ML12285A263

Confirmatory Action Letter - Actions to Address Steam Generator Tube Degradation

ML12285A263
Person / Time
Site:	San Onofre
Issue date:	10/03/2012
From:	Peter Dietrich Southern California Edison Co
To:	Collins E Document Control Desk, Office of Nuclear Reactor Regulation, NRC Region 4
References
Download: ML12285A263 (134)

Text

SOUTHERN CALIFORNIA Peter T. Dietrich EDISON EJ Senior Vice President & Chief Nuclear Officer An EDISON INTERNATIONAL Company October 3, 2012 Elmo E. Collins, Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 1600 East Lamar Blvd.

Arlington, Texas 76011-4511

Subject:

Docket No. 50-361 Confirmatory Action Letter - Actions to Address Steam Generator Tube Degradation San Onofre Nuclear Generating Station, Unit 2

References:

1. Letter from Mr. Peter T. Dietrich (SCE) to Mr. Elmo E. Collins (USNRC), dated March 23, 2012, Steam Generator Return-to-Service Action Plan, San Onofre Nuclear Generating Station

2. Letter from Mr. Elmo E. Collins (USNRC) to Mr. Peter T. Dietrich (SCE), dated March 27, 2012, Confirmatory Action Letter 4-12-001, San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation

Dear Mr. Collins:

On March 23, 2012, Southern California Edison (SCE) submitted a letter (Reference 1) to the NRC describing actions it planned to take with respect to issues identified in the steam generator (SG) tubes of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3. On March 27, 2012, the NRC responded by issuing a Confirmatory Action Letter (CAL)

(Reference 2), describing the actions that the NRC and SCE agreed would be completed to address those issues and ensure safe operations. The purpose of this letter is to report the completion of the Unit 2 CAL actions, which are to be completed prior to entry of. Unit 2 into Mode 2 (as defined in the SONGS technical specifications).

Completion of the Unit 2 CAL actions is summarized below. Detailed information demonstrating fulfillment of Actions 1 and 2 of the CAL is provided in SCE's Unit 2 Return to Service Report which is included as Enclosure 2 of this letter. Enclosure 1 provides a list of new commitments identified in this letter.

P.O. Box 128 San Clemente, CA 92672 (949).368-6255 PAX 86255 Fax: (949) 368-6183 Pete.Dietrich@sce.com

Elmo E. Collins Regional Administrator October 3, 2012 U.S. Nuclear Regulatory Commission CAL ACTION 1:

"Southern CaliforniaEdison Company (SCE) will determine the causes of the tube-to-tube interactionsthat resulted in steam generatortube wear in Unit 3, and will implement actions to prevent loss of integrity due to these causes in the Unit 2 steam generator tubes. SCE will establish a protocol of inspections and/or operationallimits for Unit 2, including plans for a mid-cycle shutdown for further inspections."

COMPLETION OF CAL ACTION 1:

SCE has determined the causes of tube-to-tube interactions that resulted in SG tube wear in Unit 3, as summarized below. In addition, SCE implemented actions to prevent loss of tube integrity due to these causes in the Unit 2 SGs and established a protocol of inspections and operational limits, including plans for a mid-cycle shutdown. These are summarized under CAL Action 2.

Causes of Tube-to-Tube Interactions in Unit 3 As noted in Reference 1, the SG tube wear that caused a Unit 3 SG tube to leak was the result of tube-to-tube interaction. This type of wear was confirmed to exist in a number of other tubes in the same region in both Unit 3 SGs. Subsequent inspections of the Unit 2 SGs found this type of wear also existed in a single pair of tubes (one contact location) in one of the two Unit 2 SGs (SG 2E-089).

To determine the cause of the tube-to-tube wear (TTW), SCE performed extensive inspections and analyses, and commissioned the assistance of experts in the fields of thermal-hydraulics and in SG design, manufacturing, operation, and maintenance. Based on the results of these inspections and analyses, SCE determined the cause of the TTW in the two Unit 3 SGs was fluid elastic instability (FEI), resulting from the combination of localized high steam velocity, high steam void fraction, and insufficient contact forces between the tubes and the anti-vibration bars (AVBs). The FEI caused vibration of SG tubes in the in-plane direction that resulted in TTW in a localized area of the SGs. Details of SCE's investigation and cause evaluation are provided in Section 6 of Enclosure 2.

Corrective and Compensatory Actions, Inspections, and Operational Limits To prevent loss of integrity due to FEI and TTW in Unit 2, SCE implemented corrective and compensatory actions and established a protocol of inspections and operational limits, including plans for a mid-cycle shutdown. These are described in CAL Action 2 below.

CAL ACTION 2:

"Priorto entry of Unit 2 into Mode 2, SCE will submit to the NRC in writing the results of your assessment of Unit 2 steam generators,the protocol of inspections and/or operationallimits, including schedule dates for a mid-cycle shutdown for further inspections, and the basis for SCE's conclusion that there is reasonable assurance,as required by NRC regulations, that the unit will operate safely."

Elmo E. Collins Regional Administrator October 3, 2012 U.S. Nuclear Regulatory Commission COMPLETION OF CAL ACTION 2:

Assessment of Unit 2 Steam Generators SCE evaluated the causes of TTW in the Unit 3 SGs and the applicability of those causes to Unit 2 and inspected the Unit 2 SGs for evidence of similar wear. SCE determined the TTW effects were much less pronounced in Unit 2 where two adjacent tubes were identified with TTW indications. The wear depth was less than 15% through-wall wear, which is below the threshold of 35% through-wall at which tube plugging is required. These two tubes are located in the same region of the SG as those with TTW in Unit 3. Given that the thermal hydraulic conditions are essentially the same in both units, the significantly lower level of TTW in Unit 2 has been attributed to manufacturing differences that resulted in greater contact between the tubes and AVBs in Unit 2, providing greater tube support. Details of SCE's investigation and cause evaluation are provided in Section 6 of Enclosure 2.

Actions to Prevent Loss of Integrity due to TTW in Unit 2 SG Tubes Including Protocol of Inspections and Operational Limits SCE has taken actions to prevent loss of Unit 2 SG tube integrity due to TTW including establishing a protocol of inspections and operational limits to provide assurance that Unit 2 will operate safely. These actions are summarized below, with details provided in Section 8 of . The operational assessments performed to confirm the adequacy of these operational limits are described in Section 10 of Enclosure 2.

1. SCE will administratively limit Unit 2 to 70% reactor power prior to a mid-cycle shutdown (Commitment 1). Limiting Unit 2 power to 70% eliminates the thermal hydraulic conditions that cause FEI from the SONGS Unit 2 SGs by reducing the steam velocity and void fraction. Further, at 70% power, the SONGS Unit 2 SGs will operate within an envelope of steam velocity and void fraction that has proven successful in the operation of other SGs of similar design. Thus, limiting power to 70% ensures that loss of tube integrity due to FEI will not occur.

2. SCE plugged the two tubes with TTW in Unit 2. As a preventive measure, additional tubes were plugged in the Unit 2 SGs. Tubes were selected for preventive plugging using correlations between wear characteristics in Unit 3 tubes and actual wear patterns found in Unit 2 tubes. Removing these tubes from service will prevent any further wear of these tubes from challenging tube integrity.

3. SCE will shut down Unit 2 for a mid-cycle SG inspection outage within 150 cumulative days of operation at or above 15% power (Commitment 2). This shortened inspection interval will ensure that any potential tube wear will not challenge the structural integrity of the in-service tubes. The protocol for mid-cycle inspections is provided in Section 8.3 of Enclosure 2.

To ensure that these actions are effective in preventing a loss of tube integrity due to FEI, SCE retained the experience and expertise of AREVA NP, Westinghouse Electric Company LLC, and lntertek/APTECH. These companies routinely perform operational assessments (OAs) of SGs for the U.S. nuclear industry. AREVA and Westinghouse also have extensive steam generator design experience. SCE retained these companies to develop independent OAs using different methodologies to evaluate whether, under the operational limits imposed by SCE, SG tube

Elmo E. Collins Regional Administrator October 3, 2012 U.S. Nuclear Regulatory Commission integrity will be maintained until the next SG inspection. Each of these independent OAs demonstrates that operating at 70% power will prevent loss of tube integrity beyond the 150 cumulative day inspection interval.

The actions to operate at reduced power and shut down for a mid-cycle inspection within 150 cumulative days of operation are interim compensatory actions. SCE will reevaluate these actions during the mid-cycle inspection based on the data obtained during the inspections. In addition, SCE has established a project team to develop and implement a long term plan for repairing the SGs.

Defense-in-depth measures were developed to provide increased safety margin in the unlikely event of tube-to-tube degradation in the Unit 2 SGs during operation at 70% power. These actions, identified in Section 9 of Enclosure 2, will facilitate early detection of a SG tube leak and ensure immediate and appropriate plant operator and management response.

Basis for Conclusion of Reasonable Assurance SCE has evaluated the causes of TTW in the Unit 3 SGs and, as described in response to CAL Action 2 above, has completed corrective and compensatory actions in Unit 2 to prevent loss of tube integrity due to these causes. Tubes within regions of the Unit 2 SGs that might be susceptible to FEI have been plugged. In addition, as described in response to CAL Action 2 above, SCE has established operational limits that eliminate the thermal-hydraulic conditions associated with FEI from the SONGS Unit 2 SGs. Specifically, operation of Unit 2 will be administratively limited to 70% power. Within 150 cumulative days of operation at or above 15% power, Unit 2 will be shut down for inspection to confirm the condition of the SG tubes.

The analyses and OAs performed by SCE and independent industry experts demonstrate that under these conditions, tube integrity will be maintained. On this basis, SCE concludes that Unit 2 will operate safely.

We understand that the NRC will conduct inspections at SONGS to confirm the bases for the above information.

Please call me or Mr. Richard St. Onge at (949) 368-6240 should require any further information.

Sincerely,

Enclosures:

1. List of Commitments

2. Unit 2 Return to Service Report cc: NRC Document Control Desk R. Hall, NRC Project Manager, San Onofre Units 2 and 3 G. G. Warnick, NRC Senior Resident Inspector, San Onofre Units 2 and 3 R. E. Lantz, Branch Chief, Division of Reactor Projects, Region IV

ENCLOSURE 1 List of Commitments

Enclosure 1 List of Commitments This table identifies actions discussed in this letter that Southern California Edison commits to perform. Any other actions discussed in this submittal are described for the NRC's information and are not commitments.

Description of Commitment Scheduled Completion Date Prior to a mid-cycle shutdown of Unit 2, SCE will mid-cycle shutdown of administratively limit operation of Unit 2 to 70% power (refer to Unit 2 cover letter, Completion of CAL Action 2).

2 SCE will shut down Unit 2 for a mid-cycle steam generator within 150 cumulative (SG) inspection outage. During this outage, inspections of days of operation at or Unit 2 SG tubes will be performed to confirm the effectiveness above 15% power of the corrective and compensatory actions taken to address tube-to-tube wear in the Unit 2 SGs. (refer to cover letter, Completion of CAL Action 2).

3 SCE will install a temporary N-16 radiation detection system prior to Unit 2 entry into (refer to Enclosure 2, Section 9.2). The temporary N-16 Mode 2 detectors will be located on the Unit 2 main steam lines and be capable of detecting an increase in steam line activity.

4 SCE Plant Operators will receive training on use of the new prior to Unit 2 entry into detection tools for early tube leak identification and on lessons Mode 2 learned from response to the January 31, 2012, Unit 3 shutdown due to a steam generator (SG) tube leak (refer to Enclosure 2, Section 9.4.2).

5 SCE will upgrade the Unit 2 Vibration and Loose Part Monitor prior to Unit 2 entry into System (refer to Enclosure 2, Section 11.1). The new system Mode 2 will provide additional monitoring capabilities for steam generator secondary side noise.

6 SCE will install analytic and diagnostic software (GE Smart prior to Unit 2 entry into Signal) utilizing existing instrumentation (refer to Enclosure 2, Mode 2 Section 11.2).

ENCLOSURE 2 San Onofre Nuclear Generating Station Unit 2 Return to Service Report

[Proprietary Information Redacted]

Enclosure 2 L7: EDISON VSOUTHERN CALIFORNIA An EDISON INTERNATIONAL Company SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONAL Company SAN ONOFRE NUCLEAR GENERATING STATION UNIT 2 RETURN TO SERVICE REPORT October 3, 2012 Page 1

SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONA%' Comnpany SONGS Unit 2 Return to Service Report Record of Revision Revision Pages/Sections/

No. Paragraphs Changed Brief Description / Change Authorization 0 Entire Document Initial Issue

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EDISON "ISOUTHERN CALIFORNIA An EDISON INTLERNA TIONA L'i Company Unit 2 Return to Service Report Table of Contents Page R E C O R D O F R E V IS IO N ........................................................................................................................ 2 LIS T O F T A BLE S ................................................................................................................................... 6 LIS T O F F IGUR E S ................................................................................................................................. 7 ABBREVIATIO NS AND ACRO NYM S ................................................................................................. 8 1.0 EX E C UT IV E S UMMA R Y ........................................................................................................... 10 1.1 Occurrence and Detection of the Unit 3 Tube Leak ................................................. 10 1.2 Inspections of the Steam Generator Tubes and Cause Evaluations of Tube Wear ........ 11 1.3 Compensatory, Corrective, and Defense-in-Depth Actions ...................................... 11 1.4 O perational A ssessm ents ......................................................................................... 11 1 .5 C o n c lu s io n ..................................................................................................................... 12

2.0 INTRODUCTION

.................................................. .... 13 3 .0 BA C KG R O UND ........................................................................................................................ 14 3.1 Steam Generator Tube Safety Functions ................................................................. 14 3.2 SG Regulatory/Program Requirements ..................................................................... 15 3.3 The SONGS Steam Generator Program ................................................................... 16 4.0 UNIT 2 AND 3 REPLACEMENT STEAM GENERATORS .................................................... 17 5.0 UNIT 3 EVENT - LOSS OF TUBE INTEGRITY ................................................................... 18 5.1 S um m ary of E vent .................................................................................................... 18 5.2 Safety Consequences of Event ....................................... 19 5.2.1 Determ inistic R isk A nalyses ........ .. ........................................................ 19 5.2.2 Probabilistic Risk Assessment (PRA) ..................................................... 20 6.0 UNIT 3 EVENT INVESTIGATION AND CAUSE EVALUATION ........................................... 21 6.1 Sum m ary of Inspections Perform ed .......................................................................... 21 6.2 Summary of Inspection Results ....................................... 22 6.3 Cause Analyses of Tube-to-Tube Wear in Unit 3 ...................................................... 30 6.3.1 Mechanistic C ause .................................................................................. 30 6.3.2 Potential Applicability of Unit 3 TTW Causes to Unit 2 ............................. 30 6.4 Industry Expert Involvem ent .................................................................................... 31 6.5 C ause A nalysis Sum m ary .......................................................................................... 31 Page 3

SOUTHERN CALIFORNIA EDISON° An EDISON INTEkRNATIOXAL' Comlpany Unit 2 Return to Service Report Table of Contents (continued)

Page 7.0 UNIT 2 CYCLE 17 INSPECTIONS AND REPAIRS ............................................................... 32 7.1 Unit 2 Cycle 17 Routine Inspections and Repairs ...................................................... 32 7.2 Unit 2 Cycle 17 Inspection in Response to TTW in Unit 3 ......................................... 33 7.3 Differences between Units 2 and 3 ............................................................................ 36 8.0 UNIT 2 CORRECTIVE AND COMPENSATORY ACTIONS TO ENSURE TUBE INTEGRITY... 37 8.1 Limit Operation of Unit 2 to 70% Power .................................................................. 37 8.2 Preventive Tube Plugging for TTW .......................................................................... 45 8.2.1 Screening Criteria for Selecting Tubes for Plugging ................................ 45 8.2.2 Plant Operations with Tubes Plugged in Unit 2 ......................................... 48 8.3 Inspection Interval and Protocol of Mid-cycle Inspections ......................................... 48 8.3.1 Inspection of Inservice Tubes (Unplugged) ............................................. 48 8.3.2 Inspection of Plugged Tubes ................................................................... 48 9.0 UNIT 2 DEFENSE-IN-DEPTH ACTIONS .............................................................................. 50 9.1 Injection of Argon into the Reactor Coolant System (RCS) ....................................... 50 9.2 Installation of Nitrogen (N-16) Radiation Detection System on the Main Steam Lines ...50 9.3 Reduction of Administrative Limit for RCS Activity Level ........................................... 50 9.4 Enhanced Operator Response to Early Indication of SG Tube Leakage ................... 50 9.4.1 Operations Procedure Changes .............................................................. 50 9.4.2 O perator Training .................................................................................... 50 10.0 UNIT 2 OPERATIONAL ASSESSMENT .............................................................................. 51 11.0 A D D IT IO NAL A CT IO NS ............................................................................................................ 52 11.1 Vibration Monitoring Instrumentation ........................ .............................................. 52 11.2 G E S m art S ignal TM .................................................... ....... ........ ......... ........ ........ ..... . . . 52 12 .0 C O NC LUS IO NS ........................................................................................................................ 53 13 .0 R E F E R E NC E S ......................................................................................................................... 54 Page 4

SOUTHERN CALIFORNIA EDISON An EDISON IN-IERNA TIO**" L Company Unit 2 Return to Service Report Table of Contents (continued)

Page ATTACHMENTS 1 SONGS Unit 2 Relevant Technical Specifications 2 AREVA Document 51-9182368-003, SONGS 2C17 Steam Generator Condition Monitoring Report*

3 AREVA Document 51-9180143-001, SONGS Unit 3 February 2012 Leaker Outage - Steam Generator Condition Monitoring Report*

4 MHI Document L5-04GA564, Tube Wear of Unit-3 RSG - Technical Evaluation Report*

5 MHI Document L5-04GA571, Screening Criteria for Susceptibility to In-Plane Tube Motion*

6 SONGS U2C1 7 Steam Generator Operational Assessment*

• [Proprietary Information Redacted]

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SOUTHERN CALIFORNIA EDISON An EDISON INTERNA 770N.4L': Coipany Unit 2 Return to Service Report List of Tables Page TABLE 5-1: SONGS UNIT 3 SG 3E-088 IN-SITU PRESSURE TESTS WITH TUBE LEAKAGE ......... 19 TABLE 6-1: STEAM GENERATOR WEAR DEPTH

SUMMARY

.................................................... 29 TABLE 7-1: TTW COMPARISON BETWEEN UNIT 2 AND UNIT 3 SGS ......................................... 36 TABLE 8-1: INDEPENDENT ATHOS COMPARISON RESULTS - STEAM QUALITY ................... 38 TABLE 8-2: COMPARISON OF MAXIMUM VOID FRACTION ........................................................ 40 TABLE 8-3: COMPARISON OF MAXIMUM INTERSTITIAL VELOCITY (FT/S) .............................. 42 TABLE 8-4: UNIT 2 STEAM GENERATOR TUBE PLUGGING

SUMMARY

.................................... 45 Page 6

J EDISON SOUTHERN CALIFORNIA An EDISON INTERNATIONALI@ Company Unit 2 Return to Service Report List of Figures Page FIGURE 3-1: REPLACEMENT STEAM GENERATOR SECTION VIEW ......................................... 14 FIGURE 6-1: STEAM GENERATOR SECTION VIEW SKETCH .................................................... 23 FIGURE 6-2: UNIT 2 DISTRIBUTION OF WEAR AT AVB SUPPORTS ......................................... 24 FIGURE 6-3: UNIT 3 DISTRIBUTION OF WEAR AT AVB SUPPORTS ......................................... 24 FIGURE 6-4: UNIT 2 DISTRIBUTION OF WEAR AT TSP SUPPORTS .......................................... 25 FIGURE 6-5: UNIT 3 DISTRIBUTION OF WEAR AT TSP SUPPORTS .......................................... 25 FIGURE 6-6: PROBABILITY OF DETECTION FOR TUBE WEAR .................................................. 26 FIGURE 6-7: 3E-088 ROTATING COIL INSPECTION REGION ..................................................... 27 FIGURE 6-8: 3E-089 ROTATING COIL INSPECTION REGION ..................................................... 28 FIGURE 7-1: 2E-088 ROTATING COIL INSPECTION REGION ..................................................... 34 FIGURE 7-2: 2E-089 ROTATING COIL INSPECTION REGION ..................................................... 35 FIGURE 8-1: STEAM QUALITY CONTOUR PLOTS FOR 100% POWER AND 70% POWER ..... 39 FIGURE 8-2: MAXIMUM VOID FRACTION VERSUS POWER LEVEL AND ................................... 41 FIGURE 8-3: INTERSTITIAL VELOCITY CONTOUR PLOTS FOR 100% POWER AND 70% POWER43 FIGURE 8-4: GAP VELOCITY AT 100% POWER AND 70% POWER FOR 2E-088 R1 41 C89 ..... 44 FIGURE 8-5: GAP VELOCITY AT 100% POWER AND 70% POWER FOR 2E-089 R1 41 C89 ........ 44 FIGURE 8-6: 2E-088 PLUGGING AND STABILIZING MAP ........................................................... 46 FIGURE 8-7: 2E-089 PLUGGING AND STABILIZING MAP ........................................................... 47 Page 7

[ SOUTHERN CALIFORNIA EDISON" An EDISON ITERNA TIOV .- Lýý Company SONGS Unit 2 Return to Service Report ABBREVIATIONS AND ACRONYMS 2E-088 Unit 2 Steam Generator E-088 2E-089 Unit 2 Steam Generator E-089 3E-088 Unit 3 Steam Generator E-088 3E-089 Unit 3 Steam Generator E-089 AILPC Accident Induced Leakage Performance Criterion Ar Argon ATHOS Analysis of Thermal-Hydraulics of Steam Generators AVB Anti-Vibration Bar CDP Core Damage Probability CM Condition Monitoring DA Degradation Assessment DID Defense in Depth ECT Eddy Current Testing EFPD Effective Full Power Days EPRI Electric Power Research Institute ETSS Examination Technique Specification Sheet FEI Fluid Elastic Instability FIV Flow Induced Vibration FO Foreign Object FOSAR Foreign Object Search and Retrieval gpd Gallons Per Day INPO Institute of Nuclear Power Operations LERP Large Early Release Probability MHI Mitsubishi Heavy Industries, Ltd.

MSLB Main Steam Line Break MWt Megawatt Thermal N-1 6 Nitrogen - 16 NEI Nuclear Energy Institute NODP Normal Operating Differential Pressure OA Operational Assessment OSG Original Steam Generator post-trip SLB Steam Line Break Post-Trip Return-To-Power Event PRA Probabilistic Risk Assessment RB Retainer Bar RCPB Reactor Coolant Pressure Boundary RCE Root Cause Evaluation RCS Reactor Coolant System Ref. Reference RSG Replacement Steam Generator SCE Southern California Edison SG Steam Generator SGTR Steam Generator Tube Rupture SIPC Structural Integrity Performance Criterion SLB Steam Line Break SGP Steam Generator Program SONGS San Onofre Nuclear Generating Station SR Stability Ratio T/H Thermal-Hydraulics TEDE Total Effective Dose Equivalent TS Technical Specification TSP Tube Support Plate Page 8

JSOUTHERN EDISON CALIFORNIA An EDISON IN'TESRNA TIONA L Company SONGS Unit 2 Return to Service Report TTW Tube-to-Tube Wear TW Through Wall TWD Through Wall Depth U2C17 Unit 2 Cycle 17 UFSAR Updated Final Safety Analysis Report UT Ultrasonic Testing WEC Westinghouse Electric Company Page 9

SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONALý9 Conpany' SONGS Unit 2 Return to Service Report 1.0 EXECUTIVE

SUMMARY

On January 31, 2012, a leak was detected in a steam generator (SG) in Unit 3 of the San Onofre Nuclear Generating Station (SONGS). Southern California Edison (SCE) operators promptly shut down the unit in accordance with plant operating procedures. The leak resulted in a small radioactive release to the environment that was well below the allowable federal limits. Subsequently, on March 27, 2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) (Ref. 1) to SCE describing actions that the NRC and SCE agreed must be completed prior to returning Units 2 and 3 to service.

To address the tube leak and its causes, SCE assembled a technical team including experts in the fields of thermal hydraulics (T/H) and in SG design, manufacture, operation, and maintenance. The team performed extensive investigations into the causes of the tube leak and developed compensatory and corrective actions that SCE has implemented to prevent recurrence of the tube-to-tube wear (TTW) that caused the leak. SCE also implemented defense-in-depth (DID) measures to provide additional safety margin. SCE has planned SG inspections following a shortened operating interval to confirm the effectiveness of its compensatory and corrective actions.

As required by the SONGS technical specifications (TSs), the SONGS Steam Generator Program (SGP), and industry guidelines, an Operational Assessment (OA) must be performed to ensure that SG tubing will meet established performance criteria for structural and leakage integrity during the operating period prior to the next planned inspection. Because of the unusual and unexpected nature of the SG TTW, SCE commissioned three independent OAs by experienced vendors. These vendors applied different methodologies to ensure a comprehensive and diverse evaluation. An additional OA was performed to evaluate SG tube wear other than TTW. Each of these OAs independently concluded that the compensatory and corrective actions implemented by SCE are sufficient to address tube wear issues so that the Unit 2 SGs will operate safely.

The purpose of this report is to provide detailed information demonstrating completion of CAL actions required prior to entry of Unit 2 into Mode 2. The report also describes in detail the basis for the conclusion that Unit 2 will continue to operate safely after restart.

This report describes:

• Results of inspections of the SG tubes

• Causes of the tube wear in the Unit 2 and Unit 3 SGs

• Compensatory and corrective actions that SCE has taken to address tube wear in Unit 2

• OAs that have been performed to demonstrate that those compensatory and corrective actions ensure that TTW will be prevented until the next SG inspections

" Additional controls and DID actions that SCE is implementing to ensure health and safety of the public in the unlikely event of a loss of SG tube integrity 1.1 Occurrence and Detection of the Unit 3 Tube Leak New SGs were placed into service at SONGS Units 2 and 3 in 2010 and 2011, respectively. The replacement steam generators (RSGs) were installed to resolve corrosion and other degradation issues present in the original steam generators (OSGs). The RSGs were designed and manufactured by Mitsubishi Heavy Industries (MHI).

On January 9, 2012, after 22 months of operation, Unit 2 was shut down for a routine refueling and SG inspection outage. This was the first inspection of the Unit 2 SG tubes performed following SG replacement. The condition monitoring (CM) assessment performed to evaluate the results of this inspection confirmed that the SG performance criteria were satisfied during the operating interval.

On January 31, 2012, while the Unit 2 outage was in progress, SONGS Unit 3 was operating at 100 percent power when a condenser air ejector radiation monitor alarm indicated a primary-to-secondary leak. Unit 3 was Page 10

J EDISON`

SOUTHERN CALIFORNIA An EDISON INTERNA TIONA L Company SONGS Unit 2 Return to Service Report promptly shut down in accordance with plant operating procedures and placed in a stable cold shutdown condition. The TS limit for operational leakage (150 gallons per day (gpd)) was not exceeded during the event. A small, monitored radioactive release to the environment occurred, resulting in an estimated 0.0000452 mrem dose to the public. This estimated dose was well below the allowable federal limit specified in 10 CFR 20 of 100 mrem per year to a member of the public.

1.2 Inspections of the Steam Generator Tubes and Cause Evaluations of Tube Wear Subsequent to the reactor cooldown, extensive inspection, testing, and analysis of SG tubes was performed in both Unit 3 SGs. This was the first inspection of the Unit 3 SG tubes performed following SG replacement after approximately 11 months of operation. The leak was identified in SG 3E-088 and was caused by TTW in the U-bend portion of the tube in Row 106 Column 78. Additional inspections revealed significant TTW in many tubes in Unit 3.

In accordance with SGP requirements for unexpected degradation, SCE initiated a cause evaluation of the TTW phenomenon. The Root Cause Evaluation (RCE) Team used significant input from the SG Recovery Team which included the services of MHI and industry experts in the fields of T/H and in SG design, manufacturing, operation, and repair. The mechanistic cause of the TTW in Unit 3 was identified as fluid elastic instability (FEI), caused by a combination of localized high steam velocity (tube vibration excitation forces), high steam void fraction (loss of ability to dampen vibration), and insufficient tube to anti-vibration bar (AVB) contact to overcome the excitation forces. The FEI resulted in a vibration mode of the SG tubes in which the tubes moved in the in-plane direction parallel to the AVBs in the U-bend region. This resulted in TTW in a localized region of the Unit 3 SGs.

Although no TTW had been detected during the routine inspections of all tubes in Unit 2, the unit was not returned to service pending an evaluation of the susceptibility of the Unit 2 SGs to the TTW found in Unit 3. In March 2012, as part of this evaluation, additional inspections using a more sensitive inspection method were performed on the Unit 2 tubes. Shallow TTW was identified between two adjacent tubes in SG 2E-089.

1.3 Compensatory, Corrective, and Defense-in-Depth Actions SCE has implemented compensatory and corrective actions that will prevent loss of integrity due to TTW in Unit 2, including:

1. Limiting Unit 2 to 70% power prior to a mid-cycle SG inspection outage

2. Preventively plugging tubes in both SGs

3. Shutting down Unit 2 for a mid-cycle SG inspection outage within 150 cumulative days of operation at or above 15% power SCE has also implemented conservative DID measures to provide an increased safety margin in the unlikely event of tube-to-tube degradation in the Unit 2 SGs during operation at 70% reactor power. Additionally, SCE has provided enhanced plant monitoring capability to assist in evaluating the condition of the SGs.

1.4 Operational Assessments As required by the CAL (Ref. 1), SCE has prepared an assessment of the Unit 2 SGs that addresses the causes of TTW wear found in the Unit 3 SGs, prior to entry of Unit 2 into MODE 2.

Due to the significant levels of TTW found in Unit 3 SGs, SCE assessed the likelihood of additional TTW in Unit 2 from several different perspectives, utilizing the experience and expertise of AREVA NP, Westinghouse Electric Company, LLC (WEC), and Intertek/APTECH. Each of these companies routinely prepare OAs to assess the safety of operation of SGs at U.S. nuclear power plants. These companies developed independent OAs to Page 11

SOUTHERN CALIFORNIA EDISON An EDISON INJA'ERAATIONAL-6 Cotnpany SONGS Unit 2 Return to Service Report evaluate the TTW found at SONGS and the compensatory and corrective actions being implemented to address TTW in the Unit 2 SGs. These OAs apply different methodologies to ensure a comprehensive and diverse evaluation. Each of these OAs concluded that the compensatory and corrective actions implemented by SCE are sufficient to address tube wear issues so that the Unit 2 SGs will operate safely. The results of these analyses fulfill the TS requirement to demonstrate that SG tube integrity will- be maintained over the reduced operating cycle until the next SG inspection.

1.5 Conclusion On the basis of the compensatory and corrective actions, DID actions, and the results of the OAs, SCE concludes that Unit 2 will operate safely at 70% power for 150 cumulative days of operation with substantial safety margin and without loss of tube integrity. Reducing power to 70% eliminates the thermal hydraulic conditions that cause FEI and associated TTW from the SONGS Unit 2 SGs. After this period of operation, Unit 2 will be shut down for inspection of the steam generator tubes to confirm the effectiveness of. the compensatory and corrective actions that have been taken. SCE will continue to closely monitor steam generator tube integrity and take corrective actions as appropriate to ensure the health and safety of the public is maintained.

Page 12

F SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIOXA L' Company SONGS Unit 2 Return to Service Report

2.0 INTRODUCTION

On March 27, 2012, the NRC issued a CAL (Ref. 1) to SCE describing actions that the NRC and SCE agreed would be completed prior to returning Units 2 and 3 to service. The purpose of this report is to provide detailed information to demonstrate fulfillment of Actions 1 and 2 of the CAL, which are required to be completed prior to entry of Unit 2 into Mode 2. The actions as stated in the CAL are as follows:

CAL ACTION 1: "Southern CaliforniaEdison Company (SCE) will determine the causes of the tube-to-tube interactionsthat resulted in steam generatortube wear in Unit 3, and will implement actions to prevent loss of integrity due to these causes in the Unit 2 steam generatortubes. SCE will establish a protocol of inspections and/or operationallimits for Unit 2, includingplans for a mid-cycle shutdown for further inspections."

CAL ACTION 2: "Priorto entry of Unit 2 into Mode 2, SCE will submit to the NRC in writing the results of your assessment of Unit 2 steam generators, the protocol of inspections and/or operationallimits, including schedule dates for a mid-cycle shutdown for further inspections, and the basis for SCE's conclusion that there is reasonableassurance, as requiredby NRC regulations,that the unit will operate safely."

This report describes the actions SCE has taken to return Unit 2 to service while ensuring that the unit will operate safely. Because the SGs in Units 2 and 3 have the same design, the causes of the tube leak in Unit 3 and the potential susceptibilityof Unit 2 SGs to the same mechanism are also addressed. This report will demonstrate that actions have been completed to prevent loss of integrity in the Unit 2 SG tubes due to these causes.

Page 13

SOUTHERN CALIFORNIA EDISON An EDISON\ INTLRX TIQRNATI.Cotnpuny SONGS Unit 2 Return to Service Report

3.0 BACKGROUND

3.1 Steam Generator Tube Safety Functions The Reactor Coolant System (RCS) circulates primary system water in a closed cycle, removing heat from the reactor core and internals and transferring it to the secondary side main steam system. The SGs provide the interface between the RCS and the main steam system. Reactor coolant is separated from the secondary system fluid by the SG tubes and tube sheet, making the RCS a closed system and forming a barrier to the release of radioactive materials from the core. The secondary side systems also circulate water in a closed cycle transferring the waste heat from the condenser to the circulating water system. However, the secondary side is not a totally closed system and presents several potential release paths to the environment in the event of a primary-to-secondary leak.

The SG tubes have a number of important safety functions. As noted above, the SG tubes are an integral part of the Reactor Coolant Pressure Boundary (RCPB) and, as such, are relied on to maintain primary system pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes act as the heat transfer surface that transfers heat from the primary system to the secondary system. Figure 3-1 provides a section view of a SONGS SG.

Figure 3-1: Replacement Steam Generator Section View U-Bend Section, Tube Bundle Tube Support Plate

" Cold Leg Tubesheet Hot Leg Page 14

SOUTHERN CALIFORNIA EDISON An EDISO INTE!RNA T1O V LA Company SONGS Unit 2 Return to Service Report 3.2 SG Regulatory/Program Requirements The nuclear industry and the NRC have instituted rigorous requirements and guidelines to ensure that SG tube integrity is maintained such that the tubes are capable of performing their intended safety functions. Title 10 of the Code of Federal Regulations (10 CFR) establishes the fundamental regulatory requirements with respect to integrity of the SG tubes. The SONGS TSs include several requirements relating to the SGs including the requirement that SG tube integrity is maintained and all SG tubes reaching the tube repair criteria are plugged in accordance with the SGP (TS 3.4.17), that a SGP is established and implemented to ensure that SG tube integrity is maintained (TS 5.5.2.11), that a report of the inspection and CM results be provided to the NRC following each SG inspection outage (TS 5.7.2.c), and that the primary-to-secondary leakage through any one SG is limited to 150 gpd (TS 3.4.13). These TSs are provided in their entirety in Attachment 1.

TS 5.5.2.11, Steam Generator Program, requires the establishment and implementation of a SGP to ensure that SG tube integrity is maintained. The SGP ensures the tubes are repaired, or removed from service by plugging the tube ends, before the structural or leakage integrity of the tubes is impaired. TS 3.4.13 includes a limit on operational primary-to-secondary leakage, beyond which the plant must be promptly shutdown. Should a flaw exceeding the tube repair limit not be detected during the periodic tube inspections, the leakage limit provides added assurance of timely plant shutdown before tube structural and leakage integrity are impaired.

TS 5.5.2.11 requires the SGP to include five provisions, which are summarized below

a. CM assessments shall be conducted during each SG inspection outage to evaluate the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The purpose of the CM assessment is to ensure that the SG performance criteria have been met for the previous operating period.

b. SG tube integrity shall be maintained by meeting the specified performance criteria for tube structural integrity, accident induced leakage, and operational leakage.

c. Tubes found by in-service inspection to contain flaws with a depth equal to or exceeding 35% of the nominal tube wall thickness shall be plugged.

d. Periodic SG tube inspections shall be performed as specified in the TS. The inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection.

e. Provisions shall be made for monitoring operational primary-to-secondary leakage.

TS 3.4.13, RCS Operational Leakage, limits primary-to-secondary leakage through any one SG to 150 gpd. The limit of 150 gpd per SG is based on the operational leakage performance criterion in the Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines (Ref. 2). The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage.

Page 15

SOUTHERN CALIFORNIA EDISON An EDISON\ INTERN4TIOAL;- Company SONGS Unit 2 Return to Service Report 3.3 The SONGS Steam Generator Program The purpose of the SGP is to ensure tube integrity and compliance with SG regulatory requirements. The program contains a balance of prevention, inspection, evaluation and repair, and leakage monitoring measures.

The SONGS SGP (Ref. 10), which implements the requirements specified in TS 5.5.2.11, is based on the NEI 97-06, Steam Generator Program Guidelines (Ref. 2) and its referenced Electric Power Research Institute (EPRI) guidelines. Use of the SGP ensures that SGs are inspected and repaired consistent with accepted industry practices.

The SGP requires assessments of SG integrity. This assessment applies to SG components which are part of the primary pressure boundary (e.g., tubing, tube plugs, sleeves and other repairs). It also applies to foreign objects (FOs) and secondary side structural supports (e.g., tube support plates (TSPs)) that may, if severely degraded, compromise pressure-retaining components of the SG. Three types of assessments are performed to provide assurance that the SG tubes will continue to satisfy the appropriate performance criteria: (1) Degradation Assessment (DA); (2) CM Assessment; and (3) OA.

The DA is the planning process that identifies and documents information about plant-specific SG degradation.

The overall purpose of the DA is to prepare for an upcoming SG inspection through the identification of the appropriate examinations and techniques, and ensuring that the requisite information for integrity assessment is obtained. The DA performed for Unit 2 Cycle 17 (U2C1 7) SG Inspection Outage is discussed in Section 7.1 of this report.

The CM is backward looking, in that its purpose is to confirm that adequate SG tube integrity has been maintained during the previous inspection interval. The CM involves an evaluation of the as-found condition of the tubing relative to the integrity performance criteria specified in the TS. The tubes are inspected according to the EPRI Pressurized Water Reactor SG Examination Guidelines (Ref. 3). Structural and leakage integrity assessments are performed and results compared to their respective performance criteria. If satisfactory results are not achieved, a RCE is performed and appropriate corrective action taken. The results of this analysis are factored into future DAs, inspection plans, and OAs of the plant. The CM results for U2C1 7 are presented in Section 7 of this report.

The OA differs from the CM assessment in that it is forward looking rather than backward looking. Its purpose is to demonstrate that the tube integrity performance criteria will be met throughout the next inspection interval.

During the CM assessments, inspection results are evaluated with respect to the appropriate performance criteria.

If this evaluation is successful, an OA is performed to show that integrity will be maintained throughout the next interval between inspections. If any performance criterion is not met during performance of CM, a RCE is required to be performed and the results are to be factored into the OA strategy. The results of the OA determine the allowable operating time for the upcoming inspection interval. The OA addressing all degradation mechanisms found during U2C1 7 is discussed in Section 10 of this report.

Page 16

f1, EDISON' SOUTHERN CALIFORNIA An EDISONJIWIRNATIO \.L Cumpany SONGS Unit 2 Return to Service Report 4.0 UNIT 2 AND 3 REPLACEMENT STEAM GENERATORS New SGs were placed into service at SONGS Units 2 and 3 in 2010 and 2011, respectively. The RSGs were intended to resolve corrosion and other degradation issues present in the OSGs. The RSGs were designed and manufactured by MHI.

The steam generator is a recirculating, vertical U-tube type heat exchanger converting feedwater into saturated steam. The steam generator vessel pressure boundary is comprised of the channel head, lower shell, middle shell, transition cone, upper shell and upper head. The steam generator internals include the divider plate, tubesheet, tube bundle, feedwater distribution system, moisture separators, steam dryers and integral steam flow limiter installed in the steam nozzle. The channel head is equipped with one reactor coolant inlet nozzle and two outlet nozzles. The upper vessel is equipped with the feedwater nozzle, steam nozzle and blowdown nozzle. In the channel head, there are two 18 inch access manways. In the upper shell, there are two 16 inch access manways. The steam generator is equipped with six handholes and 12 inspection ports providing access for inspection and maintenance. In addition, the steam generators are equipped with several instrumentation and minor nozzles for layup and chemical recirculation intended for chemical cleaning.

Page 17

SOUTHERN CALIFORNIA EDISON xNi[l:SO. I\IN .R.TI\10\AL" Company SONGS Unit 2 Return to Service Report 5.0 UNIT 3 EVENT - LOSS OF TUBE INTEGRITY 5.1 Summary of Event On January 31, 2012, while the Unit 2 refueling and SG inspection outage was in progress, SONGS Unit 3 was in Mode 1 operating at 100 percent power, when a condenser air ejector radiation monitor alarm indicated a primary-to-secondary leak. A rapid power reduction was commenced when the primary-to-secondary leak rate was determined to be greater than 75 gpd with an increasing rate of leakage exceeding 30 gpd per hour. The reactor was manually tripped from 35 percent power, and placed in a stable cold shutdown condition in Mode 5.

The TS 3.4.13 limit for RCS operational leakage (150 gpd) was not exceeded. A small, monitored radioactive release to the environment occurred, resulting in an estimated 0.0000452 mrem dose to the public, which was well below the allowable federal limit specified in 10 CFR 20 of 100 mrem per year to a member of the public.

Subsequent to the reactor cooldown, extensive inspection, testing, and analysis of SG tube integrity commenced in both Unit 3 SGs. This was the first inspection of the Unit 3 SG tubes performed following SG replacement after approximately eleven months of operation. The work scope included the following activities: bobbin probe and rotating probe examinations using eddy current testing (ECT), secondary and primary side visual examinations, and in-situ pressure testing. The location of the leak in SG 3E-088, which resulted in the Unit 3 shutdown, was determined to be in the U-bend portion of the tube in Row 106 Column 78. ECT was subsequently performed on 100% of the tubes in both Unit 3 SGs. During these inspections, unexpected wear was discovered in both SGs including wear at AVBs, TSPs, RBs, and significant TTW in the U-bend area of the tubes. The TTW in Unit 3 was found to be much more extensive than in Unit 2, where only two tubes in one SG were determined to be affected.

The EPRI guidelines (Ref. 4) allow assessment of the structural and accident induced leakage integrity to be performed either analytically or through in-situ pressure testing. In accordance with EPRI guidelines and the SGP, in-situ pressure testing was performed on a total of 129 tubes in Unit 3, (73 in SG 3E-088 and 56 in SG 3E-089) in March 2012. The pressure tests were performed to determine if the tubes met the performance criteria in the TS (Attachment 1). The testing resulted in detected leaks in eight tubes in SG 3E-088 at the pressures indicated in Table 5-1. The failure location for all eight tubes was in the U-bend portion of the tube bundle in the tube freespan area. The locations of the tubes that were pressure tested and the tubes that failed the pressure tests are shown in Figure 6-7 and Figure 6-8. The first tube listed in the table (location 106-78) was the tube with the through-wall leak which resulted in the Unit 3 shutdown on January 31, 2012. No leaks were detected in the remaining 121 tubes tested in Unit 3. For the eight tubes indicating leakage, three tubes failed both the accident induced leakage performance criterion (AILPC) and the structural integrity performance criterion (SIPC); and 5 tubes passed the AILPC but failed the SIPC. All tubes met the operational leakage performance criterion of TS Limiting Condition for Operation 3.4.13. Details of the Unit 3 inspections and in-situ testing results are documented in the Unit 3 CM Report included as Attachment 3.

Additional testing performed to identify the extent and cause of the abnormal wear is presented in Section 6.

Required reports in response to the reactor shut down and in-situ test failures were made to the NRC in accordance with 10 CFR 50.72 and 50.73 (Refs. 5-8).

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SOUTHERN CALIFORNIA EDISON

'm EDIISON /

TIT1IE Companý SONGS Unit 2 Return to Service Report Table 5-1: SONGS Unit 3 SG 3E-088 In-Situ Pressure Tests with Tube Leakage Tube Location Maximum Test Pressure Performance Criteria Not Met Test Date, Time (row-column) Achieved (see Note 1) (see Note 2) 03/14/12, 1120PDT 106-78 2874 psig Accident Induced Leakage 03/14/12, 1249PDT 102-78 3268 psig Accident Induced Leakage 03/14/12, 1425PDT 104-78 3180 psig Accident Induced Leakage 03/15/12, 1109PDT 100-80 4732 psig Structural Integrity 03/15112, 1437PDT 107-77 5160 psig Structural Integrity 03/15/12, 1604PDT 101-81 4889 psig Structural Integrity 03/15/12, 1734PDT 98-80 4886 psig Structural Integrity 03/16/12, 1216PDT 99-81 5026 psig Structural Integrity Note 1 Test Pressures: Normal Operating Differential Pressure (NODP) Test Pressure = 1850 psig (Calculated) Accident Induced Leakage DP (Main Steam Line Break) Test Pressure = 3200 psig Structural Integrity Limit (3 x NODP) Test Pressure = 5250 psig Note 2 Performance Criteria: Structural Integrity - No burst at 3 x NODP test pressure Accident Induced Leakage - leak rate < 0.5 gpm at MSLB test pressure Operational Leakage - TS Limiting Condition for Operation 3.4.13 5.2 Safety Consequences of Event As discussed above, the Unit 3 shutdown on January 31, 2012, due to a SG tube leak, resulted in a small, monitored radioactive release to the environment, well below allowable limits. The potential safety significance of the degraded condition of the Unit 3 SG tubes is discussed below.

5.2.1 Deterministic Risk Analyses The SONGS Updated Final Safety Analysis Report (UFSAR) Section 15.10.1.3.1.2 presents the current licensing basis steam line break (SLB) post-trip return-to-power event (post-trip SLB). Based on the actual plant RCS chemistry data, the accident-induced iodine spiking factor of 500, and the estimated SG tube rupture leakage rate, the calculated dose would have been at least 32 percent lower than the dose consequences reported in the UFSAR for the post-trip SLB event with a concurrent iodine spike. The postulated post-trip SLB with tube rupture and concurrent iodine spike Exclusion Area Boundary, Low Population Zone, and Control Room doses would be less than 0.068 Rem Total Effective Dose Equivalent (TEDE), which is well below the post-trip SLB Control Room limit of 5 Rem TEDE, and the Exclusion Area Boundary and Low Population Zone limit of 2.5 Rem TEDE.

The potential for a seismically-induced tube rupture was also evaluated. The analysis determined the equivalent flaw characteristics of the most limiting degraded tube in Unit 3 SG 3E-088 from its in-situ pressure test result.

This tube, Row 106 Column 78 (the leaking tube), sustained an in-situ test pressure of 2,874 psi before exceeding leakage limits. This in-situ test pressure, which is slightly more than twice the operating differential pressure on the tube, corresponds to the limiting stress for crack penetration or plastic collapse with large deformation. The combined stresses due to operating differential pressure and seismic forces corresponding to SONGS Design Basis Earthquake (DBE) are lower than this limiting stress and are also less than the allowable stress for the faulted condition (i.e., including DBE) according to the American Society of Mechanical Engineers Code.

Therefore, the degraded tube would not have burst under this worst case loading.

Page 19

SOUTHERN CALIFORNIA EDISON n FI)ISO),\ / \VTILRNA1TIO\ L. Company SONGS Unit 2 Return to Service Report 5.2.2 Probabilistic Risk Assessment A Probabilistic Risk Assessment (PRA) was performed to analyze the risk impact of the degraded SG tubes on SONGS Unit 3 SG 3E-088 with respect to two cases: (1) any increased likelihood of an independent SG tube rupture (SGTR) at normal operating differential pressure (NODP), or (2) due to a SGTR induced by an excess steam demand event, also referred to as a main steam line break (MSLB). The SONGS PRA model was used to calculate the increases in Core Damage Probability (CDP) and Large Early Release Probability (LERP) associated with each case. In both cases, all postulated core damage sequences are assumed to result in a large early release since the containment will be bypassed due to the SGTR; therefore, the calculated CDP and LERP are equal. The total Incremental LERP (ILERP) due to the degraded SG tubes (i.e., the sum of the two analyzed cases) was determined to be less than 2x10 7 . This small increase in risk is attributed to two factors.

First, the exposure time for the postulated increased independent SGTR initiating event frequency case was very short (0.1 Effective Full Power Month (EFPM)). Second, a MSLB alone does not generate sufficient differential pressure to cause tube rupture in Case 2. The differential pressure across the SG tubes necessary to cause a rupture will not occur if operators prevent RCS re-pressurization in accordance with Emergency Operating Instructions.

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SOUTHERN CALIFORNIA EDISON'

%n FIDISO,\ I\,TERNATIONUL Compzin)

SONGS Unit 2 Return to Service Report 6.0 UNIT 3 EVENT INVESTIGATION AND CAUSE EVALUATION 6.1 Summary of Inspections Performed Following the identification of SG tube leakage in the Unit 3 SG 3E-088, extensive inspections were performed to determine the location and cause of the leak. The location of the leak was identified by filling the SG secondary side with nitrogen and pressurizing to 80 psig. The test identified the tube located at Row 106, Column 78 (R106 C78) as the source of the leakage. Using eddy current bobbin and rotating probes, the tube at R106 C78 and those immediately adjacent to it were inspected and the leakage location was confirmed. The leak location was in the U-bend portion of the tube in the "freespan" area between AVB support locations (refer to Figure 6-1).

To determine the extent of the wear that had resulted in a leak, an eddy current bobbin probe examination of the full-length of all tubes in both Unit 3 SGs was performed. The locations of tubes with TTW are shown on Figures 6-7 and 6-8. Based on the results of the bobbin probe examinations, TTW indications were then examined using a more sensitive +PointTm rotating probe. Figure 6-6 illustrates a comparison of the sensitivity of the two types of examinations. The more sensitive rotating probe examinations were also performed on a region of tubes adjacent to the tubes with detected TTW. This region is also shown on Figures 6-7 and 6-8. TTW indications were identified in 161 tubes in 3E-088 and 165 tubes in 3E-089. All of the TTW flaws were located in the U-bend portion of the tubes between TSPs 7H and 7C (shown on Figure 6-1).

The more sensitive eddy current rotating probe provided an estimated depth and overall length of TTW flaws on each tube examined. The examination technique (EPRI Examination Technique Specification Sheet, ETSS 27902.2) was site validated by building a test specimen with flaws similar to the TTW flaws observed in Unit 3.

Comparison of estimated wear depths with actual wear depths of the specimen supported the conclusion that ETSS 27902.2 conservatively estimated the depths across the entire range of depths tested (from 5% through-wall to 81% through-wall).

The tubes with flaws identified by ECT were analyzed to determine if they were capable of meeting the SONGS TS tube integrity performance criteria (Attachment 1). Tubes that did not meet the performance criteria based on analysis were tested via in-situ pressure testing. As described in detail in Section 5 and in the CM report (Attachment 3), a total of 129 tubes in the Unit 3 SGs were selected for in-situ pressure testing. Three tubes failed both the AILPC and the SIPC, and 5 tubes passed the AILPC but failed the SIPC as defined in TS 5.5.2.11.

These eight tubes are listed in Table 5-1. Figure 6-7 and Figure 6-8 show the locations of the tubes that were in-situ tested and the eight tubes that did not meet the performance criteria.

Secondary side remote visual inspections were performed to supplement the eddy current results and provide additional information in support of the cause evaluation. The inspections included the 7th TSP and inner bundle passes at AVBs B04 and B09 (shown on Figure 6-1). The 7th TSP inspection revealed no unexpected or unusual conditions. The inner bundle passes included several inspections between columns 73 and 87 and showed instances of wear indications that extended outside the AVB intersection. This was confirmed by eddy current data. Additional passes were made between columns 50 and 60. These inspections did not show any AVB wear outside the AVB intersections.

Page 21

J EDISON SOUTHERN CALIFORNIA Nn FI)!SON\ I \TIRNATI AL 'Comnpany SONGS Unit 2 Return to Service Report 6.2 Summary of Inspection Results This section provides a summary of the different types of tube wear found in the SONGS Unit 2 and 3 SGs. Wear is characterized as a loss of metal on the surface of one or both metallic objects that are in contact during movement.

The following types of wear were identified in the SONGS Units 2 and 3 SG tubes:

• AVB wear - wear of the tubing at the tube-to-AVB intersections

" TSP wear - wear of the tubing at the tube-to-TSP intersections

" TTW - wear in the tube free-span sections between the AVBs located in the U-bend region.

• RB wear - wear of the tubing at a location adjacent to a RB (RBs are not designed as tube supports for normal operation)

• FO wear - wear of the tubing at a location adjacent to a FO.

Most of the tube wear identified in the SGs is adjacent to a tube support. Figure 6-1 is a side view of an SG, showing the relationship of the tubes to the two types of tube supports: TSPs in the straight portions and AVBs in the U-bend portions of the tubes. All tubes are adjacent to many of these two types of tube supports. The RB supports are not shown because a very small number of tubes are adjacent to them.

TTW indications occurred in the free span sections of the tubes. The "free span" is that secton of the tube between support structures (AVBs and TSPs shown in Figure 6-1). TTW occurred almost exclusively in Unit 3 and is located on both the hot and cold leg side of the U-tube. In many cases, the region of the tube with TTW has two separate indications on the extrados and intrados of the tube. The wear indications on neighboring tubes have similar depth and position (ranging from 1.0 to 41 inches long and 4% to 100% throughwall) along the U-bend, confirming the tube-to-tube contact.

Table 6-1 provides the Wear Depth Summary for each of the four SGs based on eddy current examination results. Detailed results of the examinations performed are provided in the Units 2 and 3 CM reports included as Attachments 2 and 3. Figures 6-2 through 6-5 provide distributions of wear at AVB and TSP supports for all four SGs.

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T SOUTHERN CALIFORNIA EDISON Nn EDISO,\ I\ TRIN. I IO \)ViV Compan)

SONGS Unit 2 Return to Service Report Figure 6-1: Steam Generator Section View Sketch Anti-Vibration Bar (AVB)

B12 Page 23

SOUTHERN CALIFORNIA EDISON An MI)ISOQ I\'TErR.ATIO\ iLV Company SONGS Unit 2 Return to Service Report Figure 6-2: Unit 2 Distribution of Wear at AVB Supports 300 280 *2SGO 260 *2SG89 240 220 200 180 0

160-140-120-z 100-8o-60-40-20- M 0- -M.

0 1 2 3 4 5 6 7 8 9 10 11 12 Number of Affected Supports Figure 6-3: Unit 3 Distribution of Wear at AVB Supports 300 280 03SG88 260 03SG89 240 220 200 180 160 140 120 E

z 100 80 60 40 20 0

0 1 2 3 4 5 6 7 8 9 10 11 12 Number of Affected Supports Page 24

SOUTHERN CALIFORNIA EDISON An FI" I TT, . TIOQ\' 1LU Company A/

SONGS Unit 2 Return to Service Report Figure 6-4: Unit 2 Distribution of Wear at TSP Supports 180 02SWG8 160 *28G89 140 120 100 0 80-E z 60-40-20-0-

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Number of Affected Supports Figure 6-5: Unit 3 Distribution of Wear at TSP Supports dl n Jill I3SG88 J__

160 - 03SG S9 140 0

0 i 8O-E z 60-40-20-0-

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Number of Affected Supports Page 25

J an DI O, I

EDISON SOUTHERN CALIFORNIA

\NTERN 'ITlQIO\. Cump~In)

SONGS Unit 2 Return to Service Report Figure 6-6: Probability of Detection for Tube Wear ECT Techniques 1.0 0.8 80.7

=0.6 0.5 j0.3 0.2

- --+- es -7"J_=estF 0.1 - - - -- - - - - - - -- P Int I IS I I.t~

0.0 0 2 4 6 3 10 12 14 16 i8 20 22 24 2 238 30 Dept dtft (%"w Page 26

EDISON SOUTHERN CALIFORNIA

.\n EI)ISON I\TIER.ITIO \ (ompanu SONGS Unit 2 Return to Service Report Figure 6-7: 3E-088 Rotating Coil Inspection Region Tube 140 Inspection Region o TTW 120 " In-Situ Tested

• In-Situ Failures 100 1._

.0 E

z 60]

40 20 04 180 170 160 150 140 130 120 110 100 90 s0 70 60 50 40 30 20 10 a Column Number Page 27

EDISON O SOUTHERN CALIFORNIA N IOVAL'. Company An EDISON IVTT[RN,7 SONGS Unit 2 Return to Service Report Figure 6-8: 3E-089 Rotating Coil Inspection Region Tube 140 Inspection Region oTTW 120

• In-Situ Tested

• In-Situ Failures 100 80]

E z

0:

40 201 0

180 170 160 150 140 130 120 110 100 90 80 70 60 so 40 30 20 10 Column Number Page 28

SOUTHERN CALIFORNIA EDISON An EDISONJ\TR:RNATIO0'."L Company SONGS Unit 2 Return to Service Report Table 6-1: Steam Generator Wear Depth Summary SG 2E-080 TW Depth AVB Wear TSP TTW Retainer Bar Foreign Object Total Tubes with Indications Indications Indications Indications Indications Indications Indications TW > 50% 0 0 0 1 0 1 1 35-49% 2 0 0 1 0 3 3 20-34% 86 0 0 0 2 88 74 10-19% 705 108 0 0 0 813 406 TW < 10% 964 117 0 0 0 1081 600 Total 1757 225 0 2 2 1986 734*

SG 2E-089 AVB Wear TSP TTW Retainer Bar Foreign Object Total Tubes with TW Depth Indications Indications Indications Indications Indications Indications Indications TW k 50% 0 0 0 1 0 1 1 35-49% 0 0 0 1 0 1 1 20-34% 78 1 0 3 0 82 67 10-19% 1014 85 2 0 0 1101 496 TW < 10% 1499 53 0 0 0 1552 768 Total 2591 139 2 5 0 2737 861*

SG 3E-088 TW Depth AVB Wear TSP TTW Retainer Bar Foreign Object Total Tubes with Indications Indications Indications Indications Indications Indications Indications TW > 50% 0 117** 48 0 0 165 74 35-49% 3 217 116 2 0 338 119 20-34% 156 506 134 1 0 797 197 10-19% 1380 542 98 0 0 2020 554 TW < 10% 1818 55 11 0 0 1884 817 Total 3357 1437 407 3 0 5204 919*

______ ________SG

________ 3E-089_____

TW Depth AVB Wear TSP TTW Retainer Bar Foreign Object Total Tubes with Indications Indications Indications Indications Indications Indications Indications TW ? 50% 0 91 ** 26 0 0 117 60 35-49% 0 252 102 1 0 355 128 20-34% 45 487 215 0 0 747 175 10-19% 940 590 72 0 0 1602 450 TW < 10% 2164 94 1 0 0 2259 838 Total 3149 1514 416 1 0 5080 887*

This value is the number of tubes with a wear indication of any depth at any location. Since many tubes have indications in more than one depth category, the total number of tubes with wear indications is not the additive sum of the counts for the individual depth categories.

• • All TSP indications >50% TW were in tubes with TTW indications.

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SOUTHERN CALIFORNIA EDISON

)V' An EDISON TERNAATION.L-' Company SONGS Unit 2 Return to Service Report 6.3 Cause Analyses of Tube-to-Tube Wear in Unit 3 6.3.1 Mechanistic Cause SCE established a RCE team to investigate the condition, extent of condition, and cause of the event in Unit 3 and to determine corrective actions. The RCE was conducted, documented, and reviewed in accordance with the SONGS Corrective Action Program (CAP). The RCE Team used systematic approaches to identify the mechanistic cause of the TTW, including failure modes analysis (Kepner-Tregoe). The RCE team had access to and used significant input from the SG Recovery Team, which included the services of MHI and industry experts in the fields of T/H and in SG design, manufacturing, operation, and repair.

The failure modes analysis identified a list of 21 possible causes. The list was narrowed down, using facts, analysis, and expert input, to a list of eight potential causes that warranted further technical evaluation. The potential causes included manufacturing/fabrication, shipping, primary side flow induced vibration, divider plate weld failure and repair, additional rotations following divider plate repair, TSP distortion, tube bundle distortion during operation (flowering),

and T/H conditions/modeling.

The eight potential causes underwent rigorous analysis using both empirical and theoretical data, and support-refute methodology. This approach identified likely causes and eliminated non-causes. Each of the potential causes was evaluated by engineering analysis of the supporting and refuting data. The mechanistic cause of the TTW in Unit 3 was identified as FEI, involving the combination of localized high steam velocity (tube vibration excitation forces), high steam void fraction (loss of ability to dampen vibration), and insufficient tube to AVB contact to overcome the excitation forces. A more detailed discussion of the cause of FEI in the Unit 3 SGs is provided in MHI's Technical Evaluation Report, which is included as Attachment 4.

6.3.2 Potential Applicability of Unit 3 TTW Causes to Unit 2 At the time of the Unit 3 SG tube leak, Unit 2 was in the first refueling outage after SG replacement and undergoing ECT inspections per the SGP. Following the discovery of TTW in Unit 3, additional Unit 2 inspections identified two tubes with TTW indications in SG 2E-089. The location of TTW in the Unit 2 SG was in the same region of the bundle as in the Unit 3 SGs indicating causal factors might be similar to those resulting in TTW in the Unit 3 SGs. Because of the similarities in design between the Unit 2 and 3 RSGs, it was concluded that FEI in the in-plane direction was also the cause of the TTW in Unit 2.

After the RCE for TTW was prepared, WEC performed analysis of Unit 2 ECT data and concluded TTW was caused by the close proximity of these two tubes during initial operation of the RSGs. With close proximity, normal vibration of the tubes produced the wear at the point of contact. With proximity as the cause, during operation the tubes wear until they are no longer in contact, a condition known as 'wear arrest'. This wear mechanism is addressed in Section 10 and Attachment 6.

As described in Section 8, the compensatory and corrective actions implemented to prevent loss of tube integrity caused by TTW in Unit 2 are sufficient to conservatively address both identified causes.

Page 30

EDISON SOUTHERN CALIFORNIA ATnFDISO,\' IVTERNATIOXA LJ'. Company SONGS Unit 2 Return to Service Report 6.4 Industry Expert Involvement Upon discovery of TTW in Unit 3, SCE commissioned the services of industry experts to assist in assessing the cause of this phenomenon. SCE selected experts based upon their previous experience in design, evaluation, tube vibration, testing and causal determinations related to SGs. Members included experts in T/H and SGPs from MPR Associates, AREVA, Babcock & Wilcox Canada, Palo Verde Nuclear Generating Station, EPRI, Institute of Nuclear Power Operations (INPO), and MHI, as well as experienced consultants including former NRC executives and a research scientist. A series of panel meetings were conducted during which testing and analysis results were presented. The panel members assessed whether the current work by SCE and its partners was sufficient in understanding the TTW phenomenon and whether the corrective actions developed were sufficient to ensure tube integrity in the future.

6.5 Cause Analysis Summary SCE has determined the mechanistic cause of the TTW in Unit 3 was FEI, resulting from the combination of localized high steam velocity, high steam void fraction, and insufficient contact forces between the tubes and the AVBs. The FEI resulted in a vibration mode of the SG tubes in which the tubes moved in the in-plane direction, parallel to the AVBs, in the U-bend region. This resulted in TTW in a localized area of the SGs. As discussed in the following sections, SCE has identified actions to prevent loss of integrity due to FEI in the Unit 2 SG tubes. The extent of condition inspections performed in Unit 2 and differences identified between Units 2 and 3 are discussed in Section 7.

The compensatory and corrective actions to prevent loss of integrity due to these causes in the Unit 2 SG tubes are discussed in Section 8.

Page 31

SOUTHERN CALIFORNIA EDISON An EI)ISO\ I \-TERNAITIO"AL4" Company SONGS Unit 2 Return to Service Report 7.0 UNIT 2 CYCLE 17 INSPECTIONS AND REPAIRS On January 9, 2012, Unit 2 was shut down for a routine refueling and steam generator inspection outage after approximately 22 months of operation. As discussed in Section 3.3, the SGP requires a CM assessment to confirm that SG tube integrity has been maintained during the previous inspection interval. SCE conducted a number of inspections on each of the two Unit 2 SGs (2E-088 and 2E-089) in accordance with the SGP. Based on the inspection results, the Unit 2 CM assessment (included as Attachment 2) concluded that the TS SG performance criteria were satisfied by the Unit 2 SGs during the operating period prior to the current U2C1 7 outage. The TS performance criteria for tube integrity for all indications were satisfied through a combination of ECT examination, analytical evaluation, and in-situ pressure testing. The operational leakage criterion was satisfied because the Unit 2 SGs experienced no measurable primary-to-secondary leakage during the operating period preceding the Cycle 17 outage.

The Unit 2 outage was in progress on January 31, 2012, when Unit 3 was shut down in response to a tube leak.

Although the SG performance criteria had been met by the Unit 2 SGs, the unit was not returned to service pending an evaluation of the tube leak in Unit 3. Subsequent to the discovery of TTW conditions in the U-bend region of the Unit 3 SGs, additional inspections were performed on the Unit 2 tubes and shallow TTW was identified in two adjacent tubes in SG 2E-089.

Section 7.1 provides a summary of results from the routine inspections performed in Unit 2 and Section 7.2 provides a summary of results from the additional Unit 2 inspections performed in response to the discovery of TTW in Unit 3.

Details of all the inspections are provided in the Unit 2 CM report (Attachment 2). Section 7.3 summarizes the differences observed between Units 2 and 3.

7.1 Unit 2 Cycle 17 Routine Inspections and Repairs The SGP requires that a DA be performed prior to a SG inspection outage to develop an inspection plan based on the type and location of flaws to which the tubes may be susceptible. This assessment was performed prior to the inspection and was updated when unexpected degradation mechanisms were found during the inspection. These unexpected degradation mechanisms included (1) RB wear and (2) the TTW observed in Unit 3.

Initially, eddy current bobbin probe examinations of the full length of each tube was performed on 100% of the tubes in both Unit 2 SGs. Selected areas were then inspected using a more sensitive rotating +PointTM examination.

During the ECT examinations, wear was detected at AVBs, TSPs and RB locations. Six tubes with high wear indications (equal to or exceeding 35% of the tube wall thickness) were found. Four of those indications occurred in the vicinity of the RBs and two were associated with AVB locations as shown in Table 6-1. One in-situ pressure test was performed on a tube with RB wear, with satisfactory results. No other indications required in-situ pressure testing. Numerous smaller depth wear indications were also reported at other AVB and TSP locations. The ECT results are summarized in Table 6-1.

In accordance with TS 5.5.2.11 .c, tubes that are found to have indications of degradation equal to or exceeding 35%

through wall (TW) are removed from service by the installation of a plug in both ends of the tube. Once plugs are installed in both ends of a tube, they prevent primary system water from entering the tube. Plugs may also be used to preventively remove tubes from service. Use of preventive plugging is discussed in Section 8.2.

An RCE was completed for the unexpected RB wear. The RCE concluded that the RB size (diameter and length) was inadequate to prevent the RB from vibrating and contacting adjacent tubes during normal plant operation. The vibration source was a turbulent two phase flow (water and steam) across the RBs. As a corrective action, the 94 tubes adjacent to the RBs in each Unit 2 SG were plugged, including two tubes with RB wear in SG 2E-088 and four tubes with RB wear in SG 2E-089.

Page 32

V EDISON SOUTHERN CALIFORNIA Nn EDISON\ I,\TERNAMTOVALý Company' SONGS Unit 2 Return to Service Report Four additional tubes were plugged due to wear at AVB locations. Two of these were plugged as required for wear depths equal to or exceeding 35% TW; the other two with through wall depths (TWDs) of approximately 32% were plugged as a preventive measure. A significant number of tubes were preventively plugged and removed from service using screening criteria based on TTW indications in Unit 3. Table 6-1 provides the total numbers of tubes and indications due to all types of wear in the Unit 2 SGs. The tubes and criteria used to select tubes to be removed from service by preventive plugging due to their susceptibility to TTW are discussed in Section 8.2 and Attachment 5.

During the eddy current inspection of SG 2E-088, FO indications and FO wear indications were reported in two adjacent tubes at the 4 TSP. A secondary side foreign object search and retrieval (FOSAR) effort was performed and the object was located and removed. A follow-up analysis identified the object as weld metal debris. The two adjacent tubes were left in service because the indications were below the TS plugging limit and the cause of the degradation had been removed.

Remote visual inspections were performed to confirm the integrity of the RBs. The results of these visual inspections are summarized below:

" No cracking or degradation of RBs or RB-to-retaining bar welds was observed

• No cracking or degradation of AVB end caps or end cap-to-RB welds was observed

" No FOs or loose parts were found in the RB locations Post sludge lancing FOSAR examination at the top-of-tubesheet (periphery and the no-tube lane) found no evidence of degradation and no FOs.

7.2 Unit 2 Cycle 17 Inspection in Response to TTW in Unit 3 Subsequent to the discovery of TTW conditions in the U-bend region of Unit 3 SGs, an additional review of the U-bend region bobbin probe data was performed for the Unit 2 SGs. The tubes selected for review encompassed the suspected TTW zone as observed in Unit 3 and tubes surrounding that zone. Over 1,000 tubes in each Unit 2 SG were reviewed. The review included a two-party manual analysis (primary/secondary) of the complete U-bend with emphasis on the detection of low level freespan indications, which may not have been reported during the original analysis of the U2C1 7 bobbin coil data. No new indications were identified during this review.

Additional examinations of the U-bends were performed using rotating probe (+Point TM) technology. The scope of this examination is identified on the tubesheet maps provided in Figure 7-1 and Figure 7-2. During this examination, two adjacent tubes with TTW indications were detected. The indications were approximately 6 inches long, located between AVBs B09 and B1 0 in tubes R1 11 C81 and R1 13 C81 in SG 2E-089. Figure 7-2 shows the location of the two tubes with TTW in 2E-089. The maps in Figure 6-7 and Figure 6-8 show the inspection region overlaying the locations of the TTW found in the Unit 3 SGs.

SCE notified the NRC of the discovery of the two tubes with TTW in a letter dated April 20, 2012. (Ref. 9)

Remote visual inspections of the secondary side upper tube bundle were conducted in the Unit 2 SGs. These inspections were similar to those performed in Unit 3 SGs to assist in the development of the mechanistic root cause of TTW and tube wear at RB locations. No indications of TTW or other conditions associated with the FEI in Unit 3 (i.e., AVB wear extending outside the supports) were observed.

Rotating Pancake Coil ECT and Ultrasonic Testing (UT) were performed to measure the tube-to-AVB gap sizes in the Unit 2 SGs. Tube-to-AVB gap data was used to validate the contact force distribution model used in the TTW OA, (Attachment 6, Appendix B).

Page 33

EDISON OSOUTHERN An EMISON I,\TER CALIFORNIA

.ITIO .\'AI, Company SONGS Unit 2 Return to Service Report Figure 7-1: 2E-088 Rotating Coil Inspection Region Tube 140 Inspection Region 120 100 E

z 60-0 40 20 1 0O 180

---

0 170 160 150 140 130 120 110 103 90 s0 70 50 so 4a 30 20 10 0 Column Number Page 34

I SOUTHERN CALIFORNIA EDISON I2\TFIrntTIOoeric CoReport Sn UI)ISOni, SONGS Unit 2 Return to Service Report Figure 7-2: 2E-089 Rotating Coil Inspection Region Tube 140 Inspection Region STTW 120

~8 100 E, a z

0 40 20 0 +,

180 170 160 150 140 130 120 110 100 90 80 70 60 50 40 0 0 10 Column Number Page 35

SOUTHERN CALIFORNIA EDISON U EDISN\ t.TiRN, 1T0NAL- Company SONGS Unit 2 Return to Service Report 7.3 Differences between Units 2 and 3 As discussed in Section 6, inspections of the Unit 3 SG's found significant levels of TTW while Unit 2 SGs were limited to two shallow indications at one area of contact between two tubes.

A comparison of TTW and of factors associated with TTW between Unit 2 and Unit 3 SGs is provided below:

Table 7-1: TTW Comparison between Unit 2 and Unit 3 SGs Description Unit 2 Unit 3 TTW Indications 2 823 TTW Tubes 2 326 Max Depth (ECT %TW) 14% 99%

Max Length (inches) -6 -41 TTW In-Situ Pressure Tests 0 129 TTW In-Situ Pressure Tests (Unsatisfactory) 0 8 Operating Period (EFPD) 627 338 In addition to the above parameters, differences in manufacturing dimensional tolerance dispersion (distribution of dimensional values for manufacturing parameters that remain within acceptable tolerances) exist between the Units 2 and 3 SGs. Manufacturing process improvements implemented during the fabrication of the Unit 3 SGs resulted in lower manufacturing dispersion than in the Unit 2 SGs. MHI concluded that the reduced manufacturing dispersion in the Unit 3 SGs resulted in smaller average tube-to-AVB contact force than in the Unit 2 SGs. Due to the smaller average tube-to-AVB contact force, Unit-3 was more susceptible to in-plane vibration.

Page 36

EDISON' SOUTHERN CALIFORNIA 1W EI)ISO,'v I %TI*.INA*TIO\"IIS Company SONGS Unit 2 Return to Service Report 8.0 UNIT 2 CORRECTIVE AND COMPENSATORY ACTIONS TO ENSURE TUBE INTEGRITY SCE has implemented the following corrective and compensatory actions to prevent the loss of SG tube integrity due to TTW in Unit 2:

1. Limiting Unit 2 to 70% power prior to a mid-cycle SG inspection outage (CAL Response Commitment 1)

2. Preventively plugging tubes in both SGs (complete)

3. Shutting down Unit 2 for a mid-cycle SG inspection outage within 150 cumulative days of operation at or above 15% power (CAL Response Commitment 2)

The actions to operate at reduced power and perform a mid-cycle inspection within 150 cumulative days of operation are interim compensatory actions. SCE will reevaluate these actions during the mid-cycle inspection using data obtained during the inspections. In addition, SCE has established a project team to develop and implement a long term plan for repairing the SGs. SCE will keep the NRC informed of any findings or developments in the future.

SCE has performed an OA to assess the adequacy of the compensatory actions taken in Unit 2. The OA results demonstrate that operating at 70% power level will prevent loss of tube integrity due to TrW. In particular, reducing power to 70% eliminates the T/H conditions that cause FEI and associated TTW from the SONGS Unit 2 SGs. The OA and supporting analyses are summarized in Section 10 and provided in Attachment 6.

8.1 Limit Operation of Unit 2 to 70% Power SCE will administratively limit Unit 2 to 70% reactor power prior to a mid-cycle SG inspection outage. The cause of the TTW in the Unit 3 SGs was in-plane tube vibration due to FEI, resulting in tube-to-tube contact and wear.

An indication of whether a tube is susceptible to FEI is a calculated term defined as the stability ratio (SR). The SR calculation takes into account T/H conditions (including fluid flow and damping) and tube support conditions and provides a measure of the margin to a critical velocity value at which the tubes may experience the onset of instability due to FEI. The OA and its supporting analyses provided in Section 10 and Attachment 6 demonstrate that operating at 70% power will result in acceptable SRs in Unit 2.

Three independent comparisons were performed of the T/H parameters of SONGS RSGs operating at 100% and 70% power. SONGS RSG's were compared with five operating plants with recirculating SGs of similar design that have not observed TTW. The SONGS RSG's were also compared with the SONGS OSGs. The comparisons were conducted as follows:

(1) SCE Engineering conducted a study of average T/H parameters (2) WEC performed an Analysis of Thermal-Hydraulics of Steam Generators (ATHOS) study of SONGS RSGs to OSGs (3) An industry expert in SG design performed an independent ATHOS comparison of T/H parameters that can influence FEI Based on these comparisons, Plant A was selected for detailed analysis due to similarity of design characteristics and thermal power rating. Both SONGS and Plant A SGs use a U-bend design with the same tube diameter and pitch. Plant A operates at 1355 megawatts thermal per SG (MWt/SG) bounding the SONGS RSGs at 70% power (1210 MWt/SG). Plant A RSGs and SONGS RSGs utilitize out-of-plane AVBs in the U-bend. Plant A RSGs have operated for two fuel cycles without indications of TTW.

Page 37

SOUTHERN CALIFORNIA EDISON An EDISON I\TIRN,.hXTIOQXAL,' Company SONGS Unit 2 Return to Service Report Results of the comparisons of three T/H parameters (steam quality, void fraction, and fluid velocity) are presented in the following subsections. These results demonstrate that operating SONGS SGs at 70% power improves the T/H parameters to values lower than those in Plant A at 100% power.

Steam Quality Steam quality, defined as mass fraction of vapor in a two-phase mixture, is an important factor used in determining SRs. Steam quality is directly related to void fraction for a specified saturation state. This description is important when considering effects on damping. Damping is the result of energy dissipation and delays the onset of FEI. Damping is greater for a tube surrounded by liquid compared to a tube surrounded by gas. Since quality describes the mass fraction of vapor in a two-phase mixture, it provides insight into the fluid condition surrounding the tube. A higher steam quality correlates with dryer conditions and provides less damping.

Conversely, lower steam quality correlates with wetter conditions resulting in more damping, which decreases the potential for FEl.

Steam quality also directly affects the fluid density outside the tube, affecting the level of hydrodynamic pressure that provides the motive force for tube vibration. When the energy imparted to the tube from hydrodynamic pressure (density times velocity squared or pv2) is greater than the energy dissipated through damping, FEI will occur. When steam quality decreases, the density of the two-phase mixture increases, decreasing velocity.

Since the hydrodynamic pressure is a function of velocity squared, the velocity term decreases faster than the density increases. Small decreases in steam quality significantly decrease hydrodynamic pressure and the potential for FEl.

Steam quality in the SONGS RSGs was calculated for 100% and 70% power using the industry expert's independent ATHOS model and compared to Plant A at 100% power. The results of the calculations are summarized in Table 8-1 and graphically presented in Figure 8-1.

Limiting SONGS power to 70% reduces steam quality and hydrodynamic pressure to values less than Plant A.

Plant A has not experienced TTW.

Table 8-1: Independent ATHOS Comparison Results - Steam Quality SONGS 100% [ SONGS 70% I Plant A 100%

Thermal Power (MWt) 1715 1199 1368 Primary Inlet Temp (*F) 597.8 589.1 596.0 Maximum Mixture Density (kg/m3) 782 772 782 Minimum Mixture Density (kg/m3) 34 97 43 Maximum Dynamic Pressure (NIm2) 4140 2430 4220 Maximum Steam Quality 0.876 0.312 0.734 Note: The thermal power levels were calculated in the independent ATHOS comparison.

Page 38

SOUTHERN CALIFORNIA EDISONý An EDISON I\TE7rRNATIO\AL!- Comparn)y SONGS Unit 2 Return to Service Report Figure 8-1: Steam Quality Contour Plots for 100% Power and 70% Power 100% Power (Maximum Steam Quality = 0.876 from Independent ATHOS T/H Comparision) 09 08-07 0 f-05 04 02%

02 01 70% Power (Maximum Steam Quality = 0.312) 09 08 07 0 f.

05 04 03 02 01 Page 39

P EDISON u SOUTHERN CALIFORNIA An EDISON \NTlRNA TIOA,1, Lý! Company SONGS Unit 2 Return to Service Report Void Fraction Void fraction, defined as volume fraction of vapor in a two-phase mixture, is a factor used in determining SRs. A higher void fraction represents a lower percentage of liquid in the steam. Liquid in the steam dampens the movement of tubes. Higher void fractions result in less damping. Decreasing the void fraction in the upper bundle region during power operation increases damping and reduces the potential for FEI.

The void fraction in the SONGS RSGs was calculated at 100% and 70% power using ATHOS models from MHI, an independent industry expert, and WEC. The results are summarized in Table 8-2.

A significant effect of limiting power to 70% is the elimination of void fractions greater than Plant A. Plant A has not experienced TTW.

Table 8-2: Comparison of Maximum Void Fraction SONGS 100% SONGS 70% [Plant A 100% 1SONGS OSGs 100%

Thermal Power (MWt) 1729 1210 1355 1709 Bend Type U-Bend U-Bend U-Bend Square Bend MHI ATHOS T/H Results 0.996 0.927 -

Independent ATHOS T/H 0994 0.911 0.985 -

Comparison I I I WEC ATHOS T/H Comparison 0.9955 0.9258 - 0.9612 Note: Not all sources had access rights to the ATHOS models of some of the comparison plants, resulting in blank cells in this table.

Page 40

SOUTHERN CALIFORNIA EDISON' An EDISON INThINATION/AL Company SONGS Unit 2 Return to Service Report Void fractions at the locations of tubes with TTW in the RSGs are shown in Figure 8-2. The figure demonstrates that the occurrence of TTW was limited to tubes operating with maximum void fractions of greater than 0.993.

Figure 8-2: Maximum Void Fraction versus Power Level and Ratio of Tube Wear versus Maximum Void Fraction 100 0 2A Wear (TTW) 90 N28 Wear (TW 80 O 3A We (TTW) 70 38 Wear (TTW) 60 I--

50 9 40 30 to 20 10 o .. W to . M . - - . r. a .a --

II It II II II It II o 11 II II it i If 11 It It i tt u I I t II II I t II I V VVVVVVVVV V V V/ V V, V Vi Maximum Void Fraction~ofiXe Wear are located indication in the on region tubes where which max void fraction exceeds 0.993 By limiting power to 70% as presented in Table 8-2, void fractions are reduced to levels well below those associated with the TTW experienced at 100% power in the SONGS RSGs.

Fluid Velocity The fluid velocity in a steam generator's secondary side is a factor in SR calculations. Hydrodynamic pressure is the fluid velocity squared multiplied by the fluid density (pv 2) and is described in the "Steam Quality" section above.

The results of the velocity calculations are summarized in Table 8-3 and a graphical presentation of the results throughout a SG is shown in Figure 8-3. Interstitial velocity is a representative average velocity of flow through a porous media, which accounts for the structures and flow obstructions in the flow path.

Page 41

SOUTHERN CALIFORNIA EDISON' An EDISON, IN'TERNA'TIOY,\AL Company SONGS Unit 2 Return to Service Report Table 8-3: Comparison of Maximum Interstitial Velocity (ft/s)

SONGS 100% [ SONGS 70% 1 Plant A 100% SONGS OSGs 100%

Thermal Power (MWt) 1729 1210 1355 1709 Bend Type U-Bend U-Bend U-Bend Square Bend MHI ATHOS TIH Results 23.60 13.38 -

Independent ATHOS T/H Copdin22.08 11.91 17.91 Compar0sion WEC ATHOS TIH Comparison 28.30 13.28 - 22.90 Note: Not all sources had access rights to the ATHOS models of some of the comparison plants, resulting in blank cells in this table.

An additional analysis of velocity at different locations along a tube at 100% and 70% power was performed by WEC. This analysis used gap velocity, which relates to interstitial velocity through the geometric arrangement of the tube bundle and the angle of incidence between the fluid flow and tube (interstitial velocity multiplied by a surface porosity based on the tube bundle geometry). Tube R141 C89 has the longest bend radius in the bundle and relatively high gap velocities. A significant reduction in gap velocity for this tube occurs in the U-bend (mainly the hot leg side) when power is limited to 70%. The results for 2E-088 are shown in Figure 8-4, and results for 2E-089 are shown in Figure 8-5. The slight differences in the plots for the two SGs are caused by differences in numbers and locations of plugged tubes.

Limiting power to 70% significantly reduces fluid velocity. The reduction in fluid velocity significantly reduces the potential for FEI.

Page 42

SOUTHERN CALIFORNIA

\--F IIEDISONp An EI /SO,/\I'TE*R.NATI/O','.AL Company SONGS Unit 2 Return to Service Report Figure 8-3: Interstitial Velocity Contour Plots for 100% Power and 70% Power 100% Power (Maximum Interstitial Velocity = 6.73 m/s = 22.08 ft/s from Independent ATHOS T/H Comparison) 7--

6-5-

4-2-

1-0-

70% Power (Maximum Interstitial Velocity = 3.63 m/s = 11.91 ft/s) 6-5-

4-.

2-1-

Li Page 43

SOUTHERN CALIFORNIA EDISONC

!kn EI)ISO, I Tr \ 1lO\

ITO"L* Compzn)'

SONGS Unit 2 Return to Service Report Figure 8-4: Gap Velocity at 100% power and 70% power for 2E-088 R141C89 HOT LEG U-BEND COLD LEG 35 3)

~ 20 10 I

475 95 1425 190 237 5 266 0 30 60 90 120 150 166 285 2375 190 1425 95 475 0 Straight Lo Height U-1e.d Angle Straight Leg Height 0 to 311.45 W0d16 0 to 10 3ees 311.485 W0Wclle6 0

• Note: Two lines are shown for 70% power because separate ATHOS simulations were run for each half of the tube bundle due to the asymmetrical plugging in the SG Figure 8-5: Gap Velocity at 100% power and 70% power for 2E-089 R141C89 HOT LEG U-1BEND COLD LEG 35.

---

IR141C6. 106 RijiC99.SG89HC70l

-R141Z69,9G9LC707 t-S C

475 95 1425 190 2375 285 265 2375 190 142-5 5 475 Straight Leg Height U-Bend Angle Straight Leg Height 0 to 311485 MiS e 01 ID0 egdees 311 485 to 0 inche

• Note: Two lines are shown for 70% power because separate ATHOS simulations were run for each half of the tube bundle due to the asymmetrical plugging in the SG.

Page 44

SOUTHERN CALIFORNIA EDISON An EDISON INTER,1ATION.10 Company SONGS Unit 2 Return to Service Report MHI's ATHOS model was used to calculate the T/H input parameters for the SR calculations. ATHOS is an EPRI computer program used by SG design companies in North America. SCE commissioned two independent T/H analyses to verify the MHI ATHOS analysis. These independent verifications were performed by WEC using ATHOS and AREVA using their T/H computer code CAFCA4. MPR Associates compared the three T/H analyses (MHI ATHOS, WEC ATHOS, and AREVA CAFCA4) and concluded the models predicted similar void fraction, quality, and velocity results.

8.2 Preventive Tube Plugging for TTW Tubes were identified for preventive plugging using correlations between wear characteristics in Unit 3 tubes and wear patterns at AVBs and TSPs in Unit 2. The screening criteria used to select these tubes is discussed in Section 8.2.1. Removing these tubes from service prevents future wear from challenging SG performance criteria for structural and leakage integrity. These tubes were plugged in addition to the 4 tubes plugged for AVB wear and the 182 tubes plugged as a preventive measure against potential RB wear (described in Section 7.1). A summary of all tubes selected for plugging in Unit 2 is provided in Table 8-4. The impact on operations of the plugged tubes is discussed in Section 8.2.2.

8.2.1 Screening Criteria for Selecting Tubes for Plugging After identification of the TTW in Unit 3, additional examinations of the susceptible region in Unit 2 identified shallow TTW on two adjacent tubes. Although the 14% TW depth of these indications was below the TS plugging threshold of 35%, the tubes were stabilized and plugged to reduce the risk of tube failure due to continued wear.

Using screening criteria developed by MHI from TTW indications in Unit 3, SCE selected 101 tubes in 2E-088 and 203 tubes in 2E-089 for preventive plugging. Nine screening criteria were identified using the quantity and location of AVB and TSP wear indications, length of AVB wear indications, average void fraction over the length of the tube, location of the tube within the tube bundle, and coupling between adjacent susceptible tubes. These criteria are provided in Attachment 5.

Table 8-4 provides a summary of all the tubes selected for plugging in Unit 2. The locations of the Unit 2 tubes selected for plugging and stabilization using the preventive plugging criteria are shown in Figure 8-6 and Figure 8-7. Additional screening criteria was provided by industry expert review (wear at 6 Consecutive AVBs) and WEC (TSP wear).

Table 8-4: Unit 2 Steam Generator Tube Plugging Summary TTW Preventive TWD TWD Preventive MHI Wear at 6 WEC Total Steram 35% at 30-35% r TTW Retainer Generator __

AVB

_

at AVB RB _ _

Bar Screening

_

Criteria I Consecutive

_

AVBs Screening

_

Additions

_

Tubes Selected 2E-088 2 2 2 0 92 101 6 2 207 2E-089 0 0 4 2 90 203 6 3 308 Page 45

J EDISON AnII)ISO\

SOUIHERN CALIFORNIA

\ I IR)N.t IJ** i (Compllý SONGS Unit 2 Return to Service Report Figure 8-6: 2E-088 Plugging and Stabilizing Map No Plug/Stab Unit 2 SG E-088 Plugging/Stabilizing Map 30% < TWD < 35%

140

• TWD => 35%

8 o °0 8

Preventative Retainer Bar 120 Preventative TTW 00

• Wear at 6 CONT AVBs 100

• WEC Recommended o Single Stabilizer 80 E o Split Stabilizer Z 60 0:

40 20 180 170 160 150 140 130 120 110 100 90 80 70 60 s0 40 30 20 10 Column Number Page 46

EDISON J

An [,OGSUSON SOUTHERN CALIFORNIA InitfI2NRuTIOrt1o

• CompR r SONGS Unit 2 Return to Service Report Figure 8-7: 2E-089 Plugging and Stabilizing Map No Plug/Stab Unit 2 SG E-089 Plugging/Stabilizing Map " TWD => 35%

140 *TTw a

8 * ~cPO 8 Preventative Retainer Bar 120 00 Preventative TTW S.

• Wear at 6 CONT AVBs 100

" WEC Recommended o Single Stabilizer E~

o Split Stabilizer 60O 0

40 20 180 170 160 150 140 130 120 110 100 90 80 70 60 50 40 30 20 10 Column Number Page 47

EDISON v SOUTHERN CALIFORNIA An EDISON INTERNATIONAL"- Comparny Unit 2 Return to Service Report 8.2.2 Plant Operations with Tubes Plugged in Unit 2 Results from MHI's ATHOS calculations were used to analyze the effect of the plugged region on tubes remaining in service. The T/H parameters evaluated were:

" Maximum void fraction, velocity, and hydrodynamic pressure along the U-bend

• Average void fraction, velocity, and hydrodynamic pressure along the hot leg portion of the U-bend

• Average void fraction, velocity, and hydrodynamic pressure along the U-bend The effect of 4% tube plugging on the remaining in-service tubes was evaluated and determined to be insignificant.

With power limited to 70%, there is no adverse impact on surrounding tubes of the preventive plugging in the Unit 2 SGs.

8.3 Inspection Interval and Protocol of Mid-cycle Inspections As demonstrated in Section 8.1, limiting operations to 70% power significantly reduces the potential for FEI and improves tube stability margins. To provide additional safety margin, the Unit 2 inspection interval has been limited to 150 days of operation at or above 15% power. The protocol for the inspections to be performed during the mid-cycle outage is described below. (CAL Response Commitment 2) 8.3.1 Inspection of Inservice Tubes (Unplugged)

The following inspections will be performed during the mid-cycle SG inspection outage:

• Eddy Current Bobbin Coil Examinations of the full length of all in-service tubes

• Rotating Coil Examinations of the following areas:

a. U-bend region - inspection scope will repeat the pattern used during the refueling outage.

(-1300 tubes/SG)

b. TSP and AVB wear bobbin coil indications > 20%

• Visual inspection of small diameter RBs and welds 8.3.2 Inspection of Plugged Tubes Plugged tubes will be inspected to determine if the compensatory and corrective actions (plugging and operating at reduced power) have been effective. The following inspections and evaluations are planned:

• Visual examination will be performed on all installed tube plugs

• 12 tubes in each SG will be unplugged and the stabilizer(s) removed to assess the effectiveness of the TTW compensatory and corrective actions. Following these inspections, all tubes will be re-plugged and stabilizers installed. The tubes will be selected as follows:

o The 2 tubes with previous TTW indications o 5 tubes adjacent to tubes with TTW wear o 5 tubes selected from representative locations that were preventively plugged as part of the compensatory and corrective actions for TTW Page 48

1 EDISON" SOUTHERN CALIFORNIA An EDISO\ ITI*R*ARTIOrNAL' Compainy Unit 2 Return to Service Report

• Any new TTW and TSP ECT indications will be assessed to determine if they are the result of FEI during the prior operating period or are cases of previously undetected wear (less than the probability of detection for the ECT probes used during the prior inspection).

" Confirmed new TTW or increases in TTW indication size beyond ECT uncertainty will require a review of the corrective actions implemented during the current inspection.

Page 49

SOUTHERN CALIFORNIA EDISON Nn EDISON INTERNATIO\' iL` Compaeny Unit 2 Return to Service Report 9.0 UNIT 2 DEFENSE-IN-DEPTH ACTIONS As described in Section 8, Section 10, and Attachment 6, the compensatory and corrective actions taken by SCE eliminate the T/H conditions that cause FEI and associated TTW from the SONGS SGs. Nonetheless, SCE has developed DID measures to provide an increased safety margin even if tube-to-tube degradation in the Unit 2 SGs were to occur. The following actions have been taken to improve the capability for early detection of a SG tube leak and ensure immediate plant operator response.

9.1 Injection of Argon into the Reactor Coolant System (RCS)

Plant design has been modified to allow periodic injection of Argon (Ar-40) into the RCS. Ar-40 is activated over a short period of time to become Ar-41. The increased RCS activity makes it easier to detect primary-to-secondary tube leaks.

9.2 Installation of Nitrogen (N-16) Radiation Detection System on the Main Steam Lines Plant design will be modified prior to Unit 2 startup (entry into Mode 2) by installing a temporary N-16 radiation detection system (CAL Response Commitment 3). This system is in addition to existing radiation monitoring systems and includes temporary N-16 detectors located on the main steam lines. This system provides earlier detection of a tube leak and initiation of operator actions.

9.3 Reduction of Administrative Limit for RCS Activity Level The plant procedure for chemical control of primary plant and related systems has been modified to require action if the specific activity of the reactor coolant Dose Equivalent (DE) Iodine (1-131) exceeds the normal range of 0.5 pCi/gm, which is one-half of the TS Limit of 1.0 pCi/gm. In the event that the normal range is exceeded, Operations is required to initiate the Operational Decision Making process to evaluate continued plant operation.

9.4 Enhanced Operator Response to Early Indication of SG Tube Leakage 9.4.1 Operations Procedure Changes The plant operating procedure for responding to a reactor coolant leak has been modified to require plant Operators to commence a reactor shutdown upon a valid indication of a primary-to-secondary SG tube leak at a level less than allowed by the plant's TSs. This procedure change requires earlier initiation of operator actions in response to a potential SG tube leak.

9.4.2 Operator Training Plant Operators will receive training on use of the new detection tools for early tube leak identification (e.g., plant design changes described above), and lessons learned in responding to the January 31, 2012, Unit 3 shutdown due to a SG tube leak (CAL Response Commitment 4). This training will enhance operator decision making and performance in responding to an indication of a SG tube leak and will be completed prior to plant startup.

Page 50

EDISON S4SOUITHERN CALIFORNIA

-n EI)I.',\ I\TI- R IOe\VT-\ILýCompany Unit 2 Return to Service Report 10.0 UNIT 2 OPERATIONAL ASSESSMENT As defined in NEI 97-06 (Ref. 2), the OA is a "Forward looking evaluation of the SG tube conditions that is used to ensure that the structural integrity and accident leakage performance will not be exceeded during the next inspection interval." The OA projects the condition of SG tubes to the time of the next scheduled inspection outage and determines their acceptability relative to the TS tube integrity performance criteria (Attachment 1).

As required by the CAL (Ref. 1), SCE has prepared an assessment of the Unit 2 SGs that addresses the causes of TTW wear found in the Unit 3 SGs, prior to entry of Unit 2 into MODE 2. The OA provided in Attachment 6 provides that assessment.

Due to the significant levels of TTW found in Unit 3 SGs, SCE has assessed the likelihood of additional TTW in Unit 2 from several different perspectives involving the experience and expertise of AREVA, WEC, and Intertek/APTECH. These companies developed independent OAs to address the TTW found at SONGS. These OAs apply different methodologies to ensure a comprehensive and diverse evaluation. The results of these analyses fulfill the TS requirement to demonstrate that SG tube integrity will be maintained until the next SG inspection. The OAs demonstrate that limiting operation to 70% power will prevent loss of tube integrity due to TTW. In particular, reducing power to 70% eliminates the T/H conditions that cause FEI and associated TTW from the SONGS Unit 2 SGs. The reduced 150 cumulative day inspection interval provides additional safety margin beyond the longer allowable inspection intervals identified in the OAs.

Page 51

SOUTHERN CALIFORNIA EDISON An EDISO,\ I\TITRNATIOrIL Cumpany Unit 2 Return to Service Report 11.0 ADDITIONAL ACTIONS As previously discussed, the OAs performed by AREVA, WEC, and Intertek/APTECH confirm that the compensatory and corrective actions implemented by SCE will result in continued safe operation of Unit 2 and that SG tube integrity will be maintained. SCE also implemented conservative DID measures to minimize the impact on public and environmental health and safety even if tube integrity were compromised. Additionally, SCE is establishing enhanced plant monitoring capability as described below.

11.1 Vibration Monitoring Instrumentation The Vibration and Loose Parts Monitoring System (VLPMS) is designed in accordance with NRC Regulatory Guide 1.133, "Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors" to detect loose metallic parts in the primary system. VLPMS includes accelerometers mounted externally to the SGs. The VLPM sensors detect acoustic signals generated by loose parts and flow. The signals from these sensors are compared with preset alarm setpoints. Validated alarms are annunciated on a panel in the control room.

To improve sensitivity of the VLPMS, the system is being upgraded to WEC's Digital Metal Impact Monitoring System (DMIMS-DX) during U2C17 refueling outage (CAL Response Commitment 5). The following improvements will be implemented by the upgrade:

" Relocation of existing VLPMS accelerometers (2 per SG) from the support skirt to locations above and below the tubesheet. These will remain as VLPMS sensors to meet Regulatory Guide 1.133.

" Increased sensitivity accelerometers (2 per SG) will be installed at locations above and below the tubesheet.

• Increased sensitivity accelerometers (2 per SG) will be installed on an 8 inch hand hole high on the side of the SGs to monitor for secondary side noises at the upper tube bundle.

The upgraded system will provide SCE with additional monitoring capabilities for secondary side acoustic signals.

M T

11.2 GE Smart Signal SCE will utilize GE Smart SignalTM , which is an analytic tool that aids in diagnosis of equipment conditions (CAL Response Commitment 6). The tool will be used to analyze historical plant process data from the Unit 2 SGs following the inspection interval.

Page 52

SOUTHERN CALIFORNIA EDISON In A EDISON J\rTRN.ATIOQ\Ll Company Unit 2 Return to Service Report

12.0 CONCLUSION

S As noted in Reference 1, the SG tube wear that caused a Unit 3 SG tube to leak on January 31, 2012, was the result of tube-to-tube interaction. This type of wear was confirmed to exist in a number of other tubes in the same region in both Unit 3 SGs. Subsequent inspections of the Unit 2 SGs identified this type of wear also existed in two adjacent tubes in Unit 2 SG E-089.

To determine the cause of the TTW, SCE performed extensive inspections and analyses. SCE commissioned experts in the fields of T/H and in SG design, manufacturing, operation, and repair to assist with these efforts.

Using the results of these inspections and analyses, SCE determined the cause of the TTW in the two Unit 3 SGs was FEI, caused by a combination of localized high steam velocity, high steam void fraction, and insufficient contact forces between the tubes and the AVBs. FEI caused in-plane tube vibration that resulted in TTW in a localized region of the SGs. The TTW in Unit 2 SG E-089 may have been caused by FEI, or alternatively, close proximity of the two tubes may have led to TTW from normal vibration.

SCE determined the TTW effects were much less severe in Unit 2 where two tubes were identified with TTW indications of less than 15% TW wear. These two tubes are located in the same region of the SGs as those with TTW in Unit 3. Given that the T/H conditions are essentially the same in both units, the less severe TTW in Unit 2 is attributed to manufacturing differences. Those differences increased tube-to-AVB contact forces in Unit 2, providing greater tube support.

To prevent loss of SG tube integrity due to TTW in Unit 2, SCE has implemented interim compensatory and corrective actions and established a protocol of inspections and operating limits. These include:

1. Limiting Unit 2 to 70% power prior to a mid-cycle SG inspection outage (CAL Response Commitment 1)

2. Preventively plugging tubes in both SGs (complete)

3. Shutting down Unit 2 for a mid-cycle SG inspection outage within 150 cumulative days of operation at or above 15% power (CAL Response Commitment 2)

On the basis of the compensatory and corrective actions discussed in Section 8, the DID actions presented in Section 9, and the results of the OAs presented in Section 10 and Attachment 6, SCE concludes that Unit 2 will operate safely at 70% power for 150 cumulative days of operation. Reducing power to 70% eliminates the T/H conditions that cause FEI and associated TTW from the SONGS Unit 2 SGs. SCE will continue to closely monitor SG tube integrity, perform SG inspections during the mid-cycle outage, and take compensatory and corrective actions to ensure the health and safety of the public.

Page 53

SOUTHERN CALIFORNIA 17,EDISON' An EDISO T 11 INTERN 'A N\ I Company Unit 2 Return to Service Report

13.0 REFERENCES

1 Confirmatory Action Letter (CAL) - Letter from Elmo E. Collins (NRC) to Peter T. Dietrich (SCE), dated March 27, 2012, Confirmatory Action Letter 4-12-001, San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation 2 Nuclear Energy Institute NEI 97-06, Steam Generator Program Guidelines, Revision 3, January 2011 3 Electric Power Research Institute (EPRI), Pressurized Water Reactor Steam Generator Examination Guidelines 4 EPRI 1019038, 1019038 Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines, Revision 3, November 2009 5 Event Notification Number 47628 - Telephone notification, Manual Trip Due to a Primary to Secondary Leak, made to the NRC Emergency Notification System (ENS) as required by 10 CFR 50.72(b)(2)(iv)(B) 6 Event Notification Number 47744 (including 2 followups) - Telephone notifications, Unit 3 Steam Generator Tubes Failed In-Situ Pressure Testing, made to the NRC ENS as required by 10 CFR 50.72(b)(3)(ii)(A) 7 Unit 3 LER 2012-001, dated March 29, 2012, Manual Reactor Trip Due to the SG Tube Leak as required by 10 CFR 50.73(a)(2)(iv)(A), actuation of the Reactor Protection System 8 Unit 3 LER 2012-002, dated May 10, 2012, SG Tube Degradation Indicated by Failed In-situ Pressure Testing as required by 10 CFR 50.73(a)(2)(ii)(A), a condition which resulted in a principal safety barrier being seriously degraded (i.e., serious SG tube degradation) 9 Letter from Peter T. Dietrich (SCE) to Elmo Collins (USNRC), dated April 20, 2012, Update of Unit 2 SG Tube Inspection Results 10 SONGS Steam Generator Program (S023-SG-1)

Page 54

i sOuTHERN CALIFORNIA J EDISON An EDI,1S N I V'FIR 1 10 L0 n)

SONGS Unit 2 Return to Service Report ATTACHMENT 1 SONGS Unit 2 Relevant Technical Specifications

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LCO 3.4.17 SG tube integrity shall be maintained.

AND .

All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.

APPLICABILITY: MODES1, 2, 3, and 4.

ACTIONS

---

NOTE-------------------------------

Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity 7 days satisfying the tube of the affected repair-criteria and tube(s) is-maintained.

not plugged in until the next accordance with-the refueling:outage or Steam Generator SG tube inspection.-

Program.

AND

• A.2 Plug the affected tube(s) in accordance Prior to entering MODE 4

I with the Steam following the Generator Program. next refueling outage or SG tube inspection B. Required Action and B.1 Be in MODE 3.: 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Timer;of Condition A AND not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube -integrity not maintained.

SAN ONOFRE--UNIT 2 3.4-51 Amendment No.204, 220

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with In accordance the Steam Generator Program. with the Steam, Generator Program SR 3.4.17.2 -Verify that-each-inspected SG tube that. Prior, to satisfies the tube repair criteria is entering MODE 4 plugged in accordance with the Steam following a SG tor Program. .

. . Genera ............ tube-inspection -

SAN ONOFRE--UNIT 2 3.4-52 Amendment No.**)9, 220

Procedures, Programs, and Manuals 5.5 5.5 Procedures, Programs, and Manuals (continued) 5.5.2.8 Primary Coolant Sources Outside Containment Program (continued) system (post-accident sampling return piping only until such time as a modification eliminates the post-accident piping as a potential leakage path). The program shall include the following:

a. Preventive maintenance and periodic visual inspection requirements; and

b. Integrated leak test requirements for each system at refueling cycle intervals or less.

5.5.2.9 Pre-Stressed Concrete Containment Tendon Surveillance Program This program provides controls for monitoring any tendon degradation in pre-stressed concrete containment, including effectiveness of its corrosion protection medium, to ensure containment structural integrity. Program itself is relocated to the LCS.

5.5.2.10 Inservice Inspection and Testing Program This program provides controls for inservice inspection of ASME Code Class 1, 2, and 3 components and Code Class CC and MC components including applicable supports. The program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components., The program itself is located in the LCS.

ý5.5.2.111 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an.evaluatio.n of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged, to confirm that the performance criteria are being met.

(continued)

SAN ONOFRE--UNIT 2 5.0-13ý Amendment No. I78,2-4, 220

Procedures, Programs, and Manuals 5.5 5.5 Procedures, Programs, and Manuals (continued) 5.5.2.11 Steam Generator (SG) Program (continued)

b. Performance criteria for SG tube integrityi SG tube integrity tlidll be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1. Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions i(ncluding startup, operation in the power range, hot standby," and cool 4dn.ahnd all antitipated.

transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state ful.l power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the. above requirements, additional loading conditions associ-ated with the design basis accidents, or combination of.

accidents in accordance with the design and lic..amsd.-.ng basis, shall also be evaluated to determine if .

associated loads contribute significantly to burst-or collapse. In the assessment.of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2; on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 0.5 gpm per SG and 1 gpm through both SGs.

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

(continued)

SAN ONOFRE--UNIT 2 5.0-14 Amendment No. +0-4,204 1

Procedures, Programs, and Manuals 5.5 5.5 Procedures, Programs, and Manuals (continued) 5.5.2.11 Steam Generator (SG) Program (continued)

c. Provisions for SG tube repair criteria.

1. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 35% of the nominal tube wall thickness shall be plugged.

d. Provisions for SG tube inspections. Periodic SG tube inspections shal.l be performed. The number and portions of the tubes inspec.teda.n.d.metho.ds of inspection shall be performed with the objective of detecting'flaws of any-type'(e.g., Vblumetrffflaws-,

axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld, at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube.

In addition to meeting the requirements of d1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such-as to ensure, that SG tube integrity is.

maintained until :the next SG inspection. An assessment of degradation shall be performed to-determine the type and. location of flaws to-which the tubes may be susceptible and, based'on this assessment, to determine which inspection methods need to be employed and at what:locations.

1. Inspect 100% of the tubes in each*SG-during the first refueling outage following SG replacement.

2. Inspect 100% of the tubes at sequential periods of 144, 108, 72, and thereafter, .60 effective full power months.

The firs.t sequential period shall be considered to begin' after the first inservice inspection.of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50%

by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective, full power months or three refueling outages (whichever is less) without being inspected.

3. If crack indications are found in any SG tube, then the next inspection for each SG.for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

SAN ONOFRE--UNIT 2 5.0-15 Amendment No. 220

Reporting Requirements 5.7 5.7 Reporting Requirements (continued) 5.7.2 Special Reports Special Reports may be required, covering inspection, test, and maintenance activities. These special reports are determined on an individual basis for each unit and their preparation and submittal are designated in the Technical Specifications.

Special Reports shall be submitted to the U. S. Nuclear Regulatory Commission, Attention: Document Control Desk, Washington, D. C.

20555, with a copy to the Regional Administrator of the Regional Office of the NRC, in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

a. When a pre-planned alternate method of monitoring post-accident instrumentation functions is required by Condition B or Condition G of LCO 3.3.11, a report shall be submitted within 30 days from the time the action is required. :The report shall outline the action taken, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the function to OPERABLEzstatns.

b. Any abnormal degradation of the containment structure detected during the tests .required'by the Pre-Stressed Concrete Containment TendonSurveillance Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken.

c. A report shall be submitted within 1.80 days after the dinitial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.2.11, Steam Generator (SG) Program. The report shall include:

(continued)

SAN ONOFRE--UNIT 2 5.0-28 Amendment No. --94-,204

Reporting Requirements 5.7 5.7 Reporting Requirements (continued)

( ') 5.7.2 Special Reports (continued)

1. The scope of inspections performed on each SG,

2. Active degradation mechanisms found,

3. Nondestructive examination techniques utilized for each degradation mechanism,

4. Location, orientation (if linear), and measured sizes (if

.available) of service induced indications,

5. Number of tubes plugged-during the inspection outage for each active degradation mechanism,

6. Total number and percentage of tubes plugged to date,

7. The results of condition monitoring, including the results of tube pulls and in-situ testing.

()

)

SAN ONOFRE--UNIT 2 5.0-29 Amendment No. +/-197,-24, 220

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.-13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shal.l be limited to:

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gallons per day primary to secondary LEAKAGE through any one Steam Generator (SG),

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS Operational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LEAKAGE not within within limits.

limits for reasons I other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A AND not met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

SAN ONOFRE--UNIT 2 3.4-37 Amendment No. +-IG 204

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 -------------------NOTES ------------- -NOTE-

1. Not required to be performed in MODE 3 Only required or 4 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state to be performed operation. during steady state

2. Not applicable to primary to secondary operation.

,LEAKAGE. If a transient

.................. ........... ....... evolution is occurring 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from the last water Perform RCS water inventory balance. inventory balance, then a water inventory balance shall be performed within 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> of the last water inventory balance K>

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />

- ---------------- NOTE----------------

Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.

SR 3.4.13.2 Verify primary to secondary LEAKAGE is .72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />

< 150 gallons per day through any one SG.

SAN ONOFRE--UNIT 2 3,4-38 Amendment No. 204

1 SOUTHERN CALIFORNIA

• J EDISON*

An I)IS( );\ I \Ir \ 4 I()\ C",Iinpan)

SONGS Unit 2 Return to Service Report ATTACHMENT 2 AREVA Document 51-9182368-003, SONGS 2C17 Steam Generator Condition Monitoring Report

[Proprietary Information Redacted]

A 20004-018 (10/18/2010)

AREVA AREVA NP Inc.

Engineering Information Record Document No.: 51 - 9182368 - 003(NP)

SONGS 2C17 Steam Generator Condition Monitoring Report Supplier Status Stamp IvPL 1814-AU651-M0156 "*1jQC: N/A

[OESIGN DOCUMENT ORDER NO. 80091,8458 K]REFERENCE DOCUMENT-NFORMATION ONLY (JVIRP IOM MANUAL MFG MAY PROCEED: OYES (NO XNWA STATUS - Astatus requwed for desnn dounenta and is opbonal forreference doonenta, Orawega aD e r v wedad apr.,ed o( arrangemensand conformance to sp"kab*c only Appoeal does not reaey toe submilter from the resporisibly of adequacy end awtabtiky ofdesign. steratonls amfor equipment represented U2.PPRVEDEXCEPT A3 NOTED - Meake Owrngs andreasuttn

§J3. NOT APPROVED.- Cavad am rautnit frrseJQ o lk s RE E GRIBBLE 10/2/12 FLS Other SCEDE(t23)5 REV 3 07111 REFERENCE S0123-XXIV-37 820 1814-AU651-M0156, REV. 1 Page 1 of 62 Page 1 of 62

(~

A 20004-018 ( 10/18/2010)

Document No.: 51-9182368-003 AREVA PROPRIETARY SONGS 2C17 Steam Generator Condition Monitoring Report Safety Related? [ YES [-' NO Does this document contain assumptions requiring verification? Di YES 0 NO Does this document contain Customer Required Format? [] YES " NO Signature Block PP, R/LR, Pagee/Sections Name and A/A-CRF, Prepared/Reviewed/

Titie/Discipline Signature AIA-CRI Date Approved or Comments Note: P/LP designates Preparer (P), Lead Preparer (LP)

R/LR designates Reviewer (R), Lead Reviewer (LR)

A/A-CRF designates Approver (A), Approver of Customer Requested Format (A-CRF)

A/A-CRI designates Approver (A), Approver - Confirming Reviewer Independence (A-CRI)

Page 2 1814-AU651-M0156, REV. 1 Page 2 of 62

A 20004-018 (10/18/2010)

Document No.: 51-9182368-003 (NP)

AREVA SONGS 2C17 Steam Generator Condition Monitoring Report Record of Revision Revision Pages/Sections/

No. Paragraphs Changed Brief Description / Change Authorization 000 All Original Release 001 Table 5-4 Edited title Table 5-7 Revised line 2 entry to max depth of 54%, line 6 entry to 29%

Table 5-8 Revised second entry to max depth of 30%

Sect. 6.2.4 Added missing callout to figure 6-6 002 All Added Sections 2.0, 4.1, 4.2, 4.3, 6.3 and 6.4. Incorporated a significant number of editorial corrections and modifications throughout the document.

003 Section 4.3 Corrected Pre-Service examination statement from "Hot Leg (HL) and Cold Leg (CL) Top of Tubesheet (TTS)" to "Hot Leg (HL) and Cold Leg (CL)

Tubesheet (TS)" to reflect that examination covered entire TS instead ofjust the Top of Tubesheet.

Section 6.1 Corrected Table number 5-2 to Table 6-2 in Section 6.1 Section 6.2 Revised discussion of plugging Table 6-4 Corrected Table 6-4 Total Indication Count Values Table 6-5 Removed TTW wear and TTW Preventative counts from Table 6-5 Appendix A and B Removed Appendix A and B Plugging lists 1814-AU651-M0156, REV. 1 Page 3 of 62 Page 3

A Document No.: 51-9182368-003 (NP)

AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report Table of Contents Page SIGNATURE BLOCK ................................................................................................................................ 2 RECORD O F REVISION .......................................................................................................................... 3 LIST OF TABLES ..................................................................................................................................... 6 LIST OF FIGURES ................................................................................................................................... 7 1.0 PURPOSE ..................................................................................................................................... 8 2.0 ABBREVIATIONS AND ACRONYMS ...................................................................................... 9 3.0 SCOPE ........................................................................................................................................ 12

4.0 BACKGROUND

.......................................................................................................................... 12 4.1 Previous Operating Experience (OE) Related to Tube-to-Tube Wear ........................ 16 4.2 Previous Operating Experience Related to Tube-to-AVB Wear .................................. 17 4.3 Pre-Service Exam ination Results ............................................................................... 18 5.0 PERFORMANCE CRITERIA ................................................................................................. 19 6.0 INSPECTION SUM MARY ...................................................................................................... 20 6.1 Eddy Current Inspections Performed .......................................................................... 21 6.2 Degradation Identified ................................................................................................. 23 6.3 Tube-to-Tube Wear Detection ................................................................................... 24 6.4 Tube-to-Tube Wear Sizing .......................................................................................... 25 6.5 Secondary Side Visual Exam ination Results .............................................................. 26 7.0 CONDITION MONITORING ASSESSM ENT ........................................................................ 47 7.1 Input Param eters ......................................................................................................... 47 7.2 Evaluation of Structural Integrity ................................................................................. 49 7.2.1 AVB wear and TSP wear .......................................................................... 49 7.2.2 Retainer Bar Wear ................................................................................... 49 7.2.3 Foreign Object W ear ................................................................................. 50 7.2.4 Tube-to-Tube Wear .................................................................................... 51 7.3 Evaluation of Accident-induced Leakage Integrity ..................................................... 52 7.3.1 AVB wear and TSP wear .......................................................................... 52 7.3.2 Retainer Bar Wear ................................................................................... 52 7.3.3 Foreign Object W ear ................................................................................. 52 7.3.4 Tube-to-Tube Wear .................................................................................... 52 7.4 Evaluation of Operational Leakage Integrity .............................................................. 53 8.0 CONDITION MONITORING CONCLUSIO N.......................................................................... 60 1814-AU651-M0156, REV. 1 Page 4 of 62 Page 4

A Document No.: 51-9182368-003 (NP)

AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report Table of Contents (continued)

Page 9 .0 R E F E R E N C E S ............................................................................................................................ 61 1814-AU651-M0156, REV. 1 Page 5 of 62 Page 5

A Document No.: 51-9182368-003 (NP)

AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report List of Tables Page TABLE 2-1: ABBREVIATIONS AND ACRONYMS ............................................................................ 9 TABLE 4-1:

SUMMARY

OF PRE-SERVICE INSPECTION RESULTS ............................................ 18 TABLE 6-1: STEAM GENERATOR TUBE INSPECTION SCOPE

SUMMARY

(FIRST PHASE) .......... 27 TABLE 6-2: APRIL 2012 RTS INSPECTION SG TUBE INSPECTION

SUMMARY

......................... 28 TABLE 6-3: JULY 2012 RTS INSPECTION SG TUBE INSPECTION

SUMMARY

.......................... 28 TABLE 6-4: WEAR INDICATION

SUMMARY

................................................................................... 29 TABLE 6-5: PLUGG ING SUM MARY ............................................................................................... 30 TABLE 6-6: REPORTED AVB WEAR DEPTHS (%TW) ................................................................... 30 TABLE 6-7: REPORTED TSP WEAR DEPTHS (%TW) ................................................................... 30 TABLE 6-8: RETAINER BAR W EAR ............................................................................................... 31 TABLE 6-9: FOREIGN OBJECT W EAR .......................................................................................... 31 TABLE 6-10: TUBE-TO-TUBE W EAR ............................................................................................... 31 TABLE 7-1: SONGS-2 STEAM GENERATOR INPUT VALUES ....................................................... 48 TABLE 7-2: EDDY CURRENT ETSS INPUT VALUES (REFERENCE 5) ....................................... 48 1814-AU651-M0156, REV. 1 Page 6 of 62 Page 6

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report List of Figures Page FIGURE 4-1: SONGS STEAM GENERATOR SUPPORT STRUCTURE LAYOUT .......................... 13 FIGURE 4-2: VIEW FROM ABOVE BUNDLE SHOWING RETAINER BAR LOCATIONS ............... 14 FIGURE 4-3: SKETCH SHOWING RETAINER/RETAINING BAR CONFIGURATION .................... 15 FIG URE 6-1: SG 2E-088 AVB W EAR .............................................................................................. 32 FIG URE 6-2: SG 2E-089 AVB W EAR .............................................................................................. 33 FIGURE 6-3: SG 2E-088 TSP WEAR - HOT LEG ........................................................................... 34 FIGURE 6-4: SG 2E-088 TSP WEAR - COLD LEG ......................................................................... 35 FIGURE 6-5: SG 2E-089 TSP WEAR - HOT LEG ........................................................................... 36 FIGURE 6-6: SG 2E-089 TSP WEAR - COLD LEG ......................................................................... 37 FIGURE 6-7: SG 2E-088 RETAINER BAR WEAR ........................................................................... 38 FIGURE 6-8: SG 2E-089 RETAINER BAR WEAR ........................................................................... 39 FIGURE 6-9: SG 2E-088 FOREIGN OBJECT WEAR ..................................................................... 40 FIGURE 6-10: TUBE-TO-TUBE WEAR (DETECTED IN SG 2E-089 ONLY) ................................... 41 FIGURE 6-11: SG 2E-088 AVB WEAR DEPTH DISTRIBUTION .................................................... 42 FIGURE 6-12: SG 2E-089 AVB WEAR DEPTH DISTRIBUTION .................................................... 43 FIGURE 6-13: SG 2E-088 TSP WEAR DEPTH DISTRIBUTION ...................................................... 44 FIGURE 6-14: SG 2E-089 TSP WEAR DEPTH DISTRIBUTION ...................................................... 45 FIGURE 6-15: FOREIGN OBJECT RETRIEVED FROM SG 2E-088 .............................................. 46 FIGURE 7-1: CM LIMIT FOR AVB WEAR, ETSS 96004.1 .............................................................. 54 FIGURE 7-2: CM LIMIT FOR TSP WEAR, ETSS 96004.1 ............................................................... 55 FIGURE 7-3: CM LIMIT FOR RB WEAR, ETSS 27903.1 ................................................................. 56 FIGURE 7-4: CM LIMIT FOR FO WEAR, ETSS 27901.1 ................................................................. 57 FIGURE 7-5: FOREIGN OBJECT POP-THROUGH AT 2560 PSI, UNIFORM 3600 THINNING, ETSS 2 7 9 0 1.1 ................................................................................................................................. 58 FIGURE 7-6: CM LIMIT FOR TUBE-TO-TUBE WEAR, ETSS 27902.2 ........................................... 59 Page 7 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report 1.0 PURPOSE In accordance with the EPRI Steam Generator Integrity Assessment Guidelines [2], a Condition Monitoring (CM) assessment must be performed at the conclusion of each steam generator eddy current examination. This process is described as "backward-looking," since its purpose is to confirm that adequate Steam Generator (SG) integrity was maintained during the most recent operating period.

It involves an evaluation of the as-found conditions of the steam generator relative to established performance criteria for structural and leakage integrity. The performance criteria are defined in plant Technical Specifications [17] [18]. The performance criteria are based on NEI (Nuclear Energy Institute) 97-06 [1] (see Section 5.0 below).

This report concludes that the SONGS (San Onofre Nuclear Generating Station) steam generator performance criteria were satisfied by Unit 2 during the operating period prior to 2C17.

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SONGS 2C17 Steam Generator Condition Monitoring Report 2.0 ABBREVIATIONS AND ACRONYMS The following table provides a listing of abbreviations and acronyms used throughout this report.

Table 2-1: Abbreviations and Acronyms Abbreviation or Definition Acronym 01C to 07C Tube Support Plate Designations for Cold Leg (7 Locations) 01 H to 07H Tube Support Plate Designations for Hot Leg (7 Locations) 2E-088 Unit 2 Steam Generator 88 2E-089 Unit 2 Steam Generator 89 3E-088 Unit 3 Steam Generator 88 3E-089 Unit 3 Steam Generator 89 3 NOPD 3 Times Normal Operating Pressure Differential 3AP 3 Times Normal Operating Pressure Differential ADI Absolute Drift Indication AILPC Accident Induced Leakage Performance Criterion ANO Arkansas Nuclear One ASME American Society of Mechanical Engineers AVB Anti-Vibration Bar B01 to B12 AVB Designations (12 Locations)

BLG Bulge C Column CE Combustion Engineering CL or C/L Cold Leg CM Condition Monitoring DA Degradation Assessment DBE Design Basis Earthquake DNG Ding DNT Dent ECT Eddy Current Testing EFPD Effective Full Power Days EOC End of Operating Cycle EPRI Electric Power Research Institute ETSS Examination Technique Specification Sheet FOSAR Foreign Object Search and Retrieval GMD Geometric Distortion GPD Gallons per Day GPM Gallons per Minute of 62 Page 9 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report Table 2-1: Abbreviations and Acronyms Abbreviation or Definition Acronym HL or H/L Hot Leg INPO Institute of Nuclear Power Operators kHz Kilohertz KSI Thousand Pounds per Square Inch LER Licensee Event Report MBM Manufacturing Burnish Mark MHI Mitsubishi Heavy Industries MSLB Main Steam Line Break NDE Non Destructive Examination NEI Nuclear Energy Institute NN Nuclear Notification NOPD Normal Operating Pressure Differential NQI Non-Quantifiable Indication NRC Nuclear Regulatory Commission NSAL Nuclear Safety Advisory Letter OA Operational Assessment OE Operating Experience OTSG Once Through Steam Generator PDA Percent Degraded Area PLP Possible Loose Part POD Probability of Detection PRX Proximity Indication PSI Pounds per Square Inch PSIG Pounds per Square Inch Gage PST Pacific Standard Time PVN Permeability Variation PWR Pressurized Water Reactor QA Quality Assurance R Row RB Retainer Bar RCS Reactor Coolant System REPL Replacement ROLLED Rolled Plug Designation ROLLSTAB Rolled Plug with a Stabilizer RPC Rotating Probe Coil RSG Recirculating Steam Generator SCE Southern California Edison 62 Page 10 1814-AU651-MO156, REV. 1 1814-AU651-M0156, REV. Page Page 10 of I 10 of 62 Page 10

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SONGS 2C17 Steam Generator Condition Monitoring Report Table 2-1: Abbreviations and Acronyms Abbreviation or Definition Acronym SG Steam Generator SIPC Structural Integrity Performance Criteria SL2 St. Lucie Unit 2 SLB Steam Line Break SONGS San Onofre Nuclear Generating Station SSA Secondary Side Anomaly SSI Secondary Side Inspection SVI Single Volumetric Indication TMI Three Mile Island TSP Tube Support Plate TTW Tube to Tube Wear TW Through Wall U3F16B Unit 3 Outage Designation UB U-bend 1814-AU651-M0156, REV. 1 Page 11 of 62 Page 11

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SONGS 2C17 Steam Generator Condition Monitoring Report 3.0 SCOPE This evaluation pertains to the SONGS Unit 2 replacement steam generators, which are reactor coolant system components. The CM assessment documented in this report is required to be completed prior to plant entry into Mode 4 during start up after a SG inspection. The Unit 2 SGs passed CM, thus an OA (Operational Assessment) shall be completed for the next inspection interval within 90 days after Mode 4.

This document was originally a portion of AREVA document 51-9177491-001, "SONGS 2C17 Steam Generator Condition Monitoring and Preliminary Operational Assessment" [14]. The decision was made to separate the Condition Monitoring and Operational Assessment portions of the document.

4.0 BACKGROUND

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 4-1: SONGS Steam Generator Support Structure Layout Page 13 1814-AU651-MO156, REV. 1I 1814-AU651-M0156, REV. Page 13 Page of 62 13 of 62 Page 13

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 4-2: View From Above Bundle Showing Retainer Bar Locations

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 4-3: Sketch Showing Retainer/Retaining Bar Configuration MIPropri°etary Page 15 REV. 11 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report 4.1 Previous Operating Experience (OE) Related to Tube-to-Tube Wear Prior to the Songs Unit 3 shutdown in January of 2012, the recent operating experience related to tube-to-tube wear was limited to once-through steam generators. In December 2011, INPO (Institute of Nuclear Power Operators) OE 34946 [19] was released. This Operating Experience Report discusses experience at Three Mile Island Unit 1 (TMI-1). In July 2012, the NRC (Nuclear Regulatory Commission) released Information Notice 2012-07 [20]. This Information Notice contains information on the experience at TMI-1 as well as Oconee and ANO-1 (Arkansas Nuclear One - Unit 1). This section summarizes the experiences at these plants with once-through steam generators.

TMI-1 completed replacement of its original Once Through Steam Generators (OTSGs) in 2010. The design of the OTSG differs from the recirculating steam generator design in that the tubes are straight.

The tubes are supported by 15 tube support plates. The first inspection of the TMI-1 replacement steam generators took place in the fall of 2011. During this examination, indications were detected on the absolute channel with no discernible response on the differential channel. The indications were designated as Absolute Drift Indications (ADIs). A comprehensive review of all of the ADIs identified tubes with long shallow wear signals between the eighth and ninth tube support plates. The indications were in adjacent tube combinations of either 2 or 3 tubes (the tube pattern is a triangular pitch). A more detailed investigation led to the conclusion that these wear indications were the result of tube-to-tube contact wear. The lengths ranged from 2 to 8 inches and from 1 to 21 percent through-wall.

As a result of the TMI-1 findings, and because TMI and ANO both have AREVA replacement steam generators, the licensee for Arkansas Nuclear One, Unit 1 (ANO-1) was notified. Upon a review of previously recorded eddy current examination data, it was determined that ANO-1 also had similar indications of tube-to-tube wear. The depth and length of the ANO-1 indications were similar to those recorded at TMI-1 In the spring of 2012, the licensee for Oconee, Unit 3 also detected wear attributed to tube-to-tube contact in their replacement steam generators. Since the design of the Oconee OTSGs, which were built by BWI, is not the same as the TMI or ANO generators, the location of the tube-to-tube wear was different, but the characteristics were similar. The lengths ranged from 1 to 9 inches and the depths ranged up to 20 percent through-wall.

The severity of the replacement OTSG tube-to-tube wear was evaluated and was not found to compromise tube integrity.

The combined experience from the above discussion demonstrated several significant points:

• New or unexpected forms of degradation may be difficult to identify. Robust inspection planning is an important part of identifying new degradation as well as properly characterizing known degradation.

• A comprehensive review of examination data from different perspectives is valuable. By considering the change in indications over time, responses to different channels or techniques, or the spatial distribution of the indications, important information may be found.

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SONGS 2C17 Steam Generator Condition Monitoring Report

" The reporting criteria is critical to proper identification of new or existing damage mechanisms.

" Comprehensive examination of new or replacement steam generators is necessary to ensure that performance is as expected.

4.2 Previous Operating Experience Related to Tube-to-AVB Wear INPO OE 35359 [21] discusses the results of the first two inspections at St. Lucie Unit 2. The recirculating steam generators at St. Lucie Unit 2 were replaced during 2007. During the Cycle 18 Refueling Outage (SL2-18, April 2009), eddy current testing of the replacement steam generators reported over 5800 AVB wear indications in more than 2000 tubes. Fourteen tubes were plugged as a result of the wear indications. None of the indications challenged the Condition Monitoring limits.

Based on the high number of wear indications reported during the SL2-18 inspection, and to further establish growth rates, the St. Lucie Unit 2 SGs were examined again during the next refueling outage at SL2-19 in January 2011. Approximately 3000 new AVB wear indications were reported during the SL2-19 examination. As a result of the SL2-19 inspection, an additional twenty-one (21) tubes were plugged, only one of which exceeded the Plant Technical Specification limit of > 40 %TW (throughwall).

The OE reinforces the importance of inspecting replacement SGs with the bobbin coil at the end of the first cycle of operation, post-replacement. The diagnostic examinations performed with the +PointTM rotating coil concluded that the AVB wear indications could be flat or tapered, single or double sided.

These wear characteristics are important to consider when selecting the proper depth-sizing technique(s).

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SONGS 2C17 Steam Generator Condition Monitoring Report 4.3 Pre-Service Examination Results During May and June of 2009, an on-site pre-service examination was performed in the Songs Unit 2 replacement SGs. The examination consisted of 100 % bobbin coil inspection of all tubes (9727 tubes),

100 % inspection of the Hot Leg (HL) and Cold Leg (CL) Tubesheet (TS) region with the +PointTM probe (9727 tubes), and a 100 % inspection of the row 1-15 U-bend regions with the +PointTM probe (1314 tubes).

No significant degradation was detected during this examination. There were a number of geometric type indications reported in each SG (dings, geometric distortions, proximity, bulge). The following table provides a count of the number of tubes and total number of indications for each Unit 2 SG.

Table 4-1: Summary of Pre-Service Inspection Results Indication Code SG 2E-088 SG 2E-089 Tube Count Indication Count Tube Count Indication Count BLG (Bulge) 0 0 1 1 DNG (Ding) 1089 2180 1033 2084 GMD (Geometric 15 19 21 31 Distortion)

MBM (Manufacturing 0 0 2 2 Burnish Mark)

NQI (Non-Quantifiable 0 0 1 1 Indication)

PLP (Potential 1 1 0 0 Loose Part)

PRX (Proximity) 66 66 42 42 PVN (Permeability 0 0 1 1 Variation) 1814-AU651-M0156, REV. 1 Page 18 of 62 Page 18

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SONGS 2C17 Steam Generator Condition Monitoring Report 5.0 PERFORMANCE CRITERIA The SONGS-2 performance criteria, based on NEI 97-06 [1] are shown below. The structural integrity and accident-induced leakage criteria were taken from Section 5.5.2.11 [17] from the SONGS-2 Technical Specifications. The operational leakage criterion was taken from Section 3.4.13 [18] of the SONGS Technical Specifications.

StructuralInteaqrity PerformanceCriterion: "All inservice steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

" Accident-induced Leakage Performance Criterion: "The primary to secondary accident-induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakage is not to exceed 0.5 gpm per SG and 1 gpm through both SGs."

• OperationalLeakage Performance Criterion: "RCS operational leakage shall be limited to 150 gallons per day primary to secondary leakage through any one steam generator."

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SONGS 2C17 Steam Generator Condition Monitoring Report 6.0 INSPECTION

SUMMARY

The SONGS Unit 2, 2C17 inspection scope occurred in three distinct phases. The first phase followed the planned shutdown for the 2C17 refueling outage and first SG ISI.

The next two inspection phases, performed in April and July 2012, were a direct result of a SG tube leak in Unit 3. The tube leak resulted from tube-to-tube wear (TTW) that was caused by fluid-elastic instability. These subsequent inspections are referred to as 2C17 RTS (Return-to-Service) inspections.

The second-phase inspection (April 2012) was a full-length U-bend inspection of tubes deemed most susceptible to tube-to-tube wear based on the degradation identified in Unit 3. The third-phase inspection (July 2012) consisted of eddy current testing to measure the gaps between the AVBs and the tubes. Based on the gap measurements, an additional 104 tubes were examined in the U-bend region with the +PointTM coil.

Inspections included the following inspection activities for each of the two replacement steam generators (SG 2E-088 and SG 2E-089) using site validated ECT techniques [7]:

" Bobbin Coil Examinations o All in-service tubes, full length tube-end to tube-end

" Rotating Coil Examinations o Tubesheet periphery and divider lane tubes (from 3" above to 1" below the top of the tubesheet), both legs, approximately 3 tubes in from the periphery and 2 tubes in from the divider lane o Full-length U-bend Exam of Tubes Adjacent to Retainer Bars o Specific locations based on results of bobbin inspections (e.g., I-codes, selected wear indications, etc.)

o Full-length U-bend +PointTM examination of tubes with potential for tube-to-tube wear (2C17 RTS inspection) o Full-length U-bend pancake coil examination of selected tubes for measurement of gaps between the AVBs and the tubes (2C1 7 RTS inspection)

• Secondary Side Visual Examinations o Foreign object search and retrieval (FOSAR) as required based on ECT o Post sludge lancing FOSAR examination at the top-of-tubesheet (periphery and the divider lane) o Visual inspections of the upper tube bundle at the 7th TSP and AVB / retainer bar regions The subsections below discuss each aspect of the inspection and describe findings that are relevant to Condition Monitoring and operational assessment.

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SONGS 2C17 Steam Generator Condition Monitoring Report 6.1 Eddy Current Inspections Performed A summary of the total number of bobbin probe and rotating probe examinations performed during 2C17 is provided in Table 6-1 and Table 6-2. The Unit 2 examination was in progress when a tube leak developed in Unit 3 SG 2E-088. As a result of finding tube-to-tube wear in Unit 3, additional analysis and examinations were performed in Unit 2.

The original inspection scope included examination of the tubing in SG's 2E-088 and 2E-089 as follows:

• 100% bobbin coil probe (610 mil diameter) examination of the complete tube length in both Steam Generators.

• 100% of all previous (Pre-service exam) and newly reported bobbin coil "I"codes, Possible Loose Part (PLP), Manufacturing Burnish Mark (MBM), Non-Quantifiable Indication (NQI), Bulge (BLG) and Permeability Variation (PVN) locations with at rotating +PointTM / pancake coil probe.

• 100% of all reported bobbin coil Ding (DNG) and Dent (DNT) locations measuring >/= 2.0 volts with a rotating +PointrM / pancake coil probe.

• A sample of AVB %TW wear indications as defined by SCE and/or tube integrity engineering.

Due to detection of a foreign object and the detection of wear at a retainer bar, scope expansions were performed in SG's 2E-088 and 2E-089 as follows:

" H/L and C/L Tubesheet Periphery exam (TSH/TSC +3/-l inches with a rotating +PointTM /

pancake coil probe.

• H/L and C/L Retainer Bar exam (07H-B06 & 07C-B07) with a single coil rotating +PointTM probe.

This exam included all tubes adjacent to retainer bar locations.

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SONGS 2C17 Steam Generator Condition Monitoring Report Due to the detection of tube-to-tube wear (TTW) in Unit 3, additional inspections were performed in Unit 2 after the initial pre-planned scope was completed. These additional inspections were performed in two separate phases in April and July 2012. These inspections are referred to as RTS (Return-to-Service) inspections. These inspections included the following inspections in both steam generators.

• April 2012 RTS inspection: Full-length U-bend +PointTM inspections of tubes believed to be susceptible to TTW based on the affected tube population in Unit 3.

• July 2012 RTS inspection: Full-length U-bend pancake coil inspection of selected tubes for measurements of tube-to-AVB gaps.

• July 2012 RTS inspection: Full-length U-bend +PointTM inspections of 104 tubes in the 2E-089 SG based on the gap measurements.

The full-length U-bend +Point TM inspections performed in April 2012 included 1371 tubes in SG 2E-088 and 1375 tubes in SG 2E-089. Since these inspections were performed for detection of tube-to-tube wear (TTW), the tubes were selected based on the location of the affected tubes in Unit 3. The defined inspection scope bounded the affected tubes in Unit 3 by a minimum of four tubes on all sides. In July 2012, an additional 104 tubes were inspected in the 2E-089 SG over the full length of the U-bend with

+PointTM. The tubes for these additional inspections were selected based on the tube-to-AVB gap measurements.

A summary of the initial examination and subsequent expansions is provided in 51-9181604-000 [23].

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SONGS 2C17 Steam Generator Condition Monitoring Report 6.2 Degradation Identified The following tube degradation mechanisms were identified during the initial 2C17 inspections and the subsequent 2C17 RTS steam generator eddy current inspections:

" Anti-Vibration Bar (AVB) wear

" Tube Support Plate (TSP) wear

• Retainer Bar (RB) wear

• Foreign Object (FO) wear

• Tube-to-tube wear (TTW)

Table 6-4 summarizes the number of degradation indications and the number of affected tubes for each of the five wear categories. A complete accounting of the number of tubes plugged and stabilized for damage other than TTW during the 2C17 outage is provided in Table 6-5. The plugging information provided in this table is current for non-TTW. Due to the ongoing SG recovery efforts, the plugging strategy and, hence, the plugging and stabilization information for tubes with TTW wear and for tubes plugged as preventative measures for TTW may change prior to startup.

Table 6-6 through Table 6-9 summarize reported AVB wear, TSP wear, RB wear, FO and tube-to-tube wear depths, respectively. Table 6-8, Table 6-9, and Table 6-10 provide detailed information on all of the RB wear, FO wear, and tube-to-tube wear flaws identified. Within Table 6-8, Table 6-9, and Table 6-10, the structurally equivalent length and depth, as well as the overall length and maximum depth of the wear are provided. These structurally equivalent dimensions correspond to a rectangular flaw which would burst at the same pressure as the measured flaw. The structurally equivalent dimensions were determined using the methods described in Section 5.1.5 of Reference 4.

Figure 6-1 through Figure 6-10 provide tubesheet maps illustrating the locations of degradation reported in each steam generator. The AVB wear is most prevalent in the central region of the tubesheet matrix, in longer tube rows (Figure 6-1, Figure 6-2). Two other regions within each SG are also affected to a lesser degree. These regions are located near the periphery in slightly lower rows.

TSP wear has affected fewer tubes than has AVB wear. TSP wear was identified at nearly every support elevation, with a greater tendency to occur on the hot leg than on the cold leg (Figure 6-3, Figure 6-4, Figure 6-5, Figure 6-6). RB wear was identified in only six tubes (Figure 6-7, Figure 6-8).

Foreign object wear was identified in two tubes in SG 2E-088 (Figure 6-9). Tube-to-tube wear was detected in two tubes in SG 2E-089.

Figure 6-11 and Figure 6-12 provide histograms of the reported depths of AVB wear which demonstrate that the vast majority of AVB wear was less than 25 %TW. Four AVB wear flaws were sized >30%TW and the affected tubes were stabilized and plugged. Figure 6-13 and Figure 6-14 provide histograms of TSP wear depths and illustrate that the growth rate of TSP wear during the first operating cycle was less aggressive than that the growth rate of AVB wear. The maximum reported TSP wear flaw was 20%TW.

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SONGS 2C17 Steam Generator Condition Monitoring Report The retainer bar wear indications were not expected as they have not been reported in other MHI steam generators with the retainer bar design. As a result of the finding of retainer bar wear, the Degradation Assessment was revised during the outage to include this new mechanism.

After the completion of the initial scope of 2C17 inspections, additional inspections were performed as a result of the detection of tube-to-tube wear in Unit 3. Tube-to-tube wear was detected in two adjacent tubes in SG 2E-089. Both flaws measured 14% TWD with +PointTM. The Degradation Assessment was also revised to include tube-to-tube wear.

6.3 Tube-to-Tube Wear Detection Subsequent to finding tube-to-tube wear conditions in the U-bends of the Unit 3 tubing, SCE requested an additional review of the U-bend area bobbin coil data in Unit 2. The tubes selected for review encompassed the suspected tube-to-tube wear zone as defined in Unit 3 and included over 1000 tubes in each steam generator. This review included a two-party manual analysis (primary/secondary) of the complete U-bend (07H to 07C) with emphasis on the detection of low level freespan indications which may not have been reported during the original analysis of the U2C17 bobbin coil data. The analysts were instructed to report any indication detected on the differential channels and all indications measuring >0.40 volts on channel 6 absolute which would be a primary channel for detection of tube-to-tube wear. All indications identified during the analysis process were reviewed and dispositioned by the primary and secondary resolution analysis team with concurrence from the IQDA (Independent Qualified Data Analyst). None of the indications reviewed by the resolution team were deemed reportable and therefore, no new NQI indications were entered into the database based on this review.

The Unit 2 Return-to-Service inspection performed in April 2012 was comprised of a U-bend +PointTM examination which included 1371 tubes in SG 2E-088 and 1375 tubes in SG 2E089. The number for SG 2E-088 is less than SG 2E-089 because plugging of 4 tubes for AVB wear had already been performed in SG 2E-088 when these inspections were performed. Since these inspections were performed for detection of tube-to-tube wear (TTW), the tubes were selected based on the location of the affected tubes in Unit 3. The defined inspection scope bounded the combined population of affected tubes in both Unit 3 SGs by a minimum of four tubes on all sides. During this inspection, two tubes with indications indicative of tube-to-tube wear (TTW) were reported in SG 2E-089. The indications were approximately 6" long, located between AVBs B09 and B10, on one side of the tube (intrados for one tube and extrados for the other) and measured a maximum depth of 14%TW. The lower voltage amplitude curve defined in EPRI ETSS 27902.2 was used for sizing the indications. The SONGS Unit 2 & 3 site validation for sizing TTW can be found in AREVA document 51-9177744-000 "Site Validation of EPRI Sizing ETSS for Tube-Tube Wear in SONGS Steam Generators" [15].

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SONGS 2C17 Steam Generator Condition Monitoring Report The bobbin coil data for these two tubes was reviewed by the Lead Level III to determine if there were reportable bobbin coil indications associated with the TTW indications. The review revealed a very small amplitude absolute signal in the same vicinity as the TTW indications in both tubes. The Channel 6 amplitude for these two indications was 0.19 volts and 0.26 volts. Based on the amplitude, signal characteristics, and voltage criteria used for the initial bobbin coil review, it was determined that the bobbin indications were not reportable and are in a depth/size range where reliable detectability is a challenge.

A review of the detection performance of the bobbin coil versus the +PointTM coil was performed using the EPRI data for ETSS 27902.2 and the actual Unit 3 tube-to-tube wear data. The review is documented in AREVA Document 51-9179946-001 [16]. The EPRI technique was not specifically developed for tube-to-tube wear, but was the closest technique available. The review showed that the

+Point probe had a slightly improved Probability of Detection (POD) over the bobbin coil and that the detection level for both techniques was above the minimum level of 0.80 POD at a 90 % LCL. The results of the Unit 3 specific tube-to-tube detection comparison produced similar results.

While the initial bobbin coil examination and subsequent review of bobbin data produced an acceptable detection performance for the depth of the two Unit 2 indications confirmed as tube-to-tube wear, it is likely that the Unit 2 flaw signal amplitudes were below the analysis detection threshold. The supplemental +PointTM examination was performed to provide the best possible detection performance.

During the July 2012 RTS inspection, an additional 104 tubes were inspected with +PointTM over the full length of the U-bend. These tubes were selected based on the tube-to-AVB gap measurements with emphasis placed on tubes having AVB intersections with gaps (as measured by eddy current) on both sides of the tube. No indications of TTW were reported in any of these tubes.

6.4 Tube-to-Tube Wear Sizing Upon detection of tube-to-tube wear in the Unit 3 SG's, a determination was made that the most appropriate technique for sizing the wear was EPRI ETSS 27902.2 or 27902.5. However, with some initial review, it was apparent that the techniques produced very conservative depth estimates. The depth estimates reported for the deepest flaws were near 100% throughwall, however the tubes had maintained structural integrity at normal operating differential pressure. Using the actual operational conditions the throughwall depth values should have been at around 80 %TW in order to withstand pop-through. Based on the best understanding of the tube-to-tube wear degradation morphology, a standard was designed with two long, gradually-tapered machined wear flaws. Although the sample had only two separate flaws, the length of the flaws made it possible to measure multiple discrete depth sizing grading units. On the basis of these multiple points, a polynomial function was developed to adjust the depth estimates. The revised technique was documented in Reference 15.

The actual flaw sizing was performed using the 27902.2 technique. Screening for selection of in situ pressure test candidates was based on the 27902.2 sizing data without the polynomial correction in Reference 15. This produced a conservative population for in situ pressure testing.

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SONGS 2C17 Steam Generator Condition Monitoring Report 6.5 Secondary Side Visual Examination Results Secondary side visual inspections were performed in accordance with the plan outlined in Reference 8.

During the eddy current inspection of SG 2E-088, foreign object indications and foreign object wear indications were reported in two adjacent tubes at the 4t TSP (see Table 6-9 and Figure 6-9).

Consequently, a secondary side foreign object search and retrieval effort was initiated, and the team successfully located and removed the object from the steam generator. Photographs of the object taken during retrieval are provided in Figure 6-15. Note that the FO wear indication identified in tube SG 2E-088 R137 C77 is visible in the upper photo in Figure 6-15. A follow-up analysis performed by SCE identified the object as weld metal debris [13]. These two adjacent tubes are being left in service because the indications are below the Technical Specification plugging limit and the cause of the degradation has been removed.

Due to the eddy current wear indications at the retainer bars, secondary side visual inspections of the retainer bars were performed in both steam generators. These inspections were performed on the retainer bars at B01, B02, B03, B130, B131, and B12. These retainer bars were selected for visual inspection since they are smaller in diameter and all retainer bar wear occurred at one of these locations. The visual inspections were focused on verifying the integrity of the retainer bar and the associated welds. All retainer bars and welds inspected were determined to be in the as-designed configuration. No cracking or degradation of the welds or retainer bars was observed.

The other secondary side examination activities (i.e., post-lancing visual exam at the top-of-tubesheet, visual exams performed in the upper bundle region) identified no foreign objects and no evidence of internal structure degradation. No conditions which could generate foreign objects or threaten tube integrity were identified during these examinations. In response to the detection of tube-to-tube wear in Unit 3, additional secondary side inspections were performed in Unit 2, similar to those done in Unit 3.

The Unit 2 inspections in response to the Unit 3 condition included the following:

" Inspection of all small-diameter retainer bars (12).

" Inspection of retaining bars in the regions correlated to AVB/TSP damage in Unit 3 (Hot and Cold leg of bars B04 and B09 from columns 56 to 119).

" Inspection of AVB end caps on the retainer bar in the same area as identified above.

• Inspection through the transition cone handhole from column 73 to 87 through all rows to periphery of the following:

o 7 th Tube Support Plate o AVB B04 Hot Leg side column 73 to 87 o AVB B04 in Columns 50-60 o AVB B09 in Column 80 to 78 Page 26 of 62 Page 26 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report These inspections did not detect tube-to-tube wear or any other conditions that may be precursor signals to tube-to-tube wear, such as AVB wear indications extending outside of the intersection between the tube and the AVB.

Table 6-1: Steam Generator Tube Inspection Scope Summary (first phase)

SCOPE DESCRIPTION SIG 2E-088 SIG 2E-089 Leg Exam Description Extents Analyzed Scope  % Completed Analyzed Scope  % Completed Hot/Cold 100 % Bobbin F/L TEH-TEC 9,727 9,727 100.00% 9,727 9,727 100.00%

Hot HL Special Interest Various 33 33 100.00% 15 15 100.00%

Cold CL Special Interest Various 45 45 100.00% 16 16 100.00%

Hot / Cold UB Special Interest Various 125 125 100.00% 131 131 100.00%

Expansion Hot HL Tubesheet Periphery TSH+3/-1 1,030 1,030 100.00% 1,030 1,030 100.00%

Cold CL Tubesheet Periphery TSC+3/-1 1,030 1,030 100.00% 1,030 1,030 100.00%

Hot HL Retainer Bar Tube RPC 07H-B06 96 96 100.00% 96 96 100.00%

Cold CL Retainer Bar Tube RPC 07C-B07 96 96 100.00% 96 96 100.00%

Total Plan 12,182 12,182 100.00% 12,141 12,141 100.00%

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SONGS 2C17 Steam Generator Condition Monitoring Report Table 6-2: April 2012 RTS Inspection SG Tube Inspection Summary SCOPE DESCRIPTION SIG 2E-088 SIG 2E-089 Leg Exam Description Extents Analyzed Scope  % Completed Analyzed Scope  % Completed Hot H/L U-Bend RPC 07H-B07 1,371 1,371 100.00% 1,375 1,375 100.00%

Cold C/L U-Bend RPC 07C-B07 1,371 1,371 100.00% 1,375 1,375 100.00%

Hot/Cold U-Bend 2-Coil Various 100.00% 100.00%

Special Interest Hot H/L U-Bend MagBias RPC 07H-B07 1 1 100.00% N/A N/A N/A Cold C/L U-Bend MagBias RPC 07C-B07 1 1 100.00% N/A N/A N/A Total Plan 2,745 2,745 100.00% 2,756 2,756 100.00%

Table 6-3: July 2012 RTS Inspection SG Tube Inspection Summary SCOPE DESCRIPTION S/G 2E-088 S/G 2E-089 Log Exam Description Extents Analyzed Scope %Completed Analyzed Scope %Completed Hot H/IL U-Bend RPC 07H-B07 N/A N/A NIA 104 104 100.00%

Cold C/IL U-Bend RPC 07C-B07 N/A N/A N/A 104 104 100.00%

Total Plan N/A N/A N/A 208 208 100.00%

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SONGS 2C17 Steam Generator Condition Monitoring Report Table 6-4: Wear Indication Summary Tubes with Steam Generator Anti-Vibration Tube Support Tube-to-Tube Retainer Foreign Total Indications SG2E88 (Through- Bar Plat Wear Bar Object Indications (out of 9727 Wall Wear) total per SG) 250% 0 0 0 1 0 1 I 35 - 490A 2 0 0 1 0 3 3 20-34% 86 0 0 0 2 88 7,4 10- 19% 705 108 0 0 0 813 406

< 10% 964 117 0 0 0 1081 600 TOTAL 1757 225 0 2 19861 734*

• This value is the number of tubes with wear indications of any depth and at any location. Since many tubes have indications in more than one depth and location, the total number of tubes is less than the total number of indications.

Tubes with Steam Generator Tube-to-Tube Retainer Foreign Total Indications SG2ES9(Through. Anti-Vibration Tube Support Wall Wear) Bar Wall Plat Wear ear)total Bar Object Indications per9727 (out of SG)

Z0>50% 0 0 0 1 0 8 6 35-49% 0 0 0 1 0 1 11 20 - 340% 78 1 0 3 0 82 6; 10-19% 1014 85 2 0 0 1101 49

< 10% 1499 53 0 0 0 1552 768 TOTAL 1 2591 139 21 5 01 2737 861*

• This value is the number of tubes with wear indications of any depth and at any location. Since many tubes have indications in more than one depth and location, the total number of tubes is less than the total number of indications.

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SONGS 2C17 Steam Generator Condition Monitoring Report Table 6-6: Plugging Summary Steam Generator Reason for Plugging 2E-088 2E-089 Total*

Retainer Bar Wear 2 4 6 AVB Wear >=35% 2 2 AVB Wear <35% for OA Margin 2 2 Preventative - Retainer Bar ** 92 90 182 Total 98 1 94 192 The plugging status shown in this table is current for non-TTW degradation. Due to the ongoing SG recovery efforts, the plugging strategy related to tubes with TTW and for preventative plugging for TTW may change prior to startup.

Although 96 tubes were included in the retainer bar inspection scope (see Table 6-1), only 94 tubes were removed from service due to their proximity to the retainer bars. Two tubes were removed from the list of potentially affected tubes after closer review of the design drawings and consultation with MHI.

Table 6-6: Reported AVB Wear Depths (%TW)

SG Average Upper 9 5 th Maximum 2E-088 10.1 19.2 35 2E-089 9.8 18.0 29 Both SGs 9.9 19.0 35 Table 6-7: Reported TSP Wear Depths (%TW)

SG Average Upper 9 5 th Maximum 2E-088 9.7 14.0 17 2E-089 10.7 16.0 20 Both SGs 10.1 15.0 20 of 62 Page 30 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report Table 6-8: Retainer Bar Wear Circ Axial Structural Structural Sizing Extent Extent Depth Length SG Row Col Location ETSS (in) (in) (%TW) (in) 2E-088 124 48 B03+0.57" 27903.1 0.35 0.31 43.4 0.27 2E-088 125 49 B03+0.46" 27903.1 0.30 0.28 52.4 0.22 2E-089 118 44 B11-0.50" 27903.1 0.16 0.26 26.5 0.21 2E-089 119 133 B02+0.54" 27903.1 0.46 0.43 83.8 0.29 2E-089 120 132 B10-0.50" 27903.1 0.16 0.23 25.3 0.18 2E-089 120 132 B11-0.42" 27903.1 0.21 0.35 27.0 0.30 2E-089 127 127 B03+0.50" 27903.1 0.31 0.45 34.7 0.30 Table 6-9: Foreign Object Wear Circ Axial Structural Structural Sizing Extent Extent Depth Length SG Row Col Location ETSS (in) (%TVV) (in) 2E-088 136 76 04H+0.56" 27901.1 0.31 0.25 25.7 0.21 2E-088 137 77 04H+0.76" 27901.1 0.31 0.20 30.2 0.15 Table 6-10: Tube-to-Tube Wear SG Row Col Location 2E-089 111 81 B09 +1.63 to +7.95 2E-089 113 81 B09 +2.03 to +8.22 62 Page 31 REV. 1 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-1: SG 2E-088 AVB Wear GROUP TUBES

-35% TWoO 2 SCE-SONGS Unit 2- REPL 2D-34% 7V 72 AVB Wear 20% Tw 54 SFG88 ReOi TOTALTUBES: 9727 HOT and COLD Leg Indicatjons SELECTED TUBES 595 PRIMARY FACE OUT OF SERVICE (A: NA SCALE 0.086"71 X Fri Aup 10 15:30.03 2012 1 30 U-. 20 170 ISO ISO 140 130 120 1 10 I Ill 74 a 00 30 20 101 NOZZLE COLUMNS NOZZLE 1814-AU651-MO156, REV. 1 Page 32 of 62 Page 32

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-2: SIG 2E-089 AVB Wear GROUP TUBES o

SCE-SONGS Unit 2- REPL 85-5 "2D-34% TWO 65 AVB Wear '20%

1W8, S/r 89 Repl TOTAL TUBES: 9727 HOT and COLD Leg Indications SELECTED TUBME814 PRIMARY FACE OUT OF SERVICE (I: NA SCALE- 0.088571 X Fri Aw 10 15:37:04 2012 MANWAY 30 30 20- -20 IQ 10 170 1" ISO 740 130 120 110 100 l Be 70 60 10 40 NOZZL NOZZLE COLUMNS NOZZLE 1814-AU651-M0156, REV. 1 Page 33 of 62 Page 33

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SONGS 2C1 7 Steam Generator Condition Monitoring Report Figure 6-3: SIG 2E-088 TSP Wear - Hot Leg GROUP TUBES

-38%TVWO 0 SCE-SONGS Unit 2- REPL 0=U.TM 0

141 Hot Leg TSP Wear -2D ING88 RepO TOTALTUSES: 9727 HOT SELECTED TUBES: 141 PRIMARY FACE OUT OF SERVICE A: NA SCALE 0.08871 X FrAu&10 15:4250 2012 NOZZLE lm 1111 120 0t 110 110 ROWS IN "0 90 a U II

$

A w 50 40 40 30 20 -

to 10 40 10 20 30 so 6 70 00 9 ISO tie IN0 130 1"0 ISO 1n 17M COLUMNS MANVAY 1814-AU651-M0156, REV. 1 Page 34 of 62 Page 34

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-4: SG 2E-088 TSP Wear - Cold Leg 1~(UUI-' 0

-=35% TVTWO TUE

'=35% 0 SCE-SONGS Unit 2 - REPL 20-34% TWD0 49 Cold Leg TSP Wear -L9) I\'1 4 I

Sr 88 Repi TOTAL TUBES: 9727 COLD SELECTEDTUBES: 49 0SC E. 7 X PRIMARY FACE OUT OF SERVICE (F : NA0 1A4E 08012 MANWAY 40 30 - 30 20- 20 to 10 170 160 0 140 130 120 110 100 o 90 so N0 s 0 1O NOZZLE COLUMNS NOZZLE 62 of 62 Page 35 REV. I1 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-5: SIG 2E-089 TSP Wear - Hot Leg GROUP TUBES

-3TWO 0 SCE-SONGS Unit 2- REPL 20U%. o Hot Leg TSP Wear 2o 86 W/8 Rep4 TOTALTUBES: 9727 HOT SB.ECTEDTUBES: 86 PRIMARY FACE OUT OF SERVICE (0): NA SCALE 0.0GN71 X FriAug 10 15:51:07 2012 NOZZLE 4-44

- 3 L,

10o go Sa 110 13O me 150 I 170 COLUMNS MANWAY Page 36 1814-AU651-MO156, REV. I1 1814-AU651-MOI 56, REV. 36 of Page 36 Page of 62 62 Page 36

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-6: SIG 2E-089 TSP Wear - Cold Leg GROUP TUBES SCE-SONGS Unit 2- REPL 20134=TWO 1 20- TWD Cold Leg TSP Wear I)

SAG89 Repi TOTAL TUS; COLD SELECTED TUBES. 34 l PRIMARY FACE OUT OF SERVICE (#: NA SCALE 0.066571 X Fi Aug 10 15:53:43 2012 MANAY N

30 20 20 10 10 170 ISO 1 140 130 120 110 100 w 7 0 30 20 10NOZZLE NOZZLE COLUMNS NZL 62 Page 37 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-7: SG 2E-088 Retainer Bar Wear CROUP TUBES SCE-SONGS Unit 2 - REPL B B2 Retainer Bar Wear Indications SOG88 ROM TOTAL TUSE8: 9727 HOT Leg Indications SELBCTBeTUMS: 2 )

PRIMARY FACE OUT OF SERVICE (14: NA SCALE 0.08571 X I Fri Am 10 11:25:33 2012 MA~WAY 00 40 4-03 3o -

40 20 10 IT in INIg 130 In20lo 0 s oI 20 10 1O0 10 0 1COI110LUMNS 100NOZZLE NOZZLE CLMSNZL of 62 Page 38 1814-AU651-M0156, 1814-AU651 REV. I1

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-8: SIG 2E-089 Retainer Bar Wear GOUP TUBE7 SCE-SONGS Unit 2- REPL RP]

Retainer Bar Wear Indications 611

-80 Rap TOTALTUBES: 9727 HOT and COLD Leg Indications SELE-TEDTUBES: 4 PRIMARY FACE OUT OF SERVICE (A: NA SCALE: 0066571 X Fd Aug 10 16 0040 2012 30 20 -

10 1 170 ISO ISO 10 120 110 100 a so 4o 30 20 ioo30 NOZZLE COLUMNS NOZZLE of 62 Page 39 REV. I1 1814-AU651-M0156, REV.

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SONGS 2C1 7 Steam Generator Condition Monitoring Report Figure 6-9: SG 2E-088 Foreign Object Wear GROUP TUBES SCE-SONGS Unit 2 - REPL F Foren Oboct Vwe 2 Foreign Object Wear (@04H)

SIG 88 Repo TOTAL TUBES: 0727 HOT SBLECTED TUBES: 2 PRIMARY FACE OUT OF SERVICE (M: NA SCALE- .066571 X FriAun 10 11:34:38 2012 NOZZLE

,ll 130 120 tie ROWS Ic I" 00 li0 so so so GO s 50 40 4.

30 30 20 10 10 20 30 40 so TO so so 100 lti 130 In 1* In 140 1t0 COLUMNS MANWAY 1814-AU651-M0156, REV. 1 Page 40 of 62 Page 40

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-10: Tube-to-Tube Wear (Detected in SG 2E-089 Only)

GROUP TUBES SCE-SONGS Unit 2 - REPL I o 2 TTW Inspection Results '2 h0 . ,-,- 104

---

---

---

... . mv SIG 89 Rapi TOTAL TUBES: 9727 HOT Leg Indications - Examinations in HOT and COLD Legs SELECTED TUBES: 1479 PRIMARY FACE OUT OF SERVICE (4): NA SCALE: 0088571 X Fri Aua 10 11:38:23 2012 MANWAY 30 20 20 tO 10 110 ItO ISO 140 130 120 110 100 90 so 70 so 50 40 30 20 No NOZZLE COLUMNS NOZZLE 62 Page 41 1814-AU651-M0156, REV. 11 1814-AU651-MO156, REV. Page 41 Page 41 of of 62 Page 41

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-11: SG 2E-088 AVB Wear Depth Distribution 450 -

397 397 400 350 309 300 c"

C 250

.4- 227

,I- 200 E 159 z 150 100 85 68 46 50 30 18 9 3 2 2 0 2 0 0 0

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Reported Depth (%TW)

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-12: SG 2E-089 AVB Wear Depth Distribution 700 647 608 600 500 424

.2 M

C._

400 V

0 311 300 E

.0 229 z

200 154 102 100 38 15 4 6 1 0 0 0 0 0 0

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Reported Depth (%TW) of 62 Page 43 REV. 11 1814-AU651-M0156, REV.

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-13: SG 2E-088 TSP Wear Depth Distribution 69 62 48 0

C6.

EU

'4-19 17 SI 1 0 0 0 0 0 0 0 0 0 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Reported Depth (%TW) 1814-AU651-M0156, REV. 1 Page 44 of 62 Page 44

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-14: SG 2E-089 TSIP Wear Depth Distribution 60-52 50 40

.E 31 30 27 0

z 20 3I I 0 0 0 0 0 0 0 0 0 0 9

10 -

0 0 0

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Reported Depth (%TW)

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SONGS 2C17 Steam Generator Condition Monitoring Report Figure 6-15: Foreign Object Retrieved from SG 2E-088 1814-AU651-M0156, REV. 1 Page 46 of 62 Page 46

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report 7.0 CONDITION MONITORING ASSESSMENT In order to satisfy Condition Monitoring requirements, all degradation mechanisms detected during the 2C17 outage must meet the structural and leakage performance criteria described in Section 5.0.

Satisfaction of the CM criteria can be demonstrated either analytically or through in situ pressure testing. Structural and accident-induced leakage integrity are evaluated analytically based on the degradation mechanism's characteristics, including circumferential extent, axial length, and through-wall depth. Operational leakage integrity is monitored via leakage detection systems and procedures during plant operation.

Consistent with the structural integrity criteria described in Section 5.0, the limiting pressure loading occurs at a value of three times the normal operating differential pressure. For SONGS-2 this value is 4290 psi [6]. In addition to pressure loads, the CM must also consider the impact of non-pressure accident loads if they could have a significant effect on the burst pressure of the degraded tubes. A review of the screening guidance of Section 3.7.2 of Reference 2 provides the basis for concluding that non-pressure accident loads are not limiting for the identified tube wear in SONGS-2 SG tubes.

Reference 2 indicates that the burst pressure of flat bar wear in U-bend flanks of re-circulating SG tubes (i.e., AVB wear), wear less than 2700 in circumferential extent at supports below the top TSP, and degradation with circumferential involvement less than 25 PDA (Percent Degraded Area) anywhere in the tube bundle; will not be significantly affected by non-pressure loads. The accident-induced leakage performance criteria must also be assessed, and in addition to the SLB pressure (2560 psi [6]), must also consider non-pressure loads where appropriate. This is discussed in more detail within this section.

In order for a degraded tube to be returned to service, the degradation must be measured using a qualified ECT sizing technique, and the degradation must be evaluated as acceptable for continued operation. The sizing techniques qualified for use at SONGS-2 are identified in the Degradation Assessment [6] and are detailed in the ECT technique site validation documents [7] and [15]. If a degradation mechanism cannot be sized with appropriate sizing confidence, it is plugged on detection.

All degradation identified during the current outage was measured with a qualified ECT technique.

This was the first inservice inspection of the SONGS Unit 2 SG tubes; performed after one cycle of operation following SG replacement. The potential for mechanical wear to develop at various locations within the SGs was recognized prior to the examination, but the identification of significant wear at retainer bars was not specifically anticipated. Although the examination program as planned was well capable of detecting this mechanism, the Degradation Assessment [6] was revised during the outage to include this new mechanism. The identification of tube-to-tube wear was not anticipated and not detected in the initial inspection scope. After the identification of tube-to-tube wear in Unit 3, additional inspections were performed, wherein two tubes in SG 2E-089 with tube-to-tube wear were identified.

7.1 Input Parameters Table 7-1 and Table 7-2 identify the input parameters used to perform the Condition Monitoring assessment. In particular, these inputs were used within the AREVA Mathcad tool which implements the SG Flaw Handbook equations [10], in order to generate the limit curves discussed in Section 7.2.

The flaw model for axial thinning with limited circumferential extent was used for the analyses (Section 5.3.3 of Reference 4). The 4290 psi 3AP value is based on a conservative assessment of Unit 2 secondary side steam pressure as measured during cycle 16.

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report Table 7-1: SONGS-2 Steam Generator Input Values Parameter Value Desired probability of meeting burst pressure limit 0.95 Tubing wall thickness 0.043 inch, [7]

Tubing outer diameter 0.750 inch, [7]

Mean of the sum of yield and ultimate strengths at temperature 116000 psi, [11]

Standard deviation of the sum of yield and ultimate strengths 2360 psi, [11]

3 X Normal Operating Pressure Differential (3 NOPD) 4290 psid, [6]

EFPD from SG Replacement through 2C17 627.11, [10]

Table 7-2: Eddy Current ETSS Input Values (Reference 6)

Parameter ETSS ETSS ETSS ETSS ETSS 96004.1 27903.1 27902.2 96910.1 27901.1 Probe Type Bobbin Coil +PointTM +PointTM +PointTM +PointTM NDE depth sizing Slope = 0.98 Slope = 0.97 Slope = 1.02 Slope = 1.01 Slope = 1.05 regression Intercept = Intercept = 2.80 Intercept = Intercept = Intercept =

parameters 2.89 %TW %TW 0.94 %TW 4.30 %TW -1.97 %TW NDE depth sizing technique uncertainty 4.19 %TW 2.11 %TW 2.87 %TVV 6.68 %TW 2.30 %TW (standard deviatior)

NDE depth sizing analysis uncertainty 2.10 %TW 1.06 %TW 1.44 %TW 3.34 %TW 1.15%TW (standard deviation)

Total NDE (Sizing and Technique) 4.69 %TW 2.36 %TW 3.22 %TW 7.48 %TW 2.60 %TW (standard deviation)*

• Total uncertainty is the technique and analysis uncertainties combined via the square root of the sum of the squares.

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report 7.2 Evaluation of Structural Integrity 7.2.1 AVB wear and TSP wear AVB wear and TSP wear were evaluated with the flaw model described in Reference 4 as "axial part-throughwall degradation < 1350 in circumferential extent." The maximum circumferential extent of a single 100%TW wear scar formed by a long flat bar positioned tangentially to the tube surface (e.g., an AVB) is 55.40. For double-sided AVB wear the total circumferential extent for this limiting case would be well below the 1350 limit established by this model; hence, this flaw model is appropriate for AVB wear.

For double-sided AVB wear and double- or triple-sided TSP wear this model also remains bounding because the AVB and TSP geometries provide sufficient circumferential separation between the wear scars to permit each indication to be treated separately. The separation between centerline contact points for AVB wear and TSP wear is 1800 and 1200, respectively, and results in negligible circumferential interaction between separate wear locations in the same axial plane of the tube.

The topic of external loads must be addressed. The maximum reported AVB wear depth (35 %TW),

adjusted upward to conservatively account for sizing uncertainty (ETSS 96004.1), is 45%TW. If it assumed that this flaw is double-sided; and it is further conservatively assumed that the total circumferential extent is 1110 (see above), the resulting Percent Degraded Area (PDA) would be 14.

Similarly, the maximum reported TSP wear depth (20%TW) adjusted to account for NDE uncertainty is 30%TW. If it assumed that this wear depth occurs at all three TSP land contacts, each with the limiting circumferential extent of 55.40, the resulting PDA would be 14. Because the circumferential involvement of these flaws is less than 25 PDA, external loads need not be considered in the evaluation of burst integrity.

The bobbin probe was used to measure the depth of AVB wear and TSP wear through the application of ETSS 96004.1. CM limit curves for AVB wear and TSP wear based upon ETSS 96004.1 and the parameters provided in Table 7-1 and Table 7-2, are provided in Figure 7-1 and Figure 7-2, respectively. These figures also include the throughwall depth of each indication reported, plotted at the assumed axial flaw length. The assumed flaw length for AVB wear indications was derived from the flaw profiles (using line-by-line sizing). Twenty-two AVB wear indications were profiled with emphasis placed on the deeper indications for profiling. Of the AVB wear scars profiled (using line by line sizing) the maximum structural length was determined to be slightly less than 0.6 inches. A bounding length of 0.7 inches was chosen for the AVB wear as shown on Figure 7-1. This is slightly longer than the 0.59 inch width of the AVBs.

The TSP wear flaws are plotted at a length of 1.4 inches, slightly longer than the thickness of the TSPs (1.38 inches). Since all AVB wear and TSP wear flaws lie below their respective CM limit curves, it is concluded that the structural integrity performance criterion was satisfied with respect to these degradation mechanisms during the operating period preceding the 2C17 outage.

7.2.2 Retainer Bar Wear Retainer bar wear was also evaluated with the "axial part-throughwall degradation < 1350 in circumferential extent" degradation model as described in Reference 4. The maximum measured circumferential extent of RB wear was 0.46 inches (Table 6-8) which corresponds with an angular extent at the mid tube wall of 750; well within the 1350 requirement for this flaw model. Because of the rather short axial extent of the RB wear indications, it is prudent to also consider the potential for rupture in the circumferential direction. For the indication with the largest circumferential extent (0.46 1814-AU651-MO156, REV. 1 Page 49 of 62 Page 49

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report inch, SG 2E-089 RI 19 C133 B02), and a limiting assumption that the wear is 100%TW over the entire circumferential extent, the PDA is found to be 21 PDA (i.e., (0.46)/(uT(mid-wall diameter)) ). This limiting flaw was evaluated with the degradation model for circumferential cracking under pressure loading as described in Reference 2. Based on this model the lower bound burst pressure in the circumferential direction was determined to be 6470 psi; much less limiting than the results from the axial part-throughwall model (discussed below). This provides the basis for concluding that the axial part-throughwall degradation model is appropriate for the evaluation of RB wear.

External loads which are assumed to exist concurrently with the SLB accident do not significantly affect burst pressure in tubes with flaws located in the U-bend region on the tube flanks (+/-450) [2]. +PointTM probe examinations were performed with another eddy current probe placed in an adjacent tube in order to estimate the position of the limiting flaw (SG 2E-089 R1 19 C1 33 B02) relative to the tube flank.

This testing showed that the flaw lies approximately 40 to 50 degrees from the flank position; consequently, the RB wear may not lie entirely within the flank region. However, it is also known that external loads do not significantly affect burst pressure in tubes with flaws whose circumferential involvement is less than 25 PDA [2]. The upper bound circumferential involvement of the limiting RB wear flaw is only 21 PDA. It is therefore concluded that the limiting Condition Monitoring structural criteria is 3x normal operating pressure differential, rather than 1.2x the combined loading of SLB pressure and external loads. In short, it is appropriate to consider pressure loading-only for the structural integrity evaluation of RB wear flaws.

The axial depth profile of each RB wear flaw was measured using ETSS 27903.1, and this data was used to determine the structurally significant dimensions of the flaws using the methods described in Section 5.1.5 of Reference 4. The results are provided in Table 6-8 and are plotted on the CM curve provided in Figure 7-3. Since the RB wear in tube SG 2E-089 R1 19 C133 B02 lies above the CM curve in Figure 7-3, it could not be demonstrated on the basis of NDE measurements and analytical evaluation that this tube met the structural integrity performance criteria. Consequently, this tube was subjected to in situ pressure testing. All other RB wear indications lie below the CM curve and, hence, are shown to meet the structural integrity performance criteria analytically.

In situ accident leakage and structural proof testing was performed on tube SG 2E-089 R1 19 C133 B02 in accordance with the guidance provided in Reference 3. The normal operating, accident level, and proof test hold pressures were adjusted to account for temperature effects on material strength, and other factors related to the test process. All testing was accomplished using full tube pressurization.

The tube was held pressurized at the required hold times without any difficulties. No leakage or rupture occurred at any time during the test, thereby successfully demonstrating that the tube met the SONGS accident leakage performance criteria and structural integrity performance criteria during the operating period preceding the 2C17 outage. This result also demonstrates the generous level of conservatism inherent in the flaw sizing and analytical methods used to evaluate SONGS SG tube volumetric degradation. The in situ test results are documented in Reference 12.

7.2.3 Foreign Object Wear Foreign object wear was evaluated with the "axial part- throughwall degradation < 1350 in circumferential extent" flaw model as described in Reference 4. The measured circumferential extent of both reported FO wear flaws was 0.31 inches or 50°, which is well within the 1350 constraint of this model. Although these flaws are short axially, the circumferential involvement is only 14 PDA. Thus these tubes would not preferentially burst in the circumferential mode prior to axial burst, and the use of the axial part-throughwall flaw model remains appropriate (see Section 7.2.2). In addition, because these flaws are located well below the top TSP (i.e., they are at the 4 th TSP), and because the 1814-AU651-MO156, REV. 1 Page 50 of 62 Page 50

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report circumferential involvement is less than 25 PDA, external loads need not be considered in the evaluation of burst integrity.

The +PointTM probe was used to measure the axial depth profile of the flaws through the application of ETSS 27901.1. This data was used to determine the structurally significant dimensions of the flaws (Table 6-9) by applying the methods described in Section 5.1.5 of Reference 4. The applicable CM limit curve, based upon ETSS 27901.1 and the parameters provided in Table 7-1 and Table 7-2, is shown in Figure 7-4 along with the structurally equivalent dimensions of each FO wear flaw. Since both flaws lie well below the CM limit curve, it is concluded that the structural integrity performance criteria was satisfied with respect to foreign object wear during the operating period preceding the 2C17 outage.

7.2.4 Tube-to-Tube Wear Tube-to-tube wear (TTW) was evaluated with the flaw model described in Reference 4 as "axial part-throughwall degradation < 1350 in circumferential extent." The circumferential extent of a TTW flaw is limited by the geometry of the interacting tubes such that it can be modeled as a single 100%TW wear scar formed by a flat bar positioned tangentially to the tube surface. In this configuration the maximum circumferential extent of the degradation will be 55.4*. For double-sided TTW this model is bounding because the wear geometry provides sufficient circumferential separation between the wear scars to permit each indication to be treated separately. The separation between centerline contact points for double-sided TTW is 1800, and results in negligible circumferential interaction between separate wear locations in the same axial plane of the tube. With respect to external loads, each wear flaw at the same axial location may be treated individually. An individual TTW flaw with a depth of 100%TW and a circumferential extent of 55.40 would be less than 16 PDA. Because the circumferential involvement of this limiting flaw is less than 25 PDA, external loads need not be considered in the evaluation of burst integrity for TTW.

The +PointTM probe was used to estimate the depth and the overall length of TTW through the application of ETSS 27902.2. The flaws had estimated maximum depths of 15% and 14%TW. The maximum indicated length of TTW was 6.32 inches. These lengths and depths are well below the CM limit curve for TTW using ETSS 27902.2 (see Figure 6-6). Despite the fact that both of these flaws clearly meet the structural integrity criterion based on the maximum measured lengths and depths, both flaws were line-by-line sized to obtain structural depths and lengths as well as to obtain information on the shapes of the flaws. Figure 6-6 depicts the structurally-equivalent dimensions of both flaws relative to the CM limit curve.

Based on the shallow depths of the TTW flaws detected, in situ pressure testing of these flaws was not required nor was it performed.

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SONGS 2C17 Steam Generator Condition Monitoring Report 7.3 Evaluation of Accident-induced Leakage Integrity 7.3.1 AVB wear and TSP wear Volumetric degradation that is predominantly axial in orientation and is greater than 0.25 inch long will leak and burst at essentially the same pressure [2]. The SONGS-2 AVB wear and TSP wear flaws meet this description. The evaluation in Section 7.2.1 demonstrated that the AVB wear and TSP wear identified during the 2C17 outage satisfied the burst integrity criteria at a pressure of 4290 psi.

Consequently, the leakage integrity of AVB wear and TSP wear at the much lower SLB pressure differential of 2560 psi is also demonstrated by that evaluation. All of the tubes with AVB wear and TSP wear flaws satisfied the SONGS accident-induced leakage performance criteria during the operating period prior to the 2C17 outage.

7.3.2 Retainer Bar Wear The accident-induced leakage integrity of tubes with RB wear is bounded by tube SG 2E-089 RI 19 C133 which had the largest measured RB wear flaw identified during the 2C17 outage. The leakage integrity of this tube was confirmed by in situ pressure testing, during which the tube did not leak or rupture at any pressure level. Based upon the in situ test results it is concluded that all of the tubes with RB wear flaws satisfied the SONGS accident-induced leakage performance criteria during the operating period prior to the 2C17 outage. The in situ test is discussed in more detail in Section 7.2.2 and in Reference 12.

7.3.3 Foreign Object Wear Since the axial length of the FO wear flaws is less than 0.25 inch it is theoretically possible that pop-through and leakage could occur prior to tube rupture. Per Reference 2, a conservative evaluation of this potential may be performed through the use of the Reference 4 flaw model for uniform depth, 3600 volumetric degradation. The limit curve of Figure 7-5 identifies the throughwall limit for uniform 3600 thinning at 2560 psi. As with a CM limit, this curve includes the effects of relational, material strength, and NDE sizing uncertainties. The relational uncertainty is the uncertainty between the actual burst pressure and the calculated burst pressure based on known structural lengths and depths. The reported maximum depth and overall axial length for the two FO wear flaws are also shown in Figure 7-5. Because both flaws lie well below the curve it is concluded that the foreign object wear identified did not violate the accident-induced leakage performance criteria during the operating period prior to the 2C17 outage.

7.3.4 Tube-to-Tube Wear Volumetric degradation that is predominantly axial in orientation and is greater than 0.25 inch long will leak and burst at essentially the same pressure [2]. The tube-to-tube wear flaws meet this description.

The evaluation in Section 7.2.4 demonstrated that the tube-to-tube wear identified during the 2C17 outage satisfied the burst integrity criteria at a differential pressure of 4290 psi. Consequently, the leakage integrity of tube-to-tube wear at the much lower SLB pressure differential of 2560 psi is also demonstrated by that evaluation. All of the tubes with tube-to-tube wear flaws satisfied the SONGS accident-induced leakage performance criteria during the operating period prior to the 2C17 outage.

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report 7.4 Evaluation of Operational Leakage Integrity Throughout the operating period preceding the 2C17 outage, SONGS Unit 2 experienced no measurable primary to secondary leakage. Therefore, the operational leakage performance criterion was satisfied during this period.

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report Figure 7-1: CM Limit for AVB Wear, ETSS 96004.1 80 70

-Condition Monitoring Limit u AVB Wear Flaws 60 \

50 -

~40

-= As discussed in Section 6.2.1, a structural 2o ==_length of 0.7" was used to bound the 10 20 actual AVB width of 0.59".

0 "_,'

o. 0.u 1t Ad2 162 se61.24 in8 1 ,6 ast 21u 0

Degradation Length (in.)

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report

..... ~.._ r ao AI 4 Figure 7-2: CM Limit for Two Wear, E I 80 70 60 50 0.

40 a) 30) 20 10 2.0 Degradation Length (in.)

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report Figure 7-3: CM Limit for RB Wear, ETSS 27903.1 100 90

-Condition Monitoring w SG89 R119 C133 B02+0.54" Limit 80

• RB Wear - Structural Equivalent 70 60 0= -----

0 0

- - - - - - - - - - -

0 50 - - - - - - - -

0 U-U 40 U

30

• U U

20 10 0

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Degradation Length (in.)

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report Figure 7-4: CM Limit for FO Wear, ETSS 27901.1 100 90

-Condition Monitoring Limit 80

• FO Wear - Structural Equivalent 70 60 4-50

£ 0

Lu Lu 40 0) 0 0

30 20 10 0

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Degradation Length (in.)

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report Figure 7-5: Foreign Object Pop-Through at 2560 psi, Uniform 3600 Thinning, ETSS 27901.1 100 psi 2560 at Flaws Limit Wear 90 - Pop-Through Object m

-- Pop-Through Limit at 2560 psi Foreign

• Foreign Object Wear Flaws 80 70- - - - - -

- - - - - -

60 0.

0 50 10 40 0.

E 0 30 cc Z

20 10 0 I I I 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Reported Axial Length (in.)

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AREVA SONGS 2C17 Steam Generator Condition Monitoring Report Figure 7-6: CM Limit for Tube-to-Tube Wear, ETSS 27902.2 SG89 FS Wear Condition Monitoring ETSS 27902.2 100 90 80 70 60 a.

50 40 30 20

. .

10 0 -t--

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AR EVA SONGS 2C17 Steam Generator Condition Monitoring Report 8.0 CONDITION MONITORING CONCLUSION This Condition Monitoring assessment has evaluated all SG tube degradation detected during the 2C17 outage against the three SONGS technical specification performance criteria. Through a combination of eddy current inspection, analytical evaluation, in situ pressure testing, and operational leakage monitoring it has been determined that the three performance criteria: 1) structural integrity, 2) accident-induced leakage integrity, and 3) operational leakage integrity; were satisfied during the operating period prior to the 2C17 outage.

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SONGS 2C17 Steam Generator Condition Monitoring Report

9.0 REFERENCES

1. NEI 97-06, "SG Program Guidelines," Rev. 3, January 2011.

2. EPRI Report 1019038, "SG Integrity Assessment Guidelines: Revision 3", November 2009.

3. EPRI Report 1014983, "Steam Generator In situ Pressure Test Guidelines, Revision 3", August 2007.

4. EPRI Report 1019037 "Steam Generator Degradation Specific Management Flaw Handbook, Revision 1", December 2009.

5. EPRI, SG Management Project, "sgmp.epriq.com."

6. AREVA Document 51-9176667-001, "SONGS 2C17 & 3C17 Steam Generator Degradation Assessment"

7. AREVA Document 51-9104383-002, "SONGS Units 2 & 3 Replacement Steam Generators Eddy Current Technique Validation"

8. AREVA Document 03-9170186-003, "Secondary Side Visual Inspection Plan and Procedure for SONGS 2C17" (SONGS Procedure Number S023-XXVII-25.36)

9. AREVA Document 32-5033045-002, "Mathcad Implementation of SG Flaw Handbook Equations for Integrity Assessment"

10. *Matheny, Southern California Edison, "Numerical Values for the SG DA, SONGS Unit 2, Southern California Edison," January 18, 2012

11. *SONGS Unit 2 Replacement Steam Generator Receipt Inspection QA Document Review Package, (statistics evaluated in Excel file "CMTR Final with Stats.xlsx")

12. AREVA Document 51-9177395-000, "In-Situ Pressure Test Summary for SONGS Unit 2 (Feb 2012)"

13. *SONGS Nuclear Notification 201854749, Created February 13, 2012

14. AREVA Document 51-9177491-001, "SONGS 2C17 Steam Generator Condition Monitoring and Preliminary Operational Assessment"

15. AREVA Document 51-9177744-000, "Site Validation of EPRI Sizing ETSS for Tube-Tube Wear in SONGS Steam Generators"

16. AREVA Document 51-9179946-001, "Comparison of Bobbin and +Point POD for Tube-Tube Wear in SONGS Steam Generators"

17. SONGS Technical Specifications Section 5.5.2.11, "Steam Generator (SG) Program",

Amendment 204

18. SONGS Technical Specifications Section 3.4.13, "RCS Operational Leakage", Amendment 204

19. INPO Operating Experience Report OE 34946, "Tube-to-Tube Contact Wear Identified in TMI-1 Steam Generators (TMI-1)"

20. NRC Information Notice 2012-07, "Tube-to-Tube Contact Resulting in Wear in Once-Through Steam Generators"

21. INPO Operating Experience Report OE 35359, "Large Number of Anti-Vibration Bar Wear Indications Reported in the Unit 2 Replacement Steam Generators (St. Lucie) 1814-AU651-M0156, REV. 1 Page 61 of 62 Page 61

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22. MHI Document L5-04GA1 11, "San Onofre Generating Station, Units 2 & 3 Replacement Steam Generators Vendor Manual", Rev 6 (SONGS Document SO23-617-1-M1273, Rev 6)

23. AREVA Document 51-9181604-000, "SONGS Unit 2 Cycle 17 and U2 Return to Service Eddy Current Inspection Technical Summary"

• These references are not available from the AREVA records center; however, they are available from the SCE document control system. Therefore, these are acceptable references for use on this contract per AREVA NP Procedure 0402-01, Attachment 8 as authorized by the PM signature on page 2.

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