code Section 111, Class 1 mechanical joints made in the installation of pressure retaining items and the Class 1 pressure retaining boundary on which repair/replacement activities have been *performed by welding. ASME Code Requirements The Code of Record for the CNS fifth 10-year I SI interval that will commence on March 1, 2016, and is scheduled to end on February 29, 2026, is ASME Code, Section XI, 2007 Edition through the 2008 Addenda. For mechanical joints resulting from repair/replacement activities 1, ASME Code, 1998 Edition, Section XJ, paragraph IWA-4540(c) requires mechanical joints made in the installation of pressure retaining items be pressure tested during a system leakage test in accordance with IWA-5211 {a). IWB-5221 (a) requires that the system leak test be conducted during operation at nominal operating pressure, or when pressurized to nominal operating pressure and temperature. 1 10 CFR 50.55a(b)(2)(xxvi), Pressure Testing Class 1, 2 and 3 Mechanical Joints, requires licensees using the ASME Code. Section XI. 2001 Edition and later editions and addenda to use the 1998 Edition of the ASME Code, Section XI, paragraph IWA-4540(c), for pressure testing Class 1, 2, and 3 mechanical joints. (10-9) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program For pressure retaining boundaries on which repair/replacement activities have been performed by welding, ASME Code, Section XI, paragraph IWA-4540 requires a hydrostatic or system leakage test in accordance with IWA-5000 prior to, or as part_of, returning to service. IWA-5200 requires that a VT-2 examination be performed to detect leakage while the system is in operation, during a system operability testt or while the system is at test conditions using an external pressurization source at temperature and pressure defined in IWB-5000. IWB-5221 (a) requires that the system leakage test to be conducted at a pressure not Jess than the pressure corresponding to 100 percent rated reactor power. Licensee's Proposed Alternative The licensee proposes to perform the system leakage test and associated VT-2 examination following repair/replacement activities in maintenance or forced outages in accordance with the provisions of ASME Code Case N-795, but using longer holding times than those specified in the code case. The system leakage test will be performed during the normal operational start-up sequence at a minimum of 900 pounds per square inch gauge (psig), approximately 90 percent of the pressure corresponding to 100 percent rated reactor power [1005 psig] with VT-2 examination folfowing after a 1-hour holding time for uninsulated components and after an 8-hour holding time for insulated components. Licensee's Basis for Requesting Relief During normal startup with normal power ascension, nominal operating pressure of 1005 psig is reached at a reactor power level of approximately 85 percent. If access to containment were permitted at this power level, personnel would be exposed to excessive radiation levels, including significant exposure to neutron radiation fields, which is contrary to station as low as reasonably achievable (ALARA) practices. The licensee stated that, during a maintenance or forced outage, there is a large decay heat load from the reactor core that is difficult to control once shutdown cooling (SOC) has been removed from service. During a short term mid-cycle shutdown, the projected heatup rate could be in the order of 0.4 degrees Fahrenheit per minute once SOC is removed from service. Under those conditions, the time available to pressurize up to test conditions, perform the VT-2 exam and return to SOC would be greatly reduced, and the hurried time frames may create a more error-likely environment. In addition, there is some inherent risk that mechanical, control or operational problems could occur while the SOC is isolated, which could delay return to SOC. Testing at these abnormal plant conditions/alignments results in additional risks and delays while providing little added benefit beyond tests, which could be performed at slightly reduced pressures under normal plant conditions. As stated, in part, in the licensee's letter dated June 9, 2015: Indication of leakage identified through the VT-2 examinations during a test at a pressure correlating to either the 100% rated reactor power level or at ~90% of that value wilt not be significantly different between the two tests. Higher pressure under the otherwise same conditions will produce a higher flow rate but the difference is not significant. Code Case N-795 proposes increased hotd times, as compared to a test performed at normal operating pressure, to allow for more leakage from the pressure boundary if a through-wall or mechanical joint (10-10) Rev_ 3_0

Cooper Station 5th ISi & 3rd Interval CISI Program leakage condition exists. NPPD proposes to implement longer hold times than those specified by the code case. NPPD believes these longer hold times are justified to allow for additional leakage to accumulate at the area of interest so as to be more evident during the VT-2 examination, should a through-wall or mechanical joint leakage condition exist. This alternate test pressure, when combined with longer hold times, is still adequate to provide evidence of leakage, should a leak exist. 3.2 NRC Staff Evaluation Performance of a system leakage test of pressure retaining boundaries, including mechanical joints, on which repair/replacement activities have been performed, is an integral part of ASME Code, Section XI requirements. The system leakage test for Examination Category B-P components normally occurs at the end of a refueling outage when the core decay heat has had time to decrease, some spent fuel has been removed, and some new fuel has been added, resulting in a relatively low decay heat load. The low decay heat load, compared to that for the high decay heat load found at the start of an outage, results in low heatup rates. When a system leakage test immediately follows a maintenance or forced outage, there is a large decay heat load from the reactor core that is difficult to control once SDC has been removed from service. Isolating SDC under high decay heat loads requires abnormal plant conditions/alignments and is accompanied by inherent risk, and the hurried time frames that result from the high heatup rates may create a more error-likely environment. In addition, there is inherent risk that mechanical, control, or operational problems could occur while the SDC is isolated. ASME developed Code Case N-795 to provide an alternative test pressure for some Class 1 pressure tests following repair/replacement activities at BWR plants. The alternative was developed because some BWR licensees believe that the Class 1 pressure tests performed at pressures corresponding to 100 percent reactor power require abnormal plant conditions and alignments that increase risk. Code Case N-795 specifies that the leakage test shall be performed at a test pressure of at least 87 percent of that required by !WB-5221 (a). Code Case N-795 requires that, before the VT-2 examination commences, a minimum 15-minute holding time for noninsulated components and a 6-hour holding time for insulated components shall be maintained. In its response to the NRG staff's request for additional information (RAI), by letter dated November 9, 2015, the licensee detailed three methods that would permit VT-2 inspection while at a pressure corresponding to 100 percent normal operating pressure. The first of these methods would require the reactor pressure vessel (RPV) to be filled with coolant and the steam lines flooded to provide a water-solid condition. Use of this method would result in extensive vafve manipulations, system lineups, and procedural controls in order to heat up and pressurize the primary system to establish the necessary test pressure without the withdrawal of control rods. The staff concludes that performance of a system leakage test at the conditions present immediately following a maintenance or forced outage using this method, would present multiple operational challenges, unusual difficulty, present a risk to plant operation, and therefore, would present a hardship. The second method described in the licensee's RAI response would perform the VT-2 examination during normal startup procedures. Nominal operating pressure of 990 psig (10-11) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program can be attained with normal startup and normal power ascension, at a reactor power level of approximately 100 percent. If access to containment were permitted at this power level, personnel would be exposed to excessive radiation levels, including significant exposure to neutron radiation fields, which is contrary to station ALARA practices. Establishing the 990 psig test conditions at a more moderate power level and in a manner to address the radiation concerns would require significant changes to the steam pressure control system. The NRC staff concludes that exposure of workers to high radiation fields would present a hardship. The third method that could possibly be used would maintain the RPV at its normal level and use decay heat to produce sufficient steam pressure to conduct the test at nominal operating pressure. The licensee states that, while the decay heat load is too high for the water-solid method discussed above, there may not be sufficient decay heat available to perform the test at 1005 psig within a reasonable time period, if at all. The NRC staff concludes that use of this alternate method would also present a hardship. The licensee proposes to use the provisions of ASME Code Case N-795, with additional conditions, for performance of a system leakage test of pressure retaining boundaries, including mechanical joints, on which repair/replacement activities have been performed. These conditions include:

a. Attainment of at least 90 percent of the operating pressure prior to the start of the holding time.

b. Holding time of 1 hour for uninsulated components prior to the VT-2 visual examination.

c. Holding time of 8 hours for insulated components prior to the VT *2 visual examination.

The system leakage test would comprise a VT-2 visual examination after the required test condition holding time. The NRC staff notes that the licensee has defined the nominal operating pressure to be a minimum of 1005 psig for components within the reactor coolant pressure boundary at CNS. Therefore, the system leakage test pressure must be at least ~900 psig before the holding time is started. The leak tightness of components involved in the repair/replacement activities must be ensured. Leakage through an orifice will be related to the differential pressure at the point of leakage, or across the connection, and is expected to scale with the square root of the pressure. Therefore, the leakage rate at the required 90 percent test pressure would be approximately 95 percent the leakage rate at 100 percent power. A 10 percent reduction in the test pressure is not expected to result in the arrest of a leak that would occur at nominal operating pressure. In the unlikely event that leakage would occur subsequent to the VT-2 visual examination at pressures associated with 100 percent rated reactor power, leakage would be detected by the drywell monitoring systems that are required by technical specifications. The NRC staff therefore concludes that the VT-2 examination, after the specified holding time at 90 percent of system normal operating pressure, will adequately assure leak tightness of the components in the reactor coolant pressure boundary. Based on the above evaluation, the NRC staff concludes that performing a VT-2 visual examination during a system leakage test at normal operating pressure following a maintenance or forced outage would present a hardship. The staff further concludes that performing the VT-2 examination at pressures equal to, or greater than, 900 psig, with holding times of 1 hour for non-insulated components and 8 hours for insulated components, will provide reasonable (10-12) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program assurance of leak tightness. It is the NRC's position that structural integrity is ensured through compliance with ASME Code requirements for design, fabrication, and nondestructive examination.

4.0 CONCLUSION

As set forth above, the NRC staff concludes that proposed alternative RP5-01, "Implementation of Code Case N-795," provides reasonable assurance of structural integrity and leak tightness, and that complying with the ASME Code requirement would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(2). Therefore, the NRC staff authorizes use of the proposed alternative at CNS during the fifth 10-year ISi interval that will commence on March 1, 2016, and is scheduled to end on February 28, 2026, until such time as ASME Code Case N-795 is published in a future revision of Regulatory Guide 1. 147, which is incorporated by reference in 10 CFR 50.55a. All other ASME Code, Section XI requirements for which relief was not specifically requested and approved in the subject requests for relief remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector. Principal Contributor: K. Hoffman Date: February 24, 2016 (10-13) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program 10 CFR 50.SSa Request Number PRS-02 Definition of Pressure Retaining Boundary for System Leakage Test Proposed Alternative in Accordance with 10 CFR S0.5Sa(z}(2) Hardship without a Compensating Increase in Quality or Safety American Society of Mechanical Engineers (ASME) Code Component(s) Affected Code Class: 1 Examination Category: B-P Item Number: B15.10 Component Numbers: All Components Subject to Pressurization During a System Leakage Test

Applicable Code Edition and Addenda

ASME Code Section XI, 2007 Edition, 2008 Addenda

Applicable Code Requirement

Paragraph IWB-5222(a) Article IWB-5000, "System Pressure Tests," Sub-subarticle IWB-5220, "System Leakage Test," Paragraph IWB-5222, "Boundaries," states that: (a) The pressure retaining boundary during the system leakage test shall correspond to the reactor coolant boundary, with all valves in the position required for normal reactor operation startup. The visual examination shall, however, extend to and include the second closed valve at the boundary extremity. (b) The Class I pressure retaining boundary which is not pressurized when the system valves are in the position required for normal reactor startup shall be pressurized and examined at or near the end of each inspection interval. This boundary may be tested in its entirety or in portions and testing may be performed during the testing of the boundary IWB-5222(a).

Reason for Request

Pursuant to 10 CFR 50.SSa, "Codes and Standards," Paragraph (z)(2), relief is requested from the requirements of ASME Code Section XI requirements for performing a system leakage test using the boundaries stated in Paragraph IWB-5222(a) because performing the pressure test with this boundary would result in a hardship without a compensating increase in quality and safety due to excessive radiation exposure and personnel safety concerns (temperature levels in the drywell). (10-14) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program Proposed Alternative and Basis for Use In lieu of a system leakage test during reactor startup, as required by IWB-5222(a), a system pressure test is performed at the pressure associated with 100% rated reactor power. a) The outboard Feedwater check valves and the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) injection check valves are the Class 1 boundary valves and are closed for this test. The Feedwater check valves are normally open for reactor startup. The inboard check valve (RF-CV-16CV) on one Feedwater line is kept open by Reactor Water Cleanup (RWCU) flow. The RWCU system is kept in service during the pressure tests. Thus, the outboard Feedwater check valve and the RCIC injection check valve on this line will be pressurized during this test. The portion of piping between the other two Feedwater check valves including the HPCI injection line will not be pressurized. b) The four outboard Main Steam Isolation Valves (MSIV) will be closed for the system pressure test and the ten-year system pressure test [IWB-5222(b)]. The inboard MSIVs are opened to pressurize the system to the outboard valves. Both Main Steam Drain Valves are normally open to facilitate for pressure control; however, the outboard Class 1 boundary valve may be closed to provide leakage isolation if needed. The outboard valves are the Class 1 boundary valves. c) Both HPCI and both RCIC steam supply valves will be closed for the system pressure test following a refueling outage. These valves close automatically on low steam supply pressure. During the ten-year system pressure test [IWB-5222(b)], the system will be pressurized to the outboard valves. The outboard valves are the Class 1 boundary valves. The position of the valves for the system leakage test as described above is consistent with the intent of IWB-5222( a). Abnormal lineups and installation of jumpers are not required for the system leakage test. The valves described above are normally open during a reactor startup. In order to pressurize the reactor coolant pressure boundary for testing, these valves must be closed. Except as described above, the Class 1 boundary is pressurized as required by the code. The VT-2 inspection includes the entire reactor coolant pressure boundary. Since the portions of the piping between the valves described above are operated at or above reactor pressure during normal operation, any through-wall leakage would be detected by the drywell leakage collection system, or by operations personnel on normal rounds. Performing a system pressure test at 100 percent reactor power would result in a hardship without a compensating increase in quality and safety. At 100% power primary containment is inerted and radiation levels are high. The proposed alternative provides reasonable assurance of operational readiness of the subject components. In summary, three of the Feedwater check valves, HPCI injection check valve, the outboard MSIVs, and the HPCI and RCIC steam supply valves will be closed during the system leakage test, but will be included in the VT-2 visual examination. A VT-2 examination will be (10-15) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program 10 CFR 50.SSa Request Number PRS-02 (continued) Definition of Pressure Retaining Boundary for System Leakage Test performed during the system leakage test at a pressure not less than that associated with 100% rated reactor power and will provide reasonable assurance of the continued operational readiness of mechanical connections, extending to the Class 1 boundary. In addition, once at or near the end of the inspection interval the system leakage test shall extend to the Class 1 boundary as required by IWB-5222(b). Based on the above, Nebraska Public Power District (NPPD) requests relief from the ASME Section XI requirements for performing a system leakage test using the boundaries stated in IWB-5222(a). Duration of Proposed Alternative This proposed alternative will be used for the duration of the fifth ten-year inservice inspection interval. Precedents PR-02, was previously approved by the Nuclear Regulatory Commission (NRC) for the fourth ten-year interval for Cooper Nuclear Station (CNS) on October 2, 2006 (ML062260I 95). References

1. NPPD Letter NLS2006015 to USN RC dated February 23, 2006, "10 CFR 50.55a Requests for Fourth Ten-Year lnservice Inspection Interval."

2. NPPD Letter NLS200605I to USN RC dated June 15, 2006, "Revision of Relief Request PR-02."

3. USN RC letter to NPPD, dated October 2, 2006, "Cooper Nuclear Station Re: Fourth I0-Year Interval lnservice Inspection Request for Relief No. PR-02" (TAC NO. MD0284).

4. PR5-02 was emergently approved by the NRC, for the CNS refueling outage RE-30 only, on November 5, 2018 (ML18311A319). Written approval was received April 29, 2019.

(ML19092A140) (10-16) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program VERBAL AUTHORIZATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELIEF REQUEST PR5-02 PROPOSED ALTERNATIVE CONCERNING SYSTEM LEAKAGE TEST COOPER NUCLEAR STATION NEBRASKA PUBLIC POWER DISTRICT DOCKET NO. 50-298 NOVEMBER 5, 2018 Technical Evaluation read by Steve Ruffin, Chief of Piping and Head Penetrations Branch, Division of Materials and License Renewal, NRR By letter dated November 5, 2018, as supplemented by email dated November 5, 2018, Nebraska Public Power District (the licensee) requested relief from the requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code), Section XI, paragraph IWB-5222, at Cooper Nuclear Station (CNS). The licensee submitted Relief Request PR5-02 for U.S. Nuclear Regulatory Commission (NRC) review and approval for an alternative system alignment for system leakage test for portions of ASME Code Class 1 feedwater, main steam, high pressure coolant injection, and reactor core isolation cooling piping at specific valve locations. Specifically, pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z)(2), the licensee submitted Relief Request PR5-02 on the basis that compliance with the specified ASME Code repair would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. In lieu of performing a system leakage test in accordance with IWB-5222(a), the licensee proposed to use (1) the pressure corresponding to 100% rated reactor power, and (2) alternate pressure retaining boundary using various alternate valve alignments for the subject piping instead of that for the normal reactor operation startup. The NRC staff determines that the alternative pressure retaining boundary will result in a few pipe segments that will not be pressure tested in accordance with IWB-5222(a). However, the NRC staff determines that the licensee's proposal to perform a VT-2 visual examination during the system leakage test at a piessure not less than that associated with 100 percent rated power and with systems in their normal lineup to the extent practical, meets the intent of Section XI. In addition, the NRC finds that the licensee has defense-in-depth measures such as RCS leakage detection system and temperature monitoring that will detect leakage from the subject piping. The NRC staff finds that the proposed pressure used for the system leakage test and the VT-2 visual examination will satisfy the intent of IWB-5222 and will demonstrate structural integrity and leak tightness of the affected piping systems. The NRC staff finds that performing the system leakage test in accordance with IWB-5222(a) would result in a hardship without a compensating increase in quality and safety because to reach the test pressure with the valves in the position for normal reactor operation startup would require entering the primary containment when the atmosphere is inerted and the radiological dose rates are high. Based on the above evaluation, the NRC staff finds that the licensee's proposed alternative will provide structural integrity and leak tightness of the subject piping because the licensee will use (10-17) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program sufficient pressure to perform the system leakage test and will perform a VT-2 visual examination. Authorization read by Robert Pascarelli, Chief of Plant Licensing Branch IV, Division of Operating Reactor Licensing, NRR As chief of the Plant Licensing Branch IV, Office of Nuclear Reactor Regulation, I concur with the conclusions of the Piping and Head Penetrations Branch. The NRC staff concludes that the proposed alternative provides a reasonable assurance of the structural integrity and leak tightness of the subject piping. The NRC staff finds that complying with the system leakage testing of the ASME Code, Section XI would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(2). Therefore, as of November 5, 2018, the NRC authorizes the use of Relief Request PRS-02 until the end of Refueling Outage 30 at Cooper Nuclear Station. All other requirements in ASME Code, Section XI, for which relief was not specifically requested and approved in this relief request remain applicable, including third-party review by the Authorized Nuclear lnservice Inspector. This verbal authorization does not preclude the NRC staff from asking additional clarification questions regarding the proposed alternative while preparing the subsequent written safety evaluation. ( 10-18) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE NUCLEAR REACTOR REGULATION REQUEST FOR ALTERNATIVE PR5-02 REGARDING SYSTEM LEAKAGE TESTING OF CLASS 1 PIPING NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated November 5, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML18313A092), as supplemented by letter dated November 8, 2018 (ADAMS Accession No. ML18319A095), Nebraska Pubric Power District (the licensee) proposed an altemative to the requirements of the American Society of Mechanical Engineers Boiler & Pressure Vessel Code (ASME Code), Section XI, IWB-5222(b ), at Cooper Nuclear Station. Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(z)(2}, the licensee submitted Relief Request PRS-02 to allow alternative system leakage testing of various ASME Class 1 piping segments on the basis that complying with the specified ASME Code requirements woutd result in hardship or unusual difficulty, without a compensating increase in the level of quality and safety. On November 5, 2018, as documented in a U.S. Nuclear Regulatory Commission (NRC) e--maii dated November 6, 2018 (ADAMS Accession No. Ml 18311A319}, the NRC staff verbally authorized the use of Relief Request PR5-02 until the concf us ion of the Cooper Nuclear Station Refueling Outage 30.

2.0 REGULATORY EVALUATION

Adherence to Section XI of the ASME Code is mandated by 10 CFR 50.55a(g)(4), which states, in part, that ASME Code Class 1, 2, and 3 components wm meet the requirements, except the design and access provisions and the preservice examination requirements, set forth in the ASME Code, Section XI. Paragraph 50.55a(z) of 10 CFR states that alternatives to the requirements of paragraphs (b) through {h) of 10 CFR 50.55a, or portions thereof, may be used when authorized by the Director, Office of Nuclear Reactor Regulation. A proposed alternative must be submitted and authorized prior to implementation. The licensee must demonstrate that: (1) the proposed alternative would provide an acceptable level of quality and safety, or (2) compliance with the Enclosure (10-19) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program specified requirements of this section would result in hardship or unusual difficulty, without a compensating increase in the level of quality and safety. Based on the above, and subject to the foflowinq technical evafuation, the NRC staff finds that regulatory authority exists for the licensee to request the use of an alternative, and the NRC to authorize the proposed alternative.

3.0 TECHNICAL EVALUATION

3.1 licensee's Request for Alternative 3.1.1 ASME Code Components Affected AU ASME Code, Section XI, Class 1, Examination Categories B-P, Item No. B15.10 components that are subject to pressurization during a system leakage test are affected by this request for alternative, as shown in the supplemental letter dated November 8, 2018, and include:

• Outboard Feedwater Check Valves (RF-CV-13CV, -15CV)
• Inboard Feedwater Check Valves (RF-CV-14CV)
• Outboard Main Steam Isolation Valves (MS-AOV-A086A, 8, C, D}
• Inboard High Pressure Coolant Injection (HPCI) Steam Supply (HPCI-MOV-M015)
• Outboard HPCI Steam Supply (HPCI-MOV-M016)
• Inboard Reactor Core Isolation Cooling (RCIC) Steam Supply (RCIC-MOV-M015)
• Outboard RCIC Steam Supply (RCIC-MOV-M016) 3.1.2 Applicable Code Edition The lnservice Inspection (ISi) Program for the fifth 10-year inservice inspection interval is based on the ASME Code, Section XI, 2007 Edition with 2008 Addenda.

3.1.3 Applicable Code Requirement The pressure retaining boundary during the system leakage test shalt correspond to the reactor coolant boundary, with au valves in the position required for normal reactor operation startup. The visual examination shall, however, extend to and include the second closed valve at the boundary extremity. 3.1.4 Reason for Request The licensee requested relief from the ASME Code, Section XI requirements for performing a system leakage test stating that performing the pressure test with the boundaries stated in paragraph IWB-5222{a) would impose an unnecessary hardship, without a compensating increase in quality and safety, due to excessive radiation exposure and personnel safety concerns due to temperature levels in the dryweU. (10-20) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 3.1.5 Licensee's Proposed Alternative and Basis for Use In the letter dated November 5, 2018, the licensee stated, in part: In lieu of a system leakage test during reactor startup. as required by IWB-5222(a), a system pressure test is perfonned at the pressure associated with 100% [percent] rated reactor power. a) The outboard Feedwater check valves and the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) injection check valves are the Class 1 boundary valves and are closed for this test The Feedwater check valves are normally open for reactor startup. The inboard check valve (RF-CV-16CV) on one Feedwater fine is kept open by Reactor Water Cleanup (RWCU) flow. The RWCU system is kept in service during the pressure tests. Thus, the outboard Feedwater check valve and the RCIC injection check valve on this line wm be pressurized during this test. The portion of piping between the other two Feedwater check valves including the HPCt injection line will not be pressurized. b) The four outboard Main Steam Isolation Valves (MSIV} wm be closed for the system pressure test and the ten-year system pressure test [IWB-5222(b )]. The inboard MS IVs are opened to pressurize the system to the outboard valves. Both Main Steam Drain Valves are nonnally open to facilitate for pressure control; however. the outboard Class 1 boundary valve may be closed to provide leakage isolation if needed. The outboard valves are the Class 1 boundary valves. c) Both HPCI and both RCIC steam supply valves wm be closed for the system pressure test following a refueling outage. These valves close automatically on low steam supply pressure. During the ten-year system pressure test [IWB-5222(b )], the system will be pressurized to the outboard valves. The outboard valves are the Class 1 boundary valves. The position of the valves for the system leakage test as described above is consistent with the intent of IWB-5222(a). Abnormal lineups and installation of jumpers are not required for the system leakage test. The valves described above are normally open during a reactor startup. In order to pressurize the reactor coolant pressure boundary for testing, these valves must be closed. Except as described above, the Class 1 boundary is pressurized as required by the code. The VT-2 inspection includes the entire reactor coolant pressure boundary. Since the portions of the piping between the valves described above are operated at or above reactor pressure during normal operation, any through-wall leakage would be detected by the drywell leakage collection system, or by operations personnel on normal rounds. Performing a system pressure test at 100 percent reactor power would result in a hardship without a compensating increase in quality and safety. At 100% [percent] power primary containment is inserted and radiation levels are high. (10-21) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program The proposed alternative provides reasonable assurance of operational readiness of the subject components. In summary, three of the Feedwater check valves. HPCI injection check valve, the outboard MSIVs, and the HPCI and RCIC steam supply valves will be closed during the system leakage test, but will be included in the VT-2 visual examination. A VT-2 examination will be performed during the system leakage test at a pressure not less than that associated with 100% [percent] rated reactor power and will provide reasonable assurance of the continued operational readiness of mechanical connections, extending to the Class 1 boundary. In addition, once at or near the end of the inspection interval the system leakage test shall extend to the Class 1 boundary as required by IWB-5222{b). 3.1.6 Hardship Justification The licensee provided the following justification for the hardship in the tatter dated November 5, 2018: Pursuant to 10 CFR 50.55a, "Codes and Standards,n Paragraph (z){2), relief is requested from the requirements of ASME Code Section XI requirements for performing a system leakage test using the boundaries stated in Paragraph IWB-5222(a) because performing the pressure test with this boundary would result in a hardship without a compensating increase in quality and safety due to excessive radiation exposure and personnel safety concerns {temperature levels in the drywall).

3. 1. 7 Duration of the Proposed Alternative As stated in the letter dated November 8, 2019, the licensee requested thatthe proposed alternative be authorized until the end of Refueling Outage 30 and not for the entirety of the fifth inservice inspection interval.

3.2 NRC Staff Evaluation The ASME Code, Section XI, Table IWB-2500-1, Examination Categories B-P, Item Number B15.10, requires that a system leakage test be performed in accordance with the ASME Code, Section XI, IWB-5220. Specifically. IWB-5222(a) states. in part, that the pressure retaining boundary during the system leakage test shaH correspond to the reactor coolant boundary, with all valves in the position required for normal reactor operation startup. The NRC staff finds that performing the system leakage test during reactor startup, and with the orientation stated in IWB-5222{ a), would result in a hardship due to the excessive radiation exposure, and an inserted atmosphere where eJevated temperatures in the drywell would present safety concerns to personnel performing the visual examination. To determine whether this hardship is outweighed by a compensating increase in quality or safety, the NRC staff evaluated how the licensee's proposed alternative testing boundary satisfies the intent of Section XL The purpose of the system pressure tests is to detect through-wall leakage in the reactor coolant boundary by visual examination. Instead of performing the system leakage test during reactor startup, a system pressure test wm be (10-22) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program performed at the pressure associated with 100 percent rated reactor power. To achieve and maintain this pressure without the reactor operating at 100 percent power requires multiple vafves that are typically open to remain closed and maintain the pressure boundary. AH portions of piping between the closed valves are operated at or above reactor pressure during normal operation, and any through-wall leakage would be detected by the dryweH leakage collection system or by operations personnel on normal rounds. Furthermore, to address the piping sections that operate at or above reactor pressure during normal operation but are not at test pressure in the proposed alternative, the licensee described the detection methods in the November 8, 2018, supplemental letter, as follows:

• The temperature alarm subsystem of [the] leak detection system is comprised of temperature sensing elements installed in the vicinity of residual heat removal (RHR). reactor water cleanup (RWCU). high pressure coolant injection (HPCI), reactor core isolation cooling (RCIC), and main steam lines (MS), and temperature switches that actuate annunciators in the Control Room. It is designed to detect leaks in the major steam piping system, especially in remote or enclosed areas such as the steam tunnel. If a steam or water leak occurs. the temperature element would sense a rise in ambient temperature and cause an alarm in the Control Room. tn addition, the continuous temperature signals are transmitted to the Plant Management Information System (PMIS} for Safety Parameter Display System {SPDS) display.
• Control Room operators monitor Main Steam Tunnel temperatures twice per shift (every six: hours) and record in [the] Operations Log when temperature exceeds 160 F [degrees Fahrenheit (°F)J.
• Drywell unidentified and identified teak rates are monitored in accordance with operations daify surveillance log every 8 hours.

The NRC staff finds that the licensee's defense-in-depth measures for both the pressurized and non-pressurized components that are covered under this relief request are suitable to provide reasonable assurance that any reactor coolant system leakage wm be detected, despite the alternate testing conditions. Additionally, the NRC staff determines that the licensee's proposal to perform a VT-2 visual examination during the system leakage test at a pressure not less than that associated with 100 percent rated power, and with systems in their normal lineup to the extent practical, will satisfy the intent of Section XI, IWB-5222. and will demonstrate structural integrity and leaktightness of the affected piping systems. Finally, the NRC staff condudes that performing the system leakage test in accordance with IWB-5222(a) would result in a hardship, without a compensating increase in quality and safety.

4.0 CONCLUSION

As set forth above, the NRC staff determines that the licensee has demonstrated that the proposed alternative provides reasonable assurance of structural integrity of the subject piping segments. and that com~ying with the specified ASME Code requirements would result in hardship or unusual difficulty, without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z}(2}. Therefore, the NRC authorizes the use of Relief Request PRS-02 at Cooper Nuclear Station for Refueling Outage 30. (10-23) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program AH other requirements of the ASME Code, Section XI, for which relief was not specifically requested and approved by the NRC staff remain applicable, inciuding third-party review by the Authorized Nuclear lnservice Inspector. Principal Contributor: A. Young Da~: ~pril 29, 2019 (10-24) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program

SUBJECT:

COOPER NUCLEAR STATION-PROPOSED INSERVICE INSPECTION ALTERNATIVE PR5-02 (EPID L-2018-LLR-0136) DATED APRIL 29, 2019 DISTRIBUTION: PUBLIC PM Fife Copy RidsACRS MailCTR Resource RidsNrrDor1Lpl4 Resource RidsNrrPMCooper Resource RidsNrrDmlrMphb Resource RidsNrrLAPBlechman Resource RidsRgn4MailCenter Resource AYoung, NRR ADAMS Access on No.: ML19092A140 *bIye-ma1 OFFICE DORULPL4/PM DORULPL4/LA DMLR/MVIB/BC* DORULPL4/BC NAME TWengert PBlechman SRuffin RPascarem (LRonewicz for) DATE 04/26/2019 04/10/2019 01/31/2019 04/29/2019 OFFICIAL RECORD COPY (10-25) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program 10 CFR 50.SSa Relief Request RPS-02 Definition of Pressure Retaining Boundary for System Leakage Test Proposed Alternative in Accordance with 10 CFR S0.55a(z}(2) Hardship without a Compensating Increase in Quality or Safety American Society of Mechanical Engineers (ASME) Code Component(s) Affected Code Class: 1 Examination Category: 8-P Item Number: 815.10 Component Numbers: All Components Subject to Pressurization During a System Leakage Test

Applicable Code Edition and Addenda

ASME Code Section XI, 2007 Edition, 2008 Addenda

Applicable Code Requirement

Paragraph IWB-5222(a) Article IWB-5000, "System Pressure Tests," Sub-subarticle IWB-5220, "System Leakage Test," Paragraph IWB-5222, Boundaries, states that: 11 11 a} The pressure retaining boundary during the system leakage test shall correspond to the reactor coolant boundary, with all valves in the position required for normal reactor operation startup. The visual examination shall, however, extend to and include the second closed valve at the boundary extremity. b} The Class 1 pressure retaining boundary which is not pressurized when the system valves are in the position required for normal reactor startup shall be pressurized and examined at or near the end of the inspection interval. This boundary may be tested in its entirety or in portions and testing may be performed during the testing of the boundary of IWB-5222(a}. Table IWB-2500-1, Examination Category 8-P, Note 2 states that: The system leakage test (IWB-5220} shall be conducted prior to plant startup following a reactor refueling outage. Reason for Reg uest Pursuant to 10 CFR 50.SSa, "Codes and Standards," Paragraph (z}(2}, relief is requested from the requirements of ASME Code Section XI requirements for performing a system leakage test using the boundaries stated in Paragraph IWB-5222(a} because performing the pressure test with this

                                                ?1 boundary would result in a hardship without &£~pensating increase in quality and safeti~v~~-

0

Cooper Station 5th ISi & 3rd Interval CISI Program to excessive radiation exposure and personnel safety concerns (temperature levels in the drywell). To obtain normal operating pressure with all valves in the position for normal reactor operation startup, the reactor must be in startup with the core critical. However, 10 CFR Part 50, Appendix G requires pressure tests and leak tests of the reactor vessel that are required by ASME Section XI, to be completed before the core is critical. Proposed Alternative and Basis for Use In lieu of a system leakage test with all valves in the position required for normal reactor operation startup, as required by IWB-5222(a), a system pressure test is performed at the pressure associated with 100% rated reactor power with the following valve positions: a) The outboard reactor feedwater (RF) check valves and the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) injection check valves are the Class I boundary valves and are closed for this test. The RF check valves are normally open for reactor startup. The inboard RF check valve (RF-CV-16CV) on one feedwater line is kept open by Reactor Water Cleanup (RWCU) flow. The RWCU system is kept in service during the pressure tests. Thus, the outboard RF check valve and the RCIC injection check valve on this line will be pressurized during this test. The portion of piping between the other two RF check valves, including the HPCI injection line, will not be pressurized. b) The four outboard Main Steam Isolation Valves (MSIV) will be closed for the system pressure test and the ten-year system pressure test [IWB-5222(b)]. The inboard MSIVs are opened to pressurize the system to the outboard valves. Both Main Steam drain valves are normally open to facilitate pressure control, however, the outboard Class 1 boundary valve may be closed to provide leakage isolation, if needed. The outboard valves are the Class 1 boundary valves. c) Both HPCI and both RCIC steam supply valves will be closed for the system pressure test following a refueling outage. These valves close automatically on low steam supply pressure. During the ten-year system pressure test [IWB- 5222(b)], the system will be pressurized to the outboard valves. The outboard valves are the Class 1 boundary valves. The positions of the valves for the system leakage test as described above and as listed in Tables 1 and 2 are consistent with the intent of IWB-5222(a). Abnormal lineups and installation of jumpers are not required for the system leakage test. The valves described above are normally open during a reactor startup. In order to pressurize the reactor coolant pressure boundary for testing, these valves must be closed. Except as described above, the Class I boundary is pressurized as required by the code. The VT-2 inspection includes the entire reactor coolant pressure boundary. For the portions of piping operated at or above reactor pressure during normal operation that are not at test pressure, defense-in-depth for detection of possible through-wall leakage is (10-27) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program provided by the following:

• The temperature alarm subsystem of the leak detection system is comprised of temperature sensing elements installed in the vicinity of residual heat removal system, RWCU system, HPCI system, RCIC system, and main steam lines (MS), and temperature switches that actuate annunciators in the Control Room. It is designed to detect leaks in the major steam piping system, especially in remote or enclosed areas such as the steam tunnel. If a steam or water leak occurs, the temperature element would sense a rise in ambient temperature and cause an alarm in the Control Room. In addition, the continuous temperature signals are transmitted to the Plant Management Information System computer for the Safety Parameter Display System display.
• Control Room operators monitor Main Steam Tunnel temperatures twice per shift and record in Operations log when temperature exceeds 160 degrees Fahrenheit.
• Drywell unidentified and identified leak rates are monitored in accordance with Operations daily surveillance log every eight (8) hours.

Performing a system pressure test at 100% reactor power would result in a hardship without a compensating increase in quality and safety. At 100%, power primary containment is inerted and radiation levels are high. The proposed alternative provides reasonable assurance of operational readiness of the subject components. In summary, three of the RF check valves, HPCI injection check valve, the outboard MSIVs, and the HPCI and RCIC steam supply valves will be closed during the system leakage test, but will be included in the VT-2 visual examination. A VT-2 examination will be performed during the system leakage test at a pressure not less than that associated with 100% rated reactor power and will provide reasonable assurance of the continued operational readiness of mechanical connections, extending to the Class 1 boundary. !n addition, once at or near the end of the inspection interval, the system leakage test shall extend to the Class 1 boundary as required by IWB-5222(b). Based on the above, Nebraska Public Power District requests relief from the ASME Section XI requirements for performing a system leakage test using the boundaries stated in IWB-5222(a). Duration of Proposed Alternative This proposed alternative will be applied for the duration of the fifth ten-year inservice inspection interval. (10-28) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Precedents PR-02 was previously approved by the Nuclear Regulatory Commission (NRC} for the fourth ten-year interval for Cooper Nuclear Station {CNS) on October 2, 2006. (ML062260195) PR5-02 was emergently approved by the NRC, for the CNS refueling outage RE-30 only, on November 5, 2018 (ML18311A319). Written approval was received April 29, 2019. (ML19092A140) References

1. Letter to U.S. Nuclear Regulatory Commission from Randall K. Edington (Nebraska Public Power District) dated February 23, 2006, "10 CFR 50.55a Requests for the Fourth Ten-Year lnservice Inspection Interval." (ML060590300)

2. Letter to U.S. Nuclear Regulatory Commission from Randall K. Edington (Nebraska Public Power District) dated June 15, 2006, "Revision of Relief Request PR-02." (ML061710101)

3. U.S. Nuclear Regulatory Commission letter to Nebraska Public Power District dated October 2, 2006, "Cooper Nuclear Station RE: Fourth 10-Year Interval lnservice Inspection Request for Relief No. PR-02." (ML062260195)

4. Letter to U.S. Nuclear Regulatory Commission from John Dent, Jr. (Nebraska Public Power District) dated November 5, 2018, 11 10 CFR 50.55a Relief Request PRS-02." (ML18313A092)

5. U.S. Nuclear Regulatory Commission email to Nebraska Public Power District dated November 6, 2018, "Cooper Nuclear Station - Verbal Authorization of Relief Request PR5-02."

(ML18311A319) 6, Letter to U.S. Nuclear Regulatory Commission from John Dent, Jr. (Nebraska Public Power District) dated November 8, 2018, "10 CFR 50.55a Relief Request PR5-02 Supplement." (ML18319A095) (10-29) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Table 1: Valves not in position required for normal reactor startup: Position Required for Position During Valve Description Normal Reactor System Leakage Test Startup Outboard Feedwater RF-CV-13CV Open Closed Check Valve Inboard Feedwater RF-CV-14CV Open Closed Check Valve Outboard Feedwater RF-CV-lSCV Open Closed Check Valve Outboard Main MS-AOV-AO86A Open Closed Steam Isolation Valve Outboard Main MS-AOV-AO868 Open Closed Steam Isolation Valve Outboard Main MS-AOV-AO86C Open Closed Steam Isolation Valve Outboard Main MS-AOV-AO86D Open Closed Steam Isolation Valve Inboard HPCI Steam HPCI-MOV-MO15 Open Closed Supply Outboard HPCI Steam HPCI-MOV-MO16 Open Closed Supply Inboard RCIC Steam RCIC-MOV-MO15 Open Closed Supply Outboard RCIC Steam RCIC-MOV-MO16 Open Closed Supply Table 2: Other valves discussed in Relief Request: Position Required for Position During Vaive Description Normal Reactor System Leakage Test Startup Inboard Main Steam MS-MOV-MO74 Open/Closed Open Drain Valve Outboard Main MS-MOV-MO77 Open/Closed Open/Closed Steam Drain Valve HPCI Injection Check HPCI-CV-29CV Closed Closed Valve Inboard Feedwater RF-CV-16CV Open Open Check Valve (10-30) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555..0001 SAFETY EVALUATION BY THE OFFICE NUCLEAR REACTOR REGULATION REQUEST FOR ALTERNATIVE RPS-02 REGARDING SYSTEM LEAKAGE TESTING OF CLASS 1 PIPING NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION DOCKET NO. 50-298

1.0 INTRODUCTION

By letter dated June 28, 2019 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML19190A092), Nebraska Public Power District (the licensee) proposed an alternative to the requirements of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code), Section XI, "Rules for lnservice Inspection of Nuclear Power Plant Components," subparagraph IWB-5222(b), at Cooper Nuclear Station. Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) paragraph 50.55a(z)(2), "Hardship without a compensating increase in quality and safety," the licensee submitted Relief Request RPS-02 to allow alternative system leakage testing of various ASME Code Class 1 piping segments on the basis that complying with the specified ASME Code requirements would result in hardship or unusual difficulty, without a compensating increase in the level of quality and safety.

2.0 REGULATORY EVALUATION

Pursuant to 10 CFR 50.55a(g)(4), "lnservice inspection standards requirement for operating plants," the ASME Code Class 1, 2, and 3 components (including supports) must meet the requirements, except the design and access provisions and preservice examination requirements, set forth in the ASME Code, Section XI, to the extent practical within the limitations of design, geometry, and materials of construction of the components. Pursuant to 10 CFR 50.55a(z), "Alternatives to codes and standards requirements," alternatives to the requirements of paragraph (g) of 10 CFR 50.55a may be used when authorized by the Director, Office of Nuclear Reactor Regulation. A proposed alternative must be submitted and authorized prior to implementation. The licensee must demonstrate (1) the proposed alternative would provide an acceptable level of quality and safety; or (2) compliance with the specified requirements of this section would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. (10-31) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program Based on the above, and subject to the following technical evaluation, the U.S. Nuclear Regulatory Commission (NRC) staff finds that regulatory authority exists for the licensee to request and the NRC to authorize the alternative requested by the licensee.

3.0 TECHNICAL EVALUATION

3.1 Licensee's Request for Alternative 3.1.1 ASME Code Components Affected The licensee identified the affected piping segments as all components subject to pressurization during a system leakage test. The components affected are ASME Code Class 1 piping. In accordance with Subarticle IWB-2500, "Examination and Pressure Test Requirements," Table IWB-2500-1, "Examination Categories," they are classified as Examination Category 8-P, Item Number 815.10. 3.1.2 Applicable Code Edition and Addenda The code of record for the fifth 10-year ISi interval is the 2007 Edition with 2008 Addenda of the ASME Code, Section XI. 3.1.3 Duration of Relief Request The licensee submitted this relief request for the fifth 10-year inservice inspection (ISi) interval which began on April 1, 2016, and will end on February 28, 2026. 3.1.4 Applicable Code Requirement The ASME Code, Section XI, Subarticle IWB-2500, Table IWB-2500-1, Examination Category 8-P requires that the system leakage test be conducted according to Sub-subarticle IWB-5220, "System Leakage Test," and the associated VT-2 visual examinations according to Sub-subarticle IWA-5240 prior to piant startup following each refueling outage. In accoidance with subpaiagiaph IWB-5221 (a), the system leakage test shall be conducted at a pressure not less than the pressure corresponding to 100 percent rated reactor power. In accordance with subparagraph IWB-5222(a), the pressure-retaining boundary during the system leakage test shall correspond to the reactor coolant pressure boundary, with all valves in the position required for normal reactor operation startup. The required VT-2 visual examination shall, however, extend to and include the second closed valve at the boundary extremity. In accordance with subparagraph IWB-5222(b), the pressure-retaining boundary during system leakage test conducted at or near the end of each inspection interval shall extend to all Class 1 pressure-retaining components within the system pressure boundary. 3.1.5 Proposed Alternative, Basis for Use, and Reason for Relief The licensee stated in its letter dated June 28, 2019, that in lieu of a system leakage test during reactor startup, as required by subparagraph IWB-5222(a), a system pressure test is performed at the pressure associated with 100 percent rated reactor power. (10-32) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program a) The outboard reactor feedwater (RF) check valves and the High-Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) injection check valves are the Class 1 boundary valves and are closed for this test. The RF check valves are normally open for reactor startup. The inboard RF check valve (RF-CV-16CV) on one feedwater line is kept open by Reactor Water Cleanup (RWCU) flow. The RWCU system is kept in service during the pressure tests. Thus, the outboard RF check valve and the RCIC injection check valve on this line will be pressurized during this test. The portion of piping between the other two RF check valves, including the HPCI injection line, will not be pressurized. b) The four outboard Main Steam Isolation Valves (MSIV) will be closed for the system pressure test and the ten-year system pressure test [subparagraph IWB-5222(b)]. The inboard MSIVs are opened to pressurize the system to the outboard valves. Both Main Steam drain valves are normally open to facilitate for pressure control; however, the outboard Class 1 boundary valve may be closed to provide leakage isolation if needed. The outboard valves are the Class 1 boundary valves. c) Both HPCI and both RCIC steam supply valves will be closed for the system pressure test following a refueling outage. These valves close automatically on low steam supply pressure. During the ten-year system pressure test [subparagraph IWB-5222(b)], the system will be pressurized to the outboard valves. The outboard valves are the Class 1 boundary valves. The position of the valves for the system leakage test as described above and as listed in Tables 1 and 2 [of the licensee's letter dated June 28, 2019] are consistent with the intent of IWB-5222(a). Abnormal lineups and installation of jumpers are not required for the system leakage test. The valves described above are normally open during a reactor startup. In order to pressurize the reactor coolant pressure boundary for testing, these valves must be closed. Except as described above, the Class 1 boundary is pressurized as required by the code. The VT-2 inspection includes the entire reactor coolant pressure boundary. Since the portions of the piping between the valves described above are operated at or above reactor pressure during normal operation, any through-wall leakage would be detected by the drywell leakage collection system, or by operations personnel on normal rounds. The licensee further stated in its letter dated June 28, 2019: Performing a system pressure test at 100 % reactor power would result in a hardship without a compensating increase in quality and safety. At 100 % power primary containment is inerted and radiation levels are high. The proposed alternative provides reasonable assurance of operational readiness of the subject components. In summary, three of the RF check valves, HPCI injection check valve, the outboard MSIVs, and the HPCI and RCIC steam supply valves will be closed during the system leakage test, but will be included in the VT-2 visual examination. A VT-2 examination will be performed during the system leakage (10-33) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program test at a pressure not less than that associated with 100 % rated reactor power and will provide reasonable assurance of the continued operational readiness of mechanical connections, extending to the Class 1 boundary. In addition, once at or near the end of the inspection interval, the system leakage test shall extend to the Class 1 boundary as required by IWB-5222(b). 3.1.6 Hardship Justification The licensee stated that performing the pressure test with the boundaries stated in subparagraph IWB-5222(a) would impose an unnecessary hardship, without a compensating increase in quality and safety, due to excessive radiation exposure and personnel safety concerns due to temperature levels in the drywell. 3.1. 7 NRC Staff Evaluation ASME Code, Section XI, Table IWB-2500-1, Examination Categories 8-P, Item Number 815.10 requires that a system leakage test be performed in accordance with the ASME Code, Section XI, Sub-subarticle IWB-5220. Specifically, subparagraph IWB-5222(a) states, in part, that "the pressure-retaining boundary during the system leakage test shall correspond to the reactor coolant pressure boundary, with all valves in the position required for normal reactor operation startup." The NRC staff finds that performing the system leakage test during reactor startup, and with the orientation stated in ASME Code, Section XI, subparagraph IWB-5222(a), would result in a hardship due to the excessive radiation exposure and an inerted atmosphere where elevated temperatures in the drywell would present safety concerns to personnel performing the visual examination. To determine whether this hardship is outweighed by a compensating increase in quality or safety, the NRC staff evaluated how the licensee's proposed alternative testing boundary satisfies the intent of Section XI. The purpose of the system pressure tests is to detect through-wall leakage in the reactor coolant pressure boundary by visual examination. Instead of performing the system leakage test during reactor startup, a system pressure test will be performed at the pressure associated with 100 percent rated reactor power. To achieve and maintain this pressure without the reactor operating at 100 percent pm,ver requires multiple valves that are typically open to remain closed and maintain the pressure boundary. All portions of piping between the closed valves are operated at or above reactor pressure during normal operation, and any through-wall leakage would be detected by the drywell leakage collection system or by operations personnel on normal rounds. Furthermore, to address the piping sections that operate at or above reactor pressure during normal operation but are not at test pressure in the proposed alternative, the licensee described the detection methods in its letter dated June 28, 2019, as follows: The temperature alarm subsystem of the leak detection system is comprised of temperature sensing elements installed in the vicinity of residual heat removal system, RWCU system, HPCI system, RCIC, and main steam lines (MS), and temperature switches that actuate annunciators in the Control Room. It is designed to detect leaks in the major steam piping system, especially in remote or enclosed areas such as the steam tunnel. If a steam or water leak occurs, the temperature element would sense a rise in ambient (10-34) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval GISI Program temperature and cause an alarm in the Control Room. In addition, the continuous temperature signals are transmitted to the Plant Management Information System computer for the Safety Parameter Display System display. Control Room operators monitor Main Steam Tunnel temperatures twice per shift [every six hours] and record in [the] Operations log when temperature exceeds 160 d.egrees Fahrenheit. Drywell unidentified and identified leak rates are monitored in accordance with Operations daily surveillance log every eight (8) hours. The NRC staff finds that the licensee's defense-in-depth measures for both the pressurized and non-pressurized components that are covered under this relief request are suitable to provide reasonable assurance that any reactor coolant system leakage will be detected, despite the alternate testing conditions. Additionally, the NRC staff determines that the licensee's proposal to perform a VT-2 visual examination during the system leakage test at a pressure not less than that associated with 100 percent rated power, and with systems in their normal lineup to the extent practical, will satisfy the intent of Section XI, paragraph IWB-5222 and will demonstrate structural integrity and leak tightness of the affected piping systems. Finally, the NRC staff finds that performing the system leakage test in accordance with subparagraph IWB-5222(a) would result in a hardship, without a compensating increase in quality and safety.

4.0 CONCLUSION

As set forth above, the NRC staff determines that the proposed alternative provides reasonable assurance of structural integrity and leak tightness of the subject piping segments, and complying with the specified requirement would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Accordingly, the NRC staff concludes that the licensee has adequately addressed all of the regulatory requirements set forth in 10 CFR 50.55a(z)(2). Therefore, the NRC staff authorizes the use of the licensee's proposed alternative at Cooper Nuclear Station, for the fifth 10-year ISi interval, which will end on February 28, 2026. All other ASME Code, Section XI requirements for which relief was not specifically requested and authorized herein by the NRC staff remain applicable, including the third-party review by the Authorized Nuclear lnservice Inspector. Principal Contributor: B. Fu, NRR Date: March 19, 2020 (10-35) Rev. 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program J. Dent, Jr.

SUBJECT:

COOPER NUCLEAR STATION - PROPOSED INSERVICE INSPECTION ALTERNATIVES RP5-02 AND RIS-02 (EPID L-2019-LLR-0063 AND EPID L-2019-LLR-0064) DATED MARCH 19, 2020 DISTRIBUTION: PUBLIC PM File Copy RidsACRS_MailCTR Resource RidsNrrDorILpl4 Resource RidsNrrPMCooper Resource RidsNrrDnrlNphp Resource RidsNrrDnrlNvib Resource RidsNrrLAPBlechman Resource RidsRgn4MailCenter Resource BFu, NRR JTsao, NRR JJenkins, NRR ADAMS A ccess1on N o.: ML20077L339 *b,y e-maI OFFICE NRR/DORL/LPL4/PM NRR/DORL/LPL4/LA NRR/DNRL/NPHP/BC* NRR/DNRL/NVIB/BC* NRR/DORL/LPL4/BC NAME TWengert (Slingam for) PBlechman MMitchell HGonzalez J Dixon-Herrity DATE 03/19/2020 03/19/2020 01/31/2020 02/10/2020 03/19/2020 OFFICIAL RECORD COPY (10-36) Rev. 3.0

Cooper Station 5th ISI & 3rd Interval CISI Program 11.0 AUGMENTED INSERVICE INSPECTION Augmented lnservice Inspections (AISls) are not ASME Section XI requirements, but are 1) additional examination areas or 2) increased inspection frequencies or combinations of both. AISI can be requested by the Nuclear Regulatory Commission (NRC), recommended in General Electric (GE) Service Information Letters (SILs), recommended by the Boiling Water Reactor Vessel Internals Program (BWRVIP) or added by CNS management direction. Most of the BWRVIP recommended examinations have been moved to the Vessels Internals Program and will not be governed under the ISi program. Although the respective augmented section has been removed, the previous assigned number for that section is noted in the table below to reflect how it was identified or is noted in the ISi database. When examination components fall into the scheduled examination requirements of ISi and are also AISI requirements, then credit for both requirements may be taken by one examination, (i.e., there will be no double examinations). The types of AISI that are required at CNS are identified in the table, below. The tab number corresponds to the tabbed pages that follow, which contain information on the specific examination to be performed. TAB DESCRIPTION 11.1 "Feedwater Nozzle Examinations In Accordance With U.S. NRC NUREG 061911 - Ultrasonic examinations of the feedwater nozzle safe ends, bores, and inside blend radii, and visual inspection of the feedwater spargers, shall be performed in accordance with NUREG 0619, as amended by the SER on the BWROG position. 11.2 "IGSCC in Stainless Steel Piping" - Ultrasonic examination (UT) of austenitic stainless steel piping in accordance with Generic Letter (GL) 88-01. Moved to the CNS Vessel Internals Program under BWRVIP-75-A- Previously identified as 11.4. (11-1) Revision 1

Cooper Station 5th ISi & 3rd Interval CISI Program 11.1 "Feedwater Nozzle Examinations In Accordance With U.S. NRC NUREG 0619"

References:

1. U.S. NRC NUREG 0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, published November 1980.

2. Letter, G. R. Horn (NPPD) to U.S. NRC, dated January 22, 1991, subject:

BWR Feedwater Nozzle Inspections, Cooper Nuclear Station.

3. Letter, G. R. Horn (NPPD) to U.S. NRC, dated August 14, 1991, subject:

BWR Feedwater Nozzle Inspections, Cooper Nuclear Station.

4. Letter, P. W. O'Connor (U.S. NRC) to G. R. Horn (NPPD), dated October 2, 1991, subject: Review of NPPD Request Regarding Feedwater Nozzle Examination Methods.

5. Letter, T. Essig (U.S. NRC) to T. J. Rausch (BWROG), dated June 5, 1998, subject: BWROG-Safety Evaluation of Proposed Alternative to BWR Feedwater Nozzle Inspections (TAC M94090)

6. Calculation NEDC 99-020, Fracture Mechanics Evaluation for The Feedwater Nozzles

7. GE-NE-523-A71-0594-A, Revision 1, May 2000, "Alternate BWR Feedwater Nozzle Inspection Requirements"

8. NRC Final Safety Evaluation of BWR Owner's Group Alternate Boiling Water Reactor (BWR) Feedwater Nozzle Inspection (TAC No. MA6787).

9. BWROG-TP-14-012, Revision 0, Feedwater Nozzle Inspection Frequency 2014, Interference Fit Spargers - Definition Clarification, July 2014.

Source Document: U.S. NRC NUREG 0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, published November 1980, Reference 1. The Control Rod Drive (CRD) Return Nozzle has been cut and capped and is no longer addressed under this document. Examination of the cap weld has been subsumed into the RI-ISi Program and the CNS Vessel Internal Program - BWRVIP-75-A. In 1980, as a result of a commitment to Reference 1, CNS removed the existing stainless steel cladding from the Reactor Pressure Vessel (RPV) feedwater nozzles and installed new triple sleeve/double piston ring seal feedwater spargers. Also, at that time, CNS implemented the nondestructive examination requirements of NUREG 0619. (11-2) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program NU REG 0619, Table 2, required a dye penetrant (PT) exam of the inside surfaces on one feedwater nozzle every nine refueling cycles. This would have required, as a minimum, removal of one feedwater sparger and a penetrant examination of that nozzle, as well as examinations of accessible portions of the remaining nozzles. Due to ALARA concerns and operational considerations, CNS proposed in Reference 2, to perform an automated ultrasonic examination (UT) of the feedwater nozzles in lieu of the specified dye penetrant examination. CNS also committed to implement automated feedwater sparger seal leakage and fatigue usage/crack growth monitoring. Furthermore, CNS committed in Reference 3 to qualify the automated UT examination techniques to be employed on a full-size BWR nozzle mockup with several narrow notches and at least one actual fatigue crack. Reference 4, documents the NRC approval of this proposal. CNS implemented these UT examinations during the 1991 Refueling Outage. The BWROG later adopted a similar approach. In Reference 5, the NRC approved the BWROG inspection program, subject to certain conditions. PT of the nozzle inside radius is no longer required. UT examination of zone 4 is no longer required and UT of zone 5 is only required once per interval. The frequency for inspection of Zones 1, 2 and 3 is now dependent upon the sparger design, a plant-specific fracture mechanics model and the examination method used. The requirements for visual inspection of the sparger are unchanged. CNS uses the triple thermal sleeve sparger design. The results of the fracture mechanics evaluation, Reference 6, demonstrate that the postulated crack growth after 30 years remains within allowable limits. The examination method used was automated, full RF recording (no threshold) prior to Refueling Outage RE22, spring, 2005. In RE22 (January 2005), CNS performed examinations in accordance to Appendix VIII as mandated by 10 CFR 50.55a using a manual technique. As demonstrated by References 3 and 4, and a review of the examination procedures previously used, CNS has been meeting the intent of the NRC SER since Refueling Outage RE16, fall, 1995. Manual ultrasonic examinations were performed in accordance to ASME Section XI, Appendix VIII in Refueling Outage RE22, spring 2005. In Reference 7, the examination will be scheduled on or before 2015. Associated Documents:

1) General Electric document GE-NE-523-A71-0594-A, Revision 1, May 2000, "Alternate BWR Feedwater Nozzle Inspection Requirements," Reference 7 and the NRC Final Safety Evaluation of BWR Owner's Group Alternate Boiling Water Reactor (BWR)

Feedwater Nozzle Inspection, refer to Reference 8. (11-3) Revision I

Cooper Station 5th ISi & 3rd Interval CISI Program

2) BWROG-TP-14-012, Revision 0, Feedwater Nozzle Inspection Frequency 2014, Interference Fit Spargers - Definition Clarification, July 2014, refer to Reference 9.

Purpose:

NUREG-0619 was issued by the NRC in November 1980, Reference 1 and described a cracking phenomenon of BWR RPV Feedwater (FW) nozzle and CRD nozzle inside radius sections. CNS has modified the Feedwater Nozzles by removal of the nozzle clad and installation of triple-sleeve spargers. The CRD Nozzle was cut and capped. As a result of enhanced technology and more sophisticated techniques for stress and fracture mechanics analysis, the examination of the FW Nozzle Blend Radius is now performed in accordance with NRC approved guidance of GE-NE-523-A71-0594-A Rev.1, Reference 7. Scope: The scope of this AISI examination program section includes UT of all four of the FW nozzle bores and inside radius sections as depicted in Figure 1 and VT-3 visual examinations for the FW spargers. A 7 B The volumetric UT examination region begins at the inside radius-to-vessel intersection point (A). The examination region ends at the point on the inner diameter (ID) corresponding to the point on the outer diameter {OD} where the taper on the nozzle thickness starts at {B}. Figure 1 Method: Volumetric UT examination will be performed on the FW nozzle inside radius sections and VT-3 visual examinations will be performed on the FW spargers. Industry Code or Standards: ASM E Section XI (11-4) Revision 1

Cooper Station 5th ISI & 3rd Interval CISI Program Frequency: Each inspection interval (10 years) - Feedwater nozzle inside radius ultrasonic examinations, as discussed in NUREG 0619, are scheduled for examination each 10-year inspection interval using either manual or automated techniques in accordance with the alternative inspection guidelines in References 7 and 8. The following is a summary of the information that has formed the basis for this schedule. Summary NPPD removed the stainless steel cladding from the RPV feedwater nozzles and installed new triple sleeve double piston ring seal feedwater spargers at CNS in 1980. CNS committed to implement the NDE requirements of NUREG-0619 which requires PT examination of the feedwater nozzle inside radius sections, visual examination of the spargers every four outages and UT of the nozzles every two years. The BWR Owner's Group (BWROG) submitted report GE-NE-523-A71-0594, Alternate BWR Feedwater Nozzle Inspection Requirements, to the NRC by letter dated October 30, 1995, proposing an alternative to the recommendations in NUREG 0619. The BWROG requested that the NRC approve its proposed alternative feedwater nozzle inspection program. The NRC issued safety evaluation (TAC M94090), dated June 5, 1998, finding the proposed alternative feedwater nozzle inspection program acceptable, subject to the conditions listed in Section 5.0 of the safety evaluation. The BWR Owner's Group (BWROG) submitted report GE-NE-A71-0594, Revision 1, dated August 1999 to the NRC for review. The NRC issued safety evaluation (TAC MA6787) in March 2000 approving the alternative inspection program in GE-NE-A71-0594, Revision 1 as acceptable. The NRC accepted version is denoted with a suffix -A, i.e., GE-NE-A71-0594-A, Revision 1, May 2000. In accordance to GE-NE-A71-05974-A, Revision 1, the use of modern UT techniques per ASME Section XI, Appendix VIII coupled with plant-specific fracture mechanics assessments that utilize actual plant thermal cycle duty, negates the need for PT examinations and the frequency of UT exams can be reduced. The fracture mechanics analysis was recalculated per (Calculation No. NPPD-13Q-301, 302, and 303; NEDC 99-20). The analysis was performed to the 1989 Edition of the ASME Section XI Code. The analysis supports an examination schedule of one examination each inspection interval, as permitted by GE-NE-A71-05974-A, Revision 1. (11-5) Revision 1

Cooper Station 5th ISi & 3rd Interval CISI Program GE-NE-A71-05974-A, Revision 1 states beginning with the first examination after compliance to Appendix VIII is required; licensee1 s examinations will be in accordance to ASME Section XI, Appendix VIII as mandated by 10CFR50.55a. The examination frequency from that point forward will be the ASME Section XI frequency except for those plants with interference fit spargers. CNS uses the new thermal sleeve design therefore the examination frequency will be 10 years as stated in ASME Section XI, Category B-D using either manual or automated techniques. The examination area for the inside radius section is based on ASME Section XI, IWB-2500-1, is Figure IWB-2500-7(b) as augmented by GE-NE-A71-05974-A, Revision 1 (i.e., Zones 1-3). Modeling is required for examinations qualified to perform the UT technique. EPRI Report IR-2014-557 estimates 100% coverage. For the spargers, CNS will conduct visual examinations to VT-3 every four (4) outages in accordance with Table 6.1 of GE-NE-A71-05974-A, Revision 1.

• NUREG 0619 feedwater nozzle inside radius section examinations were conducted on all four feedwater nozzles during Refueling Outage RE16, fall, 1995, with the Geris 2000 and supplemented with manual examinations to obtain 100% coverage.

No indications that required evaluation were recorded during these examinations.

• NUREG 0619 feedwater nozzle inside radius section examinations were conducted on all four feedwater nozzles during Refueling Outage RE22, spring, 2005. Manual examinations were performed in accordance to ASME Section XI, Appendix VIII. No indications that required evaluation were recorded during these examinations.
• NU REG 0619 VT-3 sparger examinations were last performed during Refueling Outage RE27, fall, 2012.

Acceptance Criteria or Standard: ASME Section XI, IWB-3500 Regulatory Basis: The CNS Updated Safety Analysis Report (USAR), Section 2.7.1 "lnservice Inspection", provides the basis for inspection of the RPV and appurtenances in the ISi Program and has statements, which support the use the examinations that will be performed in accordance with ASME Section XI, Appendix VIII to achieve the level of confidence needed as specified in NUREG-0619. Responsible Organization: Code Programs is responsible for the development and implementation of the augmented inspection program. Design Engineering is responsible for evaluating conditions of degradation for acceptance or corrective action. (11-6) Revision 1

Cooper Station 5th ISi & 3rd Interval CISI Program 12.0 LIST OF APPLICABLE P&IDs, ISOMETRIC AND COMPONENT DRAWINGS System P&ID No. Applicable Isometric No. Condensate & Feedwater 2004 Sheet 3 2849-4, 2849-50 Systems Circulating, Screen Wash & 2006 Sheet 1, Jelco 2824-3, X2852-3, 2852-5, 2852-20, 2852-24, Service Water System Sheet 2, Sheet 2852-25, 2852-26, 2852-27, X2852-226, X2852-241, 3 X2852-242 Control Building Service 2006 Sheet 4 2851-6, 2851-7, 2852-16, 2852-18, 2852-19, 2852-53, Water System X2852-223 Instrument Air Reactor 2010 Sheet 2 2817-218, 2817-219 Building System Service Air System 2010 Sheet 3 X2817-225, X2850-224 Primary Containment Coolin~ 2022 Sheet 1 Jelco RCO-755-1, RCO-755-2, and RCO-755-3, & Nitrogen lnerting System and Sheet 2 GE 17C3303 Sheet 4, CNS-PC-19, CNS-PC-20, 0640-012X203/215, IL-E-70-3 Sheet 29, 13095.12-FSK-1-1 Reactor Vessel 2026 Sheet 1 Jelco X2506-204, X2507-204, X2507-204A, X2507-205, Instrumentation System X2507-206, X2507-206A, X2507-207, X2507-208, X2507-218, X2507-219, X2507-220, X2507-300, X2507

                                            -301 (12-1)                                        Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program System P&ID No. Applicable Isometric No. Reactor Recirculation & 2027 Sheet 1 CNS-RR-37, CNS-RR-38 Suppression Chamber Vent and Sheet 2 lmpell ISO-RL-A, ISO-RL-B Systems & Connections CE Drawings. 232-231, 232-239, 232-241-5, 232-242, 232-244, 232-249 GE Drawings. 731E225, BA-3, BN-3, and BH-4 Yarway Drawings 021-043112, 021-102726 X2507-209,X2507 -210,X2507-21LX2 507-21~X2507-213, X2507-214, X2507-215, X2507-355, X2507-357, X2512-200, 197R576, EDS-113.03, EDS-113.04, EDS-113.05, EDS-0640-012-X203/215, EDS-0640-012-X209/229, EDS-0640-012-213AB Reactor Building & Drywell 2028 Jelco X2512-200, 2506-204, X2507-201, 2628-1, 2628-Equipment Drain System 2, 2628-3, 2628-4, 2628-5, 2628-6, 2713-12, 731E611 Sheet 4, 68-2211-43(CBI), IL-E-70-3 Sheet 20, IL-E-70-3 Sheet 24 Reactor Building 2029 2832-5 Demineralized Water System Reactor Building Closed 2031 Sheet 1 Jelco 2848-1, 2848-2, 2848-7, 2848-8, 2848-9, 2848-14, Cooling Water System and Sheet 2 2848-15, 2848-16, 2848-21, 2848-22, 2848-50, 2848-51, 2848-52, 2848-54, 2848-55, 2848-56, 2848-57 Jelco X2848-200, X2848-201, X2848-202, X2848-203, X2848-204, X2848-205, X2848-206, SKE-PC-200 Sheet 1, IL-E-70-3 Sheet 34A (12-2) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program System P&ID No. Applicable Isometric No. Reactor Building Service 2036 Sheet 1 Jelco 2851-1, 2851-2, 2851-4, 2852-3, 2852-5, 2852-6, Water System 2852-7, 2852-8, 2852-9, 2852-10, 2852-22, 2852-23, 2852-50, 2852-54, 2852-55, 2852-57 Reactor Building Floor & 2038 Sheet 1 2708-13, 2720-1, 2720-2 Roof Drain Systems Control Rod Drive Hydraulic 2039 RC Drawing CP-009 Sheet 4 System S&W Drawing 13095.19-EP-lA-2 and 13095.19-EP-lB-2 Residual Heat Removal 2040 Sheet 1 Jelco 2510-1, 2510-3, 2510-4, 2511-1, 2512-1, 2624-1, Systems and Sheet 2 2624-2, 2624-3A, 2624-3B, 2624-3C, 2624-4, 2624-5, 2624-6, 2624 -7, 2625-1, 2625-2, 2625-3, 2625-4, 2626-1, 2626-2, 2626-3, 2626-4 SWECO Drawing H-82454 Reactor Building Main 2401 GE Drawing 731E611 Sheet 4 Steam System Jelco 2506-1, 2506-2, 2506-3, X2506-201, 2601-2, 2601-3, 2614-2, 2628-1, 2628-2, 2628-3, 2628-4, 2628-5, 2628-6, 2629-1, 2629-2, 2629-50, 2507-216, 2507-217, 2507-350, 2507-351, 2507-356 Reactor Water Clean-Up 2042 Sheet 1 Jelco 2503-1, 2509-1, and X2503-200 System GE 141C7063, GE 141C7064, GE-141C7065, GE-141C7090, and 774E826 Reactor Core Isolation 2043 Jelco 2509-1, 2614-1, 2619-1, 2620-1, 2621-1, 2621-2, Coolant and Reactor Feed 2623-1, 2715-5 Systems (12-3) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program System P&ID No. Applicable Isometric No. High Pressure Coolant 2044,2049 Jelco 2509-1 2509-2, 2601-1, 2601-2, 2601-3, 2609-1, Injection and Reactor Feed Sheet 2 2611-4, 2611-5, 2611-6, 2612-2, 2614-2, 2614-3, 2623-Systems and Condensate 2,2623-3,X2623-207,2710-1,2710-2,2716-iEDS Supply System 113.01, EDS 113.02 Core Spray System 2045 Sheet 1 Jelco 2501-1, 2502-1, 2602-1, 2602-2, 2603-12603-2, 2603-3, 2603-4, 2507-200, IL-E-70-3 Sheet 13 Standby Liquid Control 2045 Sheet 2 Jelco X2504-200, X2504-201 System Diesel Gen. Bldg., Service 2077 Jelco 2852-24, 2852-25, 2852-26, 2852-27, 2852-55 Water, Starting Air, Fuel Oil, KVS-47-8 Sump System and Roof Jelco 2400-1, 2400-3, 2400-4, 2400-6, 2400-7 Drains Reactor Building Traversing 2083 2083, 68-2211 Drawing 33, SKE-MISC-131 lncore Probe Plan & Elevation Stand By Nitrogen Injection 2084 N/A System Reactor Vessel N/A GE 731E-306, 197R576, BA-3, BA-4, BN-3, CE Drawings. 232-231, 235-5, 239, 241-5, 242, 244, 249 Miscellaneous N/A Kaiser 110.01 Ci2-4) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program 13.0 NONDESTRUCTIVE EXAMINATION PROCEDURE LISTING The lnservice Inspection Program uses the following CNS NDE related procedures. No. Title 0-CNS-VT Qualification and Certification of Visual Examination (VT) NDE Personnel Visual Inspection Of Pressure Retaining Bolting And Integral Attachments, VT-3.28.1.1 1 3.28.1.2 Weld Preparation and Marking for ISi 3.28.1.3 Visual Inspection Of Pump Casings And Valve Bodies, VT-3 3.28.1.4 General Visual Examination of Containment Surfaces 3.28.1.5 Visual Examination of Containment Surfaces, VT-3 and VT-1 3.28.1.6 Visual Examination of Containment Bolting VT-1 Magnetic Particle Examination Using A/C Yoke for ASME Section XI 3.28.5.MT.1 Inspections 3.28.5.PT.1 Liquid Penetrant Examination for ASME Section XI Inspections 3.28.5.UT.0 Ultrasonic Equipment linearity Measurements 3.28.5.UT.4 General Ultrasonic Examination 3.28.5.UT.SOC Socket Weld Ultrasonic Phased Array Weld Examination 7.0.8 Pressure Testing 7.0.8.1 lnservice Leak Testing 7.2.34.1 Snubber Examination (Includes VT-3 of attachments) Pipe Snubber Removal and Installation (Includes guidance for VT-3 of 7.2.34.2 attachments) 7.2.57 ASME Category F-A Component Supports Inspection And Adjustments Since CNS has limited in-house NDE capability, a combination of vendor and CNS nondestructive examination (NDE) procedures are used as needed. The most current revision of a* referenced vendor procedure approved in accordance with CNS Administrative Procedures will be used. CNS reserves the right to use other procedures than those listed provided they meet Code requirements and are approved by CNS and the Authorized Nuclear lnservice Inspector (ANII). The Performance Demonstration Initiative (PDI) implements ASME Section XI, Appendix VIII, requirements and is implemented via the EPRI NDE Center. It is the current industry standard for UT performance demonstration. The following additional limitations from 10CFRS0.55a also apply:

• Appendix VIII Personnel Qualification. Per 50.55a(b)(2)(xiv), all personnel qualified for performing ultrasonic examinations in accordance with Appendix VIII shall receive 8 hours of annual hands-on training on specimens that contain cracks. CNS may use the annual practice requirements in Vll-4240 of Appendix VII of Section XI in place of the 8 hours of annual hands-on training provided that the supplemental practice is performed (13-1) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program on material or welds that contain cracks, or by analyzing prerecorded data from material or welds that contain cracks. In either case, training must be completed no earlier than 6 months prior to performing ultrasonic examinations at a licensee's facility.

• Certification of NDE personnel. Per 50.55a(b){2)(xviii(A), Level I and II nondestructive examination personnel shall be recertified on a 3-year interval in lieu of the 5-year interval specified in the 1997 Addenda and 1998 Edition of IWA-2314, and IWA-2314(a) and IWA-2314(b) of the 1999 Addenda through the latest edition and addenda approved per 10CFRS0.55a.
• Substitution Of Alternative Methods. Per 5O.55a(b)(2)(xix), the prov1s1ons in IWA-4520{b)(2) and IWA-4521 of the 2008 Addenda through the latest edition and addenda approved by 10CFRS0.55a, allowing the substitution of ultrasonic examination for radiographic examination specified in the Construction Code are not approved for use.
• Surface Examination. Per 50.55a(b)(2)(xxii), the use of the provision in IWA-2220, "Surface Examination," of Section XI, 2001 Edition through the latest edition and addenda approved per 10CFR50.5Sa, that allows use of an ultrasonic examination method is prohibited.

(13-2)

Cooper Station 5th ISi & 3 rd Interval CISI Program 14.0 ULTRASONIC CALIBRATION BLOCKS Ultrasonic calibration blocks listed on the following pages are used in performing examinations required by both the lnservice Inspection (ISi) and Augmented lnservice Inspection (AISI) Programs. They have been designed and procured in accordance with applicable ASME Code and regulatory requirements, and vendor recommendations, to the extent practical. For more detail, see "Ultrasonic Testing Calibration Standards Report, Cooper Nuclear Station, Unit 1, Nebraska Public Power District", Volume 1, Tab 6. (14-1) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program Ultrasonic Calibration Block Table Block ID Size (in.) Material Notes CNS-GE-3-120-C 3 SA-106 GR C CNS-GE-6-160-C 6 SA-106 GR B CNS-GE-10-120-C 10 SA-106 GR B CNS-GE-12-140-C 12 SA-106 GR B CNS-GE-14-160-C 14 SA-106 GR B CNS-GE-16-160-C 16 SA-106 GR B CNS-GE-4-80-S 4 SA-312 TP 304 CNS-GE-6-80-S 6 SA-312 TP 304 CNS-G E-10-80-S 10 SA-376 TP 304 CNS-GE-20-80-S flat SA-312 TP 304L CNS.CAL.STD.NO.15 RPV SA-533 GR B CNS.CAL.STD.NO.16 RPV SA-533 GR B CNS-GE-6-160-SS 6 SA-312 TP 304 CNS-G E-4-160-SS 4 SA-312 TP 304 reference block CNS-G E-16-75-CS 16 SA-106 GR B CRD.CAP 6 SA-508 / SB-166 CNS.CAL.STD.NO.21 6.35 SA-540 GR B24 CNS.CAL.STD.NO.22 NA A-285 GR C reference block CNS.CAL.STD.NO.23 2.75 SA-540 GR B24 CNS.CAL.STD.NO.24 NA A-285 GR C reference block CNS.CAL.STD.NO.25 NA A-285 GR C reference block (14-2) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program Ultrasonic Calibration Block Table Block ID Size (in.) Material Notes CNS.CAL.STD.NO.26 NA A-285 GR C reference block CNS.CAL.STD.NO.27 NA A-285 GR C reference block CNS.CAL.STD.NO.28 NA A-285 GR C reference block CNS.CAL.STD.NO.29 NA A-285 GR C reference block CNS.CAL.STD.NO.30 NA A-285 GR C reference block CNS.CAL.STD.NO.31 4 SA-312 TP304 reference block CNS.CAL.STD.NO.32 5 SA-4 79 TP 304 CNS.CAL.STD.NO.33 10 SA-376 TP304 CNS.CAL.STD.NO.34 12 SA-240 TP 304 CNS.CAL.STD.NO.35 22 SA-240 TP 304 CNS.CAL.STD.NO.36 24 SA-240 TP 304 CNS.CAL.STD.NO.37 24 SA-240 TP 304 CNS.CAL.STD.NO.38 28 SA-240 TP 304 CNS.CAL.STD.NO.39 20 SA-240 TP 304 CNS.CAL.STD.NO.40 flat SA-106 GR B CNS.CAL.STD. NO.42 8 SA-106 GR B CNS.CAL.STD.NO.43 8 SA-333 GR 6 CNS.CAL.STD.NO.44 NA 55 reference block CNS.CAL.STD.NO.46 NA 55 reference block CN S-48-6-80-SS 6 SA-403 GR WP31 CNS-49-10-80-SS 10 SA-403 GR WP31 (14-3) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program Ultrasonic Calibration Block Table Block ID Size (in.) Material Notes CNS-50-12-80-SS 12 SA-403 GR WP31 CNS-51-13-1.125-SS 13 SA-312 GR T316 CNS-52-14-140-SS 14 SA-312 GR T316 CNS-53-20-80-SS 20 SA-312 GR T316 CNS-54-22-80-SS 22 SA-312 GR T316 CNS-55-24-80-SS 24 SA-312 GR T316 CNS-56-28-1.25-SS 28 SA-312 GR T316 CNS-57-29-1.935-SS 29 SA-240 T316L CNS-58-30-2.25-SS 30 SA-240 T316L CNS-59-29-1.620-CS 29 SA-508 CL 111 CNS-60-14-0.972-CS 14 SA-508 CL 111 CNS-61-13-0.844-CS 13 SA-508 CL 111 CNS-62-16-0.375-CS 16 SA-106 GR B CNS-63-18-0.438-CS 18 SA-106 GR B CNS-64-4-0.531-CS 4 SA-106 GR B CNS-65-48-1. 250-CS flat SA-515 GR 70 CNS-66-2.490.276.INC 2.49 SB 166 lnconel 600 CNS-67-2.490-.276-INC 2.49 SB 166 lnconel 600 CNS-67-2.490-.276-SS 2.49 SA 479 GR 316L CNS-68-2.490-.276-SS 2.49 SA 479 GR 316L CNS-69-2-80-SS 2.375 A 312 GR TP316L (14-4) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program Ultrasonic Calibration Block Table Block ID Size (in.) Material Notes CNS-72-8-0.875 8 SA-333 GR 6 CNS-73-8-100-CS 8 SA-106 GR B CNS-75-8-120-CS 8 SA-106 GR B CNS-77-10-0.719 10 SA-106 GR B CNS-78-10-100-CS 10 SA-106 GR B CNS-79-10-0.631 10 SA-333 GR 1 CNS-83-12-1.00 12 SA-333 GR 1 CNS-85-12-160-CS 12 SA-333 GR 6 CNS-89-14-10-CS 14 SA-106 GR B CNS-96-18-100-CS 18 SA-106 GR B CNS-97-18-160-CS 18 SA-106 GR B CNS-100-18-120-CS 18 SA-106 GR B CNS-101-18-40-CS 18 SA-106 GR B CNS-102-20-40-CS 20 SA-106 GR B CNS-103-20-80-CS 20 SA-106 GR B CNS-104-24-30-CS 24 SA-106 GR B CNS-106-24-80-CS 24 SA-106-GR B CNS-107-5. 5-0. 812-SS 5.5 SA-182 F 316L CNS-108-9-1.575-SS 9 SA-182 F 316L CNS-109-5.5-0.625-CS 5.5 SA-508 CL 2 CNS-110-4-80-5S 4 SA-182 F 316L (14-5) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program Ultrasonic Calibration Block Table Block ID Size (in.) Material Notes CNS-113-24-1.063 24 SA-333 GR 1 CNS-114-24-1.063 24 SA-155 CL 1 CNS-115-24-1.593 24 SA-155 CL 1 CNS.CAL.STD.NO.116 6.25 SA-540 GR B24 Replaced with CNS.CAL.STD.N0.142 CNS-122-3-0.216-CS 3 SA-106 GR B CNS-123-2.5-0.203-CS 2.5 SA-106 GR B CNS-124-12-0.688-CS 12 SA-106 GR B CNS-126-6-0.280-CS 6 SA-106 GR B CNS-127-4-0.237-CS 4 SA-106 GR B CNS-128-8-0.322-CS 8 SA-106 GR B CNS-129-10-0.365-CS 10 SA-106 GR B CNS-130-12-0.375-CS 12 SA-106 GR B CNS-131-14-0. 3 7 5-CS 14 SA-106 GR B CNS-132-16-0.500-CS 16 SA-106 GR B CNS-133-20-0.375-CS 20 SA-106 GR B CNS-135-6-0.432-CS 6 SA-333 GR 6 CNS-136-48-1. 750-CS flat SA-515-GR 70 CNS.CAL.STD.NO.142 48.9 A540, GR24 RPV Stud UT Cal Block CNS.CAL.STD.NO.145 21.9 A540, GR23 RR Pump Stud UT Cal Block CNS. CAL.STD. N 0.144 10.0 SA508, GR2 RPV Flange Ligament CNS-80-PDIALT-A516-70 0.5-2.0 A516-70 Alternative ASME Calibration (14-6) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program Ultrasonic Calibration Block Table Block ID Size (in.) Material Notes Block CNS-81-PDIALT-T304 0.5-2.0 304 55 Alternative ASME Calibration Block CNS-82-PDIALT-T316 0.5-2.0 316 55 Alternative ASME Calibration Block 4200001626 Sample 1 2.0 A333 Grl CS Socket Weld Elbow Specimen 1 LLJ00001626 Sample 4 1.5 316 55 Socket Weld Elbow Specimen (14-7) Revision 1

Cooper Station 5th Interval ISI

                                                                     & 3rd Interval CISI Program 15.0                     COMPONENT EXAMINATION 

SUMMARY

LISTING Al.I components and component supports potentially subject to inservice NDE examination under ASME Section XI, 2007 Edition, 2008 Addenda, are contained in the CNS controlled copy titled "CNS Fifth ISi and Third Interval CISI Component Listing" document. The component listing document provides the following tables: Att.1 5th Interval ISi Standard Program Att. 2 5th Interval Pressure Testing Program Att.3 3rd Interval CISI Program Att.4 5th Interval Augmented Program Att. 5 5th Interval License Renewal Augmented The RPV internal examinations directed by BWRVIP are contained in the controlled copy titled "CNS Vessel Internals Program". See this program for specific details associated with the RPV. (15-1) Revision 1

Cooper Station 5th ISi & 3rd Interval CISI Program 16.0 INDEX OF ABBREVIATIONS SYSTEM/COMPONENT ABBREVIATIONS FOR ASME CLASS 1 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENTS AH Recirculation Loop A Hanger ASB Recirculation Loop A Seismic Restraint ASS Recirculation Loop A Seismic Restraint BH Recirculation Loop B Hanger BSB Recirculation Loop B Seismic Restraint BSS Recirculation Loop B Seismic Restraint CHR Containment Heat Removal CRD Control Rod Drive CRDH Control Rod Drive Hanger CRDS Control Rod Drive Seismic Restraint cs Core Spray (Bolting) CSA Core Spray Loop A CSB Core Spray Loop B CSH Core Spray Hanger css Core Spray Seismic Restraint CUH RWCU Hanger cus RWCU Seismic Restraint CWA Clean-Up CWB RWCU Return DH Drain Header FW Feedwater FWA Feedwater Loop A, Nozzle N4A FWAB Feedwater Loops A and B FWB Feedwater Loop B, Nozzle N4B FWC Feedwater Loop C, Nozzle N4C FWD Feedwater Loop D, Nozzle N4D

                                         / 1 C:: 1 \
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Cooper Station 5th ISi & 3rd Interval CISI Program SYSTEM/COMPONENT ABBREVIATIONS FOR ASME CLASS 1 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENTS HA MS Hanger Loop A HB MS Hanger Loop B HC MS Hanger Loop C HD MS Hanger Loop D HM RPV Bottom Head Meridional HMA Bottom Head - Meridional Welds HMB Bottom Head - Meridional Welds HMC Bottom Head - Circumferential Welds HMD Bottom Head - Circumferential Welds HME Top Head - Meridional Welds HNC Bottom Head - Vessel Support Skirt HPCI High Pressure Coolant Injection JPA Jet Pump Instrumentation - Loop A JPB Jet Pump Instrumentation - Loop B MS Main Steam (Bolting} MSA Main Steam - Loop A MSB Main Steam - Loop B MSC Main Steam - Loop C MSD Main Steam - Loop D MSDR Main Steam - Drain MSH Main Steam Hanger MSS Main Steam Seismic Restraint NB Nuclear Boiler NVE Nozzle-To-Vessel NVIR Nozzle Vessel Inner Radius PRA Pressure Retaining Bolting - Studs PRB Pressure Retaining Bolting - Nuts PRC Pressure Retaining Bolting - Washers (16-2) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program SYSTEM/COMPONENT ABBREV*ATIONS FOR ASME CLASS 1 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENTS PRO Pressure Retaining Bolting - Bushings PRE Pressure Retaining Bolting - Ligaments PRF Ring Girder Anchor Bolts PRG RPV Skirt-To-Ring Girder Bolts PSA HPCI Steam PWA HPCI Water RAH/RAD Recirculation - Loop A Discharge RAS Recirculation - Loop A Suction RBH/RBD Recirculation - Loop B Discharge RBS Recirculation - Loop B Suction RCA CRD Return RCIC Reactor Core Isolation Cooling (Bolting) RF Reactor Feedwater Bolting RFH Reactor Feedwater Hanger RFS Reactor Feedwater Seismic Restraint RHA 20 RHR Supply 11 RHB RHR - Loop A RHC RHR - Loop B RHO 6 RHR Head Spray 11 RHH RHR Hanger RHR Residual Heat Removal (Bolting) RHS RHR Seismic Restraint RR Reactor Recirculation (Bolting) RRA Recirculation - Loop B RRB Recirculation - Loop B RRC Recirculation - Loop B RRD Recirculation - Loop B RRE Recirculation - Loop B (16-3) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program SYSTEM/COMPONENT ABBREVIATIONS FOR ASME CLASS 1 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENTS RRF Recirculation - Loop A RRG Recirculation - Loop A RRH Recirculation - Loop A RRJ Recirculation - Loop A RRK Recirculation - Loop A RRP Reactor Recirculation Pump RSA RCIC- Steam RVD Reactor Vessel Drain RVI Reactor Vessel Instrumentation RWA RCIC- Water RWCU Reactor Water Cleanup (Bolting) SC Shell Course SLC Standby Liquid Control SLH Standby Liquid Control Hanger SSA MS Seismic Restraint Loop A SSB MS Seismic Restraint Loop B SSC MS Seismic Restraint Loop C SSD MS Seismic Restraint Loop D VCB RPV Circumferential Welds VLA RPV Shell Course 1 Longitudinal Welds VLB RPV Shell Course 2 Longitudinal Welds VLC RPV Shell Course 3 Longitudinal Welds VLD RPV Shell Course 4 Longitudinal Welds (16-4) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program SYSTEM/COMPONENT ABBREVIATIONS FOR ASME CLASS 2 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENT BHS Bleed Steam Hanger BSS Bleed Steam Seismic Restraint CAD Containment Atmospheric Dilution CDS Condensate Supply CND Condensate cs Core Spray HPCI High Pressure Coolant Injection HPEX HPCI Exhaust MS Main Steam MSH Main Steam Hanger MSS Main Steam Seismic Restraint N Nitrogen Primary Containment Bolting OG Off Gas PNC Nitrogen Primary Containment System PSA HPCI Steam PVH Process Vent Hanger PVS Process Vent Seismic Restraint RAS RHR Loop A, Steam RAW RHR Loop A, Suction Bypass, Torus Test Line and Torus Spray RBS RHR Loop B, Steam RBW RHR Loop B, Water RCC/REC Reactor Equipment Cooling RCIC Reactor Core Isolation Cooling RCT RH R Cross Tie RHA RHR 20" Supply RHB RHR Loop A - Water RHC RHR Loop B - Water RHO 6 RHR Head Spray 11 (i6-5) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program SYSTEM/COMPONENT ABBREVIATIONS FOR ASME CLASS 2 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENT RHE Containment Spray Loop B RHF RHR Heat Exchanger Flange Bolting RHG Containment Spray Loop A RHH RHR Hanger RHR RHR Heat Exchangers RHRA RHR Pump A Strainer, Bolting RHRB RHR Pump B Strainer, Bolting RHRC RHR Pump C Strainer, Bolting RHRD RHR Pump D Strainer, Bolting RHS RHR Seismic Restraint RPA RHR Pump, A Loop RPB RHR Pump, B Loop RPC RHR Pump, C Loop RPD RHR Pump, D Loop RSA RCIC- Steam RWA RCIC- Water RWCU Reactor Water Cleanup SON Scram Discharge Volume, North Header SDS Scram Discharge Volume, South Header SGTS Standby Gas Treatment System SW Service Water TDA Torus Drain, Loop A TDB Torus Drain, Loop B TH Torus Hanger (16-6) Revision O

Cooper Station 5th ISi & 3rd Interval GISI Program SYSTEM/COMPONENT ABBREVIATIONS FOR ASME CLASS 3 SYSTEM/COMPONENT ABBREVIATIONS SYSTEM/COMPONENTS FPC Fuel Pool Cooling and Cleanup HPCI High Pressure Coolant Injection REC Reactor Equipment Cooling SLC Standby Liquid Control SW Service Water VR Radioactive Vents (16-7) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program MISCELLANEOUS COMPONENT ABBREVIATIONS COMPONENT ABBREVIATIONS COMPONENT DESCRIPTION B Branch BHD Bottom Head BLT Bolting BU Bushings C Circumferential CAP Cap CH Channel Side cou Coupling DOM Dome DR Distributor Ring OREB Distributor Ring End Bottom DRET Distributor Ring End Top E Elbow F Flange FH Flued Head H Hanger HOU CRD Housing HSL Hanger - Shear Lug IA Elbow Inside Arc Seam L Lug LIG Ligaments LL Lifting Lug LS Longitudinal Seam M Meridional N Nozzle NIR Nozzle Inner Radius NT Nut OA Elbow Outside Arc Seam (16-8) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program MISCELLANEOUS COMPONENT ABBREVIATIONS COMPONENT ABBREVIATIONS COMPONENT DESCRIPTION OR Orifice p Pipe PC Containment PED Concrete Pedestal PU Pump R,RED Reducer RE Reducing Elbow RGB Ring Girder Bolts RP Reinforcing Plate RT Reducing Tee SAD Saddle SB Snubber SE Safe End SH Shell Side SHB Shell Bottom SHF Shell Flange SHT Shell Top SK RPV Support Skirt SOL Sock-O-Let SP Support ss Shock Suppressor SSL Snubber-Shear Lug ST Stud STB CRD Stub Tube STN Stanchion THD Top Head TS Tube Sheet TSB Tube Sheet Bottom (16-9) Revision O

Cooper Station 5th ISi & 3rd Interval CISI Program MISCELLANEOUS COMPONENT ABBREVIATIONS COMPONENT ABBREVIATIONS COMPONENT DESCRIPTION TST Tube Sheet Top V,VA Valve VE Vessel 4W Four-Way Cross WA Washer WE Weldolet VEL Velocity Limiter (16-10) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program HANGER AND SUPPORT ABBREVIATIONS ABBREVIATION DESCRIPTION ABS Attachment to Building Structure B Bolted w Welded APRC Attachment to Pressure Retaining Component B Bolted HG Hanger NA Not Attached PC Primary Containment Penetration Pl Pipe PU Pump VA Valve VE Vessel w Welded BS Building Structure CB Concrete Beam cc Concrete Ceiling CF Concrete Floor cw Concrete Wall ewe Concrete Wall and Ceiling CWF Concrete Wall and Floor ow Drywell EP Embedment Plate (16-11) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program HANGER AND SUPPORT ABBREVIATIONS ABBREVIATION DESCRIPTION FH Flued Head SSL Stainless Steel Liner ss Structural Steel TRS Torus HSK Sketch/Drawing Number of Hanger BZ Prefix Stone & Webster Drawing Vendor KE Prefix Kaiser Engineers Drawing Vendor B Prefix Berg Patterson Drawing Vendor SK Prefix ITT Grinnell Drawing Vendor Suffix E0855 EDS Drawing Vendor Suffix N NPPD Drawing IAS Intermediate Attachment of Support B Bolted w Welded SD Support Design HS Horizontal Support LS Lateral Support vs Vertical Support SF Support Function ow Dead Weight DWS Dead Weight Sliding HS Horizontal Support (16-12) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program HANGER AND SUPPORT ABBREVIATIONS FIELD ABBREVIATION DESCRIPTION INS Insulation Protection ss Stanchion Sliding vs Vertical Support ST Suppo(t Type cs Constant Support CST Constant Support Trapeze HS Hydraulic Snubber

        , MS                            Mechanical Snubber PVV                   Pumps, Valves and Vessel Supports RB                                Rigid Brace RBF                            Restraint Box Frame RBT                            Rigid Brace Trapeze RH                                Rod Hanger RHT                            Rod Hanger Trapeze RPR                           Rod Hanger Pipe Roll RSF                        Restraint Structural Frame STN                                 Stanchion SWB                                 Sway Brace sws                                 Sway Strut VL                             Velocity Limiter VS                               Variable Spring VST                          Variable Spring Trapeze (16-i3)                                          Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program HANGER AND SUPPORT ABBREVIATIONS ABBREVIATION DESCRIPTION BLDG Building/Location CONT Containment CTRL Control Building DW Drywell HP HPCI Pump Room NEQ Northeast Quad NPC North Pipe Chase R-RB Reactor Building SEQ Southeast Quad SPC South Pipe Chase SWB Service Water Building TB Torus Bottom TT Torus Top TURB Turbine Building SWQ Southwest Quad NWQ Northwest Quad (16-14) Revision 0

Cooper Station 5th ISi & 3rd Interval GISI Program JOINT-TYPE ABBREVIATIONS JOINT-TYPE DESCRIPTION ABBREVIATIONS BW Butt Weld LW Lap Joint SW Socket Weld TW T-Joint CLAD Clad NIR Nozzle Inner Radius NVE Nozzle to Vessel (16-15) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program MATERIAL SPECIFICATION ABBREVIATIONS Material Specification Material Specification Description Abbreviations (Note 1) P-1 Seamless carbon steel: ASTM-A-106-GR-B and USAS B36.10 P-2 Seamless carbon steel: ASTM-A-33-GR-1 and USAS B36.10 - by electric furnace process with Charpy "V" notch tests @-20° F and 15 ft-lbs. P-3 Electric fusion welded carbon steel: ASTM-A-155-CL-1 KC-70 plate to ASTM-A-516-GR-70 plate, fire box quality. P-4 Electric fusion welded carbon steel: ASTM-A-155-CL-1 KC-50 plate to ASTM-A-285-GR-B plate, fire box quality. P-5 Seamless carbon steel: ASTM-A-53 GR-Band USAS B36.10. P-6 Electric resistance welded carbon steel: ASTM-A-53-GR-B Type E and USAS B36.10. P-7 Seamless carbon steel (galvanized): ASTM-A-53 GR-Band USAS B36.10. P-8 Electric fusion welded carbon steel: ASTM-A-155-CL-11 C-50 plate to ASTM-A285-GR-B plate, fire box quality, designed to ASA B31.1.0 & Para. UG-28 of ASME Section VIII with 0.120" corrosion allowance. P-9 Electric resistance welded carbon steel: ASTM-A-135-GR-A and USAS B36.10. P-10 Seamless galvanized carbon steel: ASTM-A-120 and USAS B36.10 P-11 Seamless alloy steel: ASTM-A-335-GR-P-11 and USAS B36.10. P-12 Seamless & welded austenitic stainless steel: ASTM-A-312-GR-TP304 and USAS B36.10. (16-16) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program MATERIAL SPECIFICATION ABBREVIATIONS Material Specification Material Specification Description Abbreviations {Note 1) P-13 Electric fusion butt-welded straight seam carbon steel AWWA-C-201 & ASTM-A-134 plate to ASTM-A-283-GR-C pipe. P-14 Seamless and welded austenitic stainless steel: ASTM-A-312-GR-TP316 and USAS 836.19. P-15 Seamless austenitic stainless steel pipe: ASTM-A-376-GR-TP304 plate. P-16 Electric fusion welded austenitic chromium nickel alloy steel pipe: ASTM-A-358-GR-TP304. P-17 Austenitic stainless steel plate: SA-358 Class 1, A240 TP304 P-:18 SB-166 lnconel P-19 SA-312 GR TP316 P-20 Nuclear grade stainless steel pipe: 316 NG P-21 Seamless and welded austenitic stainless steel pipe: SA-312-GR-TP316L F-1 Wrought carbon steel: ASTM-A-234-GR-WPB and USAS 816.9 F-2 Wrought carbon steel: ASTM-A-234-GR-WPC and USAS 816.9 F-3 Electric fusion welded: ASTM-A-234-GR-WPBW plate to ASTM-A-516-GR-70 fire box quality F-4 Electric fusion welded: ASTM-A-234-GR-WPBW plate to ASTM-A-285-GR-B fire box quality F-5 Wrought alloy steel" ASTM-A-234-GR-WP-11 F-6 Forged carbon steel: ASTM-A-234-GR-WPB forgings to ASTM-A-105-GR-2 and USAS B16.11 (16-17) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program MATERIAL SPECIFICATION ABBREVIATIONS Material Specification Material Specification Description Abbreviations (Note 1) F-7 Wrought carbon steel: ASTM-A-105-GR-2 and USAS B16.11 and MSS-SP-49 F-8 Galvanized malleable iron: ASTM-A-197 and USAS 816.3 and 82.1 F-9 Cast bronze: ASTM-8-61 and USAS 816.15 and B2.1 F-10 Cast iron: ASTM-A-126-A and USAS 816.12 F-11 Cast Iron: ASTM-A-126-A and USAS B16.1 F-12 Wrought carbon steel: ASTM-A-234-GR-WP8W and USAS 816.9 or ASTM-A-234-GR-WP8 forging to AlOS-GR-11 and USAS 816.9 F-13 Wrought carbon steel ASTM-A-234-GR-WP8W and USAS 816.9 to match 836.10 pipe F-14 Galvanized Cast Iron: ASTM A & 8 and USAS B16.1 F-15 Malleable iron: ASTM-A-197 and USAS B16.3 and USAS 82.1 F-16 Forged alloy steel: ASTM-A-234-GR-WP-11 to ASTM-A-182-GR-F-11 and USAS B16.11 F-17 Forged alloy steel: ASTM-A-403 to ASTM-A-182-GR-F-304 and USAS B16.11 F-18 Forged alloy steel: ASTM-A-403 to ASTM-A-182-GR-F-304 and USAS B16.11 F-19 Wrought austenitic steel: ASTM-A-403 to and USAS 816.9 Grade WP-304 F-20 Wrought austenitic steel: ASTM-A-403 to and USAS B16.9 Grade WP-316 (16-18) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program MATERIAL SPECIFICATION ABBREVIATIONS Material Specification Material Specification Description Abbreviations (Note 1) F-21 Forged alloy steel: ASTM-A-403 to ASTM-A-182-GR-F-316 and USAS 816.11 F-22 Wrought carbon steel, seamless or welded, for low temperature service: ASTM-A-420-GR-WPLI and USAS B-16.11 F-23 Forged carbon steel: ASTM-A-420 to ASTM-A-350-GR-LFI and USAS B16.11 F-24 A-325-GR-LC F-25 SA-216 F-26 Wrought austenitic stainless steel: SA-403-GR-WP316L F-27 Forged austenitic stainless steel for high temperature service: SA-182-GR-F316L RPV-1 A-508/SA-508 Class 2 RPV-2 A-533/SA-533 S-1 RPV Stud: SA-540-GR-B24 NOTE 1: Material specification abbreviations generally correspond with the CNS Material Specification Codes used by the Architect-Engineer during construction. Specifications greater than P-17 or F-22, and RPV-1, RPV-2, and S-1, were added for completeness. The Component Examination Summary Tables and the ISi database uses the actual material specifications to the extent practicable. (i6-i9) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program 17.0 RI-ISi LIVING PROGRAM EVALUATION Introduction The objective of the RI-ISi program is to provide an alternative method for selection and categorizing piping and components into HSS and LSS groups for the purpose of developing a RI-ISi program as alternative to the ASME Section XI requirement for Examination Categories B-F, B-J, C-A, C-B, C-F-1, and C-F-2. CNS is a Class 1 and 2 applications that uses Code Case N-716-

1. The NRC approved this code case in August 2014 in Regulatory Guide 1.147 Revision 17. The code case was placed in Table 1 and approved with no conditions.

Purpose The RI-ISi program outlines an acceptable alternative approach to the existing Section XI requirements for the scope and frequency of piping examination. Scope Code Case N-716-1 provides alternative requirements to IWB-2420, IWB-2430, Table IWB-2500-1 Examination Category B-F and B-J, IWC-2420, IWC-2430, and Table IWC-2500-1 (excluding Examination Categories C-C and C-H), for inservice inspection of Class 1 piping welds or Class 2 components, IWB-2200 and IWC-2200 for preservice inspection of Class 1 piping welds or Class 2 component, or as additional requirements for Class 3 or non-class components. The following summarized the ASME Section XI scope included in the N-716-1 evaluations: Table 1: N-716-1 Evaluation Scope CS - Core Spray 1, 2 B-F, B-J, C-F-2 HPCI - High Pressure Coolant 2 C-F-2 Injection MS - Main Steam 1, 2 B-J, C-F-2 MSDR - Main Steam Drains 1 B-J NB - Nuclear Boiler 1 B-F, 8-j NBDR - Nuclear Boiler Drains .,

                                                        .l                8-F, 8-j NBI - Nuclear Boiler                       1                 B-F, B-J Instrumentatio n PC - Primary Containment                   2               C-F-2, C-G RCIC - Reactor Core Isolation              2                  C-F-2 Cooling REC - Reactor Equipment                     2                  C-F-2 Cooling RF - Reactor Feedwater                      1                   B-J RHR - Residual Heat Removal               1, 2         B-J, C-F-2, C-A, C-B RR - Reactor Recirculation                  1                 B-F, B-J RWCU - Reactor Water Cleanup                1                   B-J SDV - Scram Discharge Volume                2                  C-F-2 SLC - Standby Liquid Control                1                 B-F, B-J (17-1)

Revision 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Frequency The inspection periods and inspection interval are defined in 3.2. The piping segments and inspection strategy (i.e., frequency, number of examinations, and examination methods) are defined in Section 5. During the Fifth 10-Year ISi Interval, CNS will implement 100% of the inspection locations selected for examination per Code Case N-716-1. Examinations shall be performed such that the period percentage requirements of ASME Section XI are met as noted in Section 5.0. All Category C-A and C-B welds are considered LSS and do not require examination. Periodic Updates As part of the implementation of this code case, in accordance with Section 7 (N-716-1) "For the 2007 Edition through the latest Edition and Addenda, examination selections made in accordance with this Case shall be reevaluated on the basis of inspection periods that coincide with the inspection program requirements of IWA-2431. For the inspection program, the third period reevaluation will serve as the subsequent inspection interval reevaluation." This is the start of a new inservice inspection interval and the first time implementing Code Case N-716-1. As the reevaluations are performed over the course of the 5th lnservice Inspection Interval this section shall be updated accordingly. A first Period re-evaluation was performed [15] and documents the periodic reevaluation of the ASME Code Case N-716-1 Risk Based program in accordance with ASME Code Case N-716-1, Section 7 requirements for Cooper Nuclear Station (CNS). This reevaluation focuses on impacts to the ASME Code Case N-716-1 program through the evaluation of changes, physical and procedural, to the plant since its last Risk Informed periodic update which addressed Sept 15, 2012 to July 9, 2015. This report addresses changes from July 9, 2015 through June 24, 2020. This review also includes PRA information contained in [Reference 15, Paragraph 6.12]. Based upon this review, core damage frequency (CDF) and large early release frequency (LERF) values for piping pressure boundary failures and for internal flooding analysis are below the criteria for consideration of high safety significant (HSS). CCDP and CLERP vaiues are summarized in Section 4.0 of Reference 15. CCDP and CLERP values did not change from the previous review. The risk assessment has been included in this report to reflect the current values. It was noted that PRA meet the PRA Technical Adequacy Requirements of Appendix II in Code Case N-716-1 at the start of the interval Section 6.10. This analysis assumes that CNS continues meets these requirements, Cooper should verify PRA Quality. No changes to component selections were required to meet the requirements of N- 716-1 as part of this review. Selection compliance is documented in Section 5.0, N- 716-1 Compliance and Appendix E [15]. (17-2) Revision 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Corrective Action Program Any corrective action required as the result of RI-ISi examinations shall be handled in accordance with CNS Corrective Action Program. lnservice Inspection Requirements The examinations shall be completed during each 10-year inspection interval with the following exceptions: a) If during the inspection interval, a reevaluation using the RI-ISi process is conducted and scheduled items are no longer required to be examined, these items may be eliminated. b) If during the inspection interval, a reevaluation using the RI-ISi process is conducted and items are required to be added to the examination program those items shall be added in accordance with IWB-2412(b) or IWC-2412(b). LSS components are exempt from volumetric, surface, and VT-1 and VT-3 Visual Examination requirements of Section XI. HSS vessels, pumps, valves, and pressure-retaining bolting shall be selected and examined in accordance with Section XI. Ten percent of the HSS piping welds shall be selected for examination. The existing plant IGSCC (Generic Letter 88-01, Categories B through G) inspection program may be credited toward the 10% requirement, provided the requirements of N716-1 are met. The existing plant flow accelerated corrosion program and localized corrosion program, excluding crevice corrosion, may not be credited toward the 10% requirement. The selection of HSS components for examination is based on Section 4 of Code Case N-716-1. Preservice Inspections For plants implementing N-716-1 after initial startup, the PSI requirements apply only to the HSS components affected by a repair/replacement activity. a) Vessels, pumps, valves, and pressure-retaining bolting require preservice inspection at least once prior to initial service. The examination voiumes, areas, techniques, and procedures shall be in accordance with the applicable requirements of Section XI. b) Piping weld examinations, with the exception of VT-2 visual examinations listed in N-716-1 Table 1, shall be performed in accordance with the requirements defined in N716 Table 1 at least once prior to initial service. Examinations shall include all piping welds, with the exception of VT-2 visual examinations listed in N-716-1 Table 1, classified as HSS in accordance with N-716-1. Successive Examinations Successive examinations shall be in accordance with Section 6 of Code Case N-716-1. (17-3) Revision 3.0

Cooper Station 5th ISi & 3rd Interval CISI Program Additional Examinations Additional examinations shall be in accordance with Section 6 of Code Case N-716-1. Examination Coverage Code Case N-716-1 provides additional requirements for examination coverage within the Notes to Table 1. If none of these Notes apply to a specific examination listed in Table 1, then examination coverage will be in accordance with ASME Section XI.

References:

1. ASME Section XI Code Case N-716-1, "Alternative Piping Classification and Examination Requirements," Approved January, 2013.

2. Cooper ISi Weld Database

3. EPRI Letter from Mr. Pat O'Regan to Mr. Steve Welp of Calvert Cliffs Nuclear Power Plant, Inc. dated February 28, 2002

4. Cooper PRA Inputs

a. ISi IE CDFs and LERFs.xslx

b. CNS PSA-012, rev 2, "Internal Flood Evaluation Summary and Notebook," February 2015.

c. CNS PSA-014, rev 2, "Quantification Notebook," October 2011.

d. CNS PSA-001, rev 2, "Initiating Events Notebook," January 2008.

e. NEDC 08-004, rev 0, "Failure Probability of Fire Protection Piping," February 2008.

f. PSA-ES086, rev 0, "Impact on CDF of Fire Protection System (FPS) Piping Critical Breaks in Control Building," April 2008.

g. PRA-ES096, rev 0, uDispositioning of CNS PRA Findings and Observations (F&Os),U February 2010.

5. EPRI TR-112657, "Revised Risk-Informed lnservice Inspection Evaluation Procedure,"

Final Report, Revision B-A, December 1999.

6. Cooper ISi Flow Diagrams 2022, rev N78, "Primary Containment" 2026 Sht 1, rev N64, "Nuclear Boiler Instrumentation" 2027 Sht 1, rev N69, "Reactor Recirculation" 2027 Sht 2, rev N13, "Reactor Recirculation" 2040 Sht 1, rev N82, "Residual Heat Removal" 2040 Sht 2, rev N18, "Residual Heat Removal" 2041, rev N85, "Residual Heat Removal" 2042 Sht 1, rev N34, "Nuclear Boiler Drain" (17-4)

Revision 3.0

Cooper Station 5th ISi & 3 rd Interval CISI Program 2043, rev N54, {/Reactor Feedwater/Main Steam/Reactor Core Isolation Cooling 11 2044, rev N72, {/Reactor Feedwater/Main Steam/Reactor Core Isolation Cooling11 2045 Sht 1, rev N58, {/Core Spray11 2045 Sht 2, rev N21, {/Standby Liquid Control 11

7. Cooper Isometric Drawings 232-242, Rev 7, 11 Nuclear Boiler11 232-244, Rev 2, {/Nuclear Boiler11 73E611 Sheet 4, Rev N02, {/Main Steam 11 2501-1, Rev N14, "Core Spray11 2502-1, Rev N07, "Core Spray11 2503-1, Rev N13, "Reactor Water Cleanup11 2506-1, Rev N07, "Main Steam 11 2506-2, Rev N04, "Main Steam 11 2506-3, Rev Nll, "Main Steam Drains 11 2509-1, Rev N19, "Reactor Feedwater11 2509-2, Rev N13, "Reactor Feedwater11 2510-1, Rev N09, "Residual Heat Removal 11 2510-3, Rev N09, "Residual Heat Removal 11 2510-4, Rev N09, "Residual Heat Removal 11 2512-1, Rev NOS, "Reactor Recirculation 11 20977-H, Rev NOS, {/Reactor Feedwater11 21026-H, Rev N02, "Residual Heat Removal 11 CB&I 20, Rev 10, "Nuclear Boiler lnstrumentation 11 CNS-CS-3, Rev N02, "Core Spray11 CNS-CS-4, Rev N02, "Core Spray" CNS-RR-37, Rev N04, {/Reactor Recirculation" CNS-RR-38, Rev N03, {/Reactor Recirculation 11 X-2501-201, Rev NOO, "Core Spray" X-2503-200, Rev NOl, "Reactor Water Cleanup 11 X-2504-200, Rev N04, "Standby Liquid Controi" X-2504-201, Rev N02, "Standby Liquid Control 11 X-2507-218, Rev Nll, {/Nuclear Boiler lnstrumentation 11 X-2507-219, Rev N07, {/Nuclear Boiler lnstrumentation 11 X-2510-200, Rev N03, "Residual Heat Removal 11 X-2510-202, Rev N06, "Residual Heat Removal 11 X-2510-203, Rev N02, "Residual Heat Removal 11 X-2510-204, Rev N08, {/Residual Heat Removal 11 X-2512-200, Rev N04, {/Nuclear Boiler Drains 11 X-2512-201, Rev NOS, {/Reactor Recirculation" X-2512-300, Rev N04, "Reactor Recirculation 11

8. Structural Integrity Calculation No. 1401334.301, {/Degradation Mechanism Evaluation for Cooper, 11 Revision 0.

(17-5) Revision 3.0

Cooper Station 5th ISi & 3 rd Interval CISI Program

9. IDDEAL Solutions Report, "Cooper Nuclear Station History Review, Supporting Implementation of Code Case N-716-1 11 , dated July 16, 2015.

10. EPRI Report 1021467, "Nondestructive Evaluation: Probabilistic Risk Assessment Technical Adequacy Guidance for Risk-Informed In-Service Inspection Programs."

11. Regulatory Guide 1.200, Rev 2 11An Approach For Determining The Technical Adequacy Of Probabilistic Risk Assessment Results For Risk-Informed Activities."

12. Regulatory Guide 1.174, Rev 1 11 An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis."

13. NUREG/CR-6928, 11 lndustry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants," February 2007.

13. IDDEAL Solutions Report, "Cooper Nuclear Station Code Case N-716-1 Application" dated 8/10/2015.

14. IDDEAL Solutions Report, "Final Version for N716 Database 070315", Excel report

15. IDDEAL Solutions Report, Fifth Interval First Periodic Update of the Code Case N-716-1 Application, Rev 1, dated 8/26/2020.

(17-6) Revision 3.0

Cooper Station 5th ISi & 3 rd Interval CISI Program 18.0 Commitment Management Ongoing re_gulatory and internal CNS commitments applicable to the ISi Program are incorporated into program documents and plant processes where appropriate. Ongoing regulatory commitments are those made to the NRC and recorded in the CNS Regulatory Commitment Tracking System (RCTS} per AP 0.42.1. These commitments are identified and annotated in CNS documents and procedures as required by APs 0.42.1. See the table below for a list of the ISi Program ongoing regulatory commitments. Source Commitment Implementation GL 86-01 Inspect Scram Discharge Volume {SDV} as Class 2. 6.MISC.502/ 6.MISC.504 (10 year) NUREG 0619 Inspect Feedwater {FW} Nozzles., safe ends., etc. Augmented ISi Program, Section 11. GL 88-01 subsumed Inspect stainless steel piping. Subsumed by Rl-34 and CNS ISi Program 5th Interval BWRVIP-75-A and Risk- BWRVIP-75-A. addresses BWRVIP-75-A stainless Informed ISi (CAT R-A) steel welds per Code Case N-716-1 as scheduled in Section 5. NLS2008071-12 Enhance the lnservice Inspection - IWF Program to Implemented in 4th Interval. Class include Class MC piping and component supports. MC supports included in 5th Enhance the Program to clarify that the successive Interval. See Section 5 for schedule inspection requirements of IWF-2420 and the of examinations. Reference LO-additional examination requirements of IWF-2430 2008-0263-019. Closed by NRC in IR will be applied. [LRA Section B.1.20} 2013-008. N LS2010044-01 During the period of extended operation., NPPD will See Section 5 for schedule of perform periodic volumetric examinations of Class 1 examinations. Reference LO-2013-socket weld connections. Three Class 1 socket welds 0519-003. will receive volumetric examination during each 10 Year ISi interval. The examination method will be a volumetric examination of the base metal 1/2" beyond the toe of the socket fillet weld which wallows for the use of qualified ultrasonic examination techniques as close as possible to the fillet weld. The volumetric examinations will be performed by certified examiners following guidelines set forth in ASME Section V., Article 4 {18-1) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program consistent with the guidelines for examination volume of 1/2" beyond the toe of the weld as established in MRP-146, "Materials Reliability Program: Management of Thermal Fatigue in normally stagnant non-isolable reactor coolant system branch lines. NLS2008071-05 Enhance the Containment /nservice Inspection IWE-3511.3 was revised to .IWE-(Reference LO-2010- Program to add examination of required accessible 3522 in the 2007 Edition, 2008 00259-010) areas using a visual examination method and Addenda which states: Examinations of Class MC pressure-surface areas not accessible on the side requiring retaining components augmented examination to be examined using an and of metallic shell and ultrasonic thickness measurement method in penetration liners of Class CC accordance with IWE-2500(b). Enhance the program pressure-retaining components that to document material loss in a local area exceeding detect material loss in a local area 10% of the minimum containment wall thickness or exceeding 10% of the nominal wall material loss in a local area projected to exceed 10% thickness, or material loss in a local area projected to exceed 10% of the of the nominal containment wall thickness before nominal wall thickness prior to the the next examination in a accordance with /WE- next examination, shall be 3511.3 for volumetric inspections. [LRA Section documented. Such local areas shall 81.10] - Commitment updated in NLS2009040 be accepted by engineering added: To ensure the (drywell sand cushion drain) evaluation or corrected by repair I lines are obstruction free, a vacuum test of all eight replacement activities in sand bed drain lines will be performed prior to the accordance with IWE-3122. Supplemental examinations in period of extended operation (PEO). (RAJ 81.10-1). accordance with IWE-3200 shall be performed when specified as a result of the engineering evaluation. CNS will follow the Code requirements which meet the intent of this Commitment. N LS2010050-03 NPPD will complete an analysis following each Torus LO-. Results of the periodic inspection, including the supplemental ultrasonic evaluation will justify operation to examinations performed every outage on test next inspection. evaluation areas, that demonstrates that the projected pitting of the Torus up to the next inspection interval will not result in reduction of Torus wall thickness below minimum acceptable values. ***Commitment revised on 6/14/2018*** NLS2010050-02 NPPD will removed sludge and visually inspect the Section 5 of the ISI/CISI Program wetted portion of the Torus every other refueling contain the schedule of outage from RE29 {2016} until the end of the period examinations. "The CNS Fifth ISi of extended operation. In addition, CNS will perform and Third Interval CISI Component ultrasonic examinations of test evaluation areas Listing" contains a detailed (18-2) Revision 1

Cooper Station 5th ISi & 3 rd Interval CISI Program every outage as a supplement to the visual schedule by outage. inspections performed every other outage.

                         ***Commitment revised on 6/14/2018***

LO-2013-0519-001 Implement changes to the 5th 10-Year ISi Program CNS ASME Class 1 system leakage (Reference B.130 Aging to ensure the ASME Section XI Class 1 pressure test test performed each outage under Management Program} procedure conducted each outage includes visual 6.MISC.502 (6.MISC.504 end of examinations (VT-2) on Class I socket weld fittings to Interval} include all Class 1 monitor for aging degradation issues as a condition boundaries for performance of VT-2 of License Renewal. The VT-2 examinations will be examinations including small bore performed by certified examiners using ASME socket weld locations within this Section XI approved visual inspection procedures boundary. consistent with ASME Section XI. NLS2018029-01 The use of Relief Request RRS-03 is limited to a flaw RRS-03 is provided in Section 7.0 of size resulting in a leak rate of no more than 5 gallons this document. per minute. Ongoing CNS Internal Commitments Ongoing internal commitments result from CNS Corrective Action Program (CAP) activities, audits, surveillances, self-assessments, and selected operating experience documents. These commitments are identified and annotated in CNS procedures. Commitments implemented by other program related documents are identified and incorporated by reference in that document. (18-3) Revision 1

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                            & 3 Interval GISI Program Figure 19 - Torus Interior Pitting Locations (See Torus Identified Internal Pitting table and Internal Pit Examination Record for details) f tit DMlrGtl q,--.

z --- ft

• f~

                                                                  .. 2.

ADJ

• 0-CLICK TQVIEW DETAILED PITDATA PIT (,ONCE_

Nl:AAPENET PIT CONCENTRATtONS OR

• SINGLE.PITS-ON GEN SHEU. OR. NEAR RG (19-1) 1evision 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                            & 3 Interval GISI Program Torus Identified Internal Pitting 3-P1-1       N/A     2    0.050  s 9"RG      In   45.25"IW     NearRG              3/2RG 3-P1-2       N/A    2     0.055  s 3.5"RG    In   44.5"IW      Near RG            3/2RG                                  2001 3  1  3-P1-3       NIA    2     0.061  s 11.25"RG  In   52.5"IW      Near RG            3/2RG                                  2001 3  2  3-P2-10      N/A     1    0.020  s 220       Deg  22.5         RHR-A       X-225A                                        2001 3 2   3-P2-11      N/A     1    0.050 D  218       DeQ 29        YES RHR-A       X-225A CNS PIR S/N 4-14626                    2001 3 2   3-P2-12      NIA     1    0.047 D  328       DeQ 31.5      YES RHR-A       X-225A CNS PIR SIN 4-14626                    2001 3 2   3-P2-13      NIA    1     0.012  s 220       Deg 28            RHR-A       X-225A                                        2001 3 2   3-P2-14      N/A    1     0.016 s  215       DeQ 27.5          RHR-A       X-225A                                        2001 3 2   3-P2-15      NIA     1    0.009 s  315       Deg 14.5          RHR-A       X-225A                                        2001 3 2   3-P2-16      NIA    1     0.024 S  265       Deg 13            RHR-A       X-225A                                        2001 3 2   3-P2-17      NIA    1     0.002 s  260       DeQ 11.25         RHR-A       X-225A                                        2001 3 2   3-P2-18      NIA    1     0.019 s  255       DeQ 9.5           RHR-A       X-225A                                        2001 3 2   3-P2-19      NIA    1     0.040 D  210       Deg 11.38     YES RHR-A       X-225A CNS PIR SIN 4-14626                    2001 3 2   3-P2-20      NIA    1     0.032 D  260       Dea 30.5      YES RHR-A       X-225A CNS PIR S/N4-14626                     2001 3 2   3-P2-21      NIA    1     0.037 D  265       DeQ 31.5      YES RHR-A       X-225A CNS PIR SIN 4-14626                    2001 3 2   3-P2-22      NIA    1     0.039 D  210       Deq 18        YES RHR-A       X-225A CNS PIR SIN 4-14626                    2001 3 2   3-P2-23      N/A    1     0.011 s  210       Dea 14            RHR-A       X-225A                                        2001 3 2   3-P2-24      SM     1     0.007 s  205       Dea 22.5          RHR-A       X-225A

• 3 PITS 3 2001 3 2 3-P2-25 SM 1 0.032 D 210 Deg 39 YES RHR-A X-225A : 2 PITS CNS P!R SIN 4-14626 2 2001 3 2 3-P2-26 NIA 1 0.029 S 302 Dea 38 RHR-A X-225A 2001 3 2 3-P2-27 NIA 1 0.008 s 299 DeQ 26 RHR-A X-225A 2001 3 2 3-P2-28 NIA 1 0.038 D 273 Deg 19 YES RHR-A X-225A CNS PIR SIN 4-14626 2001 3 2 3-P2-29 SM 1 0.016 S 279 Dea 37 RHR-A X-225A *3PITS 3 2001 3 2 3-P2-30 NIA 1 0.021 s 279 Dea 37.5 RHR-A X-225A 2001 3 2 3-P2-4 NIA 1 0.028 S 300 Deq 29.5 RHR-A X-225A 2001 3 2 3-P2-5 NIA 1 0.005 S 330 Deq 26 RHR-A X-225A 2001 3 2 3-P2-6 NIA 1 0.017 S 300 Dea 24 RHR-A X-225A 2001 3 2 3-P2-7 NIA 1 0.046 D 285 Dea 19 YES RHR-A X-225A CNS PIR SIN 4-14626 2001 3 2 3-P2-8 NIA 1 0.030 D 270 Deq 18 YES RHR-A X-225A CNS PIR SIN 4-14626 2001 3 2 3-P2-9 NIA 1 0.012 S 270 Deq 37 RHR-A X-225A 2001 4 2 4-P2-1 NIA 1 0.022 s 170 Deg 14 Torus Drain X-213A 2001 4 2 4-P2-2 NIA 1 0.027 s 150 Deg 13.75 Torus Drain X-213A 2001 4 2 4-P2-3 NIA 1 0.013 s 180 Deg 24 Torus Drain X-213A 2001 4 2 4-P2-4 SM 1 0.026 s 160 Deg 18 Torus Drain X-213A ; GROUP OF 2 2 2001 4 2 4-P2-5 NIA 1 0.029 s 160 Deg 2 Torus Drain X-213A 2001 4 2 4-P2-6 NIA 1 0.018 s 105 Deg 2.5 Torus Drain X-213A 2001 4 4 4-P4-1 NIA 1 0.033 D 160 Deg 9 YES Torus Drain X-213A CNS PIR SIN 4-14626 2001 4 4 4-P4-2 NIA 1 0.045 D 160 Deg 21.5 YES Torus Drain X-213A CNS PIR SIN 4-14626 2001 (19-2) Rr '~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                             & 3rd Interval GISI Program Torus Identified Internal Pitting 4  4  4-P4-3       SM      1    0.034  D 105 Deg   28    YES Torus Drain X-213A  ; GROUP OF 2 CNS     PIR SIN 4-14626      2     2001 6  1  6-P1-1       N/A     1    0.018  s 19  Deg   14        RCIC        X-224                                                   2001 6  1  6-P1-10      NIA    1     0.052  D 116 Deg   12.5  YES RCIC        X-224    CNS PIR SIN 4-14626                            2001 6  1  6-P1-11      SM     1     0.018  s 121 Deg   12.5      RCIC        X-224                                             2     2001 6  1  6-P1-12      N/A     1    0.022  s 126 Deg   10.25     RCIC        X-224   ; 2 PITS, 1 3/8" dia                            2001 6  1  6-P1-13      NIA     1    0.025  s 126 Deg   24        RCIC        X-224                                                   2001 6  1  6-P1-14      NIA    1     0.023  s 121 Deg   25        RCIC        X-224                                                   2001 6  1  6-P1-15      NIA    1     0.023  $ 131 Deg   20        RCIC        X-224                                                   2001 6  1  6-P1-16      SM     1     0.028  s 131 Deg   14.5      RCIC        x~224  ; 2 PITS, 2.50" dia                        2     2001 6  1  6~P1-17      NIA    1     0.011  s 97  Deg   24        RCIC        X-224                                                   2001 6  1  6-P1-18      SM     1     0.010  s 102 DeQ   22.5  YES RCIC        X-224  ; 3 PITS, 2.50" dia CNS PIR S/N 4-14626    3     2001 6  1  6-P1-19      SM     1     0.008  s 102 Deg   24.5      RCIC        X-224                                             1     2001 6  1  6-P1-2       NIA    1     0.031  D 39  Deg   13    YES RCIC        X-224  CNS PIR SIN 4-14626                              2001 6  1  6-P1-20      SM     1     0.019  s 107 08{:l 23.25     RCIC        X-224   ; 5 PITS, 2.25" dia                       5     2001 6  1  6-P1-21      SM     1     0.013  s 107 Deg   25.25     RCIC        X-224  ; 5 PITS, 2.50" dia                        5     2001 6  1  6-P1-22      SM     1     0.021  s 107 Deg   26.5      RCIC        X-224  ; 4 PITS,2.50" dia                         4     2001 6  1  6-P1-23      SM     1     0.034  D 107 Deg   29.25 YES RCIC        X-224  ; 5 PITS, 1.50" dia CNS P!R SIN 4-14626    5     2001 6  1  6-P1-24      SM     1     0.019  s 107 Deg   31        RCIC        X-224  ; 6 PITS, 2.50" dia                        6     2001 6  1  6-P1-25      SM     1     0.008  s 111 Deg   14        RCIC        X-224  ; 4 PITS,2.50" dia                         4     2001 6  1  6-P1-26      SM     1     0.023  s 111 Deg   17        RCIC        X-224  ; 5 PITS, 2.50" dia                        5     2001 6  1  6-P1-27      SM     1     0.009  s 111 Deg   19.5      RCIC        X-224  ; 4 PITS,2.50" dla                         4     2001 6  1  6-P1-28     SM      1     0.019  s 111 Deg   22        RCIC        X-224  ; 8 PITS, 2.50" dia                        8     2001 6  1  6-P1-29      SM     1     0.Q17  s 111 De{:! 26.5      RCIC        X-224  ; 2 PITS, 1.25" dia                        2     2001 6  1  6-P1-3       SM     1     O.o15  s 68  Deg   28.5      RCIC        X-224  ; 3 PITS, 1.25" dia                        3     2001 6  1  6-P1-30      SM     1     0.014  s 111 Deg   30        RCIC        X-224  ; 4 PITS,2.50 dia                        4     2001 6 1   6-P1-31     SM      1     0.016  s 111 Deg   32.5      RCIC        X-224  ; 5 PITS, 2.50" dia                        5     2001 6 1   6-P1-32      NIA    1     0.011  s 116 Deg   13        RCIC        X-224                                                   2001 6  1  6-P1-33      NIA    1     0.009  s 116 Deg   14.5      RCIC        X-224                                                   2001 6  1  6-P1-34      N/A    1     0.011  s 116 Deg   16.5      RCIC        X-224                                                   2001 6 1   6-P1-35     SM      1     0.007  s 116 Deg   18.75     RCIC        X-224  ; 7 PITS, 2.50" dia                        7     2001 6 1   6-P1-36     SM      1     0.016  s 116 Deg   20.75     RCIC        X-224  ; 4 PITS, 1.50" dia                        4     2001 6 1   6-P1-37     SM      1     0.022  s 116 Deg   22.5      RCIC        X-224  ; 2 PITS, 1.50" dla                        3     2001 6 1   6-P1-38      SM     1     0.008  s 116 Deg   25        RCIC        X-224  ; 4 PITS,2.50" dia                         4     2001 6 1   6-P1-39     SM      1     0.014  s 116 Deg   28.5      RCIC        X-224  ; 5 PITS, 2.50" dia                        5     2001 6 1   6-P1-4      SM      1     0.020  s 68  Deg   28.5      RCIC        X-224  ; 4 PITS, 1.75" dla                        4     2001 6 1   6-P1-40     SM      1     0.010  s 126 Deg   26        RCIC        X-224  : 2 PITS, 1.50" dla                        2     2001 6 1  6-P1-41      SM      1     0.011  s 126 Deg   28        RCIC        X-224  ; 3 PITS, 2.50" dia                        3     2001 6 1  6-P1-42      SM      1     0.021  s 126 Deg   31.5      RCIC        X-224  ; 4 PITS,2.50" dia                         4     2001 6 1  6-P1-43      SM      1     0.010  s 136 Deg   23        RCIC        X-224  ; 7 PITS, 2.50" dia                        7     2001 (19-3)                                                                                           p  *~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                  & 3 rd Interval GISI Program Torus Identified Internal Pitting 6  1  6-P1-44      SM     1     0.027  s 136 Deg   25.5      RCIC X-224   ; 4 PITS,2.50" dia                    4      2001 6  1  6-P1-45      SM      1    0.018  s 136 Deg   27.25     RCIC X-224   ; 7 PITS, 2.50" dia                   7      2001 6  1  6-P1-46      N/A     1    0.016  s 136 Deg   32.5      RCIC X-224                                                2001 6  1  6-P1-47      N/A    1     0.019  s 145 Deg   16.5      RCIC X-224                                                2001 6  1  6-P1-48      SM      1    0.014  s 145 Deo   21        RCIC X-224   ; 6 PITS, 2.50" dia                   6      2001 6  1  6-P1-49      SM     1     0.018  s 145 Deg   28.5      RCIC X-224   ; 8 PITS, 2.125" dia                  8      2001 6  1  6-P1-5       NIA    1     0.020  s 73  Deg   36.75     RCIC X-224                                                2001 6  1  6-P1-50      NIA    1     NIA    s 179 Deg   14.5      RCIC X-224   ; 16 GROUPS, 3 PER, EACH 2.50" dia    48     2001 6  1  6-P1-51      NIA    1     NIA    s 262 Deg   13.5      RCIC X-224   ; 16 GROUPS, 3 PER, EACH 2.5011dia    48     2001 6  1  6-P1-52      NIA     1    NIA    s 358 Deg   10        RCIC X-224   ; 15 GROUPS, 3 PER, EACH 2.50" dla    45     2001 6  1  6-P1-6       NIA    1     0.023  s 87  Deg   27        RCIC X-224                                                2001 6  1  6-P1-7       NIA    1     0.038  D 116 Deg   22.75 YES RCIC X-224   CNS PIR      SIN 4-14626                     2001 6  1  6-P1-8       SM     1     0.025  s 111 Deg   24        RCIC X-224   ; 4 PITS,2.25u dla                    4      2001 6  1  6-P1-9       NIA    1     0.041  D 116 Deg   3.75  YES RCIC X-224     CNS PIR SIN 4-14626                        2001 7  1  7-P1-10      NIA    1     NIA    s 47  Deg   16        CS-A X-227A                                        1      2001 7  1  7-P1-11      NIA    1     NIA    s 105 Deg   16        CS-A X-227A                                        1      2001 7  1  7-P1-12      N/A    1     N/A    s 163 Deg   16        CS-A X-227A                                        1      2001 7  1  7-P1-13      NIA    1     NIA    s 131 Deg   16        CS-A X-227A                                        1      2001 7  1  7-P1-14      NIA    1     N/A    s 54  Deg   17        CS-A X-227A                                        1      2001 7  1  7-P1-15      SM     1     0.036  D 98  Deg   17.5  YES CS-A X-227A  ; 2 PITS CNS PIR SIN 4-14626          2      2001 7  1  7-P1-16      NIA    1     0.031  D 149 Deg   17.5  YES CS-A X-227A  CNS PIR SIN 4-14626                          2001 7  1  7-P1-17      NIA    1     NIA    s 198 Deg   17.5      CS-A X-227A                                        1      2001 7  1  7-P1-18      N/A    1     0.045  D 240 Deg   17.5  YES CS-A X-227A  CNS PIR S/N 4-14626                          2001 7  1  7-P1-19      SM     1     0.026  s 105 Deg   18        CS-A X-227A  ; 2PITS                               2      2001 7  1  7-P1-2       SM     1     NIA    s 22  Dea   9         CS-A X-227A  ; 4 GROUPS, 3 PER, 2-1f2" dia         12     2001 7  1  7-P1-20      NIA    1     0.030  D 131 Deg   18    YES CS-A X-227A  CNS PIR      SIN 4-14626                     2001 7  1  7-P1-21      NIA    1     N/A    s 133 Deg   18.5      CS-A X-227A                                        1      2001 7  1  7-P1-22      SM     1     NIA    s 62  Dea   18.5      CS-A X,227A  ;2PITS                                2      2001 7  1  7-P1-23      SM     1     NIA    s 105 Deg   18.5      CSA  X-227A  ; 4 GROUPS, 2-1{2" dfa.               16     2001 7  1  7-P1-24      NIA    1     N/A    s 174 Deg   18.5      CSA  X-227A                                        1      2001 7  1  7-P1-25      SM     1     NIA    s 218 Dea   18.5      CS-A X-227A  ;2PITS                                2      2001 7  1  7-P1-26      SM     1     NIA    s 160 Dea   19        CS-A X-227A  ; 3 GROUPS, 3 PITS PER                9      2001 7  1  7-P1-27      N/A    1     N/A    s 196 Deg   19        CS-A X-22.7A                                       1      2001 7  1  7-P1-28      SM     1     NIA    s 232 Dea   19        CS-A X-227A  ; 2PITS                               2      2001 7  1  7-P1-29      NIA    1     NIA    s 25  Deg   20.5      CS-A X-227A                                        1      2001 7  1  7-P1-3       NIA    1     0.032  D 243 Deg   1.25  YES CS-A X-227A  CNS PIR SIN 4-14626                          2001 7  1  7-P1-30      NIA    1     NIA    s 116 Deg   20.5      CS-A X-227A                                        1      2001 7  1  7-P1-31      SM     1     NIA    s 149 Deg   20.5      CS-A X-227A  ; 2PITS                               2      2001 7  1  7-P1-32      SM     1     NIA    s 211 Deg   20.5      CS-A X-227A  ; 20 GROUPS, 2 PITS PER               40     2001 (19-4)                                                                                 R* '~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                        & 3 Interval CISI Program Torus Identified Internal Pitting 7  1  7-P1-33      NIA     1    NIA    s 98    Deg    21         CS-A         X-227A                                                  1     2001 7  1  7-P1-34      SM      1    NIA    s 131   De!'.! 21         CS-A         X-227A   ; 4PITS                                        4     2001 7  1  7~P1-35      SM      1    NIA    s 160   DeQ    21.5       CS-A         X-227A   ; 2PITS                                        2     2001 7  1  7-P1-36      SM      1    NIA    s 182   Deg    29         CS-A         X-227A   ; 3 GROUPS, 3 PITS PER                         9     2001 7  1  7-P1-37      N/A     1    0.048  D 185   Deg    18    YES CS-A          X-227A   CNS PIR S/N 4-14626                                  2001 7  1  7-P1-38      NIA     1    0.042  D 182   Deg    19    YES CS-A          X-227A   CNSPIR SIN 4-14626                                   2001 7  1  7-P1-39      NIA    1     NIA    s 189   Deg    21         CS-A         X-227A                                                  1     2001 7  1  7-P1-4       NIA    1     NIA    s 225   Deg    3          CS-A         X~227A                                                  1     2001 7  1  7-P1-40      SM     1     NIA    s 196   Deg    24         CS-A         X.227A  ; 4 GROUPS, 9 PITS                              9     2001 7  1  7-P1-41      NIA     1    NIA    s 185   Deg    14         CS-A         X-227A   ; 2 GROUPS, 7 PITS                             7     2001 7  1  7-P1-42      SM     1     NIA    s 218   Deg    21         CS-A         X-227A  ; 2 GROUPS, 9 PITS                              9     2001 7  1  7-P1-43      NIA    1     N/A    s 225   Deg    8          CS-A         X-227A                                                  1     2001 7  1  7-P1-44      NIA    1     0.038  D 232   Deg    15    YES CS-A          X-227A  CNS PIR      SIN 4-14626                              2001 7  1  7-P1-45      SM     1     N/A    s 262   Deg    15         CS-A         X-227A  ; 6 GROUPS, 23 PITS                             23    2001 7  1  7-P1-46      NIA     1    0.049  D 254   Deg    22.5  YES CS-A          X-227A  CNS PIR SIN 4-14626                                   2001 7  1  7-P1-47      SM     1     NIA    s 254   Deg    28         CS-A         X-227A  ; 2 GROUPS, 2 PER, 2-1/2" dia                   4     2001 7  1  7-P1-48      NIA    1     0.036  D 254   Deg    26;25 YES CS-A          X-227A  CNSPIR S/N 4-14626                                    2001 7  1  7-P1-49      NIA    1     0.039  D 258   Deg    29    YES CS-A          X-227A CNS PlR SIN 4-14626                                    2001 7  1  7-P1-5       NIA    1     0.047  D 225   Deg    7     YES CS-A          X.227A CNS PlR SIN 4-14626                                    2001 7  1  7-P1-50      SM     1     NIA    s 218   Deg    30         CS-A         X-227A  ; 23 GROUPS, 63 PITS (approx)                   63    2001 7  1  7-P1-6       SM     1     NIA    s 89    Deg    7.25       CS-A         X-227A  ; 2PITS                                         2     2001 7  1  7-P1-7       SM     1     NIA    s 73    Deg    9          CS-A         X-227A  ;2PITS                                          2     2001 7  1 7-P1-8        SM     1     NIA    s 232   Deg    13.5       CS-A         X-227A  ; 2 GROUPS, 2 PER, 2-112" dia                   4     2001 7  1  7-P1-9       SM     1     N/A    s 80    Deg    14         CS-A         X-227A  ;4PITS                                          4     2001 7  5  7-P5-1       NIA    2     0.056  D 3"RG   In    47"1W YES NearRG                CNS PIR      SIN 4-14626                              2001 8  4  8-P4-1       NIA    1     0.027  s 0     Deg    5.5        Temp. Monit X-300-G  X-300-G                                               2001 8  4  8-P4-2       NIA    1     0.034  D 0     Deg    4.5   YES Temp. Monit. X-300-H  X-300-H    CNS PIR SIN 4-14626                        2001 8  4  8-P4-3       NIA    1     0.017  s 290   Deg    5.25       Temp. Monit. X-300-H X-300-H                                               2001 9  3  9-P3-1       NIA    2     0.062  D 10"RG In     31"1W YES Near RG               CNS PlR SIN 4-14626                                   2001 11 1  11-P1-1      NIA    2     0.052  D 10"RG  In    37"1W YES Near RG               CNS PlR S/N 4-14626                                   2001 11 3  11-P3-1      NIA    1     0.028  s 196   Deg    23         CS-B         X227B                                                         2001 11 3  11-P3-10     SM     1     0.038  D 218   DeQ    29    YES, CS-B         X227B   CNSPIR SIN 4-14626                              2     2001 11 3  11-P3-11     SM     1     0.044  D 211   Deg    34    YES CS-B          X2278     ; 2 PITS CNS PIR SIN 4-14626                  2     2001 11 3  11-P3-12     SM     1     0.028  s 222   DeQ    33.5       CS-8         X2278   ; 3 PITS                                        3     2001 11 3  11-P3-13     SM     1     0.034  D 222   Deg    34    YES CS-8          X227B   : 4 PITS   CNS PIR SIN 4-14626                  4     2001 11 3  11-P3-14     SM     1     0.051  D 232   Deg    33    YES CS-B          X227B   ; 3 PITS CNSPIR SIN 4-14626                     3     2001 11 3  11-P3-15     SM     1     0.042  D 240   DeQ    33.5  YES CS-B          X227B     ; 2 PITS CNS PIR S/N 4-14626                  2     2001 11 3  11-P3-16     SM     1     0.045  D 225   Deg    29.5  YES CS-B          X2278   ; 5 PITS CNS PIR SIN 4-14626                    5     2001 11 3  11-P3-17     SM     1     0.043  D 231   Deg    26.5  YES CS-B          X227B   ; 2 PITS; 1.63 to P3-21 CNS P!RSIN 4-14628    2     2001 (19-5)                                                                                                  p   *,ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                        & 3 Interval GISI Program Torus Identified Internal Pitting 11 3  11-P3-18     SM      1    0.041  D 232    Deg    14    YES CS-B        X2278     3 PITS CNS PIR SIN 4-14626                    3     2001 11 3  11-PS.19     SM      1    0.014  s 243    Deg    14        CS-B        X227B     4PITS                                         4     2001 11 3  11-P3-2      SM      1    0.022  s 207    Deg    20        CS-B        X2278     4PITS                                         4     2001 11 3  11-P3-20     SM      1    0.030  D 247    Deg    15.5  YES CS-8        X227B  ; 4 PITS  CNS PIR SIN 4-14626                    4     2001 11 3  11-P3-21     SM      1    0.035  D 232    Deg    25    YES CS-B        X227B  ; 2 PITS* 1.63" to P3-17 CNS PIR SIN 4-14626     2     2001 11  3  11-P3-22     SM      1    0.044  D 240    Deg    27    YES CS-8        X2278  ; 6 PITS CNS PIR SIN 4-14626                     6     2001 11  3  11-P3-23     SM     1     0.036  D 240    Deg    30    YES CS-8        X227B  ; 3 PITS CNS PIR SIN 4-14626                     3     2001 11  3  11-P3-24     SM     1     0.032  D 251    Deg    30    YES CS-B        X227B  ; 4 PITS CNS PIR S/N 4-14626                     4     2001 11  3  11-P3-25     SM     1     0.031  D 254    Deg    27    YES CS-B        X227B  ; 5 PITS CNS PlR SIN 4-14626                     5     2001 11  3  11-P3-26     SM      1    0.036  D 251    Deg    23.5  YES CS-B        X227B  ; 3 PITS CNS PIR SIN 4-14626                     3     2001 11  3  11-P3-27     SM     1     0.048  D 276    Deg    30    YES CS-8        X2278    ; 2 PITS CNS PIR SIN 4-14626                   2     2001 11  3  11-PS.28     SM     1     0.045  D 272    Deg    26    YES CS-B        X2278  ; 2 PITS; 1.94" to P3-30 CNS PIR SIN 4-14626     2     2001 11  3  11-P3-29     SM     1     0.041  D 272    Deg    22    YES CS-B        X2278  ; 2 PITS; 1.94" to P3-30 CNS PlR. SIN 4-14628    2     2001 11  3  11-P3-3      NIA    1     0.023  s 207    Deg    23.5      CS-8        X2278                                                         2001
                                                                                        ; 2 PITS; 1.94" to P3-28 & 29 CNS PIR SIN 4-11  3  11-P3-30     SM     1     0.038  D 272    Deg    24.5  YES CS-B        X2278                                                   2     2001 14626 11  3  11-PS.31     NIA    1     0.037  D 291    Deg    8     YES CS-8        X2278  CNS PIR SIN 4-14626                                    2001 11  3  11-P3-32     NIA    1     0.047  D 305    Deg    8.5   YES CS-8        X227B  CNS PIR SIN4-14626                                     2001 11  3  11-P3-33     SM     1     0.043  D 316    Deg    8     YES CS-B        X2278

• 2 PITS CNS PIR SIN 4-14626 2 2001 11 3 11-P3-34 NIA 1 0.045 D 320 Deg 12 YES CS-B X2278 CNS PIR SIN 4~14626 2001 11 3 11-P3-35 NIA 1 0.035 D 323 Deg 34 YES CS-8 X227B CNSPIR S/N4-14626 2001 11 3 11-P3-36 NIA 1 0.033 D 327 Deg 14.5 YES CS-B X227B CNS PIR SIN 4-14626 2001 11 3 11-P3-37 NIA 1 0.015 s 341 Dei::i 12 CS-B X227B  ; 3 PITS 2001 11 3 11-P3-38 NIA 1 0.036 D 352 Deg 14.5 YES CS-B X2278  ; 2 PITS CNS PIR SIN 4-14626 2001 11 3 11-P3-39 NIA 1 0.035 D 360 Deg 11 YES CS-B X2278  ; 2 PITS GNS PlR SIN 4-14626 2001 11 3 11-P3-4 SM 1 0.018 s 202 Dea . 15.5 CS-B X22-7B ; 3 PITS 3 2001 11 3 11-P3-5 NIA 1 0.019 s 214 Deg 15.75 CS-B X227B 2001 11 3 11-P3-6 SM 1 0.036 D 214 Dea 18 YES CS-B X227B  ; 3 PITS CNS PIR S/N 4-14626 3 2001 11 3 11-P3-7 SM 1 0.024 s 214 Deg 21 CS-B X227B ;3PITS 3 2001 11 3 11-P3-8 SM 1 0.034 D 218 Deg 22 YES CS-B X2278  ; 3 PITS CNS PIR SIN 4-14626 3 2001 11 3 11-P3-9 SM 1 0.024 s 218 Deg 26 CS-8 X2278 ;2PITS 2 2001 12 2 12-P2-1 NIA 1 0.014 s 300 Deg 12 Torus Drain X-213B 2001 12 2 12-P2-2 NIA 1 0.006 s 330 Deg 14.5 Torus Drain X-2138 2001 12 2 12-P2-3 NIA 1 0.021 s 30 Deg 8.5 Torus Drain X-213B 2001 12 2 12-P2-4 NIA 1 0.019 s 120 Deg 12.5 Torus Drain X-2138 2001 12 2 12-P2-5 NIA 1 0.049 D 60 Deg 20.5 YES Torus Drain X-213B CNS PIR SIN 4-14626 2001 12 2 12-P2-6 SM 1 NIA s 90-270 Deg 33 Torus Drain X-213B 20 2001 14 2 14-P2-1 SM 1 0.024 s 0 Deg 33 HPCI X-226  ; 4 PITS, 2.40" DIA. 4 2001 14 2 14-P2-2 NIA 1 0.023 s 279 Deg 32 HPCI X-226 2001 (19-6) Rr *"\ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                               & 3 rd Interval GISI Program Torus Identified Internal Pitting m

14 14 4 4 2 2 2 2 1.d

• 14-P2-4 14-P2-5 14-P2-6 14-P2-7 ISM NIA N/A NIA SM j1 1

1 1 1 I0.036 0.009 0.039 0.042 0.035

                                           !D s

D D D

                                              !Lo 215 186 203 151
                                                   ~

DeQ Deg Deg Deg 25 12.5 30 28

                                                              !YES ju

• YES YES YES HPCI HPCI HPCI HPCI X-226 X-226 X-226 X-226

                                                                                  ; 3 PITS, 1.00" DIA.

CNS PIR SIN 4--14626 CNS PIR SIN 4--14626 CNS PIR SIN 4--14626_

                                                                                  ; 3 PITS, 1.00" DIA CNSPIR SIN 4-14626 13 3

120011 2001 2001 2001 2001 14 3 14-P3-1 NIA 1 0.027 s 58 Deg 10 HPCI X-226 2001 14 3 14-P3-10 N/A 1 0.023 s 23 Deg 38 HPCI X-226 2001 14 3 14-P3-2 NIA 1 0.021 s 122 DeQ 12 HPCI X-226 2001 14 3 14-P3-3 NIA 1 0.023 s 70 Deg 32 HPCI X-226 2001 14 3 14-P3-4 NIA 1 0.039 D 122 Deg 31 YES HPCI X-226 CNSPIR SIN 4-14626 2001 14 3 14-P3-5 NIA 1 0.019 s 41 Deg 12.5 HPCI X-226 2001 14 3 14-P3-6 NIA 1 0.046 D 41 Deg 49 YES HPCI X-226 CNS PIR S/N4-14626 2001 14 3 14-P3-7 N/A 1 0.007 s 35 Deg 13 HPCI X-226 2001 14 3 14-P3-8 NIA 1 0.035 D 61 Deg 14,5 YES HPCI X-226 CNS PIR SIN 4-14626 2001 14 3 14-P3-9 NIA 1 0.032 D 29 Deg 9 YES HPCI X-226 CNS PIR SIN 4-14626 2001 15 1 15-P1-1 NIA 1 0.019 s 198 Deg 18.5 RHR-C X-225C 2001 15 1 15-P1-10 NIA 1 0.015 s 203 Deg 31 RHR-C X-225C 2001 15 1 15-P1-11 NIA 1 0.018 s 206 Deg 34 RHR-C X-225C 2001 15 1 15-P1-12 N/A 1 0.018 s 206 Deg 32 RHR-C X-225C 2001 15 1 15-P1-13 NIA 1 0.023 s 209 Deg 31 RHR-C X*225C 2001 15 1 15-P1-14 NIA 1 0.026 s 302 Deg 15 RHR-C X.-225C 2001 15 1 15-P1-15a NIA 1 0.030 D 285 Deg 20 YES RHR-C X*225C CNS'PIR SIN 4--14626 2001 15 1 15-P1-15b N/A 1 0.030 D 285 Deg 20 YES RHR-C X-225C CNS PIR SIN 4-14626 2001 15 1 15-P1-16 NIA 1 0.020 s 285 Deg 24 RHR-C X.-225C 2001 15 1 15-P1-17 N/A 1 0.016 s 267 Deg 25 RHR-C X-225C 2001 15 1 15-P1-18 N/A 1 0.033 D 267 Deg 20 YES RHR-C X-225C CNS PIR SIN 4-14626 2001 15 1 15-P1-2 NIA 1 0.033 D 157 Deg 17 YES RHR-C X-225C CNS PIR SIN 4--14626 2001 15 1 15-P1-3 NIA 1 0.032 D 76 Deg 9 YES RHR-C X-225C CNS PIR SIN 4--14626 2001 15 1 15-P1-4 NIA 1 0.024 s 227 Deg 14 RHR-C X-225C 2001 15 1 15-P1-5 NIA 1 0.009 s 139 Deg 24 RHR-C X*225C 2001 15 1 15-P1-6 NIA 1 0.034 D 139 Deg 27.5 YES RHR-C X-225C CNS PIR SIN 4--14626 2001 15 1 15-P1-7 NIA 1 0.034 D 221 Deg 28 YES RHR-C X-225C CNS PIR SIN 4-14626 2001 15 1 15-P1-8 NIA 1 0.020 s 209 Deg 30 RHR-C X-225C 2001 15 1 15-P1-9 N/A 1 0.031 D 206 Deg 31 YES RHR-C X-225C CNS PIR SIN 4--14626 2001 15 2 15-P2-1 N/A 1 0.021 s 227 Deg 20 RHR-D X-225D RHR-0 2001 15 2 15-P2-2 NIA 1 0.023 s 209 Deg 25 RHR-D X-225D RHR-D 2001 3 3 3-P3-001 NIA 1 0.013 s goo Dea 10.5 RHR-8 x-2258 RHR'A'&'C' 20051 3 3 3-P3-002 NIA 1 0.014 s goo Oeq 11" RHR-8 x-225B RHR 'A' &'C' 20051 3 3 3-P3-003 NIA 1 0.018 s goo Deg 10" RHR-B x-225B RHR 'A' & 'C' 20051 p, *~ion 2 (19-7) I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                              & 3rd Interval CISI Program Torus Identified Internal Pitting 3-P3-004     NIA     1    0.018 s    goo  DeQ    11.5"        RHR-B       x-225B RHR 'A' & 'C'.                             2005 3-P3-005     N/A     1    0.021    s 91°  Dea    9.75"        RHR-8       x-2258 RHR'A'&'C'                                 2005 3-P3-006     NIA     1    0.008    s 91°  Deo    9"           RHR-B       x-2258 RHR 'A' & 'C'* *1-1/2" X 3/8"              2005 3-P3-007     NIA     1    0.017    s 91°  DeQ    11"          RHR-B       x-2258 RHR'A'&'C'                                 2005 3-P3-008     NIA     1    0.006    s 91°  Dea    8.75"        RHR-8       x-2258 RHR 'A' & 'C'- 3/16" X 1"                  2005 3-P3-010     N/A     1    0.012    s 92°  Deg    9"           RHR-B       x-2258 RHR 'A' & 'C'                              2005 3-P3-011     SM      1    0.015    s 92°  Dea    12"          RHR-8       x-2258 RHR 'A' & 'C'* GROUP OF FOUR - 2"    4     2005 3-P3-012     N/A     1    0.003    s 170° Deq    14"          RHR-8       x-2258 RHR'A'&'C'                                 2005 RHR DEEP PIT- reported 1/23/05 3  3  3-P3-013     N/A     1    0.032    D 165° Deg    13"      YES RHR-8       x-2258                                            2005 CR-CNS-2005-01188 3  3  3-P3-09      NIA     1    0.020    s 92°  Dea    9"           RHR-8       X-2258 RHR'A'&'C'                                 2005 4  D  4-FD-001     NIA     1    <0.030   S oo   Deg    18"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-002     NIA     1    <0.030   S 20°  Deg    17"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-003     NIA    1     <0.030   S 25°  Deg    15-112"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-0034    NIA     1    <0.030   S 170° Deg    16-3/4"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-004     NIA    1     <0.030   S 25°  Dea    15"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-005     NIA    1     <0.030 S   25°  Dea    17"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-006     NIA    1     <0.030   S 30°  Deg    3-1/2"       Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-007     N/A     1    <0.030   S 40°  Deg    12"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-008     NIA     1    <0.030   S 45°  Deg    12"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-009     NIA     1    <0.030   S 50°  Deg    15-1/2"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-010     N/A     1    <0.030   S 55°  Deg    15-1/4"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-011     N/A     1    <0 ..030 S 55°  Deo    13"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-012     NIA     1    <0.030   S 60°  Deg    12-1/2     Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-013     NIA    1     <0.030   S 65°  Deg    18"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-014     NIA    1     <0.030   S 70°  Dea    18"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-015     NIA    1     <0.030   S 70°  Deg    14-3/4"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-016     NIA    1     <0.030   S 80°  Deo    17-1/2"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-017     N/A     1    <0.030   S 80°  Deg    18"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-018     NIA     1    <0.030   S goo  Deg    13-1/2"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD~o1g     NIA     1    <0.030   S 95°  Deg    14"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-020     NIA     1    <0.030   S 95°  Deg    1/16"        Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-021     N/A     1    <0.030   S 100° Deg    14-1/2"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-022     NIA    1     <0.030   S 105° De!'.l 14-1/2"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-023     NIA    1     <0.030   S 110° Deg    1-1/2"       Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-024     N/A     1    <0.030   S 115° Deg    16"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-025     NIA    1     <0.030   S 115° Deg    16"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-026     N/A    1     <0.030   S 115° Deg    17-3/4"      Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-027     N/A    1     <0.030   S 140° Deg    13"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-028     NIA    1     <0.030   S 145° Dea    12"          Torus Drain X-213A Torus Drain                                2005 4  D  4-FD-029     NIA     1    <0.030   S 150° Deg    4"           Torus Drain X-213A Torus Drain                                2005 (19-8)                                                                                         p   *,ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                                   & 3 Interval GISI Program Torus Identified Internal Pitting D   4-FD-030     NIA    1     <0.030    S 15011    Deg  17"     Torus Drain        ITorus Drain                                                    2005 D   4-FD-031     NIA     1    <0.030    S 165°     Dea  16-1/2" Torus Drain         Torus Drain                                                    2005 D   4-FD-032     NIA    1     <0.030    S 165°     Deg  14"     Torus Drain X-213A  Torus Drain                                                    2005 D   4-FD-033     NIA    1     <0.030    S 170°     Deg  17-1/2" Torus Drain X-213A  Torus Drain                                                    2005 D   4-FD-035     N/A     1    ..:;0,030 S 180°     Deg  1/2"    Torus Drain X-213A  Torus Drain                                                    2005 D   4-FD-036     N/A     1    <0.030    S 180°     Deg  14-3/4" Torus Drain X-213A  Torus Drain                                                    2005 D   4-FD-037     N/A     1    <0.030    S 185°     Deg  14"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-038     N/A     1    <0.030    S 190°     Dea  1"      Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-039     N/A    1     <0.030    S 190°     Deg  16"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-040     N/A     1    <0.030    S 195°     Dea  14"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-041     NIA    1     <0.030    S 210°     Dea  17-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-042     NIA     1    <0.030    S 212°     DeQ  12"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-043     N/A     1    <0.030    S 220°     DeQ  14-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-044     NIA     1    <0.030    S 24011    Dea  16"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-045     NIA     1    <0.030    S 250°     Deg  17-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-046     NIA     1    <0.030    S 275°     Deg  16"     Torus Drain X-213A  Torus Drain                                                    2005 4  .D  4-FD-047     NIA     1    <0.030    S 275°     Deg  12"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-048     NIA     1    <0.030    S 280°     Deg  9"      Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-049     NIA     1    <0.030    S 280° '   Deg  6"      Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-050     N/A    1     <0.030    S 280°     Dea  1.6"    Torus Drain X*213A  Torus Drain                                                    2005 4  D   4-FD-051     NIA    1     <0.030    S 285°     Deg  12"     Torus Drain X-213A  Torus Drain                                                    2005 4  D   4*FD-052     N/A     1    <0.030    S 3000     Deg  6"      Torus Drain X-213A  Torus Drain                                                    2005 4  D   4.fQ-053     NIA     1    <0.030    S 3000     Dea  10"     Torus Drain X*213A  Torus Drain                                                    2005 4  D   4-FD-054     N/A    1     <0.030    S 330°     Deg  14-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-055     NIA     1    <0.030    S 335°     Deg  12-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-056     N/A     1    <0.030    S 335°     Dea  9-1/4"  Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-057     NIA     1    <0.030    S 340°     Deg  10-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-058     NIA     1    <0.030    S 345°     Dea  11-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-059     NIA     1    <0.030    S 345°     Dea  13-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-060     NIA     1    <0.030    S 345      Deq   17"    Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-061     NIA     1    .<Q.030   S 350°     Dea   10"    Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-062     N/A    1     <0.030    S 347-1/2° Dea  1-1/2"  Torus Drain X-213A  Torus Draln                                                    2005 4  D   4-FD-063     NIA    1     <0.030    S 355°     Deg  16-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-064     NIA     1    <-0.030   S 357°     Dea  16-1/2" Torus Drain X-213A  Torus Drain                                                    2005 4  D   4-FD-065     NIA    1     <0.030    S 359°     Deg  17-1/2" Torus Drain X-213A  Torus Drain                                                    2005 6  1   6-P1-001     NIA    1     <0.030    S oo       Deg  5"      RCIC        X-224   RCIC                                                           2005 6  1   6-P1-002     NIA     1    <0.030    S oo       Dea  9"      RCIC        X-224   RCIC                                                           2005 6  1   6-P1-003     NIA     1    <0.030    S 58°      Deg   13"    RCIC        X-224   RCIC                                                           2005 6  1   6-P1-004     LG      1    <0.030    S 58°      Dea  19"     RCIC        X-224   RCIC; 3 total pits, 2.5" pit group                        3    2005 RCIC; "Tiger stripe bottom tip falls Into 19" region -

6 1 6-P1-005 NIA 1 <0.030 S 68° Deg 19" RCIC X-224 documented as one pit 2005 (19-9) R' :~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                   & 3 Interval GISI Program Torus Identified Internal Pitting 6  1  6-P1-006    11\lfll         0.030 s        ~           CJ *

[Rcic____ --- 1 I2005 I 6 1 6-P1 -007 IN/A 1 <0.030 S 58° Deg 12.5" RCIC X-224 RCIC 2005 6 1 6-P1 -008 INIA 1 <0.030 S 58° Deg 5.5" RCIC X-224 RCIC :2005 6 1 6-P1-000 NIA 1 <0.030 S 68° Deg 15" RCIC X-224 RCIC 2005 6 1 6-P1-010 N/A 1 <0.030 S 77.5° Dea 5" RCIC X-224 RCIC 2005 6 1 6-P1-011 NIA 1 <0.030 S 77.5° Deg 8" RCIC X-224 RCIC 2005 6 1 6-P1-012- NIA 1 <0.030 S 87° Deg 3" RCIC X-224 RCIC 2005 6 1 6-P1-013 LG 1 <0.030 S 87° Dea 15" RCIC X-224 RCIC; 3 pits total, 2.5" group D 3 2005 6 1 6-P1-014 NIA 1 <0.030 S 87° Deg 14.5" RCIC X-224 RCIC; 2005 6 1 6-P1-015 SM 1 <0.030 S 97° Deg 19" RCIC X-224 RCIC; 2 pits total, 1.5" group D 2 2005 6 1 6-P1-016 NIA 1 <0.030 S 97° Deg 10.5" RCIC X-224 RCIC; 2005 6 1 6-P1-017 SM 1 <0.030 S 106.5° Deg 8" RCIC X-224 RCIC; 10 pits, 1/2" group 0 10 2005 6 1 6-P1-018 SM 1 <0.030 S 106.5° Deg 11" RCIC X-224 RCIC; 2 pits, 1/2" group D 2 2005 6 1 6-P1-019 NIA 1 <0.030 S 116° Deg 17" RCIC X-224 RCIC:; 2005 6 1 6-P1-020 SM 1 <0.030 S 116° Deg 12" RCIC X-224 RCIC; 3 pits total, 1.5" group D 3 2005 6 1 6-P1-021 LG 1 <0.030 S 116° Deg 11-19" RCIC X-224 RCIC:; 50 pits total, 12"x16~ group D 50 2005 6 1 6-P1-022 SM 1 <0.030 S 155° Deg 15" RCIC X-224 RCIC; 4 pits total, 1/4" group D 4 2005 6 1 6-P1-023 SM 1 <0.030 S 174° Deg 17" RCIC X-224 RCIC; 4 pits total, 2* group D 4 2005 6 1 6-P1-024 SM 1 <0.030 S 194° Dea 16" RCIC X-224 RCIC; 4 pits 1.5" group D 4 2005 6 1 6-P1-025 SM 1 <0.030 S 194° Dea 9.5" RCIC X-224 RCIC; 1.5* group D 2005 6 1 6-P1-026 N/A 1 <0.030 S 223° Deg 11" RCIC X-224 RCIC 2005 6 1 6-P1-027 SM 1 <0.030 S 223° Deg 17" RCIC X-224 RCIC; 7 pits total, 2" group D 7 2005 6 1 6-P1-028 SM 1 <0.030 S 232.5° Deg 6" RCIC X-224 RCIC; 2 pits total, 112* group D 2 2005 6 1 6-P1-029 SM 1 <0.030 S 252° Deg 9" RCIC X-224 RCIC; 20 pits, 1.5" group D 20 2005 6 1 6-P1-030 SM 1 <0.030 S 271° Dea 3" RCIC X-224 RCIC; 5 pits, 2* group D 5 2005 6 1 6-P1-031 SM 1 <0.030 S 271° Dea 10" RCIC X-224 RCIC; 5 pits, 1* group D 5 2005 6 1 6-P1-032 SM 1 <0.030 S 271° Deg 14" RCIC X-224 RClC; 9 pits total, 1.5" group D 9 2005 6 1 6-P1-033 SM 1 <0.030 S 271° Deg 17" RCIC X-224 RClC; 4 pits total, 1" group D 4 2005 6 1 6-P1-034 LG 1 <0.030 S 290.5° Deg 8" RCIC X~224 RCIC; 4 Pits total, 3-1/4" group D 4 2005 6 1 6-P1-035 SM 1 <0.030 S 290.5° Deg 16" RCIC X-224 RCIC; 15 pits total, 2* group D 15 2005 6 1 6-P1-036 N/A 1 <0.030 S 310° D~ 8" RCIC X-224 RCIC 2005 6 1 6-P1-037 NIA 1 <0.030 S 339° Dea 12.5" RCIC X-224 RClC 2005 6 1 6-P1-038 SM 1 <0.030 S 349° Deg 19" RCIC X-224 RCIC; 3 pits, 2" group D 3 2005 6 1 6-P1-039 SM 1 <0.030 S 349° Dea 5" RCIC X-224 RCIC; 3 pits, 1" group D 3 2005 6 1 6-P1-040 N/A 1 <0.030 S 358.5° Dea 7.5" RCIC X-224 RCIC 2005 6 4 6-P4-001 SM 1 <0.030 S 186° Deg 6" Temp. Monit. X-300E Temp Monitor; 2 pits total, 1/2" group D 2 2005 6 14 16-P4-002 SM 1 <0.030 S 186° Deg 12" Temp. Monit. IX-300E jTemp Monllor:3 pits total, 1* group D 13 12005 6 14 16-P4-003 LG 1 <0.030 S 186° Deg 12" Temp. Monit. lx-300E hemp Monitor:20 pits. 3" group D I2a 12005 (19-10) P *.,.ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                 & 3 Interval GISI Program Torus Identified Internal Pitting 6 14 16-P4-004     NIA     1    <0.030 S 256°        Deg  9.5"  Temp. Monit. IX-300E !Temp Monitor                           I      12005 6 14 16-P4-005     SM      1    <0.030 S 279°        Deg  12"   Temp. Monit. IX-300E !Temp Monitor;5 pits, 2* group D        15     12005 6 14 l6-P4-006     SM      1    <0.030 S 349°        Deg  12"   Temp. Monit. IX-300E 12 pits total, 1/2" group D               12     12005 6  4  6-P4-007     NIA     1    <0.030 S 93°         Deg  13"   Temp. Monit IX-300F  !Temp Monitor                           I      12005 6  4  6-P4-008     NIA     1    <0.030 S 116°        Deg  10"   Temp. Monit. IX-300F !Temp Monitor                           I      12005 6  4  6-P4-009     SM      1    <0.030 S 116°        Deg  13"   Temp. Monit. X-300F   Temp Monltor;3 pits total,3/4" group D     3     2005 7  1  7-P1-001     NIA     1    <0.030 S 95°         Deg  11.5" CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1..0010   NIA     1    <0.030 S 125°        Deg  34"   CS-A          X-227A  CS-'P<                                         2005 7  1  7-P1-002     N/A     1    <0.030 S 115°        Deg  22.SU CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-003     NIA     1    <0.030 S 120°        Deg  20"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-004     NIA     1    <0.030 S 125°        Deg  18"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-005     NIA     1    <0.030 S 125°        Deg  17.5" CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-006     NIA     1    <0.030 S 125°        Deg  16"   CS-A          X-227A  CS*'A'                                         2005 7  1  7-P1-007     NIA     1    <0.030 S 125°        Deg  6"    CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1..008    NIA     1    <0.030 S 125°        Deg  9.5"  CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-009     NIA     1    <0.030 S 125°        Deg  22"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-011     NIA     1    <0.030 S 120°        Deg  29.5" CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-012     NIA     1    <0.030 S 130°        Deg  16.5" CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-013     NIA     1    <0.030 S 130°        Deg  31"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-014             1    <0.030 S 135°        Deg  5"    CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-015             1    <0.030 S 135°        Deg  20"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-016             1    <0.030 S 136°        Deg  30.5" CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-017     SM      1    <0.030 S 136°        Deg  36"   CS-A          X-227A  CS-'A'; 7 pits total, 2" group D         7     2005 7  1  7-P1-018             1    <0.030 S 140°        Deg  19"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1..019            1    <0.030 S 140° - 160° Deg  33"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-020     LG      1    <0.030 S 170°        Deg  29"   CS-A          X-227A  CS-'A'; 20 pits total. 3" group D       20     2005 7  1  7-P1-021             1    <0.030 S 175°        Deg  18"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-022     SM      1    <0.030 S 180°        Deg  21"   CS-A          X-227A  CS-'A'; 3 pits total, 1-1/2" group D     3     2005 7  1  7-P1-023             1    <0.030 S 180°        Deg  34"   CS-A          X-227A  CS-'A'                                         2005 7  1  7-P1-024     SM      1    <0.030 S 180°        Deg  33"   CS-A          X-227A  CS-'A'; 6 pits, 2" group D               6     2005 7  1  7-P1-025     SM      1    <0.030 S 185°        Deg  30"   CS-A          X-227A  CS-'P<; 3 pits total, 112* group D       3     2005 7  1  7-P1-026     SM      1    <0.030 S 185°        Deg  36"   CS-A          X-227A  CS-'P<; 6 pits. 1-1/2" group D          6      2005 7  1  7-P1-027     LG      1    <0.030 S 190°        Deg  28  CS-A          X-227A  CS-'P<; 9 PITS, 3"                      9      2005 7  1  7-P1-028     LG      1    <0.015 S 200°        Deg  20"   CS-A          X-227A  CS-'P<; 9 PITS, 3"                      9      2005 (19-11)                                                                                     R-- =~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                                    & 3 rd Interval GISI Program Torus Identified Internal Pitting 7   1  7-P1-029     NIA     1    <0.030  s    300°        IDeg  1           CJ               IX-227A IICS-'A'                                           12oos 1 7   1  7-P1-030     SM      1    <0.015  S    31~         !Dea 1
                                                                                                 .. 227~ CS-'A'; 5 PITS, 1.5" 5     2005 7   1  7-P1 -031    SM      1    <0.030  S    310°          Deg   29"          CS-A           X-227A CS.'A'; 3 PITS, 1.25"                         3     2005 7   1  7-P1-032     SM      1    <0.030  S    350°         Deg    23"          CS-A           X-227A CS-'A'; 3 PITS, 0.75"                         3     2005 7-P1-033     SM      1    <0.030  S    310°          Deg   36"          CS-A           X-227A CS-'A'; 2 PITS, 0.50"                         2     2005 CSA Test 8  1s  8-P3-001     SM      1    <0.030 S     170          Deg    38 Line X-223A    cs Test Line; 2 Pits, .s* D                      2005 8  14  8-P4-001     LG      1    <0.030 S     5            Deg    12           Temp. Monit. IX-300-G !Temp. Monitor; 6 Pits, 3" D                16     12005 8  14  8-P4-002     NIA     1    <0.030 S     160          Deg    12           Temp. Monit. IX-300-G !Temp. Monitor                              I      12005 8   4  8-P4-003     SM      1    <0.030 S     170          Deg    9            Temp. Monit IX-300-G !Temp. Monitor; 10 Pits, .75" D              110    12005 8   4  8-P4-004     SM      1    <0.030 S     170          Deg    11           Temp. Monit. IX-300-G !Temp. Monitor; 2 Pits, .5" D                      12005 12 8   4  8-P4-005     SM      1    <0.030 S     170          Deg   4             Temp. Monit. fX-300-G ITemp. Monitor; 5 Pits, 1.5" D              Is     12005 9.5" (8/9 9   1  9-P1-001     NIA     2    0.045   NIA               In    60" (IW)      Near RG                                                                   2005 RG) 9   1  S..P1-002    NIA     2    0.052   s    5" (8/9 RG)  In    49" (IW)      NearRG                                                                    2005 6.5" (8/9 9   1  9-P1-003     NIA     2    0.041   N/A               In    46.5" (IW)    NearRG                                                                    2005 RG) 1.5" (8/9 9   1  9-P1-004     N/A     2    0.074   s                 In    38" (lW)      Near RG      I         I                                          I      12005 CSB Test 10 11 l10-P1-001  ISM      11   l<0.030 ts   1175          Deg   31"to37"                   IX-223B ICS Test Line, tiger striping at waterline   I      12005 Line 10"(10/11 11  1  11-P1-001    NIA     2    0.049   n/a               In    36" (1\/V)    Near RG                                                                   2005 RG 11  3  11-P3-001    NIA     1    <0.030  S    0                 26             CS-B          X227B     CS-'B'                                            2005 11  3  11-P3-002    NIA     1    <0.030  S    0                  32            CS-B          X227B     CS-'B'                                            2005 11  3  11-P3-003    NIA     1    <0.030  S    5                  28            CS-B          X227B     CS-'B'                                            2005 11  3  11-P3-004    NIA     1    <0.030  S    IO                 34            CS-B          X227B     CS-'B'                                            2005 11  3  11-P3-005    NIA     1    <0.030  S    15                34             CS-8          X227B     CS-'B'                                            2005 11  3  11-P3-006    N/A     1    <0.030  S    300               26             CS-B          X227B     CS-'B'                                            2005 11  3  11-P3-007    N/A     1    <0.030  S    200               32             CS-8          X227B     CS-'B'                                            2005 11  3  11-P3-008    NIA     1    <0.030  S    290               20             CS-B          X227B     CS-'B'                                            2005 11  3  11-P3-009   NIA      1    <0.030  S    290               24             CS-B          X2278     CS-'B'                                            2005 11  3  11-P3-010   NIA      1    <0.030  S    290               30             CS-B          X2278     CS-'B'                                            2005 11 3   11-P3-011   NIA      1    <0.030  S    280               26             CS-8          X2278     CS-'8'                                            2005 11  3  11-P3-012    NIA     1    <0.030  S    280               35             CS-8          X227B     CS-'B'                                            2005 11  3  11-P3-013   NIA      1    <0.030  S    280                15            CS-8          X2278     CS-'B'                                            292§_

(19-12) R *~.ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                      & 3 Interval GISI Program Torus Identified Internal Pitting 11-P3-014 NIA        1    <0.030  S  270    Deg   12    CS-B         X227B  CS-'B'               2005 11-P3-015 NIA        1    <0.030  S  7      Dea   31    CS-B         X227B  CS-'B'               2005 11-P3-016 NIA        1    <0.030  S  7      Deg   27    CS-B         X2278  CS-'B'               2005 11  3  11-P3-017 NIA        1    <0.030  S  10     Deg   13    CS-B         X227B  CS-'B'               2005 11  3  11-P3-018 NIA        1    <0.030  S  250    Deg   11    CS-8         X227B  CS-'B'               2005 11  3  11-P3-019 NIA        1    <0.030  S  250    DeQ   11    CS-8         X2278  CS-'B'               2005 11  3  11-P3-020 NIA        1    <0.030  S  290    Deg   12    CS-B         X227B  CS-'B'               2005 11  3  11-P3-021    NIA     1    <0.030  S  290    Deg   14    CS-8         X227B  CS-'B'               2005 11  3  11-P3-022 NIA        1    <0.030  S  185    Deg   11    CS-8         X227B  CS-'B'               2005 11  3  11-P3-023 NIA        1    <0.030  S  185    Deg   10    CS-8         X227B  CS-'B'               2005 11  3  11-P3-024 NIA        1    <0.030  S  180    Deg   12    CS-B         X227B  CS-'B'               2005 11  3  11-P3-025 NIA        1    <0.030  S  180    Deg   14    CS-8         X227B  CS-'B'               2005 11  3  11-P3-026 NIA        1    <0.030  S  180    Deg   18    CS-8         X227B  CS-'B'               2005 12  2  12-P2-001    NIA     1    <0.030  S  oo     Dea   18"   Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-002 NIA        1    <0.030  S  oo     Deg   14"   Torus Drain  X-213B Torus Drain          2005 12  2  12-P2-003 NIA        1    <0.030  S  oo     Deg   1"    Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-004 N/A        1    <0.030  S  45°    Dea   8"    Torus Drain  X-213B Torus Drain          2005 12  2  12-P2-005 NIA        1    <0.030  S  45°/   Deg   9"    Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-006 NIA        1    <0.030  S  50°    Deg   9"    Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-007 N/A        1    <0.030  S  55°    Dea   1"    Torus Drain  X-213B Torus Drain          2005 12  2  12-P2-008. NIA       1    <0.030  S  60°    Deg   12"   Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-009 NIA        1    <0.030  S  65°    Deg   7"    Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-010 NIA        1    <0.030  S  100°   Deg   7" 5" Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-011    N/A     1    <0.030  S  10011  Deg   6"    Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-012 N/A        1    <0.030  S  180°   Dea   4"    Torus Drain  X-213B Torus Drain          2005 12  2  12-P2-013 N/A        1    <0.030  S  260°   DeA   4"    Torus Drain  X-2138 Torus Drain          2005 12  2  12-P2-014 NIA        1    <0.030  S  260°   Deg   8"    Torus Drain  X-213B Torus Drain          2005 12  2  12-P2-015 NIA        1    <0.030  S  270°   Dea   9"    Torus Drain  X-213B Torus Drain          2005 12  2  12-P2-016 NIA        1    <0.030  S  275°   Dea   12"   Torus Drain  X*213B Torus Drain          2005 12  4  12-P4-001    NIA     1    <0.030 S   oo     Deg   12"   Temp. Monit. X-300K Temp Monitor         2005 12 14 l12-P4-002  IN/A     11   l<0.030 IS 1280°  IDeg  8"     Temp. Monit. X-300K Temp Monitor         2005 12 14 l12-P4-003  IN/A     11   l<0.030 IS 1185°  IDeg   6"    Temp. Monit X-300L  Temp Monitor         2005 12  4  12-P4-004    NIA     1    <0.030 S   290°   Deg  8"     Temp. Monit X-300L  Temp Monitor         2005 14  2  14-P2-001    NIA     1    <0.030  S  oo     Deg  36"    HPCI         X-226  HPCI                 2005 14  2  14-P2-002    NIA     1    <0.030  S  oo     Deg   12 11 HPCI         X-226  HPCI                 2005 14  2  14-P2-003    NIA     1    <0.030  S  50     Dea   1211  HPCI         X-226  HPCI                 2005 14  2  14-P2-004    NIA     1    <0.030  S  10°    Deg  24"    HPCI         X-226  HPC1                 2005 (19-13)                                                          P  -'ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                 & 3 Interval CISI Program Torus Identified Internal Pitting 2005 2005 X-226  HPCI                 2005 goo    Deg  33"  HPCI         X-226  HPCl                 2005 14 2  14-P2-009    NIA     1    <0.030 S 90°    De~  22"  HPCI         X-226  HPCI                 2005 14 2  14-P'.2-010  N/A     1    <0.030 S 145°   Deg  24"  HPCI         X-226  HPCl                 2005 14 2  14-P2-011    NIA     1    <0.030 S 150°   Deg  sou  HPCI         X-226  HPCI                 2005 14 2  14-P2-012    NIA     1    <0.030 S 190°   Dea  24"  HPCI         X-226  HPCI                 2005 14 4  1.4-P4-001   N/A    1     <0.030 S oo     Deg  13"  Temp. Monit. x-300M Temp Monitor         2005 15 1  15.P1-012    NIA    1     <0.030 S 180°   Deg  27"  RHR-C        X*225C                      2005 15 1  15-P1-001    NIA     1    0.000  s oo     Deg  37"  RHR-C        X-225C                      2005 15 1  15-P1-002    N/A    1     0.000  s 50     Deg  30"  RHR-C        X-225C                      2005 15 1  15-P1-003    NIA    1     <0.030 S 120°   Deg  31"  RHR-C        X-225C                      2005 15 1  15-P1-004    NIA    1     <0.030 S 120°   Deg  31"  RHR-C        X-225C                      2005 15 1  15-P1-005    NIA    1     <0.030 S 140°   Deg  6"   RHR-C        X-225C                      2005 15  1  15-P1-006    NIA    1     <0.030 S 140°   Deg  4"   RHR-C        X-225C                      2005 15 1  15-P1-007    NIA    1     <0.030 S 170°   Deg  19"  RHR-C        X*225C                      2005 15 1  15-P1-008    NIA    1     0.007  s 175°   Deg  28"  RHR-C        X-225C                      2005 15 1  15-P1-009    NIA    1     0.003  s 175° / Dea  33"  RHR-C        X*225C                      2005 15 1  15-P1-010    NIA    1     0.003  s 175°   Deg  32"  RHR-C        X-225C                      2005 15 1  15-P1-011    NIA    1     <0.030 S 175°   Deg  32"  RHR-C        X-225C                      2005 15  1  15-P1-013    NIA    1     <0.030 S 180°   Deg  28"  RHR-C        X-225C                      2005 15 1  15-P1-014    NIA    1     <0.030 S 180°   Deg  36"  RHR-C        X-225C                      2005 15  1  15-P1-015    NIA    1     <0.030 S 180°   Dea  37"  RHR-C        X-225C                      2005 15 1  15-P1-016    NIA    1     <0.030 S 180°   Dea  23"  RHR-C        X-225C                      2005 15 1  15-P1-017    NIA    1     <0.030 S 180°   Deg  20"  RHR-C        X-225C                      2005 15  1  15-P1-018    NIA    1     0.003  s 180°   Deg  31"  RHR-C        X-225C                      2005 15  1  15-P1-019    NIA    1     0.002  s 180°   Dea  28"  RHR-C        X-225C                      2005 15  1  15-P1-020    NIA    1     <0.030 S 180°   DeQ  28"  RHR-C        X-225C                      2005 15 1  15-P1-021    NIA    1     <0.030 S 190°   Dea  17"  RHR-C        X-225C                      2005 15 1  15-P1-022    N/A    1     <0.030 S 190°   Deg  19"  RHR-C        X-225C                      2005 15  1  15-P1-023    N/A    1     <0.030 S 210°   [)eg 11"  RHR-C        X-225C                      2005 15  2  15.P2-012    NIA    1     0.000  s 180°   Deo  27"  RHR-D        X-225D RHR'D'               2005 15 2  15-P2-001    NIA    1     0.001  s 40     Dea  38"  RHR-D        X-225D RHR 'D'              2005 15  2  15-P2-002    NIA    1     <0.030 S 130°   Deg  6"   RHR-D        X-225D RHR'D'               2005 15  2  15-P2-003    NIA    1     <0.030 S 130°   Dea  6.5" RHR-D        X-225D RHR'D'               2005 15  2  15-P2-004    N/A    1     <0.030 S 130°   Deg  9"   RHR-D        X-2250 RHR'D'               2005 15  2  15-P2-005    NIA    1     <0.030 S 135°   Deg  15"  RHR-D        X-2250 RHR'D'               2005 15  2  15-P2-006    N/A    1     0.005  s 140°   Deg  23"  RHR-D        X-225D RHR'D'               2005 15  2  15-P2-007    NIA    1     <0.030 S 170°   Deg  13"  RHR-D        X-2250 RHR'D'               2005 (19-14)                                                         Rr-* -:~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                                                             & 3 rd Interval CISI Program Torus Identified Internal Pitting NIA     1    <0.030 15-P2-009    NIA     1    <0.030 S 15-P2-010    NIA     1    0.000 s      183°      Deg   38"             RHR-D     X-2250 15-P2-011    NIA     1    <0.030 S     185°/     Deg   38"             RHR-D     X-225D  RHR'D' 15  2  15-P2..Q13   NIA     1    <0.030 S     oo        Dei:i 37"             RHR-D     X-2250  RHR'D' 1   4  1-P4-1       N/A     2    0.073 s      2"        in. 8"              NearRG            1/16 RG 2   1  2-P1-1       NIA     2    0.055 s      8"1W      in    10"             Near RG           1/2RG                                                    I      12008 2   1  2-P1-2       NIA     2    0.054 s      8"1W      in    19"             NearRG            1/2RG                                                            2008 2   3  2-P3-1       N/A     2    0.058 s      5.511W    in    13.5"           Near RG           213RG                                                    I      12008 2  13  2-P3-2       NIA 2/3 RG pit located on weld actual p!t depth may be lower I 2    0.092   D    38"1W     in    3"          YES Near RG                                                                           12008 CR-CNS-2008-2770 2   3  2-P3-3       NIA     2    0.060   s    43"1W     in    13.5"           Near RG           2/3RG                                                            2008 2   3  2-P3-4       NIA     2    0.059   s    42"1W     in    13.5            Near RG           2/3 RG                                                           2008 2   4  2-P4-1       NIA     2    0.060   s    60"1W     in    5"              Near RG           2/3RG                                                            2008 2   4  2-P4-2       NIA     2    0.060   s    60"1W     in    5"              Near RG           2/3 RG                                                           2008 2   4  2-P4-3       N/A     2    0.050   s    53"1W     in    7.5"            Near RG           2/3 RG                                                           2008 2   4  2-P4-4       N/A     2    0.065   s    51"1W     in    9"              Near RG           2/3RG                                                            2008 2   4  2-P4-5       N/A     2    0.059   s    51"1W     in    9"              Near RG           2/3RG                                                            2008 2   5  2-P5-1       NIA     2    0.054   s 6'1W         in    15"             Near RG           1/2RG                                                            2008 2   5  2-P5-2       NIA     2    0.055   s 5'1W         in    13.5"           Near RG           1/2RG                                                            2008 2   5  2-P5-3       NIA     2    0.057   s    28"1W     in    12.5            Near RG           1/2 RG                                                           2008 2   5  2-P5-4       N/A     2    0.049   NIA 10"1W      in    12"             NearRG            1/2 RG                                                           2008 2   5  2-P5-5       NIA     2    0.064   s    10"1W     in    12"             Near RG           1/2 RG                                                           2008 2   5  2-P5-6       NIA     2    0.063   s    5"!W      in    9"              Near RG           1/2 RG                                                           2008 2   5  2-P5-7       NIA     2    0.081   s    0.25"1W   in    9"              Near RG           1/2RG                                                            2008 2   5  2-P5-8       NIA     2    0.037   N/A 1"1W       in    6"              Near RG           1/2RG                                                            2008 2   5  2-P5-9       NIA     2    0.063   s    2"1W      in    10"             Near RG           1/2RG                                                            2008 3   1  3-P1-1       N/A     2    0.058   s    6"from RG in.

6' from IW Near RG 213 RG 2008 4.5' from I 3 11 l3-P1-2 IN/A 12 I0.052 IS IB"from RG in. INear RG I 1213 RG I 12008 IW 2"from 4' from 3 11 l3-P1-3 IN/A 12 ID.055 IS 1 in. I INear RG I 1213 RG I 12008 RG IW 2"from 4' from 3 11 l3-P1-4 IN/A 12 I0.061 IS 1 RG in. IW I INear RG I 1213 RG I 12008 4' from 3 11 l3-P1-5 IN/A 12 I0.088 IS l5"from RG in. I !Near RG I 1213 RG I 12008 IW (19-15) fV**~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                          & 3 Interval CISI Program Torus Identified Internal Pitting 3 11 l3-P1-6      IN/A    12   I0.059 IS  15" from RGlin. l~rom I        INear RG I       1213 RG                                   I     12008 3 11 l3-P1-7      IN/A    12   I0.053  IS 15" from RG lln. l~rom     I    !Near RG I       1213 RG                                   I     12008 3  2  3-P2-1       N/A     1    0.054   D  170         deg    !"

1 from YES RHR-A 0Ipewall X-225A X-225A CR-CNS-2008-2770 2008 3 2 3-P2-10 N/A 1 0.010 s 180 deQ 32 RHR-A X-225A X-225A 2008 3 2 3-P2-11 NIA 1 0.006 s 185 deg 19 RHR-A X-225A X-225A 2008 3 2 3-P2-12 N/A 1 0.022 s 185 deq 29 RHR-A X-225A X-225A failed repair 2008 3 2 3-P2-13 NIA 1 0.022 s 180 deg 32 RHR-A X-225A X-225A 2008 3 2 3-P2-14 N/A 1 0.006 s 185 dea 30.5 RHR-A X-225A X-225A failed repair 2008 3 2 3-P2-15 N/A 1 0.010 s 190 dea 31 RHR-A X-225A X-225A failed repair 2008 3 2 3-P2-16 NIA 1 0.013 S 185 deg 34 RHR-A X-225A X-225A 2008 3 2 3-P2-17 N/A 1 0.030 D 180 dea 37 YES RHR-A X-225A X-225A CR-CNS-2008-2770 2008 3 2 3-P2-18 N/A 1 0.047 D 190 deg 36 YES RHR-A X-225A X-225A CR..CNS-2008-2770 2008 3 2 3-P2-19 NIA 1 0.030 s 195 dea 36 RHR-A X-225A X-225A failed repair 2008 3 2 3-P2-2 NIA 1 0.007 s 170 dea 18" RHR-A X-225A X-225A 2008 3 2 3-P2-20 N/A 1 0.008 s 200 deg 35 RHR-A X-225A X-225A failed repair 2008 3 2 3-P2-21 NIA 1 0.032 D 210 dea 30 YES RHR-A X-225A X-225A CR-CNS-2008-2770 2008 3 2 3-P2-22 NIA 1 0.010 s 200 deQ 35 RHR-A X-225A X-225A 2008 X-225A Adj to Pit 03-02-05; 1.5" clear 3 12 l3-P2-23 IN/A 11 I0.037 ID 15 ldeg 38 YES RHR-A X-225A distance I 12008 CR-CNS.-2008-2770 3 2 3-P2-24 N/A 1 0.024 S 230 deg 22 RHR-A X-225A X-225A 2008 3 2 3-P2-25 NIA 1 0.039 D 255 deg 15 YES RHR-A X-225A X-225A CR-CNS-2008-2770 2008 3 2 3-P2-26 NIA 1 0.023 s 260 deo 8.5 RHR-A X-225A X-225A 2008 3 2 3.-P2-27 NIA 1 0.025 S 265 deQ 24.5 RHR-A X-225A X-225A 2008 3 2 3-P2-28 N/A 1 0.019 s 250 dea 27 RHR-A X-225A X-225A 2008 3 2 3-P2-29 NIA 1 0.013 s 230 dea 27 RHR-A X-225A X-225A 2008 3 2 3-P2-3 NIA 1 0.Q11 s 1 dea 35" RHR-A X-225A X-225A failed repair 2008 3 2 3-P2-30 N/A 1 0.029 s 270 dea 33 RHR-A X-225A x.:225A 2008 3 2 3-P2-31 NIA 1 0.031 D 270 dea 6 YES RHR-A X-225A X-225A CR-CNS-2008-2770 2008 3 2 3-P2-32 N/A 1 0.025 s 270 deg 31 RHR-A X-225A X-225A 2008 3 2 3-P2-33 N/A 1 0.022 s 270 dea 31 RHR-A X-225A X-225A 2008 3 2 3-P2-34 N/A 1 0.016 s 280 deg 39 RHR-A X-225A X-225A 2008 3 2 3-P2-35 NIA 1 0.021 s 290 dea 13.5 RHR-A X-225A X-225A 2008 3 2 3-P2-36 N/A 1 0.012 s 295 deg 14 RHR-A X-225A X-225A 2008 3 2 3-P2-37 N/A 1 0.021 s 340 deg 30 RHR-A X-225A X-225A 2008 3 2 3-P2-38 N/A 1 0.022 s 315 deq 38 RHR-A X-225A X-225A 2008 (19-16) R- :~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                         & 3 Interval CISI Program Torus Identified Internal Pitting 13 12 f3-P2-4      !NIA    11   jo.005  Is          ~             I    fRHR-A           X-225A failed repair                          I      12ooaI
                                                                                                    ~ 8di to Pit 03-0 3 12 l3-P2-5      IN/A    11   ID.050 ID  15      ldeg   38       YES RHR-A   X-225A   distance                                              2008 (failed repair) CR-CNS-2008-2770 3  2  3-P2-6       NIA     1    0.008   s  355 -   deq   19            RHR-A  X-225A   failed reoair                                         2008 3  2  3-P2-7       NIA     1    0.009   s  1       deg   20            RHR-A  X-225A   X-225A failed repair                                  2008 3  2  3-P2-8       N/A     1    0.035   D  9.0     deq   9        YES RHR-A   X-225A   X-225A CR..CNS-2008-2770                              2008 3  2  3-P2-9       NIA     1    0.012   s  170     dea   26            RHR-A  X-225A   X-225A                                                2008 3  3  3-P3-1       NIA     1    0.027   s  1       deQ   11            RHR-B  x-2258   X-2258                                                2008 3  3  3-P3-10      N/A     1    0.007   s  48      deg   19            RHR-B  x-2258   X-2258                                                2008 3  3  3-P3-11      NIA     1    0.024   S  48      dea   16            RHR-8  x-2258   X-2258                                                2008 3  3  3-P3-12      NIA     1    0.037   D  48      deo   24       YES RHR-8   x-2258   X-2258 CR-CNS-2008-2770                               2008 3  3  3-P3-13      NIA     1    0.016   S  50      deg   17            RHR-8  x-2258   X-225B                                                2008 3  3  3-P3-14      NIA     1    0.020   s  60      deq   20.5          RHR-B  x,-225B  X-2258                                                2008 3  3  3-P3-15      NIA     1    0.040   D  70      deg   19       YES RHR-B   x-2258   X-2258 CR-CNS-2008-2770                               2008 3  3  3-P3-16      NIA     1    0.023   s  75      deq   14            RHR-8  x-2258   X-2258                                                2008 3  3  3-P3-17      N/A     1    0.008   s  315     deq   52            RHR-B  x-2258   X-2258                                                2008 3  3  3-P3-18      NIA     1    0.006   s  315     deg   50            RHR-B  x-2258   X-2258                                                2008 3  3  3-P3-19      NIA     1    0.010   s  315     dea   47            RHR-8  x-225B   X-2258                                                2008 X-2258 Apprx 50 small pit groups containing 3 13 l3-P3-2     ISM      11   I0.021 IS  1320-10 ldeg  !15-38        IRHR-8 jx-2258  j120 pits 1/8 -114 dia. Depth< 30 mil, ave 5 1120 12008
                                                                   .I mil 1 2'x2.5' area near X-225B 3 13 l3-P3-20    IN/A     11   I0.008 IS  1315    ldeq  143     I     IRHR-8 lx-2258  IX-2258                                        I      12008 X-2258 Apprx 3 small pit groups containing 3 13 l3-P3-21    ISM      11   I0.017 IS  1313    ldeg  150     I     IRHR-8 jx-2258  112 pits 1/8 - 1/4 dia. Depth< 30 mil, ave 5   112 12008 mil 5"x5" area near X-2258 3  3  3-P3-22      NIA     1    0.045   D  313     deq   45       YES RHR-B   x-225B   X-225B CR..CNS-2008-2770                              2008 3  3  3-P3-23      NIA     1    0.008   s  320     dea   40.5          RHR-8  x-2258   X-2258                                                2008 3  3  3-P3-24      NIA     1    0.010 S    325     dea   40.5          RHR-B  x-2258   X-2258                                                2008 3  3  3-P3-25      N/A     1    0.033   D  325     deq   39.5     YES RHR-B   x-2258   X-225B CR-CNS-2008-2770                               2008 3  3  3-P3-26      NIA     1    0.016   S  325     deQ   39.5          RHR-B  x-2258   X-2258                                                2008 3  3  3-P3-27      NIA     1    0.006   s  315     dea   37            RHR-8  x-2258   X-225B                                                2008 3  3  3-P3-28      N/A     1    0.002   s  330     deg   30            RHR-B  x-2258   X-2258                                                20081 X-225B Apprx 20 small pit groups containing 3  13 l3-P3-29    ISM      11   10.010 IS  1330    ldeg  127     I     IRHR-B jx-2258 130 pits 118 -1/4 dia. Depth< 30 mil, ave 5     130    12008 mil, 14x17" area near X-2258 3  3  3-P3-3       NIA     1    0.007   s  15      de    36            RHR-B  X-225B X-2258                                                  2008 3  3  3-P3-30      NIA     1    0.007   s  300     de    15            RHR-8  X-2258 X-2258                                                  2008 (19-17)                                                                                             p  *~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                  & 3 Interval CISI Program Torus Identified Internal Pitting 3  3-P3-31      N/A     1    0.022   s  300  deQ   13         RHR-B  X-225B  X-225B                                                2008 3  3-P3-32      N/A     1    0.041   D  300  dea   11    YES RHR-B   X-225B  X-225B    CR-CNS-2008-2770                            2008 3  3-P3-33      NIA     1    0.015   s  310  deq   16         RHR-B  x-2258  x-225B                                                2008 3  3  3-P3-34      N/A     1    0.043   D  310  deg   24    YES RHR-8   x-225B  x-2258    CR-CNS-2008-2770                            2008 3  3  3-P3-35      N/A     1    0.042   D  310  dea   29    YES RHR-B   x-2258  X-2258    CR-CNS-2008-2770                            2008 3  3  3-P3-36      NIA     1    0.030   s  310  deq   35         RHR-8  x-2258  x-2258                                                2008 3  3  3-P3-37      N/A     1    0.050   D  305  deg   34    YES RHR-8   x-2258  x-2258    CR-CNS-2008-2770                            2008 3  3  3-P3-38      N/A     1    0.048   D  305  dea   27    YES RHR-8   x-225B  X-2258    CR-CNS-2008-2770                            2008 3  3  3-P3-39      N/A     1    0.029   s  305  deg   20         RHR-B  x-2258  x-2258                                                2008 3  3  3-P3-4       NIA     1    0.017   s  20   deQ   15         RHR-8  X-225B  X-2258                                                2008 3  3  3-P3-40      NIA     1    0.014   S  275  deQ   26         RHR-8  x-2258  x-2258                                                2008J X-225B Apprx 30 small pit groups containing 3 13 l3-P3-41     ISM     11   to.011  Is 1270 lcteg j12   I    jRHR-8  x-225B 50 pits 118 -1/4 dia. Depth< 30 mil, ave 5 mil, 18x10" area near X-225B 150    12008 X-2258 Apprx 2 small pit groups containing 4 3 13 l3-P3-42    ISM      11   lo.010 Is  1255 ldeg  j25.5 I    jRHR-8 jx-225B jpits 1/8 -1/4 dia. Depth< 30 mil, ave 5 mil, 14 4"x4" area near X-225B 12008 X-225B Apprx 8 small pit groups containing 3 13 l3-P3-43     ISM     11   to.022  Is  250  deg   23         RHR-B  x-2258 15 pits 118 - 114 dia. Depth < 30 mil, ave 5   115    12008 mil 6"x12" area near X-2258 3  3  3-P3-44      NIA     1    0.002   s  250  dea   19         RHR-B  x-2258 x-225B                                                 2008 3  3  3-P3-45      NIA     1    0.045   D  230  dea   19    YES RHR-B   x-225B X-225B CR-CNS-2008-2770                                2008 3  3  3--P3-46     NIA     1    0.017   s  230  deg   22         RHR-8  x-225B x-2258                                                 2008 3  3  3-P3-47      NIA     1    0.014   S  225  dea   27         RHR-8  x-2258 x-2258                                    '

2008 3 3 3--P3-48 NIA 1 0.028 s 220 deg 20 RHR-8 x-2258 x-2258 2008 3 3 3-P3-49 NIA 1 0.018 s 210 deg 32 RHR-B x-225B x-2258 2008 3 3 3-P3-5 NIA 1 0.008 s 25 dea 32 RHR-B X-2258 X-2258 2008 3 3 3-P3-50 NIA 1 0.008 s 205 deq 35 RHR-B x-2258 x-225B 2008 3 3 3-P3-51 NIA 1 0.016 s 175 deg 18 RHR-B x-2258 x-2258 2008 3 3 3-P3-52 NIA 1 0.019 S 170 dea 22 RHR-8 x-2258 x-2258 2008 3 3 3-P3-53 NIA 1 0.018 S 178 deq 19.5 RHR-8 x-225B x-2258 2008 3 3 3-P3-54 NIA 1 0.014 S 178 dea 22 RHR-B x-2258 x-2258 2008 3 3 3-P3-55 NIA 1 0.016 s 178 deq 17 RHR-8 x-2258 x-2258 2008 3 3 3-P3-56 NIA 1 0.014 S 180 dea 29 RHR-B x-2258 x-225B 2008 3 3 3-P3-57 NIA 1 0.014 S 182 deg 27 RHR-8 x-2258 x-2258 2008 3 3 3-P3-58 N/A 1 0.024 S 182 dea 37 RHR-8 x-2258 x-225B 2008 3 3 3-P3-59 NIA 1 0.059 D 170 deg 32.5 YES RHR-B x-2258 X-225B CR-CNS-2008-2770 2008 3 3 3-P3-6 NIA 1 0.013 S 30 deg 36 RHR-8 X-2258 X-2258 2008 (19-18) p -ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                            & 3rd Interval GISI Program Torus Identified Internal Pitting 3 3  3-P3-60      NIA     1    0.024  s   182     deg   13         RHR-B       x-225B   x-2258                                                 2008 3 3  3-P3-61      N/A     1    0.017  s   110     deq    12        RHR-8       x-2258   x-2258                                                 2008 3 3  3-P3-62      N/A     1    0.046  D   130     deQ   22     YES RHR-8       x-2258   x-225B CR..CNS-200~2770                                2008 3 3  3-P3-63      NIA     1    0.027  s   230     deg   37         RHR-8       x-2258   x-2258                                                 2008 3 3  3-P3~64      NIA     1    0.013  s   230     deo   34         RHR-8       x-2258   x-2258                                                 2008 3 3  3-P3-65      NIA     1    0.002  s   182     deq   18         RHR-B       x-2258   x-2258                                                 2008 3 3  3-P3-66      NIA     1    0.028  s   170     deq   24         RHR-A       X-225A   X-225A                                                 2008 3 3  3-P3-67a     SM      1    0.011  s   170     dea   29         RHR-A       X-225A   X-225A Pit oroup; 3 pits near X-225A             3     2008 3  3  3-P3-67b     SM     1     0.011  s   171     deg   30         RHR-A       X-225A   X-225A Pit group; 2 pits near X-225A             2     2008 3 3  3-P3-67c     SM      1    0.011  s   172     deq   31         RHR-A       X-225A   X-225A Pit oroup; 3 Pits near X-225A             3     2008 3 3  3-P3-68      NIA     1    0.003  s   175     deq   37         RHR-A       X-225A   X-225A                                                 2008 3 3  3-P3-69      NIA     1    0.045  D   170     deg   36     YES RHR-A       X-225A   X-225A CR-CNS-2008-2770                                2008 3 3  3-P3-7       N/A    1     0.014  s   45      deQ   26         RHR-8       X-2258   X-2258                                                 2008 3 3  3-P3-70      NIA     1    0.024  s   130     deq   29         RHR-A       X-225A   X-225A                                                 2008 3  3  3-P3-71      N/A    1     0.055  D   130     deQ   31.5   YES RHR-A       X-225A   X-225A CR-CNS-2008-2770                                2008 3  3  3-P3-72a    SM      1     0.000  s   120     deq   26         RHR-A       X-225A   X-225A Pit oroup* 3 pits near X-225A             3     2008 3  3  3-P3-72b    SM      1     0.000  s   121     deq   27         RHR-A       X-225A   X-225A Pit oroup* 2 pits near X-225A             2     2008 3  3  3-P3-73a     SM     1     0.006  s   120     deQ   18         RHR-A       X-225A   X-225A Pit Qroup; 2 pits near X-225A             2     2008 3 3  3-P3-73b     SM      1    0.006  s   121     deQ   19         RHR-A       X-225A   X-225A Pit Qroup* 2 pits near X-225A             2     2008 3  3  3-P3-74      N/A    1     0.014  s   115     deq   14.5       RHR-A       X-225A   X-225A                                                 2008 3 3  3-P3-75      NIA    1     0.014  s   115     deQ   12         RHR-A       X-225A   X-225A                                                 2008 3 3  3-P3-76a     SM      1    0.011  s   105     deQ   7.5        RHR-A       X-225A   X-225A Pit qroup: 3 pits near X-225A             3     2008 3  3  3-P3-76b     SM     1     0.G11  s   106     deq   8.5        RHR-A       X-225A   X-225A Pit qrouo: 3 Pits near X-225A             3     2008 3  3  3-P3-8       NIA    1     0.D15  s   15      deq   22.5       RHR-8       X-2258   X-2258                                                 2008 3  3  3-P3-9       NIA     1    0.009  s   45      deQ   21         RHR-8       X-225B   X-2258                                                 2008 3  3  3-P3-77      N/A    2     0.051  s   15" iw  in. 4" ro      Near RG              3/4RG                                                  200.

3 3 3-P3-78 NIA 0.049 314 RG Does not exceed re~ir threshold 2 NIA 36"iw in. 2.5" Near RG 2008 value --*1 3 3 3-P3-79 NIA 2 0.070 s 36" in. 2.5 11 Near RG 314 RG 20081 s 1 3 4 3-P4-1 N/A 2 0.061 6 ft iw ft 6 rq NearRG 3/4RG 2008 3 4 3-P4-2 NIA 2 0.059 s 6 ft iw ft 6 rq Near RG 3/4RG 2008 3 4 3-P4-3 NIA 2 0.068 s 1 iw in. 4 ra NearRG 3/4RG 2008 3 5 3-P5-1 NIA 2 0.065 s 4'1W in. 4 Near RG 2/3RG 2008 3 5 3-P5-2 NIA 2 0.048 N/A 4'1W in. 10 Near RG 2/3 RG Does not exceed repair threshold value 2008 3 5 3-P5-3 NIA 2 0.054 s 4'1W in. 10 Near RG 2/3RG 2008 3 5 3-P5-4 NIA 2 0.068 s 3.5'1W in. 6 Near RG 2/3 RG 2008 3 5 3-P5-5 NIA 2 0.055 s 32"1W in. 1 NearRG 2/3RG 2008 3 5 3-P5-6 N/A 2 0.053 s 7"1W in. 6 Near RG 2/3RG 2008 4 1 4-P1-NIA NIA 2 0.046 NIA NIA NIA NIA Torus Drain Does not exceed repair threshold value 2008 (19-19) p- '~ion 2 I

th 19.0 Containment Indication Tracking Cooper Station 5 Interval ISi rd

                                                                                                                                         & 3 Interval GISI Program Torus Identified Internal Pitting 4  1  4-P1-NIA     NIA     N/A NIA     NIA NIA    NIA  NIA        Torus Drain         No indications exceeding threshold values             2008 4  2  4-P2-1       NIA     1    0.010  s   315    dea  9"         Torus Drain X-213A  X*213A                                                2008 4  2  4-P2-2       NIA     1    0.020  s   335    dea  10"        Torus Drain X*213A  X*213A 4 pits                                         2008 4  2  4-P2-3       NIA     1    0.015  s   335    dea  17"        Torus Drain X*213A  X-213A 2 pits                                         2008 4  2  4-P2-4       NIA     1    0.010  s   30     dea  18"        Torus Drain X-213A  X-213A                                                2008 4  2  4-P2-5       NIA     1    0.010  s   40     dea  14"        Torus Drain X*213A  X-213A                                                2008 4  2  4-P2-6       NIA     1    0.010  s   50     deg  15"        Torus Drain X-213A  X*213A                                                2008 4  2  4-P2-7       NIA     1    0,015  s   60     dea  18"        Torus Drain X-213A  X-213A 3 pits                                         2008 4  2  4-P2-8       NIA     1    0.015  s   60     dea  8"         Torus Drain X.-213A X-213A                                                2008 4  2  4-P2-9       N/A     1    0.010  s   90     deQ  13"        Torus Drain X-213A  X-213A                                                2008 4  2  4-P2-NIA     NIA     N/A NIA     NIA NIA    NIA  NIA        Torus Drain         No Indications exceeding threshold values             2008 4  3  4-P3-NIA     NIA     NIA NIA     NIA NIA    NIA  NIA        Torus Drain         No indications exceeding threshold values             2008 4  4  4-P4-1       NIA     1    0.Q15  s   115    deq  18"        Torus Drain X-213A  X-213A2 pits                                          2008 4  4  4-P4-2       NIA     1    0.010  s   115    deq  15"        Torus Drain X-213A  X-213A                                                2008 4  4  4-P4-3       NIA     1    0.010  s 150      deg  15"        Torus Drain X-213A  X-213A                                                2008 4  4  4-P4-4       NIA     1    0.049  D   180    deg  12"    YES Temp. Monit X-300D  X-300D CR-CNS-2008-02650                              2008 4  5  4-P5-1       NIA     1    0.010  s   200    dea  17"        Torus Drain X-213A  X-213A                                                2008 4  5  4-P5-2       NIA     1    0.011  s   225    deq  16"        Torus Drain X-213A  X-213A                                                2008 4  5  4-P5-3       NIA     1    0.010  s   230    dea  16"        Torus Drain X.-213A X-213A                                                2008 4  5  4-P5-4       NIA     1    0.015  s   250    deg  1"         Torus Drain X-213A  X*213A 2 pits                                         2008 5  4  5-P4-1       NIA     2    0.062  s   6 1 IW N/A  12"RG      Near RG             5/6 rg                                                2008 5  4  5-P4-2       NIA     2    0.046  NIA 6'1W   N/A  12"RG      Near RG             5/6 RG Does not exceed repair threshold value         2008 5  4  5-P4-3       NIA     2    0.057  s   9'6"1W NIA  12"RG      Near RG             5/6 rg                                                2008 6  1  6-P1-10      NIA     1    0.007  s   20     deo  15.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-11      NIA     1    0.002  s   20     deq  12.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-12      N/A     1    0.009  s   25     deg  14.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-13      NIA     1    0.004  s   25     dea  11.25"     RCIC        X..224  X-224                                                 2008 6  1  6-P1-14      N/A     1    0.002  s   26     deg  10.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-15      NIA     1    0.001  s   25     deg  1611       RCIC        X-224   X-224                                                 2008 6  1  6-P1-16      N/A     1    0.001  s   25     dea  17.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-17      NIA     1    0.001  s   25     dea  18"        RCJC        X-224   X-224                                                 2008 6  1  .6-P1-18     NIA     1    0.016  s   27     deo  10.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-19      NIA     1    0.003  s   35     deq  7.25"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-20      NIA     1    0.030  s   95     deg  18.5"      RCIC        X-224   X-224                                                 2008 6  1  6-P1-21      N/A     1    0.030  s   120    deg  18.75      RCJC        X-224   X-224                                                 2008 6  1  6-P1-22      NIA     1    0.030  s   170    dea  17.5       RCIC        X-224   X-224                                                 2008 6  1  6-P1-23      N/A     1    0.030  s   185    dea  17"        RCIC        X-224   X-224                                                 2008 6  1  6-P1-24      NIA     1    0.030  s   190    deg  13"        RCIC        X-224   X-224                                                 2008 (19-20)                                                                                               p   *,ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                       & 3 Interval GISI Program Torus Identified Internal Pitting 6  1  6-P1-25      NIA     1    0.030  s   190 6  1  6-P1-26      NIA     1    0.030  s   195    deg   1811        RCIC          X-224 6  1  6-P1-27      NIA     1    0.030  s   200    deg   1.51'       RCIC          X-224   X-224 6  1  6-P1-28      NIA     1    0.030  s   250    deg   15"         RCIC          X-224   X-224            2008 6  1  6-P1-29      NIA     1    0.030  s   255    deg   19.5"       RCIC          X-224   X-224            2008 6  1  6-P1-3       NIA     1    0.012  s 5        deg   19"         RCIC          X-224   X-224            2008 6  1  6-P1-30      NIA     1    0.030  s 310      dei:, 5"          RCIC          X-224   X-224            2008 6  1  6-P1-31      N/A     1    0.030  s 330      deg   13.5"       RCIC          X-224   X-224            2008 6  1  6-P1-4       NIA     1    0.010  s 7        deg   1.5"        RCIC          X-224   X-224            2008 6  1  6-P1-5       NIA     1    0.013  s 7        deg   12.5"       RCIC          X-224   X-224            2008 6  1  6-P1-6       N/A     1    0:000  s   1      deg   13.5"       RCIC          X-224   X-224            2008 6  1  6-P1-7       NIA     1    0.000  s   1      deg   13.5"       RCIC          X-224   X-224            2008 6  1  6-P1-8       NIA     1    0.006  s 15       deg   3"          RCIC          X-224   X-224            2008 6  1  6-P1-9       NIA     1    0.008  s 20       deg   5.5"        RCIC          X-224   X-224            2008 6  1  6-P1-1       NIA     2    0.076  s   40"1W  In. 5.5" RIG    NearRG                5/6 RIG          2008 6  1  6-P1-2       NIA     2    0.073  s 23"1W    In. 2"RIG       NearRG                5/6 RIG          2008 6  3  6-P3-NIA     NIA     NIA  NIA    NIA NIA    NIA   NIA         HPCI                  X-226            2008 6  4  6-P4-1       NIA     1    0.030  s   300    deg   2"          Temp. Monit. X-300E   X-300E           2008 6  4  6-P4-2       NIA     1    0.030  s   120    deg 11.5       I !Temp. Monit. IX-300E IX-300E     I    12008 6  4  6-P4-3       NIA     1    0.030  s   180    deg   2"          Temp. Monit. X-300F   X-300F           2008 7  1  7-P1-1       N/A     2    0.069  s   7.5"1W In. 7.5" RIG    Near RG               7/6 RG           2008 7  1  7-P1-2       N/A     2    0.053  s   6"1W   In. 8"R/G       Near RG               7/6 RIG          2008 7  1  7~P1-3       NIA     2    0.055  s   4.5"1W In. 7.5" R/G    Near RG               7/SRG            2008 7  1  7-P1-4       NIA     2    0.061  s   3"1W   In. 5.5" RIG    Near RG               716 RIG          2008 7  1  7-P1-5       NIA     2    0.063  s   9"1W   In. 11.5 RIG    NearRG                7/6RG            2008 7  1  7-P1-N/A     NIA     2    0.019  N/A NIA    NIA   N/A         NearRG                N/A              2008 7  1  7-P1-N/A     NIA     2    0.022  NIA NIA    N/A   NIA         Near RG               NIA              2008 7  1  7-P1-6       NIA     3    0.041  NIA 50     Deg   22          Liciuid Level         X-206B           2008 7  3  7-P3-1       NIA     2    0.060  s   35.51W In. 11.5 R/G    Near RG               7/8 RG           2008 7  3  7~P3-2       N/A     2    0.061  s   271W   In. 9.5 RIG     Near RG               7/8 RIG          2008 7  3  7-P3-3       NIA     2    0.064 s    131W   In. 11.5 R/G    Near RG               7/8RG            2008 7  4  7-P4-NA      NIA     3    0.000                               Gen Shell             0                2008 7  5  7-P5-1       N/A     2    0.056  s   29.51W In.   ?"RIG       NearRG                7/6RG            200~

(19-21) p- -:~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                  & 3 rd Interval CISI Program Torus Identified Internal Pitting 7   5  7-P5-2       NIA     2     0.064  s    6"IW      In.

11.5" RIG Near RG 7/6 RIG 2008 7 5 7-P5-3 NIA 2 0.062 s 5.5"IW In. 9"R/G NearRG 7/6 R/G 2008 36" from 8 1 8-P1-N/A NIA 3 0.071 NIA 48"IW In. Gen Shell 0 2008 RG 18" from 8 13 l8-P3-N/A IN/A 13 I0.080 IN/A 148" IW lln. IRG I IGen Shell I lo I 12008 96" from 8 13 l8-P3-N/A IN/A 13 I0.089 IN/A 136" IW lln. 1 1 !Gen Shell I lo I 12008 RG 96" from 8 13 l8-P3-N/A IN/A 13 I0.090 IN/A 136" IW lln. I.BfL_ I IGen Shell I lo I 12008 2" FROM I lo 12008 9 15 l9-P5-NA IN/A 13 I0.075 IN/A 148" IW In. 4/5WS IGen Shell I I 11 11 I 11-P1 -N/A IN/A 13 I0.086 IN/A I~~ 1 -2 N/A 48"WL Gen Shell 0 2008 11 14 l11-P4-1 IN/A 12 I0.060 IS l54"IW In. 6.25" RG Near RG 11/12 r/g 2008 11 14 l11-P4-2 N/A 2 0.062 s 50.5"IW In. 7.75" RG Near RG 11/12 r/g 2008 11 4 11-P4-3 N/A 2 0.067 s 45.5"IW In. 7.75" RG Near RG 11/12r/g 2008 11 4 11-P4-4 NIA 2 0.073 s 46IW In. 7"RG Near RG 11/12 rig 2008 11 4 11-P4-5 N/A 2 0.061 s 7"IW In. 3.25" RG NearRG 11/12 rig 2008 11 14 I 11-P4-6 IN/A 12 O.G78 s 27/8" IW In. 5.75" RG Near RG 11/12 rig 2008 7-3/4" 11 4 11-P4-7 NIA 2 0.063 s 3.5"IW In. RG NearRG 11/12 r/g 2008 11 5 11"'.P5-1 NIA 2 0.075 s 47"IW In. 3.5"RG NearRG 11/10 rg 2008 11 5 11-P5-2 NIA 2 0.059 s 43"IW In. 4.5"RG NearRG 11/10 rg 2008 11 5 11-P5-3 NIA 2 0.062 s 45.5"IW In. 9.5"RG Near RG 11/10 rg 2008 11 5 11-P5-4 NIA 2 0.055 s 321W In. 3.5"RG Near RG 11/10 rg 2008 12 1 12-P1-1 NIA 2 0.052 s 57IW In BRG Near RG 12111 rig 2008 12 1 12-P1-2 N/A 2 0.066 s 59.5IW In 7RG NearRG 12/11 rg 2008 12 1 12-P1-3 NIA 2 0.055 s 50.51W In 6.75RG NearRG 12/11 rg 2008 12 1 12-P1-4 NIA 2 0.053 s 50.5 In 7RG NearRG 12/11 rg 2008 12 1 12-P1-5 NIA 2 0.058 s 44.5IW In 9.25 RG NearRG 12/11 rg 2008 12 1 12-P1*6 NIA 2 0.068 s 46 IW In 10.5 RG Near RG 12/11 rg 2008 12 2 12-P2-1 NIA 1 0.002 s 1 deg 16 Torus Drain X*213B X-213B 2008 (19-22) Rt:1vision 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                        & 3rd Interval CISI Program Torus Identified Internal Pitting 12 2  12-P2-10     NIA     1    0.002  s 325    deQ    4 12 2  12-P2-11     NIA     1    0.002  s 315    dea    1         Torus Drain    X-2136   X-2136            2008 12 2  12-P2-12     NIA     1    0.002  s 10     deQ    4.25      Torus Drain    X-2138   X-213B            2008 12 2  12-P2-13     NIA     1    0.002  s 12     deg   6          Torus Drain    X-2138   X-213B            2008 12 2  12-P2-14     NIA     1    0.002  s 90     deq   0.25       Torus Drain    X-2136   X-213B            2008 12  2  12-P2-2      NIA     1    0.002  s 2      deo    16        Torus Drain    X-2138   X-213B            2008 12 2  12-P2-3      N/A     1    0.002  s 275    deq   9.75       Torus Drain    X-213B   X-213B            2008 12 2  12-P2-4      NIA     1    0.002  s 276    deq   9.5        Torus Drain    X-213B   X-213B            2008 12  2  12-P2-5      N/A     1    0.002  s 290    deg   9.5        Torus Drain    X-2138   X-213B            2008 12  2  12-P2-6      NIA     1    0.002  s 300    dea   13         Torus Drain    X-213B   X-213B            2008 12  2  12-P2-7      N/A     1    0.002  s 315    deq   9          Torus Drain    X-213B   X-213B            2008 12  2  12-P2-8      NIA    1     0.002  s 325    deg   10         Torus Drain    X-2138   X-213B            2008 12  2  12-P2-9      N/A     1    0.002  s 350    dea   17.5       Torus Drain    X-213B   X-2138            2008 12  2  12-P2-NA     NIA    3     0.000  s        In               Gen Shell               0                 2008 12  3  12-P3-1      NIA    2     0.057  s 121W   In    6.75 RG    NearRG                  12/13 rg          2008 12  3  12-P3-2      NIA    2     0.055  s 561W   In    9RG        NearRG                  12113 rg          2008 12  3  12-P3-3      NIA    2     0.053  s 45.51W In    9.5RG      NearRG                  12/13 rg          2008 12  3  12-P3-4      NIA    2     0.054  s 431W   In    8RG        NearRG                  12/13 rg          2008 12  4  12-P4-10     N/A    1     0.002  s 135    ctea  13.5       Torus Drain    X-213B   X-2138            2008 12  4  12-P4-11     N/A    1     0.002  s 135    deQ   4.5        Torus Drain    X-2138   X-213B            2008 12  4  12-P4-12     N/A    1     0.002  s 110    deg   6.75       Torus Drain    X-213B   X-2138            2008 12  4  12-P4-13     NIA    1     0.002  s 170    dea   4          Torus Drain    X-213B   X-213B            2008 12  4  12-P4-14     N/A    1     0.002  s 165    cteo  4.5        Torus Drain    X-213B   X-213B            2008 12  4  12-P4-4      N/A    1     0.002  s 5      deg   8          Temp. Mon it. X-300 L   X-300  L          2008 12  4 12-P4-5       NIA    1     0.004  s 85     deg   12         Temp. Mon it. IX-300 L IX-300 L    I     12008 12  4  12-P4-6     NIA     1     0.006  s 60     deg 112       I ITemp. Mon it. IX-300 L IX-300 L    I     12008 12  4  12-P4-7      NIA    1     0.005  s 70     deg l3        I !Temp. Monit. IX-300 L  IX-300  L   I     12008 12 4   12-P4-8      NIA    1     0.002  s 25     deg   7          Temp. Monit. X-300 K    X-300 K           2008 12 4   12-P4-9      NIA    1     0.002  s 100    dea   16         Torus Drain    X-213B   X-2138            2008 12 4  12-P4-1       N/A    2     0.059  s 231W   In    12 RG      NearRG                  12/13 rg          2008 12 4  1.2-P4-2      NIA    2     0.058  s 321W   In    11.5 RG    NearRG                  12113 rg          2008 12 4  12-P4-3      N/A     2     0.058  s 741W   In    10.5 RG    Near RG                 12/13 rg          2008 12 5   12-P5-1      NIA    1     0.002  s 190    deg   7.5        Torus Drain    X-2138   X-213B            2008 12 5  12-P5-2       N/A    1     0.002  s 235    deq   2          Torus Drain    X-213B   X-213B            2008 (19-23)                                                                P   'ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                        & 3 Interval CISI Program Torus Identified Internal Pitting

[x-zfas - -- ------ ------------

   ~                  IN/A    !1   !0.002 !S !230   ldeg  I~       !Torus Drain                                        7 I      j2ooa 1 12 5  12-P5-0      NIA     3    <0.030 S                        Gen Shell           0                                        2008 14 2  14-P2-10     NIA     1    0.017  s  200    deg   26"      HPCI        X-226   X-226                                    2008 14 2  14-P2-2      NIA     1    0.017  s  180    dea   30"      HPCI        X-226   X-226                                    2008 14 2  14-P2-2      NIA     1    0.017  s  200    dea   26"      HPCI        X-226   X-226                                    2008 14 2  14-P2-3      NIA     1    0.017  s  180    deg   30 11 HPCI        X-226   X-226                                    2008 14 2  14-P2-4      NIA     1    0.017  s  190    dea   24"      HPCI        X-226   X-226                                    2008 14 2  1.4-P2-5     NIA     1    0.017  s  190    dea   26"      HPCI        X-226   X-226                                    2008 14 2  14-P2-6      NIA     1    0.017  s  190    deg   26"      HPCI        X-226   X-226                                    2008 14 2  14-P2-7      NIA     1    O.D18  s  190    dea   28"      HPCI        X-226   X-226                                    2008 14 2  14-P2-8      NIA     1    0.018  s  190    deg   29"      HPCI        X-226   X-226                                    2008 14 3  14-P3-1      NIA     1    0.019  s  30     deg   14"      HPCI        X-226   X-226                                    2008 14 3  14-P3-2      NIA     1    0.020  s  30     deg   13"      HPCI        X-226  X-226                                     2008 14 3  14-P3-3      NIA     1    0.019  s  60     deg   15"      HPCI        X-226   X-226                                    2008 14 3  14-P3-4      NIA     1    0.018  s  150    deg   32"      HPCI        X-226   X-226                                    2008 14 3  14-P3-5      NIA     1    0.019  s  150    dea   32"      HPCI        X-226   X-226                                    2008 15 1  15-P1-1      N/A     1    0.025  s  235    dea   20.5"    RHR-C       X-225C X-225C                                    2008 15 1  15-P1-10     NIA     1    0.010  s  170    dea   30.5"    RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-11     NIA     1    0.010  s  120    dea   16.75"   RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-12     NIA     1    0.004  s  110    deg   24.75"   RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-13     NIA     1    0.003  s  110    deQ   12"      RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-14     NIA     1    0.022  s  112    dea   10 318"  RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-15     N/A     1    0.025  s  75     deo   14.5"    RHR-C       X*225C  X-225C                                   2008 15 1  15-P1-16     NIA     1    0.010  s  75     deo   29.75"   RHR-C       X-225C X-225C                                    2008 15 1  15-P1-17     NIA     1    0.015  s  60     dea   30"      RHR-C       X-225C  X*225C                                   2008 15 1  15-P1-18     NIA     1    0.010  s  50     dea   29.75"   RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-19     NIA     1    0.015  s  50     dea   10.25"   RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-2      NIA     1    0.020  s  235.5  deo   20.5     RHR-C       X-225C X-225C                                    2008 15 1  15-P1-20     N/A     1    0.005  s  2      dea   9.5"     RHR-C       X-225C  X-225C 4 pits                      4     2008 15 1  15-P1-21     N/A     1    0.005  s  2      deq   16"      RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-22     NIA     1    0.003  s  2      deq   29"      RHR-C       X-225C X-225C                                    2008 15 1  15-P1-23     NIA     1    0.005  s  360/0  deg   27.7511  RHR-C       X-225C X-225C                                    2008 15 1  15-P1-24     NIA     1    0.010  s  355    dea   23.5"    RHR-C       X-225C X-225C                                    2008 15 1  15-P1-25     NIA     1    0.005  s  350    deo   21.5"    RHR-C       X-225C X-225C                                    2008 15 1  15-P1-26     N/A     1    0.003  s  345    dea   23.75"   RHR-C       X-225C X-225C 3 pits                       3     2008 15 1  15-P1-27     NIA     1    0.010  s  335    dea   31"      RHR-C       X-225C X-225C                                    2008 15 1  15-P1-28     N/A     1    0.015  s  320    deg   34.5"    RHR-C       X-225C  X-225C                                   2008 15 1  15-P1-29     NIA     1    0.015  s  300    deq   28"      RHR-C       X-225C  X-225C                                   2008 (19-24)                                                                               p '<:iion 2 I

19.0 Containment Indication Tracking Cooper Station 5 th Interval ISi

                                                                                                                                 & 3 rd Interval CISI Program Torus Identified Internal Pitting 15  1  15-P1-3      NIA     1    0.010  s   234 15  1  15-P1-30     NIA     1    0.003  s   225      dea   27 718"        RHR-D         X-225D   X-225D                              2008 15  1  15-P1-31     NIA     1    0.010  s   315      deq   33.5"          RHR-D         X-225D   X-225D                              2008 15  1  15-P1-32     NIA     1    0.010  s   312      deg   32.5"          RHR-D         X-225D   X-2250                              2008 15  1  15-P1-33     NIA     1    0.010  s   312      dea   13.75"         RHR-D         X-225D   X-2250                              2008 15  1  15-P1-4      NIA     1    0.005  s   230      deo   25.75"         RHR-C         X-225C   X-225C                              2008 15  1  15-P1-5      NIA     1    0.003  s   200      deg   25.25"         RHR-C         X*225C   X-225C                              2008 15  1  15-P1-6      NIA    1     0.015  s   190      dea   20.75"         RHR-C         X-225C   X-225C                              2008 15  1  15-P1-7      NIA    1     0.039  D   170      deQ   15.5"      YES RHR-C         X-225C   X-225C  CR..CNS-2008-2770           2008 15  1  15-P1-8      NIA     1    0.020  s   165      dea   16.75"         RHR-C         X-225C   X-225C                              2008 15  1  15-P1-9      NIA     1    0.010  s   170      dea   35.25"         RHR-C         X-225C   X-225C                              2008 15  1  15-P1-0      NIA    3     0.000  NIA                               Gen Shell              0                                   2008 15  2  15-P2-1      NIA    1     0.003  s   115      deQ   19 11 RHR-D         X-225D   X-225D                              2008 15  2  15-P2-2      NIA    1     0.005  s   45       deQ   23.75"         RHR-D         X-225D   X-225D                              2008 15  2  15-P2-0      NIA    3     0.000  NIA                               Gen Shell              0                                   2008 15  4  15-P4-1      NIA    2     0.051  s   3.25" iw in    5.25" ro       NearRG                 15/16 RG                            2008 15  4  15-P4-0      NIA    3     0.000  NIA                               Gen Shell              0                                   2008 16  1  16-P1-1      NIA    2     0.065  s   21"1W    in    8"RG           Near RG                15/16 RG                            2008 6 318" 16 1   16-P1-2      NIA    2     0.060  s   37.5"1W  in RG NearRG                 15/16 RG                            2008 16  1  16-P1-3      NIA    2     0.059 s    57"1W    in    12RG         NearRG                 15/16 RG                            2008 16  1  16-P1-4      NIA    2     0.054 S    87"1W    in    7.5"RG         Near RG                15/16 RG                            2008 16  1  16-P1-0      N/A    3     0.000                                    Gen Shell              0                                   2008 16  3  16-P3-1      NIA    2     0.064 S    63"1W    in    3.5"RG         Near RG                16/1 RG                             2008 16 3   16-P3-2      NIA    2     0.066  s   33.5"1W  in    8.25"RG        NearRG                 16/1 RG                             2008 16 3   16-P3-0      NIA    3     0.000 s             in                   Gen Shell              0                                   2008 16 4   16-P4-10     NIA    1     0.004  s   235      deg   12.5"          Temp. Monit. X-300 P   X-300 P                             2008 16 4   16-P4-11     NIA    1     0.009  s   240      deg  113"      I    !Temp. Monit. IX-300 P IX-300 P                     I      12008 16 4    16-P4-12     NIA    1     0.005  s   250      deg  112"      I    !Temp. Monit. IX-300 P IX-300 P                     I      12008 16 4   16-P4-13     N/A    1     0.005  s   265      deg 111"       I    !Temp. Monit. IX-300 P IX-300 P                     I      12008 16 14   16-P4-14     NIA    1     0.005  s   265      deg  112.5"    I    !Temp. Monlt. IX-300 P IX-300 P                     I      12008 16  14 16-P4-15      NIA    1     0.005  s   270      deg  112.75"   I    !Temp. Monit. IX-300 P IX-300 P                     I      12008 (19-25)                                                                                      P  *~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                        &3      Interval GISI Program Torus Identified Internal Pitting 16  4  16-P4-16     N/A     1    0.010  s  250   deg 19.25"    I jTemp. Monit. IX-300 P IX<~00 P    I       12008 16  4  16-P4-17     N/A     1    0.028  s  210   deg 113"      I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-18     NIA     1    0.028  s  180   deg 113"      I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-19     N/A     1    0.028  s  210   deg 111"      I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-2      N/A     1    0.001  s  360/0 deg 17      I jTemp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-20     NIA     1    0.028  s  210   deg 15"       I jTemp. Monit. IX-300 P IX-300 P    I       12008 16 14  16-P4-21     NIA     1    0.028  s  225   deg 13"       I !Temp. Mon it. IX-300 P IX-300 P   I       12008 16  4  16-P4-22     NIA     1    0.028  s  150   deg 18"       I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-23     NIA     1    0.028  s  90    deg 13"       I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-24     NIA     1    0.010  s  60    deg   113"    I !Temp. Mon it. IX-300 P IX-300 P   I       12008 16  4  16-P4-25     NIA     1    0.010  s  30    deg 111"      I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-3      NIA     1    0.001  s  359   deg 13.75"    I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-4      NIA     1    0.001  s  25    deg 16.25"    I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-5      N/A     1    0.001  s  45    deg 16.25"    I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-6      N/A     1    0.005  s  170   deg 14.25"    I !Temp. Monit. IX-300 P IX-300 P    I       12008 16  4  16-P4-7      N/A     1    0.010  s  190   deg 112"      I !Temp. Monit. IX-300 P IX-300 P    I       12008 16 14 116-P4-8      N/A     1    0.003  s  215   deg 113"      I !Temp. Monit. IX-300 P IX-300 P    I       12008 16 14 he-P4-9       N/A     1    0.010  s  220   deg    12.75" I !Temp. Monit. IX-300 P IX-300 P    I       12008 11.25" 16  4  16-P4-1      N/A     2    0.066  s  96"1W in               Near RG                 16/1 RG            2008 RG 16  4  16-P4-0      NIA     3    0.000  s                         Gen Shell               0                  2008 1   1  375-81-1     SM      3    0.005  NA                        Gen Shell                           30     2011 2   3  364-82-1             3    0.040  NA                        Gen Shell                           1      2011 (19-26)                                                                   P  **ision 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                                         & 3rd Interval CISI Program Torus Identified Internal Pitting 2  3  365-B2-I             3    0.052  NA                            Gen Shell                                                         1     2011 3  5  356-B3-I     SM      3    0.005  NA                            Gen Shell           overall for Plate 5                           10    2011 3  5  355-83-1             2    0.060  NA   7" RG    In     45       Near RG            Same as marked old indication                  1     2011 20"PW                                       76"from ringe girder 4/5 44"dwn from 4  4  336-84-1     LG      3    0.005  NA            In     44"WL    Gen Shell                                                         200 2011 4/5                                         waterline 5  5  316-85-1     LG      3    0.045  NA                            Gen Shell           AvQ 45 mils                                   60    2011 5  2  293-B5-I     LG      3    0.035  NA                            Gen Shell          Average pitting at IW                          40    2011 5  4  306-B5-1     LG      3    0.005  NA                            Gen Shell          overall for plate 4                            35    2011 5  3  297-85-1     SM      3    0.005  NA                            Gen Shell                                                         25    2011 5  1  282-85-1             3    0.060  NA                            Gen Shell                                                         1     2011 5  1  283-85-1             3    0.050  NA                            Gen Shell                                                         1     2011 5  1  284-85-1             3    0.055  NA                            Gen Shell                                                         1     2011 5  1  286-85-1             3    0.070  NA                            Gen Shell                                                         1     2011 5  2  291-B5-l             3    0.050  NA                            Gen Shell                                                         1     2011 5  2  292-B5-l             3    0.055  NA                            Gen Shell                                                         1     2011 5  4  301-85-1             3    0.058  NA                                               midway down from waterline 18" from ring Gen Shell                                                         1     2011 girder 5 14 1302-B5-l            13   I0.065 INA I               I       I                    Imidway down from waterline 18" from ring I                                I                 !Gen Shell I        girder 11    12011 5  4  303-B5-I             3    0.065  NA                                               midway down from waterline 18" from ring Gen Shell                                                         1     2011 1girder 5  3  296-85-1     SM      3    0.005  NA                            Gen Shell                                                         4     2011 5  5  310-85-1             3    0.063  NA                            Gen Shell                                                         1     2011 5  5  311-85-1             3    0.070  NA                            Gen Shell                                                         1     2011 5  5  312-85-1             3    0.075  NA                            Gen Shell                                                         1     2011 5  5  313-85-1             3    0.070  NA                            Gen Shell                                                         1     2011 5  5  314-85-1             3    0.070  NA                            Gen Shell                                                         1     2011 7  1  249-87-1     SM      1    0.017  s   180      Deg    30"PN     CS-A       X-227A CS-A X-227 A defect in old .coating repair      6     2011 8  1  226-88-1             3    0.062  NA                            GenSheU                                                           1     2011 8  1 227-88-1              3    0.060  NA                            Gen Shell                                                         1     2011 8  1 228-88-1              2    0.056  s   3.5RG    In     8 IW      Near RG                                                           1     2011 8  2 230-88-1              3    0.058  NA                                               Location half way up from IW (first one found Gen Shell                                                         1     2011 in that gen location) 8  2  231-88-1             3    0.070  NA                            Gen Shell                                                         1     2011 8  2 232-88-1              3    0.070  NA                            Gen Shell                                                         1     2011 8  2 233-88-1              3    0.060  NA                            Gen Shell                                                         1     2011 8 3  237-88-1              3    O.D78  NA                            Gen Shell                                                         1     2011 8  3 238-88-1              2    0.070  s   8.5RG   In      47.51W    Near RG                                                           1     2011 8 3  239-88-1              2    0.070  s   7RG     In      491W      Near RG                                                           1     2011 (19-27)                                                                                              p    ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                   & 3 Interval CISI Program Torus Identified Internal Pitting 9   2  203-B9-I     LG      3     0.050  NA                             Gen Shell Avq 50 mils at IW                               45    2011 9   5  221-89-1     LG      3     0.045  NA                             Gen Shell overall pit count and depth in area             40    2011 9   1  197-B9-I             3     0.065  NA                             Gen Shell                                                 1     2011 9   1  198-B9-I             3     0.056  NA                             Gen Shell                                                 1     2011 9   2  201-89-1             3     0.075  NA                             Gen Shell                                                 1     2011 9   2  202-B9-I             3     0.056  NA                             Gen Shell                                                 1     2011 9   3  205-89-1             3     0.062  NA                             Gen Shell                                                 1     2011 9   3  206-B9-I             3     0.075  NA                             Gen Shell                                                 1     2011 9   3  207-B9-I             3     0.065  NA                             Gen Shell Coating to the right gives high dft reading     1     2011 9   4  212-89-1             3     0.060  NA                             Gen Shell                                                 1     2011 9   4  213-89-1             3     0.065  NA                             Gen Shell Previously noted lamer than 66 mils             1     2011 9   4  214-89-1             2     0.045  NA                             Near RG                                                   1     2011 9   4  215-89-1             3     0.064  NA                             Gen Shell                                                 1     2011 9   5  21S.B9-I             3     0.065  NA                             Gen Shell                                                 1     2011 9   5  219-89-1             3     0.061  NA                             Gen Shell                                                 1     2011 9   5  220-89-1             3     0.067  NA                             Gen Shell                                                 1     2011 10  5  187-810-- LG         3     0.005  NA                             Gen Shell Gen area of pittlno averaae mil of 5 to 1O      50    2011 10  5  188-810--            3     0.048  NA                             Gen Shell                                                 1     2011 10  2  170-810-- SM         3     0.058  NA  72 PW 2/3 In      24       Gen Shell                                                 5     2011 10  2  171-810-- SM         3     0.073  NA  72 PW2/3 In       0        Gen Shell                                                 3     2011 11  1  137-811--            3     0.065  NA                             Gen Shell                                                 1     2011 11  1  139-811--            2     0.072  s   10 RG      In     43IW     NearRG                                                    1     2011 11  1  140-811--            2     0.055  s   11.5 RG    In     36IW     Near RG                                                   1     2011 11  3  152-B11-- SM         3     0.005  NA  20 PW2/3 In       40IW     Gen Shell                                                 25    2011 11  3  147-811-- SM         3     0.057  NA  16RG       In     155IW    Gen Shell Included in line 147                            3     2011 11  3  146-811-- SM         3     0.030  NA  15RG       In     155IW    Gen Shell                                                 2     2011 11  3  148-811-- SM         3     0.050  NA  7 PW2/3    In     139IW    Gen Shell                                                 2     2011 12  1  100-812--            3     0.040  NA                             Gen Shell                                                 1     2011 12  1  101-812--            3     0.052  NA                             Gen Shell                                                 1     2011 12  1  102-812--            3     0.064  NA                             Gen Shell                                                 1     2011 4.5" from RG11/12 & 36" from IW / Overall 12 11 1104-812--   I       12    lo.033 INA 14.5 RG    l1n    l361W  I !Near RG   area of plate 1 exhibits general surface       11    12011 corrosion 12 3   120-812--            2     0.000  NA                             Near RG                                                   1     2011 12 3   122-812--            3     0.021  NA                             Gen Shell                                                 1     2011 14 1   65-814--             2     0.031  NA                             Near RG   overall Isolated areas of corrosion             1     2011 (19-28)                                                                                  p  *ision 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                                    & 3 Interval CISI Program Torus Identified Internal Pitting 14  2  68-B14-              3    0.030   NA                             Gen Shell                                                                 1     2011 14  3  73-B14--            3     0.030   NA                             Gen Shell                                                                 1     2011 14  3  74-B14--            3     0.065   NA                             Gen Shell                                                                1      2011 15   1  36-B15-             3     0.067   NA                             Gen Shell                                                                1      2011 15   1  37-B15-              3    0.079   NA                             Gen Shell                                                                1      2011 15   2  42-B15--            3     0.085   NA                             Gen Shell                                                                1      2011 15   3  43-B15-             3     0.030   NA                             Gen Shell                                                                1      2011 15   3  44-815--            3     0.000   NA                             Gen Shell    20 mils                                                     1      2011 15   5  51-B15--            2     0.060   s   6RG        In    50IW      Near RG                                                                  1      2011 15   3  59-B15--            3     0.060   NA                             Gen Shell                                                                1      2011 16   1  3-816--             3     0.000   NA                             Gen Shell                                                                1      2011 16   1  5-B16--             3     0.048   NA                             Gen Shell                                                                1      2011 16   1  6-B16--             3     0.057   NA                             Gen Shell                                                                1      2011 16   1  7-816--             2     0.058   s   6RG        In    85IW      Near RG                                                                  1      2011 16   1  8-816--             3     0.042   NA                             Gen Shell                                                                1      2011 16   2  12-816--            3     0.062   NA                             Gen Shell                                                                1      2011 16   2  13-816--            3     0.060   NA                             Gen Shell                                                                1      2011 16   3  16-B16--            3     0.065   NA                             Gen Shell                                                                1      2011 16   4  21-816--            3     0.065   NA                             Gen Shell                                                                1      2011 16   4  22-816--            3     0.072   NA                             Gen Shell                                                                1      2011 16   5  24-816-             3     0.062   NA                             Gen Shell                                                                1      2011 16   5  25-B16--            3     0.064   NA                             Gen Shell                                                                1      2011 16   5  26-B16-             3     0.070   NA                             Gen Shell                                                                1      2011 16   5  28-'B16--           2     0.055   s   10.25 RG   In    26IW      Near RG      Left of RG 15/16                                            1      2011 16   5  29-816--            2     0.058   s   10RG       In    36.5IW    NearRG       Left of RG 15/16                                            1      2011 16   2  14-B16--    SM      3     0.030   NA                             Gen Shell                                                                10     2011 1    5  83-B1-1     NIA     2     0.055   s   10RG      In     8"1W      Near RG      RIG 1/16                                                    1      2012 1    5  84-81-1     NIA     2     0.052   s   8RG       In     6°IW      Near RG      R/G 1/16                                                    1      2012 2    1  8-82-1      N/A     2     0.055   s   10 RG      In    121 IW    Near RG      right of 1/2 RG; Match# on Shell with Indication ID: 2-1-1  1      2012 2   11 19-B2-I     IN/A    12    10.060  IS  l12RG     lln    1111Iw right of 1/2 RG; Match # on Shell with lndicatlon ID: 2                                                                              Near RG                                                                 11     12012 2

right of 1/2 RG; Match# on Shell with Indication ID: 2 2 11 110-82-1 IN/A 12 10.058 IS l6RG lln l63IW I !Near RG 3 11 12012 2 11 111-B2-I N/A 2 0.056 s 5RG In right of 1/2 RG; Match# on Shell with Indication ID: 2 46IW Near RG 11 12012 4 2 11 112-B2-I N/A 2 0.064 s 10RG In 39IW Near RG right of 1/2 RG; Match# on Shell with Indication ID: 2-1-511 12012 2 11 113-B2-I IN/A 12 10.055 IS 111 RG lln l39IW I !Near RG I l~ght of 112 RG; Match # on Shell with Indication ID: 2 11 po12 I (19-29) p *~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                             & 3 Interval GISI Program Torus Identified Internal Pitting 2 13 114-82-1     IN/A    12    0.050   s  9RG    In     130IW    Near RG    left of 2/3 RG; Match # on Shell with Indication ID: 2-3-7 11     12012 2 13 115-B2-I     IN/A    12    0.061   s  BRG    In     62IW     NearRG     left of 2/3 RG; Match # on Shell with Indication ID: 2-3*8 11     12012 2 13 116-82-1     IN/A    12   10.060   s  8RG    In     62IW     NearRG     left of2/3 RG; Match# on Shell with Indication ID: 2-3-9 11       12012 left of 2/3 RG; Match# on Shell with Indication ID: 2      2 13 117-B2-1     IN/A    12   I0.058 IS  l10RG  lln    l59IW  I INear RG                                                                11    12012 10 left of 2/3 RG; Match # on Shell with Indication ID: 2      2 13 118-B2-I     IN/A    12   10.062 IS  l9RG   lln    l59IW  I !Near RG                                                                11    12012 I  11 left of 2/3 RG; Match # on Shell with Indication ID: 2      2 13 119-B2-1     IN/A    12   I0.066  ts 110 RG lln    l49IW  I !Near RG I  15                                                          11    12012 2 13 120-82-l     IN/A         10.061 IS  l7RG          I42IW    INear RG Ileft of 2/3 RG; Match # on Shell with Indication ID: 2 11 12                     lln           I          I  16 12012 Ieft of 2/3 RG; Match # on Shell with Indication ID: , 2      2 13 121-82-1     IN/A    12   10.053 IS  111 RG lln    l36IW  I INear RG I 117                                                          11    12012 lleftof2/3 RG;   Match #on Shell with Indication ID: 2      2 13 122-82-1     IN/A    12   I0.052 IS  111 RG lln    l35IW  I INear RG I  18                                                          11    12012 1eft of 2/3 RG; Match# on Shell with Indication ID: 2      2 13 123-82-1     IN/A    12   10.054 IS  111 RG lln    l341W  I INear RG I 119                                                          11    12012 1e1t of 2/3 RG; Match# on Shell with Indication ID: 2      2 13 124-82-1     IN/A    12   I0.056  ts 110 RG lln    l301W  I INear RG I 120                                                          11    12012 Ieft of 2/3 RG; Match# on Shell with Indication ID: 2      2 13 125-B2-1     IN/A    12   10.052 IS  110 RG lln    l28IW  I !Near RG I 121                                                          11    12012 left of 2/3 RG; Match # on Shell with Indication ID: 2      2 13 126-B2-I     IN/A    12   10.054 IS  l10RG  lln    l531W  I !Near RG                                                                11    12012 I  12 left of 2/3 RG; Match # on Shell with Indication ID: 2      2 13 127-B2-I     IN/A    12   10.061  IS 111 RG lln    l56IW  I INear RG I  13 11    12012 left of 2/3 RG; Match # on Shell with Indication ID: 2      2  3  28-B2-I      NIA     2    0.062   s  11 RG  In     54IW     Near RG    14 1     2012 3  5  69-83--1     N/A     2    0.050   s  7RG    In     45"IW    Near RG    Areas off 2/3 RIG                                            1     2012 6  3  107-B6-l     N/A     2    0.065   s  7RG    In     85IW     Near RG    Left of 6/7 RG; Match # on Shell with ID: 6-3-1              1     2012 6  3  108-86-1     NIA     2    0.055   s  10 RG  In     76IW     Near RG    Left of 6/7 RG; Match # on Shell with ID: 6-3-2              1     2012 6  3  109-86-1     NIA     2    0.061   s  11 RG  In     43IW     Near RG    Left of 6/7 RG; Match # on Shell with ID: 6-3-3              1     2012 6  3  110-B6-I     NIA     2    0.060   s  11 RG  In     35IW     NearRG     Left of 617 RG; Match # on Shell with ID: 6-3-4              1     2012 6  3  111-86-1     NIA     2    0,063   s  10RG   In     341W     Near RG    Left of 6/7 RG; Match # on Shelf with ID: 6-3-5              1     2012 6  4  115-86-1     N/A     2    0.065   s  9RG    In     821W     Near RG    Right of 6/7 RG; Match # on Shell with ID: 6-4-6             1     2012 6  4  116-86-1     NIA     2    0.069   s  SRG    In     31 IW    Near RG    Right of6f1 RG; Match# on Shell with ID: 6-4-7               1     2012 6  4  117-86-1     N/A     2    0.073   s  7RG    In     11 IW    Near RG    Right of 617 RG; Match # on Shell with ID: 6-4-8             1     2012 6  5  121-B6-I     NIA     2    0.057   s  8RG    In     1081W    Near RG    Left of 6/5 RG; Match # on Shell with ID: 6-5-9              1     2012 6  5  122~86-I     N/A     2    0.057   s  5RG    In     391W     Near RG    Left of 6/5 RG; Match# on Shell with ID: 6-5-10              1     2012 6  5  123--86-1    NIA     2    0.053   s  7RG    In     37IW     Near RG    Left of 6/5 RG; Match # on Shell with ID: 6-5-11             1     2012 7  3  145-87-1     N/A     2    0.054   s  10RG   In     108IW    Near RG    Left of7/8 RG; Match# on Shell ID: 7-3-1                     1     2012 r

(19-30) *ision 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                          & 3 Interval CISI Program Torus Identified Internal Pitting 7   4  146-87-1     NIA     2    0.052 s  3RG    In   134IW     Near RG        Right of 7/8 RG; Match # on Shell ID: 7-4-2             1    2012 7   4  147-8,7-1    NIA     2    0.064 s  11 RG  In   119IW     Near RG        Right of7/8 RG; Match #on Shell ID: 7-4-3               1    2012 7   4  148-87-1     NIA     2    0.051 s  3RG    In   86IW      Near RG        Right of 7/8 RG; Match# on Shell ID; 7-4-4              1    2012 7   4  149-B7-I     NIA     2    0.072 s  8RG   In    36IW      Near RG        Right of7/8 RG; Match #on Shell ID; 7-4-5               1    2012 7   4  150-87-1     NIA     2    0.058 s  9RG    In   16IW      Near RG        Right of7/8 RG; Match #on Shell ID; 7-4-6               1    2012 7   4  151-B7-I     NIA     2    0.056 s  7RG   In    11 IW     Near RG        Right of 7/8 RG; Match# on Shell ID; 7-4-7              1    2012 7   5  152-87-1     NIA     2    0.069 s  3RG   In    31 IW     Near RG        Left of 7/6 RG; Match # on Shell ID; 7-5-8              1    2012 8   1  161-88-1     NIA     2    0.058 s  6RG   In    109IW     Near RG        Right of 8/7 RG; Match# on Shell ID: 8-1-1              1    2012 8   1  162-88-1     N/A     2    0.066 s  12RG  In    68IW      Near RG        Right of8/7 RG; Match #on Shell ID: 8-1-2               1    2012 8   5  169-88-1     NIA     2    0.060 s  8RG   In    117IW     Near RG X-300G Left of arr RG; Match # on Shell ID: 8-5-3              1    2012 8   5  170-88-1     NIA     2    0.061 s  10RG  In    47IW      Near RG        Left of 8/7 RG; Match # on Shell ID: 8-5-4              1    2012 8   5  171-88-1     NIA     2    0.052 s  9RG   In    46IW      Near RG        Left of 8/7 RG; Match # on Shell ID; 8-5-5              1    2012 8   5  172-88-1     N/A     2    0.069 s  9RG   In    33IW      NearRG         Left of 817 RG; Match # on Shell ID; 8-5-6              1    2012 Failed coating on 2005 Repair. Match# on Shell ID: 10-8  14 l1TT-88-0    IN/A    11   10.036  D 130   Deg   11 PN YES X-300G         31-12. 2nd shallower pit wihtln 1.5"                    1    2012 CR..CNS-2012-08522 9   4  186-89-1     NIA     2    0.055  s 10RG  In    6IW       Near RG        TS@ Waterline 10 #9-4-1 10" Right RG 6" Up              1    2012 9   4  187-89-1     N/A     2    0.054  s 12RG  In    41 IW     Near RG         TS @ Waterline ID # 9-4-2                              1    2012 11  1  208-B11-*    NIA     2    0.055  s 11 RG In    77IW      NearRG         ID #11-1-1                                              1    2012 11  1  209-811--    NIA     2    0.056  s 11 RG In    35IW      Near RG        10#11-1-2                                               1    2012 11  1  210-811--    NIA     2    0.054  s 11 RG In    48IW      Near RG        10#11-1-3                                               1    2012 11  3  215-B11--    N/A     2    0.056  s 8RG   In    3IW       Near RG        10#11-3-4                                               1    2012 11  3  216-B11--    NIA     2    0.052  s 11 RG In    16IW      Near RG        ID #11-3-5                                              1    2012 11  3  218-811--    N/A     2    0.059  s 7RG   In    37IW      Near RG        10#11-3-7                                               1    2012 11  3  219-B11--    N/A     2    0.062  s 8RG   In    3IW       Near RG        10#11-3-8                                               1    2012 11  3  220-811--    NIA     2    0.068  s 10RG  In    4IW       Near RG        ID #11-3-9                                              1    2012 11   5  225-811--    NIA     2    0.061  s 12RG  In    86IW      Near RG GTS@ Waterline General Isolated Corrosion ID #11                                                                                     10 5    2012 15  1  242-815--    N/A     2    0.062 s  12RG  In    10IW      Near RG X-225C Right of15/14 RG; Match# on Shell ID: 15-1-1            1    2012 15   3  243-815--    NIA     2    0.054 s  9RG   In    28IW      Near RG X-225C Left of 15/16 RG; Match# on Shell ID: 15-3-2            1    2012 15  3  244-815--    NIA     2    0.057 s  8RG   In    21 IW     NearRG  X-225C Left of 15/16 RG; Match# on Shell JD: 15-3-3            1    2012 15  3  245-B15--    NIA     2    0.062 s  11 RG In    20IW      Near RG        Left of 15/16 RG; Match #on Shell ID: 15-3-4            1    2012 15  3  246-B15--    N/A     2    0.060 s  11 RG In    20IW      Near RG        Left of 15/16 RG; Match# on Shell ID: 15-3-5            1    2012 15  3  247-815--    NIA     2    0.054 s  6RG   In    15IW      NearRG         Left of 15/16 RG; Match# on Shell ID: 15-3-6            1    2012 15   5  256-B15--    NIA     2    0.054 s  8RG   In    59IW      Near RG        Left of 15/14 RG; Match #on Shell ID: 15-5-7            1    2012 15   5  257-815--    NIA     2    0.060 s  7RG   In    59IW      Near RG        Left of 15/14 RG; Match # on Sh ell ID: 15-5-8          1    2012 15  5   258-815--    NIA     2    0.057 s  8RG   In    54IW      Near RG        Left of 15/14 RG; Match# on Shell ID: 15-5-9            1    2012 15  5   259-815--    NIA     2    0.066 s  3RG   In    51 IW     NearRG         Left of 15/14 RG; Match# on Shell ID: 15-5-10           1    2012 15  5   260-815--    NIA     2    0.060 s  6RG   In    44IW      Near RG        Left of 15/14 RG; Match# on Shell ID: 15-5-11           1    2012 (19-31)                                                                                                R- -:"ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                              & 3 Interval GISI Program Torus Identified Internal Pitting 15 5  261-B15--    NIA     2    0.053  s  6RG  In    41 IW      Near RG   Left of 15/14 RG; Match #on Shell ID: 15-5-12    1    2012 15 1  284-B15-2    NIA     1    0.022  s  90   Deg   13 PN      X-225C    13" out, 90 degrees; Match # on Shell ID: 3      1    2012 31" out, 310 degrees: Match# on Shell ID: 4 15 1  285-B15-2    NIA     1    0.035  D  310  Deg   31 PN  YES X-225C                                                     1    2012 CR-CNS-2012--08579 15 1  286-815-2    NIA     1    0.028  s  315  Deg   34 PN      X-225C    34" out, 315 degrees; Match # on Shell ID: 5     1    2012 16 5  95-816--     NIA    2     0.059 s   10RG In    36"1W      Near RG   t/S at waterline G/lSO corrosion                 1    2012 453-B1-I     NA     2     0.0503 S  7RG  In    1301W      NearRG    1-1-1 7" off RG and 130" from IW                 1    2014 454-81-1     NA     2     0.0677 S  8RG  In    21W        Near RG   1-1-2 8" off RG and 2" from IW                   1    2014 1  455-B1-1     NA     3     0.0687 NA                       Gen Shell Random pit depth                                 1    2014 1  456-B1-I     NA     3     0.0283 NA                       Gen Shell Random pit depth                                 1    2014 1  1  457-B1-I     NA     3     <0.030 NA                       Gen Shell Random pit depth                                 1    2014 1  2  459-B1-1     NA     3     0.0657 NA                       Gen Shell Random pit deoth                                 1    2014 1  2  460-B1-I     NA     3     0.0757 NA                       Gen Shell Random pit depth                                 1    2014 1  2  461-B1-1     NA     3     0.0677 NA                       Gen Shell Random pit depth                                 1    2014 1  3  463-81-l     NA     2     0.074  s  10RG In    731W       NearRG    1-3-1 1O" off RG and 73 from IW 11 1    2014 1  3  464-81-1     NA      2    0.0527 S  10RG In    151W       NearRG    1-3-2 1O" off RG and 15" from IW                 1    2014 1  3  465-B1-l     NA     3     0.0593 NA                       Gen Shell Random pit depth                                 1    2014 3  466-B1-l     NA     3     0.058  NA                       Gen Shell Random pit depth                                 1    2014 3  467-81-1     NA     3     0.0587 NA                       Gen Shell Random pit depth                                 1    2014 1  4  469-B1-1     NA     2     0.0543 S  8RG  In    101W       NearRG    1-4-1 8" off RG and 10" from IW                  1    2014 1  4  470-B1-I     NA     3     0.05   NA                       Gen Shell Random pit deoth                                 1    2014 1  4  471-B1-I     NA      3    0.079  NA                       Gen Shell Random pit depth                                 1    2014 1  4  472-81-1     NA      3    0.0643 NA                       Gen Shell Random pit depth                                 1    2014 1  5  474-B1-1     NA      2    0.0527 S  9RG  In    1 lW       NearRG    1-5-1 9" off RG and 1" from IW                   1    2014 1  5  475-B1-I     NA      3    0.036  NA                       Gen Shell  Random pit depth                                1    2014 1  5  476-81-1     NA      3    Q.0507 NA                       Gen Shell  Random Pit depth                                1    2014 1  5  477-81-1     NA      3    0.055  NA                       Gen Shell Random pit depth                                 1    2014 2  1  416-82-1     NA      2    0.0533 S  5RG  In    971W       NearRG    2-1-1 5" off RG and 97" from IW                  1    2014 2  1  417-B2-1     NA      2    0.052  s  6RG  In    321W       NearRG    2-1-2 6" off RG and 32" from IW                  1    2014 2  1  418-B2-1     NA      3    0.0657 NA                       Gen Shell  Random Pit deoth                                1    2014 2  1  419-82-1     NA      3    0.0577 NA                       Gen Shell  Random pit depth                                1    2014 2  1  420-82-1     NA      3    0.078  NA                       Gen Shell  Random oit deoth                                1    2014 2  2  422-B2-1     NA      3    0.0913 S  32PW In    131 IW     Gen Shell 2-2-1 32" from WS of Plate 1/2 and 131" from IW 1     2014 2  2  423-B2-1     NA      3    0.0637 NA                       Gen Shell  Random oit depth                                1    2014 2  2  424-B2-1     NA      3    0.0677 NA                       Gen Shell  Random pit depth                                1    2014 Repair# 2-3-1. Located 4" from RG2/3 and 58" up 2  3  426-B2-1     NA      2    0.097  D  4RG  In    581W   YES Near RG                                                    1    2014 from IW. CR-CNS-2014-08799 2  3  427-B2-I     NA      2    0.0727 S  4RG  In    531W       NearRG    2-3-2 4" off RG and 53" from IW                  1    2014 2  3  428-B2-1     NA      3    0.0617 NA                       Gen Shell  Random pit depth                                1    2014 2  3  429-B2-1     NA      3    0.0623 NA                       Gen Shell  Random pit depth                                1    2014 (19-32)                                                                                     p   '<,ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                          & 3 rd Interval CISI Program Torus Identified Internal Pitting 2 4  433-B2-0     NA     1     <0.030 S  0-360 Deg   Various Temp. Monit. X-300A Repair# 2-4-1 With-in 13" Radius      1      2014 2 4  434-82-1     NA     2     0.0503 S  11 RG In    44IW    NearRG              2-4-2 11" off RG and 44" from IW      1      2014 2 4  435-82-1     NA     2     0.0533 S  6RG   In   32IW     NearRG              2-4-3 6" off RG and 32" from IW       1      2014 2 4  436-B2-I     NA     3     0.047  NA                     Gen Shell           Random pit depth                      1      2014 2 4  437-B2-I     NA     3     0.041  NA                     Gen Shell           Random pit depth                      1      2014 2 4  438-B2-I     NA     3     0.0453 NA                     Gen Shell           Random pit depth                      1      2014 2 5  448-B2-I     NA     2     0.061  s  7RG   In    120IW   Near RG             2-5-1 7" off RIG 120" UP from 6       1      2014 2 5  449-B2-I     NA     2     0.06   s  3RG   In   65IW     NearRG              2-5-2 3" off RIG and 65" up from 6    1      2014 2 5  450-B2-I     NA     2     0.05   s  3RG   In   32IW     NearRG              2-5-3 3" off R/G 32" UP from 6        1      2014 3 1  359-B3-I     NA     2     0.0473 NA                     NearRG              Random pit depth                      1      2014 3 1  360-B3-I     NA     3     0.0677 NA                     Gen Shell           Random pit depth                      1      2014 3 1  361-B3-I     NA     3     0.0727 NA                     Gen Shell           Random Pit depth                      1      2014 3 2  362-B3-2     NA     1     <0.030 S  0-360 Deg  Various  RHR-A        X-225A 3-2-1 29 areas of edge rust           29     2014 3 2  364-B3-I     NA     3     0.0633 NA                     Gen Shell           Random pit depth                      1      2014 3 2  365-83-1     NA     3     0.0717 NA                     Gen Shell           Random Pit deoth                      1      2014 3 2  366-83-1     NA     3     0.0787 NA                     Gen Shell           Random pit depth                      1      2014 3 3  367-B3-2     NA     1     <0.030 S  0-360 Dea  Various  RHR-C        X-225B 3-3-1 16 areas of edge rust           16     2014 3 3  368-83-2     NA     1     <0.030 S  0-360 Deg  Various  RHR C        X-2258 3-3-2    96" up from 6                       2014 3 3  369-83-1     NA     2     0.0457 NA                     NearRG              Random pit depth                      1      2014 3 3  370-83-1     NA     3     0.048  NA                     Gen Shell           Random oit depth                      1      2014 3 3  371-B3-I     NA     3     0.0537 NA                     Gen Shell           Random pit depth                      1      2014 3 4  373-83-1     NA     2     0.0427 NA                     Near RG                                                   1      2014 3 4  374-B3-I     NA     2     0.0587 S  6RG   In   64IW     NearRG              3-4-1   6" off R/G 64" UP from 6      1      2014 3 4  375-B3-I     NA     2     0.0503 S  6RG   In   61 IW    NearRG              3-4-2    6" off R/G 61" up from 6     1      2014 3 4  376-83-1     NA     2     0.058  s  5RG   In   40IW     NearRG              3-4-3    5" off RIG 40" up from 6     1      2014 3 4  377-83-1     NA     2     0.0617 S  4RG   In   36IW     NearRG              3-4-4    4" off RIG 36" up from 6     1      2014 3 4  378-83-1     NA     2     0.0583 S  4RG   In   28IW     Near RG             3-4-5     4" off RIG 28" up from 6    1      2014 3 5  381-B3-I     NA     2     0.05   s  11 RG In   104IW    Near RG             3-5-1    11" off RIG 104 up from 6    1      2014 3 5  382-B3-I     NA     2     0.0467 NA                     NearRG              Random pit depth                      1      2014 3 5  383-83-1     NA     2     0.048  NA                     NearRG              Random pit depth                      1     2014 4 1  332-B4-I     NA     3     <0.030 NA                     Gen Shell           Random pit depth                      1      2014 4 1  333-84-1     NA     3     0.033  NA                     Gen Shell           Random pit depth                      1      2014 4 1 334-B4-I      NA     3     0.0377 NA                     Gen Shell           Random pit denth                      1     2014 4 2  340-84-1     NA     1     <0.030 S  0-360 Deg  Various  TorusDrain   X-213A 4-2-1   9 edge rust areas             9      2014 4 2 337-B4-I     NA      3     0.07   NA                     Gen Shell           Random Pit deoth                      1     2014 4 2 338-B4-I      NA     3     <0.030 NA                     Gen Shell           Random pit depth                      1     2014 4 2 339-B4-I      NA     3     0.0323 NA                     Gen Shell           Random pit depth                      1     2014 4 3 342-84-1     NA      3     0.0407 NA                     Gen Shell           Random Pit depth                      1     2014 4 3 343-B4-I      NA     3     0.055  NA                     Gen Shell           Random pit depth                      1     2014 (19-33)                                                                                     R,.. '~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                                 & 3 rd Interval GISI Program Torus Identified Internal Pitting 14 f3 !344-B4-I    !NA     !3   !0.071  !NA         C=:=J         CJ*--"                  I Random   pit depth                                11     !2014 I 4  4  351-84-0     NA      1    <0.030 S   0-360   Deg   Various     Temp. Monit. X-300D   4-4-4 2 edge rust areas                            2      2014 4  4  346-B4-l     NA      2    0.067   s  8RG     In                Near RG               4-4-1 8" off RIG 32" up from pipe on shell         1      2014 4  4  347-84-1     NA      2    O.d683  S  7RG     In                Near RG               4-4-2 7" off RIG 27" uo from oioe on shell         1      2014 4  4  348-84-1     NA      2    0.0563  S  5RG     In    821W        NearRG                4-4-3 5" off RIG 82" UP from 6                     1      2014 4  5  353-84-1     NA      2    0.0613  S  5RG     In    101W        NearRG                4-5-1 5" off RIG 1O" up from 6                     1      2014 4  5  354-84-1     NA      3    0.048   NA                           Gen Shell             Random pit depth                                   1      2014 4  5  355-B4-I     NA      3    0.0527  NA                           Gen Shell             Random pit depth                                   1      2014 5  1  135-85-1     NA      3    0.0663  NA                           Gen Shell             Random pit depth                                   1      2014 5  1  136-B5-1     NA      3    0.064   NA                           Gen Shell             Random oit deoth                                   1      2014 5  1  137-B5-l     NA      3    0.065   NA                           Gen Shell             Random pit depth                                   1      2014 5  2  139-B5-1     NA      3    0.084   NA                           Gen Shell             Random pit depth                                   1      2014 5  2  140-B5-1     NA      3    0.0807  NA                           Gen Shell             Random oit depth                                   1      2014 5  2  141-B5-1     NA      3    0.057   NA                           Gen Shell             Random pit depth                                   1      2014 5  3  143-B5-I     NA      3    0.075   NA                           Gen Shell             Random pit depth                                   1      2014 5  3  144-B5-l     NA      3    0.0437  NA                           Gen Shell             Random pit depth                                   1      2014 5  3  145-85-1     NA      3    0.0357  NA                           Gen Shell             Random pit depth                                   1      2014 5  4  147-85-1     NA      2    0.0647  S  7RG     In    1271W       NearRG                Repair# 5-4-1 7" off RIG 127" up from 6 oclk       1      2014 5  4  148-B5-I     NA      2    0.0623 S   10RG    In    761W        NearRG                Repair# 5-4-2 10" off Gusset 7f:f' up from 6 oclk  1      2014 5  4  149-B5-1     NA      3    0.095   s          In    241W        Gen Shell             Repair# 5-4-3 24" right of RIG 24" up from 6       1      2014 5  5  150-B5-l     NA      2    0.0493 NA                            Near RG               Random pit depth                                   1      2014 5  5  151-B5-l     NA      2    0.0507 S   10.5 RG In    561W        NearRG                Repair #5-5-1 10.5" off RIG 56" from 6 o'clock     1      2014 5  5  152-85-1     NA      2    0.052   s  9RG     In    501W        Near RG               Repair #5-5-2 9" off RIG 50" from 6 o'clock        1      2014 5  5  153-85-1     NA      2    0.0503  S  6RG     In    401W        NearRG                Repair #5-5-3 6" off R/G 40" from 6 o'clock        1      2014 5  5  154-B5-1     NA      2    0.0533  S  8RG     In    421W        Near RG               Repair #5-5-4 811 off RIG 42" from 6 o'clock       1      2014 5  5  155-B5-I     NA      2    0.0527  S  9RG     In    271W        Near RG               Repair #5-5-5 9" off RIG 27" off the 6 o'clock     1      2014 6  1  161-B6-2     NA      1    <0.030  S  0-360   Deg   Various     RCIC         X-224    6-1-1 25 areas of edge rust                        25     2014 6  1  163-B6-I     NA      3    0.0467  NA                           Gen Shell             Random Pit depth                                   1      2014 6  1  164-B6-I     NA      3    0.051   NA                           Gen Shell             Random pit depth                                   1      2014 6  1  165-86-1     NA      3    0.048   NA                           Gen Shell             Random pit depth                                   1      2014 6  2  167-B6-I     NA      3    0.0557  NA                           Gen Shell             Random Pit depth                                   1      2014 6  2  168-B6-I     NA      3    0.0777  NA                           Gen Shell             Random pit depth                                   1      2014 6  2  169-B6-l     NA      3    0.0627  NA                           Gen Shell             Random pit depth                                   1      2014 6  3  171-86-1     NA      2    0.0613  S  9RG     In    31W         Near RG               reoair# 6-3-1   9" off RIG 3" up from 6            1      2014 6  3  172-86-1     NA      3    0.0517  NA                           Gen Shell             Random pit depth                                   1      2014 6  3  173-86-1     NA      3    0.0477  NA                           Gen Shell             Random pit depth                                   1      2014 6  4  175-86-0     NA      1    <0.030 S   0-360   Deg   Various     Temp. Monit. X-300F   6-4-1 around temp gauges 8 areas of edge rust      8      2014 (19-34)                                                                                                       r   \c;ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                            & 3rd Interval CISI Program Torus Identified Internal Pitting 6 4  177-B6-I     NA     3     0.043  NA         c=J          CJ                  I Random   pit depth                                 11    !2014 I 6 4  179-86-1     NA     3     0.0307 NA                         Gen Shell          Random pit depth                                    1     2014 6 4  180-86-1     NA     3     0.0723 NA                         Gen Shell          Random pit depth                                    1     2014 6 5  181-B6-I     NA     2     0.053  s  9RG     In   55IW       Near RG            reoair# 6-5-1 9" off RIG 55 uo from 6             1     2014 6 5  182-86-1     NA     2     0.0463 NA                         Near RG           Random oit depth                                     1     2014 6 5  183-B6-I     NA     3     0.0583 NA                         Gen Shell         Random pit depth                                     1     2014 7 1  185-87-2     NA      1    <0.030 S  0-360   Deg  Various    CS-A      X-227A  7-1-1 42 edoe rust areas                             42    2014 7 1  186-87-1     NA     2     0.0687 S  11.5 RG In   22IW       NearRG            7-1-2 11.5" off RIG 22" UP from 6                    1     2014 7 1  187-B7-I     NA     3     0.051  NA                         Gen Shell         Random pit deoth                                     1     2014 7 1  188-87-1     NA     3     0.0697 NA                         Gen Shell          Random pit depth                                    1     2014 7 2  190-87-1     NA     3     0.0717 NA                         Gen Shell         Random oit depth                                     1     2014 7 2  191-B7-l     NA     3     0.0677 NA                         Gen Shell          Random pit depth                                    1     2014 7 2  192-B7-I     NA     3     0.0577 NA                         Gen Shell         Random pit depth                                     1     2014 7 3  195-B7-I     NA     3     0.064  NA                         Gen Shell         Random Pit depth                                     1     2014 7 3  196-87-1     NA     3     0.061  NA                         Gen Shell         Random pit depth                                     1     2014 7 3  197-B7-I     NA     3     0.047  NA                         Gen Shell         Random pit depth                                     1     2014 7 4  200-B7-I     NA     3     0.0617 NA                         Gen Shell         Random oit deoth                                     1     2014 7 4  201-B7-l     NA     3     0.0573 NA                         Gen Shell         Random pit depth                                     1     2014 7 4  202-B7-I     NA     3     0.0703 NA                         Gen Shell         Random oit depth                                     1     2014
    ,7 5  205-87-1     NA     3     0.0617 NA                         Gen Shell         Random pit depth                                     1     2014 7 5  206-87-1     NA     3     0.0687 NA                         Gen Shell         Random pit depth                                     1     2014 7 5  207-87-1     NA     3     0.0553 NA                         Gen Shell         Random pit depth                                     1     2014 8 1  213-88-1     NA     3     0.0467 NA                         Gen Shell         Random pit depth                                     1     2014 8 1  214-B8-I     NA     3     0.06   NA                         Gen Shell         Random pit depth                                     1     2014 8 1  215-B8-I     NA     3     0.0483 NA                         Gen Shell         Random oit deoth                                     1     2014 8 2  216.88-1     NA     3     0.0487 NA                         Gen Shell         Random pit depth                                     1     2014 8 2  217-88-1     NA     3     0.0457 NA                         Gen Shell         Random pit depth                                     1     2014 8 2  218-88-1     NA     3     0.0697 NA                         Gen Shell         Random pit depth                                     1     2014 8 3  507-88-2     NA     1            s  125     Deg  40PN       CS-A      X-223A  8-3--3 1 area fo edge rust                           1     2014 8 3  508-B8-2     NA     1            s  130     Deg  40PN       CS-A      X-223A  8-3-4 40 off pen                                   3     2014 8 3  509-B8-2     NA     1            s  160     DeQ  37PN       CS-A      X-223A  8-3-5 37" off pen                                    1     2014 8 3  510-88-2     NA     1            s  170     Deg  43PN       CS-A      X-223A  8-3--6 43" off oen                                   3     2014 8 3  511-88-2     NA     1            s  180     Deg  42PN       CS-A      X-223A  8-3-7 42" off pen                                    3     2014 8 3  512-88-2     NA     1            s  225     Deg  31 PN      CS-A      X-223A  8-3-8 31" off pen WL                                 3     2014 8 3  220-88-1     NA                                                               8-3--1 5" off gusset and 60" off 6 o'clock position 2     0.0633 S  5RG     In   60IW       NearRG                                                                 1     2014 IW 8  3  221-88-l     NA     3     0.0903 S          In   57IW       Gen Shell         8-3--2 31" off RG and 57" off 6 o'clock position IW 1      2014 8  3  222-88-1     NA     3     0.039  NA                         Gen Shell         Random pit depth                                     1     2014 8 3  223-8,8-1    NA     3     0.0693 NA                         Gen Shell         Random pit depth                                     1     2014 (19-35)                                                                                                   R **ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                                    & 3 Interval CISI Program Torus Identified Internal Pitting 8  14 1227-B8-0    INA     11    l<0.030 IS  10-360 IDeg   13PN I !Temp. Monit. IX-300G 8-4-3 Located in a 3' area adjacent to X-300H       13    12014 8  14 1225-88-1    INA     12   I0.0593 IS   l5RG   lln    1541W    I INearRG       I       8-4-1 5" off gusset and 54" off 6 o'clock position IW 11    12014 8-4-2 5" off gusset and 43" off 6 o'clock position 8   4  226-B8-I     NA      2     0.051   s   5RG    In     43IW       Near RG IW 1     2014 8   4  229-B8-I     NA      3     0.0413 NA                            Gen Shell                                                                 1     2014 8   4  230-B8-I     NA      3     0.04    NA                           Gen Shell                                                                 1     2014 8   4  231-88-1     NA      3     0.038   NA                           Gen Shell                                                                 1     2014 8   5  232-88-1     NA      2     0.0593 S    6RG    In     751W       Near RG              8-5-1 6" off RG and 75" off 6 o'clock position IW    1     2014 8   5  233-B8-I     NA      3     0.0437  NA                           Gen Shell                                                                 1     2014 8   5  234-B8-1     NA      3     <0.030  NA                           Gen Shell                                                                 1     2014 8   5  235-88-1     NA      3     .0.0263 NA                           Gen Shell                                                                 1     2014 8   5  236-B8-I     NA      3     <0.030  NA                           Gen Shell            General rust grade                                   5     2014 9   1  239-B9-I     NA      2     0.063   s   9RG    In     841W       NearRG               9-1-1 9" off RIG 84" up from 6                       1     2014 9   1  240-B9-I     NA      2     0.0477  NA                           NearRG               Random Pit depth                                     1     2014 9   1  241-B9-I     NA      2     0.0557  S   7RG    In     49IW       NearRG               9-1-2 7" right of RIG 49" up from 6                  1     2014 9   1  242-89-1     NA      3     0.0473  NA                           Gen Shell            Random pit depth                                     1     2014 9   2  244-B9-1     NA      3     0.0693  NA                           Gen Shell            Random oit deoth                                     1     20.14 9   2  245-B9-I     NA      3     0.0623  NA                           Gen Shell            Random pit depth                                     1     2014 9   2  24&.B9-l     NA      3     0.0623  NA                           Gen Shell            Random oit deoth                                     1     2014 9   3  249-89-1     NA      3     0.0663  NA                           Gen Shell            Random oit depth                                     1     2014 9   3  250-B9-I     NA      3     0.062   NA                           Gen Shell            Random pit depth                                     1     2014 9   3  251-89-1     NA      3     0.0637  NA                           Gen Shell            Random pit depth                                     1     2014 9   4  252-B9-1     NA      2     0.0563 S    10RG   In     74IW       NearRG               9-4-1 10" off RIG 74" UP from 6                      1     2014 9   4  253-B9-I     NA      3     0.0637  NA                           Gen Shell            Random pit depth                                     1     2014 9   4  254-89-1     NA      3     0.0567  NA                           Gen Shell            Random Pit depth                                     1     2014 9   5  257-B9-I     NA      3     0.0517  NA                           Gen Shell            Random pit depth                                     1     2014 9   5  258-89-1     NA      3     0.0577  NA                           Gen Shell            Random pit depth                                     1     2014 9   5  259-B9-I     NA      3     0.0693  NA                           Gen Shell            Random pit depth                                     1     2014 10  1  440-B10-2    NA      1     <0.030  S   0-360  Dea    Various    CS-B          X-223B 10-1-1 4 edae rustarec1s                             4     2014 10  1  441-810-2    NA      1     <0.030  S   240    Deg    43PN       CS-B          X-2238 10..1-2 43" off pen 240 degree az                    3     2014 10  1  442-B10-2    NA      1     <0.030  S   190    Deo    28PN       CS-B          X-2238 10-1-3 28' off oen at WL                             3     2014 10  1  443-B10-2    NA      1     <0.030  $   170    Deg    35PN       CS-B          X-2238 10-1-4 35" off pen                                   3     2014 10  1  444-810-2    NA      1     <0.030  S   140     Deg   30PN       CS-B          X-2238 10-1-5 30" off pen                                   3     2014 10  1  445-B10-2    NA      1     <0.030  S   130     Deg   31 PN      CS-B          X-223B 10-1-6 31" off pen                                   3     2014 10- 1-7 40" off pen and falls below 43" inspection 10  1  446-810-2    NA      1     <0.030 S    120     Deg   40PN       CS-B          X-223B                                                      3     2014 radius 10  1  262-810--    NA      3     0.0683 NA                            Gen Shell            Random pit dePth                                     1     2014 10  1  263-810--    NA      3     0.054   NA                           Gen Shell            Random pit depth                                     1     2014 (19-36)                                                                                                     p-**i.sion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                                                  & 3rd Interval CISI Program Torus Identified Internal Pitting 10 1  264-B10-- INA       13   10.0607 INA I       c::=J                l==:J, . .,            IRandom pit depth                              11    !2014 I 10 1  265-B10--    NA      3    <0.030  NA                                   Gen Shell          General rust grade                                   2014 10 2  266-B10--    NA      3    0.0677  NA                                   Gen Shell          Random pit depth                               1     2014 10 2  267-B10--    NA      3    0.054   NA                                   Gen Shell          Random pit depth                               1     2014 10 2  268-B10-     NA      3    0.057   NA                                   Gen Shell          Random pit depth                               1     2014 10 3  271-810--    NA      3    0.0473  NA                                   Gen Shell          Random p.it depth                              1     2014 10 3  272-B10--    NA      3    <0.030  NA                                   Gen Shell          Random pit depth                               1     2014 10 3  273-B10--    NA      3    0.0527  NA                                   Gen Shell          Random pit depth                               1     2014 10 3  274-810--    NA      3    <0.030  NA                                   Gen Shell          General rust grade                             3     2014 10 4  277-B10--    NA      2    0.064   s    6RG   In      741W              NearRG             10-4-1 6" of gusset RG and 74" from IW         1     2014 10 4  278-B10-- . NA       3    0.0257  NA                                    Gen Shell         Random pit depth                               1     2014 10 4  279-B10--    NA      3    0.0517  NA                                   Gen Shell          Random pit depth                               1     2014 10 4  280-B10-     NA      3    0.0667  NA                                   Gen Shell          Random pit depth                               1     2014 10 5  282-B10--    NA      2    0.0547  S    7RG   In      76IW               NearRG            10-5-1 7" from RG and 76" from IW              1     2014 10 5  283-810--    NA      2    0.062   s    7RG   In      20IW               NearRG            10-5-2 7" from RG and 20" from IW              1     2014 10 5  284-810--    NA      3    0.071   NA                                   Gen Shell          Random pit depth                               1     2014 10 5  285-B10--    NA      3    0.0687  NA                                    Gen Shell         Random pit depth                               1     2014 10 5  286-810--    NA      3    0.053   NA                                    Gen Shell         Random pit depth                               1     2014 10 5  287-B10-     NA      3    <0.030  NA                                   Gen Shell          General rust made                              3     2014 11 1  78-B11--     NA      2    0.0577  S    0 RG  In      78IW               Near RG           11-1-1 repair# 78"upfrom6oclk                  1     2014 11 1  79-B11--     NA      2    0.0597  S    0RG   In      68IW               Near RG           11-1-2 repair 68" up from 6 oclk               1     2014 11 1  80-B11--     NA      2    0.0827  S    8RG   In      581W               Near RG           11-1-3 8" from ausset and 58"uo from 6 oclk    1     2014 11 1  81-B11--     NA      2    0.071   s    0RG   In      42IW               NearRG            11-1-4 42" UP from 6 oclk                      5     2014 11 1  82-B11--     NA      2    0.0833  S    0RG   In      38IW               NearRG            11-1-511 38" up from 6                         1     2014 11 1  83-811--     NA      2    0.0637  S    0RG   In      36IW               NearRG            11-1-6 36" UP from 6                           1     2014 11 1  84-811--     NA      2    0.0657  S    0RG   In      30IW               NearRG            11-1-7 30" up from 6                           1     2014 11 1  87-811--     NA      3    0.057   NA                                    Gen Shell         Random pit depth                               1     2014 11 1  88-811--     NA      3    0.069   NA                                    Gen Shell         Random pit depth                               1     2014 11 1  89-B11-*     NA      3    0.0787  NA                                    Gen Shell         Random pit depth                               1     2014 11 2  91-B11--     NA      3    0.0797  NA                                    Gen Shell         Random pit depth                               1     2014 11 2  92-B11--     NA      3    0.0697  NA                                    Gen Shell         Random pit depth                               1     2014 11 2  93-B11--     NA      3    0.0663  NA                                    Gen Shell         Random pit depth                               1     2014 11 3  95-B11-2     NA      1    <0.030  S    0-360 Deg     Various            CS-8      X-2278  reoair# 11-3-1 29 areas of edge rust           29    2014 11 3  96-B11-2     NA      1    0.024   s    45    Dea     14 PN              CS-B      X-2278  reoair# 11-3-2 14" off pen                     1     2014 11 3  97-B11-2     NA      1    0.021   s    30    Dea     32 PN              CS-B      X-2278  repair# 11-3-3 32" off pen                     4     2014 11 3  98-B11-2     NA      1    0.0297  S    20    Deg     30PN               CS-B      X-2278  repair# 11-3-4 30" off pen                     1     2014 11 3  99-B11-2     NA      1    0.0223  S    15    Deg     32PN               CS-B      X-2278  reoair#11-3-5 32"off oen                       1     2014 11 3  100-B11-2 NA         1    0.021   s    350   Deg     18PN               CS-B      X-2278  repair# 11-3-6 18" off pen                     1     2014 11 3  101-811-2 NA         1    0.0243 S     340   Deg     26PN               CS-B      X-227B  repair#11-3-7 26" off pen                      1     2014 11 3  102-B11-2 NA         1    <0.030 S     265   D_e_g _ 5.§_l:_f\l__       C§-EL     X-227B  repair# 11-3-8 5 1/2" off pen                  1     2014 (19-37)                                                                                                       P   :~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                              & 3rd Interval CISI Program Torus Identified Internal Pitting 11 13 1103-B11-2   INA     11   I0.04   ID  1270   IDeg   8 PN    YES CS-B       X-227B insert plate. Metal Loss with no coating 40mils. 1     2014 CR-CNS-20.14-06796 11  3  104-B11-2    NA      1    <0.030  S   195    Deq   7PN         CS-B       X-227B repair # 11-3-10 7"off penetration                 1     2014 11  3  105-B11-2    NA      1    <0.030  S   195    Deg   2PN         CS-B       X-2278 repair# 11-3-11 2" off penetration                 1     2014 11  3  106-B11-2    NA      1    <0.030  S   160    Deg   20PN        CS-B       X-2278 repair# 11-3-12 20" off penetration                1     2014 11  3  107-B11-2    NA      1    0.0217  S   225    Deg   36PN        CS-B       X-2278 repair# 11-3-13 36" off pen                        1     2014 11  3  111-B11--    NA      2    0.078   s   2RG    In    42IW        Near RG           repair# 11-S-14 2" off RIG 42" up from 6 oclk      1     2014 11  3  112-811--    NA      2    0.0577  S   14 RG  In    36IW        NearRG            repair# 11-3-15 14" off RIG 36" up from 6 oclk     1     2014 11  3  11S-B11--    NA      2    0.0647 S           In                Near RG           repair# 11-3-16                                    1     2014 11  3  114-B11--    NA      2    0.041   NA                           Near RG           Random pit depth                                   1     2014 11  3  115-B11--    NA      2    0.0617  S   11 RG  In    23IW        NearRG            repair# 11-3-17 11" off RIG 23" up from 6          1     2014 11  3  116-B11--    NA      2    0.056   s   11 RG  In    19IW        NearRG            repair# 11-3-18 11" off RIG 1l;l" up from 6        1     2014 11  3  117-B11--    NA      2    0.0533  S   15 RG  In    17IW        Near RG           repair# 11-3-19 15" off RIG 17" UP from 6          1     2014 11  3  118-811--    NA      2    0.057   s   14RG   In    13IW        Near RG           repair# 11-3-2014" off RIG 13" up from 6           1     2014 11  3  108-811--    NA      3    0.0487  NA                           Gen Shell         Random pit depth                                   1     2014 11  3  109-B11--    NA      3    0.056   NA                           Gen Shell         Random pit depth                                   1     2014 11  3  11 O-B11--   NA      3    0.0677  NA                           Gen Shell         Random Pit depth                                   1     2014 11  4  119-B11--    NA      2    0.0583  S   4RG    In    40IW        NearRG            repair#11-4-1     4" off RIG 40" up from 6         1     2014 11  4  120-811--    NA      2    0.0613  S   9RG    In    27IW        NearRG            repair# 11-4-2 9"off RIG 27" UP from 6             1     2014 11  4  121-B11--    NA      2    0.0583  S   12RG   In    121W        NearRG            repair# 11-4-3 12"off R/G 12" up from 6            1     2014 11  4  122-B11-     NA      2    0.05    s   5RG    In    11 lW       Near RG           repair# 11-4-4     5" off RIG 11" up from 6        1     2014 11  4  123,.811--   NA      2    0.0513  S   6RG    In    5IW         Near RG           repair# 11-4-5 6" off RIG 5" up from 6             1     2014 11  4  124-B11-     NA      2    0.0537  S   9RG    In    7IW         Near RG           reoair# 11-4-6 9"off RIG 7" UP from 6              1     2014 11  5  127-B11--    NA      2    0.053   s   10RG   In    125IW       NearRG            repair# 11-5-1 1O"off R/G 125" UP from 6           1     2014 11  5  128-811--    NA      2    0.0543  S   4RG    In    109IW       NearRG            repair# 11-5-2 4" off RIG 109" uo from 6           1     2014 11  5  129-B11--    NA      2    0.0627  S   1 RG   In    52IW        NearRG            repair# 11-5-3 1" off RIG 52" UP from 6            1     2014 12  1  290-B12--    NA      2    0.0587  S   10RG   In    70IW        NearRG            12-1-1 10" off RG and 70" from IW                  1     2014 12  1  291-812-     NA      2    0.0517  S   3RG    In    50IW        Near RG           12-1-2 3" off RG and 50" from IW                   1     2014 12  1  292-B12--    NA      3    0.0643  NA                           Gen Shell         Random pit depth                                   1     2014 12  1  293-B12--    NA      3    0.059   NA                           Gen Shell         Random pit depth                                   1     2014 12  1  294-B12--    NA      3    <0.030  NA                           Gen Shell         Random pit depth                                   1     2014 12  1  295-B12--    NA      3    <0.030  NA                           Gen Shell         General rust arade                                 5     2014 12  2  387-B12-1    NA      1    <0.030  S   0-360  Deq   Various     TorusDrain X-213B 12-2-2 Repairs are in the 18" Radius               17    2014 12-2-1 4" from the Plate 2/3 weld and 66" from 12  2  296-B12-     NA      2    0.0757 S    4RG    In    66IW        NearRG                                                               1     2014 thelW 12  2  297-812--    NA      3    0.06    NA                           Gen Shell         Random pit depth                                   1     2014 12  2  298-B12--    NA      3    0.0447 NA                            Gen Shell         Random Pit depth                                   1     2014 12  3  300-B12--    NA      2    0.0497 NA                            NearRG            Random pit depth                                   1     2014 12  3  301-812--    NA      3    0.0807 NA                            Gen Shell         Random pit depth                                   1     2014 12  3  302-812--    NA      3    0.054   NA                           Gen Shell         Random pit depth                                   1     2014 (19-38)                                                                                                  p,***sion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                                 & 3 rd Interval CISI Program Torus Identified Internal Pitting 112 !3  !303-812--   lNA     13   !0.0767 !NA       c=J             CJ                         Random pit depth                                11    !2014 I 12  14 1305-912-0    NA      1    <0.030 S   0-360 Deg   Various        Temp. Monit. IX-300L 112-4-1   Located in a 13" Radius of X-300L     15     12014 12   4  306-B12-0    NA      1    <0.030 S   0-360 Deg   Various        Temp. Monit. X-300K   12-4-2 Located in a 13" Radius of X-300K         5     2014 12   4  307-B12--    NA      2    0.0493  NA                            Near RG               Random pit depth                                 1     2014 12   4  308-B12~-    NA      2    0.0543 S   5RG   In    581W           Near RG               12-4-3 5" from the gusset and 58" from the IW    1     2014 12   4  309-B12--    NA      3    0.0537 NA                             Gen Shell             Random pit depth                                 1     2014 12   4  310-912--    NA      3    0.0593  NA                            Gen Shell             Random pit depth                                 1     2014 12   4  311-912--    NA      3    0.0487  NA                            Gen Shell             Random oit depth                                 1     2014 12   5  314-912--    NA      3    0.055   NA                            Gen Shell             Random pit depth                                 1     2014 12   5  315-812--    NA      3    0.0627  NA                            Gen Shell             Random pit depth                                 1     2014 12   5  316-B12--    NA      3    0.0693  NA                            Gen Shell             Random pit depth                                 1     2014 13   1  482-813--    NA      3    0.0323  NA                            Gen Shell             Random pit depth                                 1     2014 13   1  483-813--    NA      3    0.029   NA                            Gen Shell             Random pit depth                                 1     2014 13   1  484-813--    NA      3    0.0487  NA                            Gen Shell             Random pit depth                                 1     2014 13   2  486-B13--    NA      3    0.0527  NA                            Gen Shell             Random pit depth                                 1     2014 13   2  487-813--    NA      3    0.0223  NA                            Gen Shell             Random pit depth                                 1     2014 13   2  488-B13--    NA      3    0.0233  NA                            Gen Shell             Random pit depth                                 1     2014 13   3  491-B13--    NA      3    <0.030  NA                            Gen Shell             Random pit depth                                 1     2014 13   3  492-B13--    NA      3    0.0417  NA                            Gen Shell             Random pit depth                                 1     2014 13   3  493-813--    NA      3    <0.030  NA                            Gen Shell             Random pit depth                                 1     2014 13   4  496-B13--    NA      3    0.0327  NA                            Gen Shelf             Random pit depth                                 1     2014 13   4  497-B13--    NA      3    0.0387  NA                            Gen Shell             Random pit depth                                 1     2014 13   4  498-B13--    NA      3    0.0237  NA                            Gen Shell             Random pit depth                                 1     2014 13   5  501-B13--    NA      3    0.044   NA                            Gen Shell             Random pit depth                                 1     2014 13   5  502-B13--    NA      3    0.0417  NA                            Gen Shell             Random Pit depth                                 1     2014 13   5   503-813--    NA      3    0.0243  NA                            Gen Shell             Random pit depth                                 1     2014 14   1  39-814-      NA      3    <0.030  NA                            Gen Shell             Random pit depth                                 1     2014 14   1  40-814--     NA      3    <0.030  NA                            Gen Shell             Random pit depth                                 1     2014 14   1  41-B14--     NA      3    0.029   NA                            Gen Shell             Random oit deoth                                 1     2014 14   2  42-814-2     NA      1    <0.030  S  0-360 Deg   Various        HPCI          X-226   27 edqe rustfailed repairs 14-2-1                27    2014 14   2  43-B14-2     NA      1    <Q.030  S  136   Deg   36PN           HPCI          X-226   18" UP from penetration TS 14-2-2                1     2014 14   2  44-814-2     NA      1    0.0297  S  172   Deg   36PN           HPCI          X-226   Reoair 14-2-3 36" UP from penetration            1     2014 Repair# 14-2-4. Near Pen X-226 HPSI 36" from 14 12    45-B14-2     NA      1    0.031   D  193   Deg   36PN      YES HPCI           X-226   oenetration nozzel on Az 172 dea. CR-CNS-2014-   1     2014 14 2     46-814-2     NA      1    0.021   s  222   Deg  136 PN    I    IHPCI         lX-226  1Repair 14-2-5 36" from penetration             11     12014 14 2    47-814-2     NA      1    <0.030 S   229   Deg   36PN           HPCI          X-226   Reoair 14-2-6                                    1     2014 14 12   48-B14-2     NA      1    <0.030 S   287   Deg  J36PN    l    JHPCI           X-226   Reoair 14-2-7                                    1     2014 (19-39)                                                                                                        R' *,ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                & 3 Interval CISI Program Torus Identified Internal Pitting 1

3 3 0.031 NA Gen Shell 14 2 54-B14-- NA 3 0.0263 NA Gen Shell 14 3 56-814- NA 3 0.0433 NA Gen Shell 14 3 57-B14-- NA 3 0.0447 NA Gen Shell 14 3 58-B14-- NA 3 0.0343 NA Gen Shell 14 4 63-814-0 NA 1 <0.030 S 0-360 Deg Various Temp. Monit. X-300N 14-4-3 4 areas of failed repair 4 2014 14 4 64-B14-0 NA 1 <0.030 S 0-360 Deg Various Temp. Monit. X-300M 14-4-4 2 failed repair edge rust 2 2014 14 4 60-814-- NA 2 0.0513 S 10RG In OIW Near RG at 6 oclock 10 right of RG 14-4-1 1 2014 14 4 61-B14-- NA 2 0.0553 S 9RG In 321W NearRG Repair 14-4-2 9"off RG 32" up from 6 ws 1 2014 14 4 66-B14-- NA 3 0.0703 NA Gen Shell Random pit depth 1 2014 14 4 67-B14-- NA 3 0.053 NA Gen Shell Random pit depth 1 2014 14 4 68-B14-- NA 3 0.0307 NA Gen Shell Random Pit depth 1 2014 14 5 71-B14-- NA 3 0.048 NA Gen Shell Random Pit depth 1 2014 14 5 72-B14-- NA 3 0.0523 NA Gen Shell Random pit depth 1 2014 14 5 73-B14-- NA 3 0.0467 NA Gen Shell Random pit depth 1 2014 15 1 10-B15-2 NA 1 0.0223 S 320 Deg 24 PN RHR-B X-225C 7" right 14/15 RG 24"up from penetration 1 2014 15 1 11-B15-2 NA 1 <0.030 S Os360 Dea Various RHR-B X-225C 3 edge rust on old coating repairs 3 2014 15 1 13-B15-- NA 3 0.03 NA Gen Shell Random pit depth 1 2014 15 1 14-B15-- NA 3 0.0303 NA Gen Shell Random pit depth 1 2014 15 1 15-B15-- NA 3 0.0493 NA Gen Shell Random Pit depth 1 2014 15 2 12-B15-2 NA 1 <0.030 S Dea Various RHR-D X-2250 4 edoe rust on old coating repairs 4 2014 15 2 21-B15-2 NA 1 <0.030 S RHR-8 X-225C 1 2014 15 2 34-B15- NA 3 <0.030 NA Gen Shell Random pit depth 1 2014 15 2 35-815-- NA 3 <0.030 NA Gen Shell Random pit depth 1 2014 15 2 38-B15--- NA 3 <0.030 NA Gen Shell Random pit depth 1 2014 15 3 17-815-- NA 3 0.0313 NA Gen Shell Random pit depth 1 2014 15 3 18-815-- NA 3 0.0203 NA Gen Shell Random pit depth 1 2014 15 3 19-B15- NA 3 0.0243 NA Gen Shell Random pit depth 1 2014 15 4 22-815-- NA 2 0.0467 NA Near RG Random pit depth 1 2014 15 4 24-B15-- NA 3 0.0493 NA Gen Shell Random oit depth 1 2014 15 4 25-815--- NA 3 0.0523 NA Gen Shell Random pit depth 1 2014 15 5 28-B15--- NA 3 0.0487 NA Gen Shell Random Pit depth 1 2014 15 5 29-815--- NA 3 0.0587 NA Gen Shell Random pit depth 1 2014 15 5 30-815--- NA 3 0.055 NA Gen Shell Random pit depth 1 2014 16 1 320-B16-- NA 2 0.0457 NA NearRG Random Pit deoth 1 2014 16 1 321-B16- NA 3 0.0497 NA Gen Shell Random pit depth 1 2014 (19-40) F '.ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                              & 3rd Interval CISI Program Torus Identified Internal Pitting 2014 324-B16--    NA      3    0.061  NA                     Gen Shell           Random pit depth                         1     2014 12  325-B16-     NA     3     0.0157 NA                     Gen Shell           Random pit depth                         1     2014 2  326-B16--    NA     3     <0.030 NA                     Gen Shell           Random pit depth                         1     2014 3  388-816-     NA     2     0.0647 S  8RG   In    82IW    NearRG              16-3-1 8" off RG and 82" from IW         1     2014 3  389-B16--    NA     2     0.057  s  9RG   In    70IW    NearRG              16-3-2 9" off RG and 70" from IW         1     2014 3  390-816--    NA     2     0.065  s  8RG   In    64IW    NearRG              16-3-3 8" off RG and 64" from IW         1     2014 3  391-B16--    NA     2     0,0577 S  8RG   In    49IW    NearRG              16-3-4 8" off Qusset and 49" from IW     1     2014 3  392-B16--    NA     2     0,0547 S  5RG   In    45IW    NearRG              16-3-5 5" off gusset and 45" from IW     1     2014 3  393-B16--    NA     2     0.0553 S  12RG  In    251W    NearRG              16-3-6 12' off gusset and 25" from IW    1     2014 3  394-B16--    NA     3     0.0877 NA                     Gen Shell           Random pit depth                         1     2014 16  3  395-B16--    NA     3     0.06   NA                     Gen Shell           Random pit depth                         1     2014 16  3  396-B16--    NA     3     0.0643 NA                     Gen Shell           Random pit depth                         1     2014 16  4  398-816-0    NA      1    <0.030 S  0-360 Deg   Various Temp. Monit X-300P  16-4-1 Repairs are in the 13" Radius     7     2014 16  4  399-B16-0    NA     1     <0.030 S  0-360 Deg   Various Temp. Monit. X-300O 16-4-2 Repairs are in the 13" Radius     7     2014 16  4  400-B16--    NA     2     0.0633 S  9RG   In    108IW   Near RG             16-4-3 9" off RG and 108 from IW         1     2014 16  4  401-816-     NA     2     0.052  s  10 RG In    48IW    Near RG             16-4-4 10" off gusset and 48" from IW    1     2014 16  4  402-816--    NA     2     0.0563 S  6RG   In    7IW     Near RG             16-4-5 6" off gusset and 7" from IW      1     2014 16  4  403-816--    NA     3     0.065  NA                     Gen Shell           Random pit depth                         1     2014 16  4  404-816--    NA     3     0.07   NA                     Gen Shell           Random pit depth                         1     2014 16  4  405-B16--    NA     3     0.0583 NA                     Gen Shell           Random pit depth                         1     2014 16  5  407-B16--    NA     2     0.0563 S  5RG   In    94IW    NearRG              16-5-1 5" off RG and 94" from IW         1     2014 16  5  408-B16--    NA     2     0.0603 S  10RG  In    77IW    Near RG             16-o-2 10" off ausset and 77" from IW    1     2014 16  5  409-B16--    NA     2     0.06   s  10RG  In    29IW    Near RG             16-5-3 10"off RG and 29" from IW         1     2014 16  5  410-B16-     NA     3     0,059  NA                     Gen Shell           Random oit deoth                         1     2014 16  5  411-B16--    NA     3     0.0543 NA                     Gen Shell           Random oit deoth                         1     2014 16  5  412-816--    NA     3     0.0567 NA                     Gen Shell           Random pit depth                         1     2014 (19-41)                                                                                      R r .".\iOn 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                                 & 3 Interval GISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                        Internal Pit Examination Record G F RWR Four/Marte I C'.ontainrmmt - Toms        Owed Visual Fx::aminafinn of Class MC MP.ta! ContainmAnt ComponP.nts Underwater Engineering Set-vices. tnc.                                  QCP-9.1.6-CNS, Rev .2

[IIIll!!I

• Im IN-SERVJCE INSPECTION DIRECT VISUAL Record NO. NUC2016114-l-PER-001 Me-asurements taken on Interior Torus Shell I 470 1 3 332-81-1 2 69.0 13.3 55.7 0.056 0.38 Shallow Corrosion-Zinc Deplete, Substrate, REG-2, tsoiated Ctg. repair DZ Inside NRG 1-3-1 470 1 5 335-81-1 2 88.0 17.0 71.0 0.071 0.38 Shallow Spot Corrosion, SUbstrate, REG-2, Isolated ctg. repair DZ Inside NRG 1-5-1 470 1 5 335-81-1 2 70.0 16.0 54.0 0.054 0.38 Shallow Spot Corrosion,Substrate,REG-2,lsoiated ctg. repair OZ Inside NRG 1-5-2 470 1 5 3J6..81-! 2 72.0 18.0 SU 0.054 0.38 Shallow Spot Corrosion,Substrate,REG-2,lsoiated ctg. repair OZ fnside NRG 1-5-3 47G 1 1 336-81-1 3 58.0 10.7 47.3 0.047 0.38 NA Spot COrrosion,Substrate,REG-3,lsolated documenl Random Pi Depth 470 1 1 337-81-1 3 60.0 11.3 48.7 0.049 0.38 NA Spot COrrosion,Substrate,REG-3,lsolated document Random Pi Depth 470 1 1 337-81-1 3 61.0 13.3 47.7 0.048 0.38 NA Spot COrrosion, Substrate, REG-3, Isolated document Random Pit Depth 470 1 2 338--81-1 3 72.0 i3.7 58.3 0.058 0.38 NA Spot corrosion, Sutlstrate, REG-3, Isolated documenl Random Pit Depth 470 1 2 338-81-1 3 57.0 10.0 47.0 0.047 0.25 NA Spot corrosion, Substrate, REG-3, lsoiated documenl Random Pit Depth 470 1 2 JJ9--01-I J 63.0 12.J 50.7 0.051 0.25 NA Opot Corrooion, Oubs1:re, m:()-;3, botated document RandomritDeptn 470 1 3 339-81-1 3 53.0 11.7 41.3 0.041 0.38 NA Spot corrosion, Substrate, REG-3, Isolated documenl Random Pit Depth 470 1 3 340-81-1 3 54.0 12.7 41.3 0.041 0.38 NA Spot corrosion, Swstrate, REG-3, Isolated documenl Random Pit Depth 470 1 4 340-81-1 3 58.0 13.3 44.7 0.045 0.38 NA Spot corrosion, Substrate, REG-3, Isolated document Random Pit Depth 47G 1 4 341-81-! 3 73.0 14.0 59.0 (U)59 0.25 NA Spot corrosion, Substrate, REG-3, Isolated document Random Pit Depth 470 i 4 341-81-1 3 72.0 14.3 57.7 0.058 0.25 NA Spot corrosion, Sutlstrate, REG-3, Isolated documenl Random Pit Depth 440 2 1 322-82-1 3 65.0 15.3 49.7 t}.050 0.25 NA Spot corrosion, Sutlstrate, REG-3, Isolated document Random Pit Depth 44G 2 1 323-82-1 3 70.0 16.0 SU 0.054 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 44G 2 1 323-82-1 3 68.0 16.3 53.7 0.054 0.38 NA Spot corrosion. Substrate. REG-3. Isolated documenl Random Pi Depth 44G 2 2 324-82-1 3 65.0 15.7 48.7 0.049 0.38 NA Spot corrosion, Subs1rate, REG-3, Isolated document Random Pit Depth 44G 2 2 324-82-1 3 75.0 17.7 59.3 0.059 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 44G 2 2 325--82-1 3 76.0 15.7 58.3 0.058 0.38 NA Spot corrosion, Substrate, REG-3, lsoiated documenl Random Pit Depth 440 2 3 325-82-1 3 85.0 14.3 69.3 0.069 0.38 NA Spot Corrosion, Substrate, REG-3, lsoiated document Random Pit Depth 44G 2 3 326-82-1 3 75.0 15.0 60.7 0.061 0.25 NA Spot corrosion, Substrate, REG-3, tsolated document Random Pit Depth (19-42) P '~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                         & 3 Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                         Internal Pit Examination Record G.E. BWR Four/Mark I Containment- Torus          Direct Visual Examina1ion of Class MC Metal Containment Components Underwater Engineering Services, Inc.                                    QCP-9.1.6-CNS, Rev 2

[WI1n1:ua=t:f!1l'tlllf!,IIIm IN-SERVICE INSPECTION DIRECT VISUAL Record NO. NUC2016114-L-PER-001 I Measurements taken on Interior Torus Shell 44G 2 3 326-82-1 3 00.0 18.0 65.0 OJ)65 0.38 NA Spot COrrosion, Substrate, REG--3, Isolated document Random Pit Depth 44G 2 4 327-82-1 3 11.0 17.3 53.0 0.053 0.38 NA Spot Corrosion, Substrate, REG--3, Isolated document Random Pit Depth 44G 2 4 327-82-1 3 73.0 16.0 55.7 0.056 0.38 NA Spot Corrosion, Substrate, REG--3, Isolated documenl Random Pit Depth 44G 2 4 3 67.0 12.3 51J) 0.051 0.25 NA Spot Corrosion, Substrate, REG--3, Isolated 328-82-1 document Random Pit Depth 44G 2 4 3 65.0 14.7 52.7 0.053 0.25 NA Spot COrrosion, Substrate, REG--3, Isolated 328-82-1 document Random Pit Depth 44G 2 5 3 65.0 15.0 50.3 0.050 0.38 NA Spot Corrosion, Subsb'ate, REG--3, Isolated 329-82-1 document RandomPitDepth 44G 2 5 3 62.0 15.3 47.0 0.047 0.38 NA Spot Corrosion, Subsb'ate, REG-3, Isolated 329-82-1 documenl Random Ptt Depth 44G 3 1 308-83-1 3 68.0 18.0 50.0 0.050 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated documenl Random Pit Depth 44G 3 1 309-83-1 3 61.0 18.0 43.0 0.043 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 44G 3 1 310-83-1 3 64.0 17.7 46.3 0.046 0.38 NA Spot Corrosion, Subsb'ate, REG-3, Isolated document Random Pit Depth 44G 3 1 311-83-1 3 60.0 17.0 43.0 OJ}43 0.25 NA Spot COrrosion, Substrate, REG-3, Isolated documenl Random Pit Depth 44G 3 2 311-83-1 3 67.0 17.3 49.7 0.050 0.25 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 44G 3 2 312-83-1 3 65.0 17.7 47.3 OJM7 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated documenl Random Pit Depth 44G 3 3 312-83-1 3 60.0 17.3 42.7 0.043 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 44G 3 3 313-83-1 3 55.0 17.3 31.1 0.038 0.38 NA Spot COrrosion, Substrate, REG-3, Isolated documenl Random Pit Depth 44G 3 3 313-83-1 3 72.0 14.7 57.3 0.057 0.25 NA Spot COrrosion, Subsb'ate, REG-3, Isolated document Random Pit Depth 44G 3 4 314-83-1 3 60.0 17.3 42.7 0.043 0.25 NA Spot Corrosion, Substrate, REG--3, Isolated document Random Pit Depth 44G 3 4 314-83-1 3 55.0 16.7 38.3 0.()33 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 44G 3 4 315-83-1 3 58.0 17.3 40.7 0.041 0.38 NA Spot Corrosion, Subsb'ate, REG--3, Isolated document Random Pit Depth 44G 3 5 315-83-1 3 61.0 17.0 44.0 0.044 0.38 NA Spot Corrosion, Subsb'ate, REG--3, Isolated document Random Pit Depth 44G 3 5 316-83-1 3 50.0 17.3 32.7 0.033 0.25 NA Spot Corrosion, Substrate, REG--3, Isolated documenl Random Pit Depth 44G 3 5 316-83-t 3 59.0 15.3 43.7 0.044 0.25 NA Spot COrrosion, Subsb'ate, REG-3, Isolated documenl Random Pit Depth (19-43) R" *~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                             & 3 Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                           .Internal Pit Examination Record G.E. BWR FourfMark I Containment - Torus         Direct Visual Examination of Class MC Metal Containment Components Underwater Engineering Services, Inc.                                        QCP-9.1.6-CNS. Rev 2 l.'fl!H                 'lH{I IN-SERVICE INSPECTION                                                           DIRECT VISUAL                                   Record NO. NUC2016114-l-PER-001 Measurements taken on Interior Torus Sheil 34R   4    1  59-84-1      2  59.0    4.7    54.3  0.054      0.38   Shallow      Spot Corrosion, Substrate, REG-3, Isolated  document      Random Pit Depth 34R   4    1  60-84-1     3   35.0     6.7   28.3  0.028      0.13   NA           Spot Corrosion, Substrate, REG-3, Isolated  document      Random Pit Depth 34R   4    1  61-84-1      3  38.0     9.3   28.7  0.029      0.13   NA           Spot Corrosion, Substrate, REG-3, Isolated  document      Random Pit Depth 34R   4    1  62-84-1     3   25.0     4.3   21.7  0.022     0.13    NA           Spot Corrosion, Substrate., REG-3, Isolated document      Random Pit Depth 34R   4   2   63-84-1     3   49.0    7.3    41.7  0.042     0.38    NA           Spot Corrosion, Substrate, REG.J, Isolated  document      Random Pit Depth 34R   4   2   64-84-1     3   30.0    6.7    23.3  0.023     0.13    NA           Piffing, Substrate, REG-3, Random           document      Random Pit Depth 34R   4   2   65-84-1      3  40.0    7.0    33.0  0.033     0.13    NA           Piffing, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   3   66-84-1     3   43.0    7.7    35.3  0J)l5      0.13   NA           Pitting. Substrate, REG-3, tsolated         document      Random Pit Depth 34R   4    3  67-84-1     3   60.0    6.7    53.3  0.053      0.13   NA           Piffing, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   3   68-84--1    3   70.0    8.7    61.3  0.061     0.38    NA           Pitting, Substrate, REG-3, Isolated         doc:uroont    Random Pit Depth 34R   4   4   76-84-1     3   27.0    5.5    21.7  0.022     0.13    NA           Pitting, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   4   77-84-1      3  65.0    5.3    59.7  0.060     0.38    NA           Pitting, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   4   78-84-1     3   27.0    5.2    21.8  0Jl22     0.13    NA           Pitting, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   5   79-84-1     3   30.0    4.1    23.0  OJ}23     0.13    NA           Pitting, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   5   80-84-1     3   67.0    6.7    62.0  0.062      0.38   NA           Pitting, Substrate, REG-3, Isolated         document      Random Pit Depth 34R   4   5   81-84-1     3   43.0    9.3    37.3  f}.()37   0.13    NA           Pitting, Substrate, REG-3, Random           document      Random Pit Depth 34R   5   1   84-85-1     3   40.0     10.7  29.3  0.029     0.13    NA           Piffing, Substrate, REG-3, Random           document      Random Pit Depth 34R   5   1   86-85-1     3   35.0    5.0    l(U   0.030     0.13    NA           Pitting, SUbstrate, REG-3, Random           document      Random Pit Depth 34R   5   1   86-85-1     3   53.0    8.3    44.7  0J)45     0.13    NA           Ptffing. Substrate, REG-3, Random           doc:uroont    Random Pit Depth 34R   5   2   87.£35-1    3   70.0    8.0    62.0  0.062     0.38    NA           Pitting, Substrate, REG-3, Random           document      Random Pit Depth 34R   5   2   88.£35-1    3   45.0    7.7    37.3  0.037     0.13    NA           Pitting, Substrate, REG-3, Random           document      Random Pit Depth 34R   5   2   89-85-1     3   30.0    1.1    22.3  o.f)22    0.13    NA           Pitting, Substrate, REG-3, Random           document      Random Pit Depth 34R   5   3   90-85-1     3   25.0    7.9     17.1 0.017     0.13    NA           Pitting, Substrate, REG-3, Random           document      Random Pit Depth

( 1 ~-44) r<P"*s1on L

th 19.0 Containment Indication Tracking Cooper Station 5 Interval ISi rd

                                                                                                                                      & 3 Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                        Internal Pit Examination Record G.E. BWR Four/Mark I Containment- Torus        Direct Vtsual Examination of Class MC Metal Containment Components Underwater Engineering Services, lnc.                                   QCP-9.1.6-CNS, Rev 2
                                                                                                  ***rt:

IN-SERVICE INSPECTION DIRECT VISUAL Record NO. NUC2016114-L..PER-001 Measurements taken on Interior Torus Shell 34R 5 3 91-85-1 3 85.0 10.0 75.0 0.075 0.50 NA Pitting, SUbstrate, REG-3, Random Ctg. repair Random Pit Depth 6' left RG 1' up 34R 5 3 92-85-1 3 90.0 10.3 79.7 0.080 0.50 NA Piffing,SUbstrate,REG-3,Random Ctg. repair Random Ptt Depth 6' left RG 3* up 34R 5 4 95-85-1 3 75.0 10.7 67.3 0.067 0.38 NA Pitting, Substrate. REG-3, Random document Random Pit Depth 34R 5 4 96-85-1 3 70.0 5.0 63.3 0.063 0.38 NA Pitting, Substrate. REG-3, Random document Random Pit Depth 34R 5 4 97-85-l 3 57.0 8.J 49.3 (l.049 0.13 NA Pitting, Substrate, REG--3, Random document Random Pit Depth 34R 5 5 98-85-l 3 67.0 8.0 60.3 0.()60 0.13 NA Pitting, Substrate, REG-3, Random document Random Pit Depth 34R 5 5 99-85-l 3 90.0 7.7 80.3 0.080 0.38 NA Pitting, Substrate, REG-3, Random document Random Pit Depth 34R 5 5 99-85-1 3 75.0 7.7 67.3 OJ)67 0.38 NA Pitting, Substrate, REG-3, Random document Random Pit Depth 34R 5 5 99-85-1 3 70.0 6.7 63.3 0.063 0.38 NA Pitting, Substrate, REG-3, Random document Random Pit Depth 34R 5 5 99-85-1 3 57.0 7.7 49.3 0.049 0.38 NA Pitting. Substrate, REG-3, Random document Random Pit Depth 34R 5 5 99-85-l 3 67.0 6.7 60.3 OJJ60 0.38 NA Pitting, Substrate, REG-3, Random document Random Pit Depth Random Pit Depth 10" up from 6 and 34R 5 5 99-85-1 3 90.0 9.7 80.3 0.080 0.50 NA Pitting, SUbstrate, REG--3, Random document s* off 415 34R 5 5 100-85-1 3 65.0 8.1 56.l 0.056 0.13 NA Pitting, SUbstrate., REG~3, Random document Random Pit Depth 36R 6 4 129-86-t 2 64.0 7.0 57.0 0.057 0.38 Shaflow Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 4 134-86-1 3 89.0 7.1 81.3 0.081 0.50 NA Spot Corrosion, Substrate, REG--3, lsdated document Random Pit Depth 36R 6 4 135-86-1 3 87.0 8.0 79.0 0.079 0.50 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth 36R 6 4 136-86-1 3 70.0 8.7 61.3 0.061 0.38 NA Spot Corrosion, Substrate, REG-3, tsolated document Random Pit Depth 36R 6 4 137-86-1 3 00.0 7.3 72.7 OJ)73 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 5 138-86-1 3 75.0 7.0 68.0 0.008 0.25 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 5 139-86-1 3 63.0 7.0 56.0 0.056 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 1 140-86-t 3 70.0 8.0 62.0 0.062 0.25 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 1 14H36-I 3 60.0 7.3 52.1 0.053 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth (19-45) P '"ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                           & 3 Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                          Internal Pit Examination Record G.E. BWR fourfMark I Containment - Torus         Direct Visual Examination of Class MC Metal Containment Components Underwater Engineering Services, Inc.                                     QCP-9.1.6-CNS, Rev 2

[ill:IJIUIIIl=t:f11ill1Utllllm IN-SERVICE INSPECTION DIRECT VISUAL Record NO. NUC2016114-l-PER-001 Measurements taken on Interior Torus Shell I 36R 6 1 142-86-1 3 89.0 8.7 80.3 0.080 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 2 143.£6-t 3 60.0 6.3 53.7 0.054 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 36R 6 3 144-86-1 3 68.0 7.7 61.3 ().(161 0.38 NA Spot Corrosion, Substrate, REG-3, isolated document Random Pit Depth 36R 7 1 164.£7-1 2 64.0 11.3 52.1 0.053 0.13 Shalfow Pitting, SUbstrate, REG-2, Random Ctg. repair Pitting inside NRG 7+19 38R 7 5 174.£7-1 3 65.0 17.3 41.1 OJ.l48 0.13 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth 38R 7 5 175-87-1 3 54.0 16.0 38.0 0.038 0.13 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth 38R 7 4 176-87-1 3 37.0 11.3 25.7 0.026 0.13 NA Spot Corrosion, Substrate, REG-3, isolated document Random Pit Depth 38R 7 4 1TT-87-! 3 75.0 12.3 62.7 0.063 0.38 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth 38R 7 4 178-87-l 3 78.0 11.3 66.7 tl.067 0.38 NA Spot Corrosion, Subst'ate. REG-3, Isolated document Random Pit Depth 38R 7 3 179-87-1 3 34.0 11.0 23.0 0.023 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 7 3 100-87-1 3 74.0 13.0 61.0 0.061 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 7 2 181-87-1 3 66.0 11.0 55.0 0.055 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 7 2 182-87-1 3 69.0 14.0 55.0 OJ)55 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 7 2 183-87-1 3 63.0 11.7 51.3 0.051 0.13 NA Spot Corrosion, Substrate, REG-3. Isolated document Random Pit Depth 38R 7 1 184.£7-1 3 73.0 18.7 54.3 0.054 0.13 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth 38R 8 5 196-88-1 3 n.o 12.0 65.0 0.065 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 8 5 197-88-1 3 70.0 13.7 56.3 0.()56 0.38 NA Spot Corrosion, Substrate, REG-3, isolated document Random Pit Depth 38R 8 5 198-88-1 3 65.0 11.7 53.3 0.053 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 8 5 199-88-1 3 73.0 12.3 60.7 0.061 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 8 4 200-88-1 3 59.0 11.7 47.3 0.047 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 38R 8 3 .201-88-1 3 96.0 15.3 80.7 0.081 0.38 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth 38R 8 3 202-88-1 3 92.0 9.3 82.7 0.083 0.50 NA Spot Corrosion, Substrate, REG-3, lsolated document Random Pit Depth (19-46) R- '~ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                           & 3 Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                        Internal Pit Examination Record G.E. BWR Four/Mark I Containment- Torus        Direct Visual Examination of Class MC Metal Containment Components Underwater Engineering Services, lnc.                                   QCP-9.1.6-CNS, Rev 2 PIT DEPTH EXAMINATION IN-SERVICE INSPECTION                                                    DIRECT VISUAL                                  I    Record NO. NUC2016114-l-PER-001 Measurements taken on Interior Torus Shetl                   I 38R   8   2  203-88-1     3   77.0    13.3 63.7 0.064    0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated    document       Random Pit Depth 38R   8   2  204-88-1     3   78.0    16.3 61.7 ll.062   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated    document       Random Pit Depth 38R   8   2  205-88-i     3  89.0     13.3 75.7 0.076    0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated    document       Random Pit Depth 38R   8   1  206-88-1     3  78.0     13.0 65.0 0.065    0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated    document       RandomPitOepth 41R   9   1  209--89-1    2  71.0     15.3 55.7 0.()56   0.13    Shallow    Corrosion - Pitting, Substrate, REG-3, Random Ctg. repair    Recair 9-1-1 41R   9   1  210-89-1     2  75.0     16.0 59.0 OJ)59    0.38    Shallow    Corrosion - Pitting, Substrate, REG-3, Random Ctg. repair    Repaif 9-1-2 41R   9   1  211-89-1     2  75.0     15.7 59.3 0.059    0.38    Shallow    Corrosion - Pitting, Substrate, REG-3, Random Ctg. repair    Repaif 9-1-3 41R   9   1  212-89-1     2  68.0     17.0 51.0 0.051    0.38    Shallow    Corrosion- Pitting, Substrate, REG-3, Random  Ctg. repair    Repair9-1-4 41R   9   1  213-89-1     3  62.0     17.0 45.0 0.045    0.38    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   1  214-89-1     3   50.0    13.7 36.3 0.036    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   1  215-89-i     3  60.0     18.7 41.3 0.041    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   2  216-89-1     3   70.0    20.0 50.0 0.050    0.38    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   2  217-89-1     3   71.0    15.0 56.0 0.056    0.38    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9  2   218-89-1     3  54.0     15.0 39.0 0.039    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   3  219-89-1     3   60.0    17.0 43.0 0.043    0.13    NA         Corrosion - Pitting, Subs1rate, REG-3, Random document       Random Pit .Depth 41R   9   3  220-89-1     3  60.0     17.7 42.3 0.0.42   0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   3  221-89-1     3   50.0    17.3 32.7 0.033    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   4  224-89-1     3   52.0    15.3 33.0 0.033    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9  4   225-89-1     3  40.0     16.0 22.3 0.022    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9  4   226-89-1     3  50.0     15.7 32.0 0.032    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   5  227-89-1     3  52.0     19.0 36.3 0.036    0.13    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth 41R   9   5  228-89-1     3   43.0    17.7 26.3 0.026    0.13    NA         Corrosion-Pitting,Substrate,REG-3,Random      document       Random Pit Depth 41R   9   5  229-89-1     3   70.0    18.0 54.0 OJ)54    0.38    NA         Corrosion - Pitting, Substrate, REG-3, Random document       Random Pit Depth (19-47)                                                                                                P -~ion 2

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                           & 3 rd Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                       Internal Pit Examination Record G.E. BWR Four/Mark I Containment- Torus        Dired Visual Examination of Class MC Metal Containment Components Underwater Engineering Services, tnc.                                  QCP-9.1.6-CNS, Rev 2

[ID1,un. *1** 11 N IN-SERVICE INSPECTION DIRECT VISUAL Record NO. NUC2016114-L-PER-001 Measurements taken on Interior Torus Shell I 41R 10 1 232-810- 3 56.0 11.7 44.3 0.044 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 41R' 10 1 233--810-

• 3 60.0 12.7 47.3 0.047 0.38 NA Corrosion - Pitting, substrate, REG-3, Random document RandomPitOepth 41R 10 1 234-810- 3 60.0 12.7 47.3 OJ)47 0.38 NA COl'l'OSion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 43R 10 2 235-810- 3 50.0 1.1 42.3 0.042 0.13 NA corrosion-Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 10 4 246-810-- 3 45.0 7.3 37.7 0.1)38 0.13 NA Corrosion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 43R 10 4 247-810- 3 80.0 7.3 72.7 0.073 0.50 NA Corrosion- Pitting, Substrate, REG-3, Random doo.tment Random Pit Depth 43R 10 5 248-810- 3 30.0 5.7 24.3 0.024 0.13 NA Corrosion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 43R 10 5 249-810-- 3 55.0 11.3 43.7 0.044 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 10 5 250-810- 3 65.0 7.3 57-7 0.058 0.38 NA Corrosion - Pitting, substrate, REG-3, Random document Random Pit Depth 43R 11 1 255-811- 3 50.0 8.7 41.3 l>.041 0.13 NA COl'l'OSion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 11 1 256-811- 3 60.0 8.7 51.3 0.051 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 11 2 258-811- 3 65.0 10.0 56-0 0.05-0 0.38 NA COl'l'OSion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 11 2 259-811- 3 76.0 15.0 61.0 0.()61 0.38 NA Corrosion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 43R 11 2 260-811- 3 60.0 15.0 46.7 0.047 0.38 NA Corrosion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 43R 11 3 270-811- 3 65.0 9.0 56.0 0.056 0.38 NA COl'l'OSion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 43R 11 3 271-811- 3 61.0 12.0 49.0 0.049 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 11 3 272-811- 3 57.0 10.7 46.3 0.046 0.13 NA Corrosion- Pitting, SUbstrate, REG-3, Random doo.tment Random Pit Depth 43R 11 4 274-811- 2 70.0 8.7 61.3 0.061 0.38 Shallow Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 11 4 276-811-- 3 50.0 8.7 41.3 0.041 0.13 NA COl'l'OSion - Pitting, Substrate, REG-3, Random document Random Pit Depth 43R 11 4 277-811- 3 45.0 10.3 34.7 0.035 0.13 NA COl'l'OSion-Pittil'lg, SUbstrate, REG-3, Random doo.tment Random Pit Depth 43R 11 5 279-811- 3 33.0 8.3 24.7 0.025 0.13 NA Corrosion - Pitting, substrate, REG-3, Random document Random Pit Depth 43R 11 5 280-811- 3 51.0 8.7 42.3 0.042 0.13 NA COl'l'OSion - Pitting, Substrate, REG-3, Random document Random Pit Depth (19-48) R' -:<;ion 2

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                                                             & 3rd Interval CISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                         Internal Pit Examination Record G.E. BWR Four/Mark: I Containment - Torus       Direct Visual Examination of Class MC Metal Containment Components Underwater Engineering Services, Inc.                                    QCP-9.1.6-CNS, Rev 2 IJIWl                     'AU[I N IN-SERVICE INSPECTION                                                     DIRECT VISUAL                                         Record NO. NUC2016114-l-PER-001 I                    Measurements taken on Interior Torus Shell 43R 11     5  281-811-     3  65.0     12.0   53.0 0.053   0.13    NA         Cooosion - Pitting, Substrate, REG-3, Random    document      Random Pit Depth 55R 12    4   411-812-     2   65.0    10.7   54.3 0.054   0.13    Shallow    Corrosion - Pitting, Substrate, REG-2, Isolated Ctg. repair   PittinQ inside NRG 12-4-1 55R 12    4   411-812--    2   67.0    10.0   57.0 0.057   0.13    Shallow    Corrosion- Pitting, Substrate, REG-2, Isolated  Ctg. repair   Pit:tinQ inside NRG 12-4-2 55R 12     1  414-812--    3   78.0    10.3   67.7 0.068   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     1  414-812-     3  75.0     9.3    65.7 0.066   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Oepih 55R 12     1  415-812-     3   72.0    10.0   62.0 0.062   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     2  415-812--    3  88.0     6.3    81.7 0.082   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     2  416-812-     3   75.0    11.3   63.7 0.064   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R   12   2  416-812-     3   76.0    10.0   66.0 0.066   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depih 55R 12     3  417-812-     3   60.0    10.3   49.7 0.050   0.13    NA         Spot Corrosion, Substrate, REG-3, tsolated      document      Random Pit Depth 55R 12     3  417-812-     3  80.0     11.0   69.0 0.069   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Oepih 55R 12     3  418-812-     3   78.0    10.7   67.3 0.067   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     4  418-812-     3   73.0    14.7   58.3 0.058   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     5  419-812-     3  62.0     11.0   51.0 0.051   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     5  419-812--    3   72.0    9.3    62.1 0.063   0.13    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 55R 12     5  420-812-     3   68.0    11.7   56.3 0.056   0.13    NA         Spot Corrosion. Substrate, REG-3, Isolated      document      Random Pit Oepih 53R 13     1  399-813-     3  34.0     8.0    26.0 0.026   0.13    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 53R   13   1  400-813-     3  32.0     8.3    23.7 0.024   0.13    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 53R 13     1  400-813-     3   37.0    9.3    27.7 0.028   0. 13   NA         Spot Corrosion, Substrate, REG-3, lsolated      document      Random Pit Depth 53R 13     2  401-813-     3   63.0    11.0   52.0 0.052   0.38    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 53R 13    2   401-813-     3   40.0    11.0   29.0 0.029   0.13    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depth 53.R  13   2  402-813-     3   32.0    10.7   21.3 0.021   0.13    NA         Spot Corrosion, Substrate, REG-3, Isolated      document      Random Pit Depih (19-49)                                                                                                      R'" 1ision 2   I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                      & 3rd Interval GISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                      Internal Pit Examination Record G.E. BWR Four/Mark I Containment- Torus        Direct Visual Examination of Class MC Metal Containment Components Underwater Engineering Services, Inc.                                   QCP-9.1.6-CNS, Rev 2
                                                                     !illIt'll!la:               nm]

IN-SERVICE INSPECTION DIRECT VISUAL Record NO. NUC2016114-l-PER-001 Measurements taken on Interior Torus Shell I 53R 13 3 402-813- 3 40.0 9.0 31.0 0.031 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document RandomPitDepth 53R 13 3 403-813- 3 33.0 8.7 24.3 0.024 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 13 3 403-813-- 3 34.0 8.0 26.0 0.026 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 13 4 404-813- 3 60.0 10.7 49.3 0.049 0.38 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 13 4 404-813- 3 43.0 10.7 32.3 (Ul32 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 53R 13 4 405-813- 3 35.0 8.3 26.7 0.027 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 53R 13 5 405-813- 3 38.0 11.7 26.3 0.026 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 13 5 406-813- 3 45.0 9.3 35.7 0.036 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 13 5 406-813- 3 40.0 9.0 31.0 0.031 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 1 387-814- 3 35.0 0.0 35.0 0.035 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 1 388-814-- 3 37.0 0.0 37.0 ().037 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 53R 14 1 388-814-- 3 40.0 0.0 40.0 0.040 0.38 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 2 389-814- 3 45.0 0.0 45.0 0.045 0.38 NA Spot Corrosion, Substrate, REG-3, Isolated document Random PU Depth 53R 14 2 389-814- 3 49.0 11.0 38.0 OJ}la 0.13 NA Spot Corrosion, Subslrate., REG-3, Isolated document Random Pit Depth 53R 14 2 390-814- 3 47.0 9.0 38.0 OJ)la 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 53R 14 3 390-814- 3 53.0 11.7 41.3 0.041 0.13 NA Spot Corrosion, Substrate., REG-3, Isolated document Random Pit Depth 53R 14 3 391-814-- 3 36.0 11.3 24.7 0.025 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 3 391-814- 3 37.0 9.3 27.7 0.023 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 4 392-814- 3 86.0 9.3 76.7 0.077 0.50 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 53R 14 4 392-814- 3 50.0 10.7 39.J 0.039 0.13 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 4 393-814- 3 66.0 10.0 56.0 OJ):56 0.38 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 5 393-814- 3 54.0 8.0 46.0 0.046 0.38 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth 53R 14 5 394-814- 3 50.0 8.7 41.3 0.041 0.38 NA Spot Corrosion, Subslrate, REG-3, Isolated document Random Pit Depth (19-50) P *~ion 2

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                             & 3rd Interval GISI Program Nebraska Public Power District Cooper Nuclear Station RE29                                         Internal Pit Examination Record G.E. BWR Four/Marte I Containment- Torus        Direct Vtsual Examination of Class MC Metal Containment Components Underwater Engineering Services, Inc.                                      QCP-9.1.6-CNS, Rev 2
                                                                        !ill:l                        nml IN-SERVICE INSPECTION                                                       DIRECT VISUAL                                      Record NO. NUC2016114-l-PER--001 Measurements taken on Interior Torus Shet_l_ _ _ _ _ _ _~

53R 14 5 394-814- 3 42.0 10.0 32.0 0.032 0.13 NA Spot Corrosion, Substrate, REG-3, Isolated document Random Pit Depth 49R 15 1 359-815-2 1 30.0 16.7 13.3 0.013 0.13 ~ Corrosion - Zinc Depletion, REG-1, Isolated Ctg. repair Repair 15-1-1 49R 15 1 361-815-- 3 48.0 12.0 36.0 0.036 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 49R 15 1 361-815-- 3 55.0 13.3 41.7 0.042 0.38 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 49R 15 1 362-815- 3 50.0 14.7 35.3 0.035 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 49R 15 2 363-815- 3 47.0 15.0 32.0 0.032 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 49R 15 2 364-815- 3 30.0 11.0 19.0 0.019 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 51R 15 3 364-815-- 3 30.0 10.0 20.0 0.020 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 51R 15 3 365-815- 3 34.0 10.0 24.0 0.024 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 51R 15 3 365-B15- 3 34.0 12.3 21.7 0.022 0.13 NA Corrosion - Pitting, SUbstrate, REG-3, Random document Random Pit Depth 51R 15 4 367-815- 3 31.0 19.3 11.7 0.012 0.13 NA Corrosion - Pitting, substrate, REG-3, Random document Random Pit Depth 51R 15 4 367--815- 3 62.0 16.7 45.3 0.045 0.38 NA Corrosion- Pitting, Substrate, REG-3, Random document Random Pit Depth 51R 15 4 368--815- 3 35.0 19.0 16.0 0.016 0.13 NA Corrosion - Pitting, substrate, REG-3, Random document Random Pit Depth 51R 15 5 368--815- 3 60.0 16.0 44.0 U44 0.38 NA Corrosion-Pitting,Subs1rate,REG-3,Random document Random Pit Depth 51R 15 5 369-815- 3 76.0 12.3 63.7 0.064 0.38 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 51R 15 5 369-815- 3 33.0 12.7 20.3 0.020 0.13 NA Corrosion - Pitting, Substrate, REG-3, Random document Random Pit Depth 51R 15 5 370-815- 2 68.0 12.3 55.7 0.056 0.38 Shatlow Corrosion- Pitting, Substrate, REG-2, Random document Random Pit Depth 49R 16 1 342-816- 2 63.0 11.7 51.3 0.051 0.38 Shatlow Corrosion - Pitting, Substrate, REG-2, Random document Random Pit Depth 49R 16 1 342-816- 2 63.0 13.7 49.3 0.049 0.38 NA Corrosion - Pitting, SUbstrate, REG-2, Random document Random Pit Depth 49R 16 1 343-816- 3 41.0 10.7 36.3 0.030 0.38 NA Corrosion - Pitting, SUbstrate. REG-3, Random document Random Pit Depth 49R 16 1 343-816- 3 62.0 13.7 43.3 0.048 0.38 NA Corrosion - Pitting, substrate, REG-3. Random document Random Pit Depth 49R 16 1 344-816-- 3 32.0 8.7 23.3 0.023 0.13 NA Corrosion- Pitting, SUbstrate, REG-3, Random document Random Pit Depth (19-51) P *~ion 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi rd

                                                                                                                                                 & 3 Interval CISI Program
                                                                                                        ~.

Nebraska Public Power District Cooper Nuclear Station RE29 Internal Pit Examination Record G.E. BWR Four/Mark I Containment - Torus Direct Visual Examination of Class MC Metal Containment Components Underwater Engineering Services. Inc. IN-SERVICE INSPECTION QCP-9.1.6--CNS, Rev 2 1:111:,,st. DIRECT VISUAL

                                                                                                     ... m Record NO. NUC2016114-l-PER-001
                                           ~ - - - - _ _ _M~easur~1ents taken on Interior Torus Sh~--~~~****                     l 49R 16   2   345-816--    3  55.0     13.0  42.0  OJM2     0.38    NA.          Corrosion - Pitting, SUbstrate, REG-3, Random   doct.lrtlent   Random Pit Depth 49R 16   2   345-816-     3  60.0     11.0  49.0  0.049    0.38    NA           Corrosion - Pitting, SUbstrate, REG-3, Random   document       Random Pit Depth 49R  16  3   346-816-     3  35.0     11.7  23.3  0.021    0.13    NA           Corrosion - Pitting, substrate, REG-3, Random   document       Random Pit Depth 49R  16  3   346-816-     3  75.0     13.7  61.l  0.061    0.38    NA           Corrosion - Pitting, SUbstrate, REG-3, Random   document       Random Pit Depth 49R  16  3   347-816-     3  77.0     15.7  61.3  OJ)61    0.38    NA           Corrosion- Pitting, SUbstrate, REG-3, Random    doct.lrtlent   Random Pit Depth 49R  16  3   347-816-     2  65.0     15.0  50.0  0.050    0.38    Shallow      Con'osion - Pitting, Substrate, REG-3, Random   document       Random Pit Depth 49R 16   4   348-816-     2  70.0     16.3  53.7  0.054    0.38    ShaHow       Corrosion - Pitting, SUbstrate. REG-3, Random   document       Random Pit Depth 49R 16   4   355-816-    3   61.0     11.3  49.7  0.050    0.38    NA           Corrosion- Pitting, SUbstrate, REG-3, Random    document       Random Pit Depth 49R 16   4   356-816-     3  68.0     12.7  55.3  0.055    0.38    NA           Corrosion - Pitting, Substrate, REG-3, Random   document       Random Pit Depth 49R 16   4   356-816-     3  45.0     12.7  32.3  0.032    0.13    NA           Corrosion - Pitting, substrate, REG-3, Random   document       Random Pit Depth 49R 16   5   357-816-     3  57.0     13.7  43.3  0.043    0.38    NA           Corrosion - Pitting, SUbstrate, REG-3, Random   document       Random Pit Depth 49R  16  5   357-816-     3  57.0     15.0  42.0  0.042    0.38    NA           Corrosion - Pitting, Substrate, REG-3, Random   document       Random Pit Depth 49R  16  5   358-816-    2   88.0     15.7  72.3  0.072    0.50    Shallow      Corrosion - Pitting, Substrate, REG-2, Isolated Ctg. repair    Repair 16-5-1 (19-52)                                                                                                 P   *.. ion 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                        & 3 Interval GISI Program Figure 19.2 - Torus Exterior Indication Locations Top View (see Torus Exterior Indication table below for details)

TQPVIEW BX!*.TOR.-14(R) r E>..11*OR.*20 EXf~::~-4/~

                                                                                                                   /     '      ,,,      "",
                                                                                                                                       "3/4. f@rt,U        \
                                                                                                                                                             \
                                                                                                                 ~                  f"-~~.
                                                                                                                                    \ 67D
                                                                                                                                                         )
                                                                                                                                     \_,_/
                                                                                                                 '.Dfflt
                                                                                                                . P.S EXT,TOR.-10
              /~y BX!R".TOR.*l(Rl
              \.*
                 ~
                    \

I r\ ,!~-Toa.:ioo

                               \   _...---fmt' EXT.TOR.-6(R>,_:_~

EXT.TOR.-9 EXT.TOR.-11 EXT.TOR.-12

                      ~~*>

{Bl .. Bs1m111£d Area Q.. ftny lffltifRI (19-53) R" * 'i.on 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                       & 3 Interval CISI Program Figure 19.3 - Torus Exterior Indications Bottom View (see Torus Exterior Indication table below for details)

EXT.TOR.-17{R) EXT.TOR.-18(R) t N

                                                      -+-

I I EXT.TOR.*3(R)

                                                                                                      @ "'Reoopted Area Ntf     Y1D 0 . . Bu Log.1Jons 0

llaTroM PIJITU

                                                                                                         "'hPAArt Cgtumn LmtJ0u (19-54)                                                                            P        ion 2 I

19.0 Containment Indication Tracking Cooper Station 5 th Interval ISi rd

                                                                                                                                                                          & 3 Interval CISI Program Torus Exterior Indication table Out~gel ID R~port                          OR-CNS                         Location                                         IU!ms De,~ription                                         Comments (per Report*)
                                                                                                             ,~~J~dl~ (1!,lg l.il~teoog/@rie(1;):~t.pr¢'~              W024Sl*99Sg:was 1nitiated to*further L~techcn the.,$ide ofthe torcUs                   (a~:*feetwide x 7:feetlong. Bare,metalw.as :assessi,the,.eoni:f ftfon of:,the base materfals RE26    VT..:2011-021     mIQfl'.~\

2lif11-2~'6S outer radiuSibetween lower iaentif'fed*:imsev:eral areas. Hydraulic;,snubber and repair as necessany. VT-1 *of the bare tfltc1l>st columns 1,and .2 atEL;a~s* BS..S,-1T6A'iSilob fl~~tly above this a.tea, metal surface showed noislgns of.base and the reserv,mr was:fu1l. metal df,!gradattoo. .Area was*recoated~

                                                                                                            ~ppears*tabe:2 temporar:y weld attachments W04SX99S.9'was inftiated to further JiiQCated.orrlh,t:tiid~ ofth~to~                   ~~P:t~fmareJy:;1.'i-2° fl')Qfarn~t~r;. ~a¢h        fJ$~S~th~,c~ndftfon o:b:he f1as~;mqterlaLS,
                            ,*WiiIOf!,*~*

f{E26 I VT..:2or1-021 (Bt;co't.;Tro) 2El;11.:2259 I outer'radius between.1awei: columns contafns,arc,sfrikes:and under'!"Cuftfng, worst: and repair as ne.cessacy. VT-1 ofthe bare l5:and"l6',rt,EL 8701* ciis(r"'*~2 c;(~~th, NQ ~~k,~t~rlfne~r m~tql l!.Jrfl~e show~~ na$tgns Qf pijse fndications :emanatfngfrom the ara:stdke metal degradation. Area:was recoated. Arij.a appe,at$'io bav02.th~ e~ter:fqr c¢attng,c;tn~ W048'.1995,9 was initiated :tp further Locatedon the,sideofthe terus severafareas:of prfmer removed Jn,a lO."wicle assessthe*conditi' on ofthe base materials sXT 1TOR**3, RE26 VT-2011-02'1 2011~2269 outE!rtadtusadJa~nt,,te.lower R3.6 11 lorrg<area~ IUppec1rs'.io t:r~t>tlfysurfa~ and repair as,necessar;y. VT-1.ofthe bare fBE'CQATEO) columns 12 {between11 and 12} at ,coatings damctg~ fram pr:evious maintenance metal surface showed ncfsigns of base EL 868' actMtres and th~r~fqre doe.s nonip-pear to be metal degradation. Area was recoated. a service induced flaw

• 7 [between 7and 8:}on tne inside I

Located. adja. cent to lowe.r,.co***lum... ". s Exte.rfor.~tf.. n*gappe..arsto b~*de.gr,,ade*c:I* .over a band about 2 to3 feetwfde. In addition Stained area was determined to be RE26 VT-20.11-02'1 EXJ:dQBd 2011-.226.9

• there ls,a Wfde area ofwhatappe,ars;to be a.<<:~ptable as is. Nctaddl1;iona1 actt¢ns circumference of the Torus at sfmflar to Hmedeposfts running down the required.

apprqxim:a.telyEL.a~a* to8aPt outsfde,crrc.umference e>,f trarto:rus. Outer:ciciatingscfegraiiatton*ribservsdion an Cent~lly.fpea~d ~~eN loW"er itrea apr:,roirm:~te~ l' Wit:'~ by 1r long Pt~vfc:5!Jslv ra~ntmea tndf'tlonwas RE2e columns 1. and 2:anthe lnstae (running:fn,a horizontal dfrectfon}~* This determined to; be,accep.table,as primer is VT-2.0lJ-021 EXT.,;.TOR,~$ :2011-2269 (:1rcumferen~*t>f theiT<::>ru& at E.L fru:ficatfc:*mwas prevteusry,fden'tffied rn refU!#I stilt inti~. f\Jo adtf ltfona.l Attfcins 875' outage RE':24,andwas evaluateif:and found to reqlilfred. h.a TWe>t2:)~r$'as4' ~:Bi.n site wlth th'f!JQP coat mfss!ng,,buHhe,prlmer is,strll vfsfbte. Coattnij 1-.oc:ated *cm the Q'ater :radluS&sldeudf ,,aUntsJo:catfon:~ppe:ars'.to have beerrhee.ted we 48:19Q59 was rnrtrat~d'to*assesSzand RE2? \/T-2f11-021 :m::mff.i: ~, _ the torus,; betwaen;eolumns'1:5,and bywefair1g from tfie,fntertc,r:ohhe Torus recoat::a:s:necessary. VT-1 ofthe bare

                          '{R££!GAI§p)       Ql 1* 2* 469
                                                        , I tG onthe oof~.r~circumfetenee:,~                       ~tisrngdiseolor~t lon of t:ne coatrng,            metal surface sht?Wed n.o:$fgns of base the Torus EL 8lG1                          ln$pe~~sron the,*t,nstd~:er'the Torus              metal. d~gradation. Area was recoated.

confirmed/the lnstallati'o0.o'fpfp f0Jhangers to the fostde of the Torus.* (19-55) R ;on 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                                                                                                                   & 3 Interval CISI Program I.D Outagel    R'eport                       GR-CNS                        Location                                   Items: Description                                      *Comments

{per Report) The trtdlcatf($nwas raentrffed to be.anAr~ Stt'.ike'*th~twa:s measyr4d to.be o.,811 X:0;2 11 Cal¢Ulf.11:f~n.NEO.C $4-,?6itl!atetmft:led that wrth,e d~pthof Ctol 11 .This.indieatrorthas Located;g feetwest*ofthe ee:nter t:he prevlously*ldentlfied indh::atfon was pr;eviQYSly J;;een r~pc;,rt~d, and Is being RE26 \TT-2011-02'1 wa:tm-1'.il' 2P1.l"!ZSOS; I nne ctfBenrFZ~ 1;5":west ofweld c- acceptable-asis'.(S:tep,4:2.4.lof pr<>cedure monJtored :lnC'NSprocedure~6.PCA02 Rev.a,

                                                           '31 and 1711 north of wetd*et,,.f3                                                             5.PC.4t!1i ~ev8} and doesnotcompromtse
                                                                                                   ~fep 4.,2.4A. The fn:qtqatfQnw~s.detetmfn~d the rntegrffy't>f the:vessel to. have no:dlscernfble .differences from JjrevJc,us exa.rnfnatfons The ar~ea wtS'Jd.~n.trfled*tob:e iJ cotterete like material thatis16" by 28. Thfs concrete lfke mateti.tll w~s Identified to,beFon top. of the Jnf tfal torus:~tfhg*and haS'sf ncebeen r.ecoated. There,are.a few small a.n=as*where, the concr.ete has'detached from the Torus               .W048199S~"was Initiated to further Located under the .east edie of           shell, whf ch removed some-of .the or~lnal ass.ess.thec:ond.itf.on ofthe basematerfals RE26   VT-'2@11.-02'.1   EXLI9Ik1~    :20U-2SOS       Bent F? and 67 11 northohhe Torus              .coating and fffsome;,ar:eas exposed the          and r~patra:snecessary, VT.-lofthe bare fflEWA:IllPl T:op Dead Center.                 primer. The,r.emainln~areas . of concrete            metal surface showed no signs of .base
                                                                                                    ~rm~~rto be tfghtf\/ a.tO:i¢,rrn1Jt9tbe$Urfa~.e r:t:tf!.n!I \;:leBJ:'.id~,ti{;)n" Antawas recpatetJ .

ofthe*Torus.and dono't appear to be causin& anyia9<:f ftfi:;,natd1;3gra(ft:1ttPn.:of th~ l>~~ material. Also, theiareas,,where 0the primer tias bJ:~r:i e~~dt1r:ft,eir tt>be tn~ct and dA not,showany signs .ofaddftfonaJ :degradatfon The area was ldentrfled,.to:be a coatlog,stafn Located .on the top of"the torus, 3" rnJength wftb a:eoatfng.de:gradatlon .2 11 In W04S'l99S.9':was initia.ted,to.Jurther direcrtl.y undenn,lve SW~VJ>:.. dlinneter. E>amqge ~PP~aJ$ to b'e a,used!by ~ssass th~.~ri~Jtton phh~ basematerfals RE26 VT-2011-021 EXJYIQR-J,4 .2011"".2505 TCV451B, atthe center:Hne ofBent lea~{:le fromMalve:,~W-C'tlP;.;TC\14518; ihe a.nd r:epair:as,necessar;y. VT-1;ef'the bare CRE¢Q'AJ£:PJ F4*,mcf 4,~~.tl lncb~ nortnea,t'of ~am~ge.J$PP~~ruo ll.~* IJmtte.1;4 ~ the t9R ~t rrt~tf.l! $Pm stiqwej rte*.sJgo:s of*~~.~ the Torus centerltne weld and has not.yet propagated fothe base metal degradation. :Ar.ea*was recoated. ma~rial The ar~:a w;ts'tqen.tlfieq.te*.bea ~oocr~e,l!l<e Located on the top ,ofthe torus, S~ materfal 211 fn length. The concrete lfke W0::4819959,was fnffiated to farther feet riPtth . of Bl:fnt PS and 4 fe~t 6: materlat:a*ppears to:be Qn top ofthe fnltfal a~se~t"thl:! conditfon C)f the baS'.e materials RE26 vr.2011-0.21. EXII2B"l:5 :2011-2505 inches west of the top: of '.the Torus torus coatlng,and has slnce been recoated. and repafr as necessary. *VT~1.ofthe bare fM<<>AJiri) centerline weld near hangerSW- The.concrete rstfghtfy"adheringtothe surface metal surface showed no,.slgns of ba.se H 16.0 ofthe Torus and does not*appear to be metal :degradation. causing,any,additlona.1.degrad:ation (19-56) qevision 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi

                                                                                                                                                                        & 3rd Interval CISI Program Outagel ID         CR-CNS.

Report (per Report) Location l-ms oe,~,riptio:n .C9n,rnents Located orr the tsp<df the* *torus. 2 The in'dleatlorrMias fdentffred to hearrAr.c Calru1adonNED<?'Sl4,,;:f75determlned that feetndrth <'if centerlf'he, of Berit:ns~ Strfk~.that wa;s,mea.stut.ed tQ be 1.2'.' x 0.4"0

                                                                                                                                                                 ;the pl"~V1Qusly1dehtfffed indf.bc:3tfon was:

ffE26 VT-201~-S21 OO)T,QR,rl§ 1011--2665. 1.S;25" north of weld ~~1 :arrd wfth;a depth of&.Oli11* L'Oeatfon'hasbeen acceptable as ts: ($tep,4.:i.a~,1of*procedure 0 30:75" east,ofCD-9 arrd 4.~3 rnches previouslv,*reJ?ol"tedandJsbein~ monttore&Jn 6.PCA02 RevBland does:notcompromise westolwetd C~,; (;N,S proced.ure,6.,P¢.40~~~ws. Step 4;.2.4.;,3 I the integr:fj'.lpoftbevessel RE27 I Vf-F:12-036: M:Tog,..n 20124$090 I L~tedtmder the tPFustti

                                                             ,     . * *** l. *.,,.     **

I

                                                                                       ~ 3 on Area,oF*ru.stand fJ.aldn& p.a. int was identified tha'.t'requfr~d surface:prep;to;exam base After surface pre~acti.vitres. 1

• the ,area was re-examtned 0/T-F12..:Q8:1}arrd found to fflttQ.f\1£0) support co umn m 3*

VT-P12-0M materfal. have:no rndfc:atl'ons. Ar.ea was recoated. VT-Ff'2-ma RB27 I & MTqft,'/18 tRECCYAlU,!) Lo d 'd.* th.*.*. . .1 8 7,, . 201241060 I * ~t.e un e,r,,, e*,tf';)t!J$.;.~

• sup:port.,eo umn """*

                                                                                         . alt' on 1

Area:df rustand flaking. pai.nt wasfdentifted that required surfac:e;prep/toexam base IAfte. rs.u.rrace.*.* p.rep:a***ct*w**ltfes,,sth.ea. r.e. a.* was re-examfned t'1T..f12-08:1)and found to

• d
• VT-F\1~-0&1 m.ater:fal. have11orn reat{ons. Area was recoated, Th~ ltldfttitf<lrt'Wi!S fdentm*~c:1 t:t, l:te an'Arc P~r~cPl~ut~tr<.?t't NEO:C94~276, which Strfke and was measuredto,beb.:2s11 rn I

evaluated.simllar tv?es of localfzed diam.e~r Wftb*a:depth ofO.Gl". The,ar~,strike lMdt<:att0hS'iand'1e(),r(¢!0(:J~d that ff the Located under the top torus Bent fs located on the upper .portion of the Torus: fndrcattort ts,-:<2.5 Inches fn'dlameter and RE27 \IT-F12~036, m raR:...J9 20124806(). F!t 7.S" eas. to'fw.eld ro-s:and; 15" sh***eltWhfoh:.has a*.nomfnaltlifckn.ess.,oro.:s1e letsthan'halfthe;nomfnat*itte.ll*'tlii~n esa. north of wela c-21. rnch. Thereha'{e beer,'OtherfrrcUeatTons:*of ~djscent toctheiTqdicattoq, the indl~tion

                                                                                                    *arclltrikes;on the Ter::us.sheU, whfch:are have, fs£ode*,allowabl~:acceptable,as, J.s> and been documentediin 5.?e.402, notrtrcat'.fon d<:>e$ .not:comprgmf$e the Jrttegt'i:t;y*of the 10083!fa,.ano::CR :t..0'1988'                                          vessel Tfj~ 1rtdft:atfQtlWJl~ t~~ntffi~(l tp b-e,~mArc              P!?r~~,~tJ.l~tJon NE{)C\~ll,-~9>> 'Whfcb StrJke arrd wasmeasured:to,be:ll:10" fn*                   evaluated.*sJinltar,types* oflocalized dT~m~t~r wtth~rd:~pth <:>f:O:.Q4'1* Th~t~f:'y~.v.'.iKe fntif~atfo'.11srr-1r1!111<%~rt:cl.gtf~'tfia.tJfth.~.

tocated,6 tnches from.Bent F4. 0.7° is located entheupperportfomofthe Tor.us fndfca:tlen ls,,<2:.S:tnches indtameter and RE.l7 VT-F:12-036 m:rtm,.20. 2012...SQ60 test c>,f'Welcl Q.Q-6:and7;0" tt't#rth of sH~ll Wh~lth~;s a ~m.fn~I th!ck;n~~,ef Q;616 l~s~'cttlan.halfthe,f'forrHn1lJ,,.$hell thtekne'!Ss weld [)..;fS. fnch. There:have.been,other"irrdlcatibns'.o f adJacentts:theJndfeati.on,.:theJndi'catlon

                                                                                                    .aro$trtkeS::on the Toi'.usshell. whict-rare have            is,code :atloWable,,,a~ceptable,asJs, and been documentecHn 6J>e.4d2, notffieation does not compromfse ,the fntegrftyof the 100833:n:+a'rtd;ca 1-01968                                             vessel The lrrdleatf.on,was fdentrfted to be.an A~c                 Percalculatfon NEOti:94-2-16, which Strike,.and wasmeasure<fto:be0~2Qt' fn                     ,evaluated slmllar types ofJocallzed tjfameterwittra*dePtb of'0'"01°. The~ro,stdf<'.e                tndfcatr9n$,aJ:1d'tcon~l1JA:ed'th~tJf the Loea.ted under Bent F2. 1,2.7.S          fs,fQcated on the.upper,i:>ortion.;oHhe Torus              indicationJs,,<2.S:i.nchesin diameter and 8£27    VT../7$2-e,36   EXTlTQR,;:Z1  '2Ql2,.$Pq0 I w.est~ ~3.1 and 18.511 not:th"of$0- sb~ll wt'tttJthss a'.nt>n:tfn'l;ll 'thr~kne~;orQ.sJe               .l~S$'.,thfl.n h~lftoatr~m1nat:shell ttiidcrress

13. inch. There. have been,other' indfcatfonsof adJacent tosthe fndfcatfon,. the'indrcation arc:§trlke$(;.l'fl the, Ttu:us sh~ll, ,whtqh, ~re h~ve Is code ~ll.owatile.. ,~~~e.P~bl~i:a,S,;f.S-, and beerrdo.cumentedJn a:Pt:.402, nofiflea:tion doesnoM:ompromfse* the fntegdty of the 1QQ~S.7~rtdiG8 H)laea \/e$S~I (19-57) Revision 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                  & 3 rd Interval CISI Program Figure 19.4 Drywell Indications @ 0° RE26 - Ind.# 6 0.6" x 2.5" Paint Chip Area                 ~

Located @ 40° Az and 888' (floor to wall) Ref. CR-CNS-201 1-3139 RE27-DW-005 1.5" x 1.0" Paint Chip Area Located @ 003° Az and 888' (floor to wall)

                                                      ~
                                                      ~If/tr'('

(19-58) ~evision 2 I

19.0 Containment Indication Tracking Cooper Station 5th Interval ISi

                                                                                                          & 3 rd Interval GISI Program t

st Figure 19.5 Drywell Indications @ 90 ° \I,, i [4J t1\ El. 921' RE26 - Ind. # 3 Missing Coating Located @ 90° Az and 12' above 9'01' EL Ref. CR-CNS-2011-2958 Floor EL 888' I I I l  ! I I - - _ -1. L ------l l -______

                                                                             -       -'-_.Jr ELEVATION SffOWJI AT 90" (19-59)                                                                                   1evision 2 I

19.0 Containment Indication Tracking th Cooper Station 5 Interval ISi rd

                                                                             & 3 Interval GISI Program Figure 19.6 Drywell Indications @ 180 ° RE26 - Ind. # 1 0.6" x 0.5" Paint Chip Area Located @ 180° Az and 3' above 888' EL ~-

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                                                         .!11-!0WN ((f I" (19-60)                                                 Revision 2 I

Cooper Station 5th ISi & 3rd Interval CISI Program 20.0 lnservice Inspection (ISi) and Containment Inspection (CISI) History 20.1 ISi Program History CNS was constructed in accordance with the requirements of American National Standards Institute (ANSl)/ASME B31.1-1967 and B31.7-1969. In 1968, the ASME published the Draft Code for lnservice Inspection of Nuclear Reactor Coolant Systems, providing rules for lnservice Inspection of reactor coolant systems. The first official publication was January 1, 1970. Compliance with the ASME code requirements (i.e., Section XI) was made mandatory by Atomic Energy Commission (AEC) for nuclear plants with construction permits after April 1, 1970. Although the new rule became effective after the construction of CNS was essentially completed, the requirements of the rule were incorporated into Appendix J of the CNS Final Safety Analysis Report (FSAR). The requirements applied only to Class 1 systems. Inspection requirements for Class 2 systems were added to ASME Section XI in the Winter 1972 Addenda. Pump and valve testing and repair and replacement requirements were added in the Summer 1973 Addenda. Inspection requirements for Class 3 systems were added in the 1974 Edition. The requirements for inspection of Class 2 and Class 3 systems, pump and valve testing, and repair and replacement were not invoked by the regulations until 1976. In general, nuclear power plants are responsible for preparation of plans and schedules and filing of these plans and schedules with the Nuclear Regulatory Commission (NRC). Additionally, the ten-year interval plan is unaffected by changes in the ASME Section XI requirements {unless mandated by changes to 10CFR50.55a), however these changes could come into effect with subsequent ten-year interval plan submittals. For example, at the end of the first ten-year interval in July 1984, CNS updated the ISi and lnservice Testing (1ST) programs to the ASME Section XI 1980 Edition, Winter 1981 Addenda, as required by 10CFRS0.55a, {f) and (g). The program plan may also include a separate augmented section for Non-Code required examinations. These "augmented" examinations typically result from external commitments made to the NRC through docketed correspondence (e.g., responses to NRC Bulletins, Generic Letters (GL), and Inspection Reports (IR)) or internal commitments resulting from vendor correspondence, CNS experience, or industry operating experience. First Interval The commercial operation date for Cooper Nuclear Station is July 1, 1974. (20-1) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program The three inspection periods during the first inspection interval were as follows: 1 July 1, 1974 to October 30, 1977 2 November 1, 1977 to March 30, 1981 3 April 1, 1981 to June 30, 1984 Due to the Recirculation Piping Replacement outage from 1984 to 1985, the third period was extended to May 31, 1985 as allowed by IWA-2430(e). Second Interval In 1993 CNS began preparing for the next update of the ISi Program. Consultants were brought in to assess the status of the second interval examinations and draft the update for the third interval. In 1994 the NRC issued a confirmatory to CNS on a variety of issues. One issue was the adequacy of the ISi Program. Safety related piping in the Reactor Equipment Cooling (REC) and Service Water (SW) systems had not been included in the program. CNS personnel had misunderstood the piping classification requirements needed to implement the program. The Burns and Roe piping classification system used during construction did not match the ASME Section XI criteria for Class 3 systems. One of the contributing factors to this error was a lack of industry participation by the program engineeL As part of the corrective action, the second interval program was completely revised. New relief requests were generated, submitted to the NRC and approved. Any examinations or tests that had not been performed were completed during the Fall 1995 outage. The three inspection periods during the second inspection interval were as follows: (20-2) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program 1 June 1, 1985 to September 30, 1988 2 October 1, 1988 to January 31, 1992 3 April 1, 1992 to August 31, 1995 The plant remained shut down to resolve the CAL issues from May 1994 to February 1995. Consequently the third period of the second interval was extended to February 29, 1996 as allowed by JWA-2430{c). The third ten-year interval program was developed and submitted to the NRC. Implementation began March 1, 1996. The three inspection periods during the third inspection interval were as follows. 1 March 1, 1996 to June 30, 1999 2 July 1, 1999 to October 30, 2002 3 November 1, 2002 to February 28, 2006 The NRC, in their inspection report for the 1997 outage, noted the improvements in the conduct of the ISi Program. In addition, CNS was one of the first plants to develop and implement a Primary Containment inspection program in response to the September 1996 change to 10CFRS0.SSa. (Under this CFR revision, the requirements of ASME Section XI, Subsection IWE, 1992 Edition, 1992 Addenda which applies to Class MC components (i.e., Containment) were incorporated by reference into 10CFR50.55a.) Although rolled under the ISi Program, the CNS CISI Program for Class MC maintains a separate ten-year interval plan, a different ten-year interval, and a separate process for Class MC relief requests. In November 1999, 10CFRS0.55a was again revised to include Appendices VII and VIII to ASME Section XI. Appendix VII supplemented the training requirements for the Level I, II, and Ill NOE inspectors and Appendix VIII revised the ultrasonic testing (UT} requirements to incorporate the performance demonstration initiative. (20-3) Revision 0

Cooper Station 5th ISi & 3rd Interval CISI Program Fourth Interval The Fourth Interval lnservice Inspection Program was developed in accordance with the requirement of 10 CFR 50.55a and the 2001 Edition through the 2003 Addenda of the ASME Section XI Code. When the fourth interval started CNS was on 18 months cycles. In RE27 CNS began 24 months cycles. The three inspection periods were as follows: 1 March 1, 2006 to June 30, 2009* 2 July 1, 2009 to September 14, 2012** 3 September 15, 2012 to March 31, 2016***

• In accordance with IWB-2412(b), certain examinations from the Third Interval were performed during the Fall of 2006 (RE23} however were credited to the Third Interval

    **The second period dates were revised from November 1, 2012 to September 15, 2012 to align with the CNS refueling schedule. Examinations scheduled to start pre-outage (i.e., September 15, 2012 with an outage start date of October 13, 2012) and during RE27 were credited to the Third Period.
    ***RE27 was the first outage in the Third Period and the start of the 24 month cycles.

20.2 CISI Program History First Interval On September 9, 1996, 10CFRS0.55a was amended to incorporate the requirements of ASME Section XI Code 1992 Edition through the 1992 Addenda of Subsection IWE and IWL (Containment Program). Subsection IWE contains the requirements for liners and penetrations of light water cooled nuclear power plants and IWL contains the requirements for ISi of reinforced concrete containments (not applicable at CNS}. The rule at the time required licensees to incorporate the new requirements into their ISi programs and to complete examinations equal to the required First Period Inspections within five years (i.e., no later than September 9, 2001}. Subsection IWE requires that examinations be performed at the required inspection periods of 3, 7 and 10 calendar years of plant service within the interval. Therefore, the First Period Examinations were completed by September 8, 2001 to meet 10CFR50.55a requirements. The three inspection periods during the first inspection interval were as follows: (20-4) Revision O

Cooper Station 5th ISi & 3rd Interval CISI Program 1 September 9, 1996 to September 8, 2001 2 September 9, 2001 to January 8, 2005 3 January 9, 2005 to May 8, 2008 Second Interval On October 1, 2004, 10 CFR 50.55a was revised to incorporate by reference the 2001 Edition of ASME Section XI up to and including the 2003 Addenda. The CISI Program was updated to meet the requirements of the 2001 Edition through the 2003 Addenda. The three inspection periods during the second inspection interval were as follows: 1 May 9, 2008 to September 8, 2011 2 September 9, 2011 to January 8, 2015 3 January 9, 2015 to March 31, 2016*

• Request for Alternative RC3-01 was NRC approved to align the CISI Third Interval with the ISi Fifth Interval which will start on April 1, 2016.

(20-5) Revision 0}}