Text

SCE Brief on Issues Referred by the Commission, Attachments 6 to 11
	ML13030A456
Person / Time
Site:	San Onofre
Issue date:	06/25/2009
From:	Hall J; Plant Licensing Branch IV
To:	Ridenoure R; Southern California Edison Co
	SECY RAS
Shared Package
ML130310300	List: ML13030A441; ML13030A451; ML13030A456; ML13030A462; ML13030A467;
References
	RAS 24060, 50-361-CAL, 50-362-CAL, ASBLP 13-924-01-CAL-BD01, TAC MD9160, TAC MD9161
	Download: ML13030A456 (114)
	v • d • e

SCE ATTACHMENT 6

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 June 25, 2009 Mr. Ross T. Ridenoure Senior Vice President and Chief Nuclear Officer Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, CA 92674-0128

SUBJECT:

SAN ONOFRE NUCLEAR GENERATING STATION, UNITS 2 AND 3 ISSUANCE OF AMENDMENTS RE: TECHNICAL SPECIFICATION CHANGES IN SUPPORT OF STEAM GENERATOR REPLACEMENT (TAC NOS. MD9160 AND MD9161)

Dear Mr. Ridenoure:

The Commission has issued the enclosed Amendment No. 220 to Facility Operating License No. NPF-10 and Amendment No. 213 to Facility Operating License No. NPF-15 for San Onofre Nuclear Generating Station (SONGS), Units 2 and 3, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated June 27, 2008, as supplemented by letters dated August 13, 2008, and February 5, 2009.

The amendments revise TSs 3.4.17, "Steam Generator (SG) Tube Integrity," 5.5.2.11, "Steam Generator (SG) Program," 5.5.2.15, "Containment Leakage Rate Testing Program," and 5.7.2.c, "Special Reports," and support of the replacement of the steam generators at SONGS, Units 2 and 3.

A copy of our related Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely, JJ:::I~en~ct Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-361 and 50-362

Enclosures:

1. Amendment No. 220 to NPF-10

2. Amendment No. 213 to NPF-15

3. Safety Evaluation cc w/encls: Distribution via Listserv

SCE ATTACHMENT 7

SOUTHERN CALIFORNIA EDISON' An EDISON INTERNATIONAL l. Company March 23, 2012 Elmo E. Collins, Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 1600 East Lamar Blvd.

Arlington, Texas 76011-4511

Subject:

Docket Nos. 50-361 and 50-362 Steam Generator Return-to-Service Action Plan San Onofre Nuclear Generating Station

Dear Mr. Collins:

Peter T. Dietrich Senior Vice President & Chief Nuclear Officer The purpose of this letter is to describe the actions Southern California Edison (SCE) is taking with respect to steam generator tube issues at the San Onofre Nuclear Generating Station (SONGS). As you know, SONGS Units 2 and 3 are currently shutdown as we inspect and analyze the causes of steam generator tube wear issues. Our top priority is to protect the health and safety of the public by understanding the causes of these issues and taking corrective actions to address those causes.

As part of the normal end-of-cycle steam generator tube inspections performed following the first cycle of operation, all of the tubes in both Unit 2 steam generators were inspected using eddy current inspection technology. More detailed eddy current inspections of tubes were performed in areas exhibiting signs of wear in accordance with SCE's Steam Generator Program Requirements (SGPR) which are consistent with Electric Power Research Institute (EPRI) guidelines. Unanticipated wear was identified in a number of tubes adjacent to steam generator retainer bars, and this wear was determined to be the result of retainer bar contact with the tubes. The tube with the most significant wear indication in the Unit 2 steam generators was pressure tested in accordance with the SGPR. The results demonstrated that the tube met the steam generator leakage and structural performance criteria as required by Technical Specifications. No tubes on Unit 2 were found to have failed these criteria.

With respect to Unit 3, a leaking steam generator tube was identified by SCE on January 31, 2012, and the unit was promptly shut down before Technical Specification leakage limits were exceeded, with no public health or safety consequences. All of the tubes in both Unit 3 steam generators were inspected using eddy current inspection technology. Indications of the same type of wear adjacent to the retainer bars found in Unit 2 were identified in Unit 3.

In addition, subsequent inspections and testing in Unit 3 identified a number of steam generator tubes that did not meet the leakage and structural performance criteria as required by Technical Specifications. SCE has identified the wear mechanism that caused the tube leak as tube-to-tube interaction, and further testing, analysis, and corrective actions to address this wear mechanism are underway.

P.O. Box 128 San Clemente, CA 92672 (949) 368-6255 PAX 86255 Fax: (949) 368-6 183 Pete.Dietrich@sce.com

Elmo E. Collins Regional Administrator U.S. Nuclear Regulatory Commission ~1ar c h 23, 2012 Inspections of the Unit 2 steam generator tubes have not shown the wear associated with tube-to-tube interaction seen in the Unit 3 steam generators. We will continue to assess the data obtained from Unit 3 for applicability to Unit 2 and will take necessary corrective actions.

SCE commits to complete the following actions as indicated for each unit:

Actions for Unit 2

1. The mechanisms causing steam generator tube wear in Unit 2 have been identified, and all tubes for which testing indicated wear in excess of SGPR and EPRI guidelines have been plugged. SCE also plugged all tubes adjacent to the retainer bars, whether worn or not, as a preventive measure. SCE has documented these issues in its Corrective Action Program (CAP) for analysis and resolution.

2. SCE will determine the causes of the tube-to-tube interactions that resulted in steam generator tube wear in Unit 3, and will implement actions in accordance with the CAP to prevent loss of integrity due to these causes in the Unit 2 steam generator tubes. Once these actions have been determined, SCE will establish a protocol of inspections and/or operational limits for Unit 2, including plans for a mid-cycle shutdown for further inspections.

3. Prior to entry of Unit 2 into Mode 2, SCE will, in a joint meeting, provide the NRC the results of our assessment of Unit 2 steam generators, the protocol of inspections and/or operational limits 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.

4. Both prior to and after entry of Unit 2 into Mode 2, the protocol and inspection time frames described in Action 2 above will be adjusted, as necessary, to account for the results of ongoing inspections and analyses of the causes of tube-to-tube interactions in the Unit 3 steam generators. NRC will be notified of any proposed changes to this protocol.

Actions for Unit 3

5. SCE will complete in-situ pressure testing of tubes with potentially significant wear indications in accordance with the EPRI Steam Generator In-Situ Pressure Test Guidelines and will plug tubes in accordance with those guidelines.

6. SCE will plug all tubes with wear indications in excess of SGPR and EPRI guidelines as well as perform preventive plugging or take other corrective actions to address retainer bar-related tube wear in Unit 3.

7. SCE will determine the causes of tube-to-tube interaction and implement actions in accordance with the Corrective Action Program to prevent recurrence of loss of integrity in the Unit 3 steam generator tubes while operating.

8. SCE will establish a protocol of inspections and/or operational limits for Unit 3, including plans for a mid-cycle shutdown for inspections. The protocol is intended to minimize the progression of tube wear, and ensure that tube wear will not progress to the point of degradation that could cause tubes to not meet leakage and structural strength test criteria.

Elmo E. Collins Regional Administrator U.S. Nuclear Regulatory Commission March 23, 2012

9. Prior to entry of Unit 3 into Mode 4, SCE will, in a joint meeting, provide the NRC the results of our assessment of Unit 3 steam generators, the protocol of inspections and/or operational limits 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.

We will proceed deliberately and conservatively to implement these steps, always bearing in mind that safety is our first priority. We will also keep the NRC informed of our progress and of the results of our tests and analyses., "Commitment List" contains the commitments made in this letter.

Please do not hesitate to contact me or Mr. Richard St Onge at 949 368-6240 should you require any further information.

Attachments:

As stated.

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

ATTACHMENT 1 COMMITMENT LIST Docket Nos. 50-361 and 50-362 Steam Generator Return-to-Service Action Plan The following list identifies those actions committed to by Southern California Edison (SCE) for the San Onofre Nuclear Generating Station (SONGS) in this document.

Any other actions discussed in the submittal are described only for information and are not regulatory commitments.

No.

Commitment Due Date Actions for Unit 2 1

The mechanisms causing steam generator tube wear in Unit 2 Complete have been identified, and all tubes for which testing indicated wear in excess of SGPR and EPRI guidelines have been plugged. SCE also plugged all tubes adjacent to the retainer bars, whether worn or not, as a preventive measure. SCE has documented these issues in its Corrective Action Program (CAP) for analysis and resolution.

2 SCE will determine the cause(s) of the tube-to-tube Prior to entry of interactions that resulted in steam generator tube wear in Unit Unit 2 into Mode 2 3, and will implement actions in accordance with the CAP to prevent loss of integrity due to these potential causes in the Unit 2 steam generator tubes. Once these actions have been determined, SCE will establish a protocol of inspections and/or operational limits for Unit 2, including plans for a mid-cycle shutdown for further inspections.

3 Prior to entry of Unit 2 into Mode 2, SCE will, in a joint Prior to entry of meeting, provide the NRC the results of our assessment of Unit 2 into Mode 2 Unit 2 steam generators, the protocol of inspections and/or operational limits 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.

4 Both prior to and after entry of Unit 2 into Mode 2, the protocol Ongoing and inspection time frames described in Action 2 above will be adjusted, as necessary, to account for the results of ongoing inspections and analyses of the causes of tube-to-tube interactions in the Unit 3 steam generators. NRC will be notified of any proposed changes to this protocol.

Actions for Unit 3 5

SCE will complete in-situ pressure testing of tubes with Prior to entry of potentially significant wear indications in accordance with the Unit 3 into Mode 4 EPRI Steam Generator In-Situ Pressure Test Guidelines and will plug tubes in accordance with those guidelines.

Page 1 of 2

No.

6 7

8 9

Docket Nos. 50-361 and 50-362 Commitment Due Date SCE will plug all tubes with wear indications in excess of Prior to entry of SGPR and EPRI guidelines as well as perform preventive Unit 3 into Mode 4 plugging or take other corrective actions to address retainer bar-related tube wear in Unit 3.

SCE will determine the cause(s) of tube-to-tube interaction Prior to entry of and implement actions in accordance with the Corrective Unit 3 into Mode 4 Action Program to prevent recurrence of loss of integrity in the Unit 3 steam generator tubes while operating.

SCE will establish a protocol of inspections and/or operational Prior to entry of limits for Unit 3, including plans for a mid-cycle shutdown for Unit 3 into Mode 4 inspections. The protocol is intended to minimize the progression of tube wear, and ensure that tube wear will not progress to the point of degradation that could cause tubes to not meet leakage and structural strength test criteria.

Prior to entry of Unit 3 into Mode 4, SCE will, in a joint Prior to entry of meeting, provide the NRC the results of our assessment of Unit 3 into Mode 4 Unit 3 steam generators, the protocol of inspections and/or operational limits 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.

Page 2 of 2

SCE ATTACHMENT 8 L

VSOUTHERN CALIFORNIA 7:

EDISON 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

+

L h

Page 2

"I SOUTHERN CALIFORNIA EDISON 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 L IS T O F T A B L E S...................................................................................................................................

6 L IS T O F F IG U R E S.................................................................................................................................

7 ABBREVIATIO NS AND ACRO NYM S.................................................................................................

8 1.0 EX E C U T IV E S U M M A 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 B A C K G R O U N D........................................................................................................................

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 M echanistic 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 N A L A C T IO N S............................................................................................................

52 11.1 Vibration Monitoring Instrumentation........................

52 11.2 G E S m art S ignal TM....................................................

................................................ 52 12.0 C O N C L U S IO N S........................................................................................................................

53 13.0 R E F E R E N C E S.........................................................................................................................

5 4 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

2 3

4 5

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

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

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

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

SONGS U2C1 7 Steam Generator Operational Assessment*

[Proprietary Information Redacted]

Page 5

SOUTHERN CALIFORNIA EDISON An EDISON INTERNA 770N.4L': Coipany Unit 2 Return to Service Report List of Tables Page TABLE 5-1:

TABLE 6-1:

TABLE 7-1:

TABLE 8-1:

TABLE 8-2:

TABLE 8-3:

TABLE 8-4:

SONGS UNIT 3 SG 3E-088 IN-SITU PRESSURE TESTS WITH TUBE LEAKAGE......... 19 STEAM GENERATOR WEAR DEPTH

SUMMARY

29 TTW COMPARISON BETWEEN UNIT 2 AND UNIT 3 SGS.........................................

36 INDEPENDENT ATHOS COMPARISON RESULTS - STEAM QUALITY................... 38 COMPARISON OF MAXIMUM VOID FRACTION........................................................

40 COMPARISON OF MAXIMUM INTERSTITIAL VELOCITY (FT/S).............................. 42 UNIT 2 STEAM GENERATOR TUBE PLUGGING

SUMMARY

45 Page 6

J SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONALI@ Company Unit 2 Return to Service Report List of Figures Page FIGURE 3-1:

FIGURE 6-1:

FIGURE 6-2:

FIGURE 6-3:

FIGURE 6-4:

FIGURE 6-5:

FIGURE 6-6:

FIGURE 6-7:

FIGURE 6-8:

FIGURE 7-1:

FIGURE 7-2:

FIGURE 8-1:

FIGURE 8-2:

FIGURE 8-3:

FIGURE 8-4:

FIGURE 8-5:

FIGURE 8-6:

FIGURE 8-7:

REPLACEMENT STEAM GENERATOR SECTION VIEW.........................................

14 STEAM GENERATOR SECTION VIEW SKETCH....................................................

23 UNIT 2 DISTRIBUTION OF WEAR AT AVB SUPPORTS.........................................

24 UNIT 3 DISTRIBUTION OF WEAR AT AVB SUPPORTS.........................................

24 UNIT 2 DISTRIBUTION OF WEAR AT TSP SUPPORTS..........................................

25 UNIT 3 DISTRIBUTION OF WEAR AT TSP SUPPORTS..........................................

25 PROBABILITY OF DETECTION FOR TUBE WEAR..................................................

26 3E-088 ROTATING COIL INSPECTION REGION.....................................................

27 3E-089 ROTATING COIL INSPECTION REGION.....................................................

28 2E-088 ROTATING COIL INSPECTION REGION.....................................................

34 2E-089 ROTATING COIL INSPECTION REGION.....................................................

35 STEAM QUALITY CONTOUR PLOTS FOR 100% POWER AND 70% POWER.....

39 MAXIMUM VOID FRACTION VERSUS POWER LEVEL AND...................................

41 INTERSTITIAL VELOCITY CONTOUR PLOTS FOR 100% POWER AND 70% POWER43 GAP VELOCITY AT 100% POWER AND 70% POWER FOR 2E-088 R1 41 C89.....

44 GAP VELOCITY AT 100% POWER AND 70% POWER FOR 2E-089 R1 41 C89........ 44 2E-088 PLUGGING AND STABILIZING MAP...........................................................

46 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 2E-089 3E-088 3E-089 AILPC Ar ATHOS AVB CDP CM DA DID ECT EFPD EPRI ETSS FEI FIV FO FOSAR gpd INPO LERP MHI MSLB MWt N-1 6 NEI NODP OA OSG post-trip SLB PRA RB RCPB RCE RCS Ref.

RSG SCE SG SGTR SIPC SLB SGP SONGS SR T/H TEDE TS TSP Unit 2 Steam Generator E-088 Unit 2 Steam Generator E-089 Unit 3 Steam Generator E-088 Unit 3 Steam Generator E-089 Accident Induced Leakage Performance Criterion Argon Analysis of Thermal-Hydraulics of Steam Generators Anti-Vibration Bar Core Damage Probability Condition Monitoring Degradation Assessment Defense in Depth Eddy Current Testing Effective Full Power Days Electric Power Research Institute Examination Technique Specification Sheet Fluid Elastic Instability Flow Induced Vibration Foreign Object Foreign Object Search and Retrieval Gallons Per Day Institute of Nuclear Power Operations Large Early Release Probability Mitsubishi Heavy Industries, Ltd.

Main Steam Line Break Megawatt Thermal Nitrogen - 16 Nuclear Energy Institute Normal Operating Differential Pressure Operational Assessment Original Steam Generator Steam Line Break Post-Trip Return-To-Power Event Probabilistic Risk Assessment Retainer Bar Reactor Coolant Pressure Boundary Root Cause Evaluation Reactor Coolant System Reference Replacement Steam Generator Southern California Edison Steam Generator Steam Generator Tube Rupture Structural Integrity Performance Criterion Steam Line Break Steam Generator Program San Onofre Nuclear Generating Station Stability Ratio Thermal-Hydraulics Total Effective Dose Equivalent Technical Specification Tube Support Plate Page 8

JSOUTHERN CALIFORNIA EDISON 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 SOUTHERN CALIFORNIA EDISON`

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 California Edison Company (SCE) will determine the causes of the tube-to-tube interactions that resulted in steam generator tube 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 operational limits for Unit 2, including plans for a mid-cycle shutdown for further inspections."

CAL ACTION 2: "Prior to 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 operational limits, 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."

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 Support Plate Tubesheet Tube Bundle Cold Leg 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, SOUTHERN CALIFORNIA EDISON' An EDISONJ IWIRNATIO \\.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).

Page 18

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:

(Calculated)

Note 2 Performance Criteria:

Normal Operating Differential Pressure (NODP) Test Pressure = 1850 psig Accident Induced Leakage DP (Main Steam Line Break) Test Pressure = 3200 psig Structural Integrity Limit (3 x NODP) Test Pressure = 5250 psig 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\\

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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.

Page 20

SOUTHERN CALIFORNIA EDISON'

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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 SOUTHERN CALIFORNIA EDISON 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.

Page 22

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

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Page 27

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SOUTHERN CALIFORNIA EDISON An EDISON J\\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

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

1 35-49%

0 0

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.

Page 29

SOUTHERN CALIFORNIA EDISON An EDISON

)V' 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

SOUTHERN CALIFORNIA EDISON ATn FDISO,\\' 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 SOUTHERN CALIFORNIA EDISON 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

OSOUTHERN CALIFORNIA EDISON An EMISON I,\\TER

.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 60-40 E

z 0

20 1 0O 0

180 170 160 150 140 130 120 110 103 90 s0 70 50 Column Number so 4a 30 20 10 0

Page 34

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

~8 100 E,

a z

0 40 20 0 +,

180 170 160 150 140 130 120 110 100 90 80 70 60 Column Number 5

0 40 0

0 10 Page 35

SOUTHERN CALIFORNIA EDISON U EDISN\\ t.T iRN, 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

SOUTHERN CALIFORNIA EDISON' 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,.hX TIOQXAL,' 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 pv 2) 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 u SOUTHERN CALIFORNIA EDISON 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% 1 SONGS 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 indication on tubes which are located in the region where 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 (pv2) 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, r

I

\\

T 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 W 0 0Wclle6

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 35.

t-S COLD LEG IR141C6. 106

RijiC99. SG89HC70l

-R141Z69,9G9LC707 C

475 95 1425 190 2375 285 Straight Leg Height 0 to 311485 MiS e

U-Bend Angle 01 ID0 egdees 265 2375 190 142-5 5

Straight Leg Height 311 485 to 0 inche 475

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 Screening Consecutive Screening Tubes Generator RB

_ I AVB at AVB Bar Criteria AVBs Additions 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 SOUIHERN CALIFORNIA EDISON AnII)ISO\\

\\

I IJ**

IR)N.t i (Compllý SONGS Unit 2 Return to Service Report Figure 8-6: 2E-088 Plugging and Stabilizing Map Unit 2 SG E-088 Plugging/Stabilizing Map 140 120 100 8

o

°0 8

No Plug/Stab 30% < TWD < 35%

TWD => 35%

Preventative Retainer Bar Preventative TTW

Wear at 6 CONT AVBs

WEC Recommended o Single Stabilizer o Split Stabilizer 00 E

Z 0:

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

J SOUTHERN CALIFORNIA EDISON An [,OGSUSON InitfI2NRuTIOrt1o r

CompR SONGS Unit 2 Return to Service Report Figure 8-7: 2E-089 Plugging and Stabilizing Map Unit 2 SG E-089 Plugging/Stabilizing Map 140 120 100 8

~cPO 8

a 00 No Plug/Stab

" TWD => 35%

TTw Preventative Retainer Bar Preventative TTW

Wear at 6 CONT AVBs

" WEC Recommended o Single Stabilizer o Split Stabilizer S.

E~

0 60O 40 20 180 170 160 150 140 130 120 110 100 90 80 70 Column Number 60 50 40 30 20 10 Page 47

SOUTHERN CALIFORNIA EDISON v 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 SOUTHERN CALIFORNIA EDISON" 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

S4SOUITHERN CALIFORNIA EDISON

-n EI)I.',\\

R I\\TI-IOe\\VT-\\ILý Company 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.

11.2 GE Smart Signal TM 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 A

In 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 INTERN T

'A 11 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 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 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

SCE ATTACHMENT 9

50- 361 v SAN ONOFRE NUCLEAR GENERATING STATION, Unit 2 Improved Technical Specifications based on NUREG-1432, "Standard Technical Specifications Combustion Engineering Reactorsn

TABLE OF CONTENTS 1.0 USE AND APPLICATION 1.1-1 1.1 Definitions 1.1-1 1.2 Logical Connectors...................

1.2-1 1.3 Completion Times..

1.3-1 1.4 Frequency..

1.4-1 2.0 SAFETY LIMITS (SLs)..

2.0-1 2.1 SLs 2.0-1 2.2 SL Violations.

2.0-1 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY...

3.0-1 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY........

3.0-4 3.1 REACTIVITY CONTROL SYSTEMS.....

3.1-1 3.1.1 SHUTDOWN MARGIN (SDM)-Tow > 200F.

3.1-1 3.1.2 SHUTDOWN MARGIN (SDM)-Tow < 200-F 3.1-2 3.1.3 Reactivity Balance 3.1-3 3.1.4 Moderator Temperature Coefficient (MTC) 3.1-5 3.1.5 Control Element Assembly (CEA) Alignment 3.1-7 3.1.6 Shutdown Control Element Assembly (CEA) Insertion Limits.

3.1-12 3.1.7 Regulating CEA Insertion Limits...

3.1-14 3.1.8 Part Length Control Element Assembly (CEA)

Insertion Limits 3.1-18 3.1.9 Boration Systems - Operating............

3.1-20 3.1.10 Boration Systems - Shutdown............

3.1-22 3.1.11 Not Used 3.1.12 Special Test Exception (STE) -

Low Power Physics Testing 3.1-24 3.1.13 Special Test Exceptions (STE) -

At Power Physics Testing.3.1-26 3.1.14 Special Test Exceptions (STE) -

Reactivity Coefficient Testing.

3.1-28 3.2 POWER DISTRIBUTION LIMITS...............

3.2-1 3.2.1 Linear Heat Rate (LHR) 3.2-1 3.2.2 Planar Radial Peaking Factors (Fxy) 3.2-3 3.2.3 AZIMUTHAL POWER TILT (Tq) 3.2-5 3.2.4 Departure From Nucleate Boiling Ratio (DNBR)....

3.2-9 3.2.5 AXIAL SHAPE INDEX (ASI) 3.2-12 3.3 INSTRUMENTATION....................

3.3-1 3.3.1 Reactor Protective System (RPS)

Instrumentation-Operating...........

3.3-1 3.3.2 Reactor Protective System (RPS)

Instrumentation-Shutdown 3.3-10 3.3.3 Control Element Assembly Calculators (CEACs)...

3.3-14 3.3.4 Reactor Protective System (RPS) Logic and Trip Initiation 3.3-18 (continued)

SAN ONOFRE--Unit 2 ii Amendment No. 127

TABLE OF CONTENTS 3.3 INSTRUMENTATION (continued) 3.3.5

-Engineered Safety Features Actuation System (ESFAS)

Instrumentation 3.3-22 3.3.6 Engineered Safety Features Actuation System (ESFAS)

Logic and Manual Trip...................

3.3-27 3.3.7 Diesel Generator (DG) -Undervoltage Start 3.3-32 3.3.8 Containment Purge Isolation Signal (CPIS) 3.3-35 3.3.9 Control Room Isolation Signal (CRIS) 3.3-39 3.3.10 Not Used 3.3.11 Post Accident Monitoring Instrumentation (PAMI) 3.3-44 3.3.12 Remote Shutdown System.........................

3.3-48 3.3.13 Source Range Monitoring Channels............

3.3-51 3.4 REACTOR COOLANT SYSTEM (RCS)......

3.4-1 3.4.1 RCS DNB Pressure, Temperature, and Flow Limits......................

3.4-1 3.4.2 RCS Minimum Temperature for Criticality.......

3.4-4 3.4.3 RCS Pressure and Temperature (P/T) Limits 3.4-5 3.4.3.1 Pressurizer Heatup/Cooldown Limits.....

3.4-13 3.4.4 RCS Loops-MODES 1 and 2.....

3.4-15 3.4.5 RCS Loops-MODE 3.......

3.4-16 3.4.6 RCS Loops-MODE 4.......

3.4-18 3.4.7 RCS Loops-MODE 5, Loops Filled..............

3.4-21 3.4.8 RCS Loops-MODE 5, Loops Not Filled...........

3.4-24 3.4.9 Pressurizer 3.4-26 3.4.10 Pressurizer Safety Valves...................

3.4-28 3.4.11 Not Used 3.4.12.1 Low Temperature Overpressure Protection (LTOP)

System, RCS Temperature PTLR Limit 3.4-30 3.4.12.2 Low Temperature Overpressure Protection (LTOP)

System, RCS Temperature > PTLR Limit..........

3.4-35 3.4.13 RCS Operational LEAKAGE 3.4-37 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage........

3.4-39 3.4.15 RCS Leakage Detection Instrumentation.........

3.4-44 3.4.16 RCS Specific Activity..................

3.4-47 3.4.17 RCS Steam Generator (SG)

Tube Integrity..........

3.4-51 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5-1 3.5.1 Safety Injection Tanks (SITs) 3.5-1 3.5.2 ECCS-Operating.......

3.5-4 3.5.3 ECCS-Shutdown.

.3.....

. 3.5-8 3.5.4 Refueling Water Storage Tank (RWST)

. 3.5-9 3.5.5 Trisodium Phosphate (TSP) 3.5-11 (continued)

SAN ONOFRE--Unit 2 iii Amendment No.

204 208

TABLE OF CONTENTS 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6.1 3.6.6.2 3.6.7 3.6.8 3.7 3.7.1 3.7.2 3.7.3 3.7.4 3.7.5 3.7.6 3.7.7 3.7.7.1 3.7.8 3.7.9 3.7.10 3.7.11 3.7.12 3.7.13 3.7.14 3.7.15 3.7.16 3.7.17 3.7.18 3.7.19 3.8 3.8.1 3.8.2 3.8.3 3.8.4 3.8.5 3.8.6 3.8.7 3.8.8 3.8.9 3.8.10 CONTAINMENT SYSTEMS Containment Containment Air Locks Containment Isolation Valves Containment Pressure....

Containment Air Temperature Containment Spray and Cooling Systems Containment Cooling System...

Not Used Containment Dome Air Circulators PLANT SYSTEMS Main Steam Safety Valves (MSSVs).

Main Steam Isolation Valves (MSIVs)

Main Feedwater Isolation Valves (MFIVs)

Atmospheric Dump Valves (ADVs)

Auxiliary Feedwater (AFW) System Condensate Storage Tank (CST T-120 and T-121)

Component Cooling Water (CCW) System Component Cooling Water (CCW)

Safety Related Makeup System Salt Water Cooling (SWC) System.

Not Used Emergency Chilled Water (ECW)

Control Room Emergency Air Cleanup System (CREACUS)

Not Used Not Used Not Used Not Used Fuel Storage Pool Water Level....

Fuel Storage Pool Boron Concentration Spent Fuel Assembly Storage Secondary Specific Activity ELECTRICAL POWER SYSTEMS...

AC Sources - Operati ng AC Sources - Shutdown...

Diesel Fuel Oil, Lube Oil, and Starting Air DC Sources - Operati ng DC Sources - Shutdown Battery Parameters.....

Inverters-Operating...

Inverters - Shutdown Di stri buti on Systems - Operati ng Di st ri but ion Systems - Shutdown.

3.6-1 3.6-1 3.6-3 3.6-8 3.6-16 3.6-17 3.6-18 3.6-21 3.6-25 3.7-1 3.7-1 3.7-5 3.7-7 3.7-9 3.7-11 3.7-16 3.7-18 3.7-19a 3.7-20 3.7-22 3.7-24 3.7-29 3.7-30 3.7-32 3.7-35 3.8-1 3.8-1 3.8-17 3.8-20 3.8-23 3.8-27 3.8-30 3.8-34 3.8-36 3.8-38 3.8-40 (continued)

SAN ONOFRE--Unit 2 iv Amendment No. 218

TABLE OF CONTENTS (continued) 3.9 3.9.1 3.9.2 3.9.3 3.9.4 3.9.5 3.9.6 4.0 4.1 4.2 4.3 REFUELING OPERATIONS..........

Boron Concentration Nuclear Instrumentation Containment Penetrations.....

Shutdown Cooling (SDC) and Coolant Circulation-High Water Level Shutdown Cooling (SDC) and Coolant Circulation-Low Water Level...

Refueling Water Level DESIGN FEATURES Site..

Reactor Core.

Fuel Storage 3.9-1 3.9-1 3.9-2 3.9-4 3.9-6 3.9-8 3.9-10 4.0-1 4.0-1 4.0-1 4.0-4 5.0 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 ADMINISTRATIVE CONTROLS............

Responsibility...............

Organization................

Unit Staff Qualifications.........

Technical Specifications (TS) Bases Control Procedures, Programs, and Manuals.....

Safety Function Determination Program (SFDP)

Reporting Requirements...........

High Radiation Area............

5.0-1 5.0-1 5.0-2

.5.0-5

......5.0-6

.5.0-7 5.0-21

.5.0-23 5.0-30 I

SAN ONOFRE--Unit 2 v

Amendment No. 197

Definitions 1.1 1.0 USE AND APPLICATION 1.1 Definitions

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

The defined terms of this section appear in capitalized type and are applicable throughout these Technical Specifications and Bases.

Term Definition ACTIONS ACTIONS shall be that part of a Specification that prescribes Required Actions to be taken under designated Conditions within specified Completion Times.

AXIAL SHAPE INDEX (ASI)

ASI shall be the power generated in the of the core less the power generated in half of the core, divided by the sum of generated in the lower and upper halves core.

lower half the upper the power of the ASI = lower - upper lower + upper AZIMUTHAL POWER TILT (Tq)

CHANNEL CALIBRATION AZIMUTHAL POWER TILT shall be the power asymmetry between azimuthally symmetric fuel assemblies.

A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass the entire channel, including the required sensor, alarm, display, and trip functions, and shall include the CHANNEL FUNCTIONAL TEST.

Calibration of instrument channels with resistance temperature detector (RTD) or thermocouple sensors may consist of an inplace cross calibration of the sensing elements and normal calibration of the remaining adjustable devices in the channel.

Whenever a sensing element is replaced, the next required inplace cross calibration consists of comparing the other sensing elements with the recently installed sensing element.

(continued)

SAN ONOFRE--UNIT 2 1.1-1 Amendment No. 127

Definitions 1.1 1.1 Definitions CHANNEL CALIBRATION (continued)

CHANNEL CHECK CHANNEL FUNCTIONAL TEST The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is calibrated.

A CHANNEL CHECK shall be the qualitative assessment, by observation, of channel behavior during operation. This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter.

A CHANNEL FUNCTIONAL TEST shall be:

a. Analog channels-the injection of a simulated or actual signal into the channel as close to the sensor as practicable to verify OPERABILITY, including required alarms, interlocks, display and trip functions;

b. Bistable channels (e.g., pressure switches and switch contacts)-the injection of a simulated or actual signal into the channel as close to the sensor as practicable to verify OPERABILITY, including required alarm and trip functions; or

c. Digital computer channels-the use of diagnostic programs to test digital computer hardware and the injection of simulated process data into the channel to verify OPERABILITY, including alarm and trip functions.

The CHANNEL FUNCTIONAL TEST may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is tested.

CORE ALTERATION CORE ALTERATION shall be the movement or manipulation of any fuel, sources, reactivity control components, or other components, excluding control element assemblies (CEAs) withdrawn into the upper guide structure, affecting reactivity, (continued)

SAN ONOFRE--UNIT 2 1.1-2 Amendment No. 127

Definitions 1.1 1.1 Definitions CORE ALTERATION (continued)

CORE OPERATING LIMITS REPORT (COLR)

DOSE EQUIVALENT 1-131 E - AVERAGE DISINTEGRATION ENERGY ENGINEERED SAFETY FEATURE (ESF) RESPONSE TIME within the reactor vessel with the vessel head removed and fuel in the vessel.

Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.

The COLR is the unit specific document that provides cycle specific parameter limits for the current reload cycle. These cycle specific parameter limits shall be determined for each reload cycle in accordance with Specification 5.7.1.5.

Plant operation within these limits is addressed in individual Specifications.

DOSE EQUIVALENT I-131 shall be that concentration of I-131 (microcuries/gram) that alone would produce the same thyroid dose as the quantity and isotopic mixture of 1-131, 1-132, I-133, 1-134, and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in ICRP-30, Supplement to Part 1, pages 192-212, Tables titled, "Committed Dose Equivalent in Target Organs or Tissues per Intake of Unit Activity."

E shall be the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives > 15 minutes, making up at least 95% of the total noniodine activity in the coolant.

The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.).

Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of I

(continued)

SAN ONOFRE--UNIT 2 1.1-3 Amendment No. 188

Definitions 1.1 1.1 Definitions ENGINEERED SAFETY measurement, response time may be verified for FEATURE (ESF)

RESPONSE

selected components provided that the components TIME (Continued) and methodology for verification have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a.

Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) leakoff), that is captured and conducted to collection systems or a sump or collecting tank;

2.

LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCS)

LEAKAGE through a steam generator to the Secondary System (primary to secondary LEAKAGE).

b.

Unidentified LEAKAGE All LEAKAGE that is not identified LEAKAGE.

c.

Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

MODE A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in the reactor vessel.

(continued)

SAN ONOFRE--UNIT 2 1.1-4 Amendment No.

188 204

Definitions 1.1 1.1 Definitions OPERABLE - OPERABILITY PHYSICS TESTS A system, subsystem, train, component, or device shall be OPERABLE when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation.

These tests are:

a.

Described in Chapter 14, Initial Test Program of the SONGS Units 2 and 3 UFSAR;

b.

Authorized under the provisions of 10 CFR 50.59; or

c.

Otherwise approved by the Nuclear Regulatory Commission.

The PTLR is the unit specific document that provides the reactor vessel pressure and temperature limits, including heatup and cooldown rates, for the current reactor vessel fluence period.

These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.7.1.6.

RTP shall be a total reactor core heat transfer rate to the reactor coolant of 3438 MWt.

PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)

RATED THERMAL POWER (RTP)

(continued)

SAN ONOFRE--UNIT 2 1.1-5 Amendment No. 203

Definitions 1.1 1.1 Definitions REACTOR PROTECTIVE SYSTEM (RPS)

RESPONSE

TIME SHUTDOWN MARGIN (SDM)

The RPS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RPS trip setpoint at the channel sensor until electrical power to the CEAs drive mechanism is interrupted.

The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured.

In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC.

SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:

(continued)

SAN ONOFRE--UNIT 2

1. 1-5a Amendment No. 203

Definitions 1.1 1.1 Definitions Shutdown margin (SDM)

(continued)

a. All full length CEAs (shutdown and regulating) are fully inserted except for the single CEA of highest reactivity worth, which is assumed to be fully withdrawn. However, with all CEAs verified fully inserted by two independent means, it is not necessary to account for a stuck CEA in the SDM calculation. With any CEAs not capable of being fully inserted, the reactivity worth of these CEAs must be accounted for in the determination of SDM, and I STAGGERED TEST BASIS THERMAL POWER

b. There is no change in part length CEA position.

A STAGGERED TEST BASIS shall consist of the testing of one of the systems, subsystems, channels, or other designated components during the interval specified by the Surveillance Frequency, so that all systems, subsystems, channels, or other designated components are tested during n Surveillance Frequency intervals, where n is the total number of systems, subsystems, channels, or other designated components in the associated function.

THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

I SAN ONOFRE--UNIT 2 1.1-6 Amendment No. 200

RCS Specific Activity 3.4.16 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.16 RCS Specific Activity LCO 3.4.16 The specific activity of the reactor coolant shall be limited to:

a. DOSE EQUIVALENT I-131 specific activity

1.0 pCi/gm; and

b. Gross specific activity

100/E pCi/gm.

APPLICABILITY:

MODES I and 2, MODE 3 with RCS average temperature (Tas 9) Ž 500°F.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. DOSE EQUIVALENT I-131

- - - - - - NOTE -

> 1.0 pCi/gm.

The provisions of Specification 3.0.4 are not applicable.

A.1 Verify DOSE Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EQUIVALENT 1-131 within the acceptable region of Figure 3.4.16-1.

AND A.2 Restore DOSE 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months EQUIVALENT 1-131 to within limit.

(continued)

SAN ONOFRE--UNIT 2 3.4-47 Amendment No. 127

RCS Specific Activity 3.4.16 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Be in MODE 3 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion TaV9 < 5000F.

Time of Condition A not met.

OR DOSE EQUIVALENT I-131 in the unacceptable region of Figure 3.4.16-1.

C. Gross specific C.1 Perform SR 3.4.16.2.

4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months activity of the reactor coolant not AND within limit.

C.2 Be in MODE 3 with 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months TaVg < 500*F.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.16.1 Verify reactor coolant gross specific 7 days activity < 1O0/E pCi/gm.

(continued)

SAN ONOFRE--UNIT 2 3.4-48 Amendment No. 127

RCS Specific Activity 3.4.16 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 4.

SR 3.4.16.2 NOTE--------------------

Only required to be performed in MODE 1.

Verify reactor coolant DOSE EQUIVALENT I-131 specific activity

< 1.0 pCi/gm.

14 days AND Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after THERMAL POWER change of 2 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period 1

SR 3.4.16.3

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

Not required to be performed until 31 days after a minimum of 2 EFPD and 20 days of MODE 1 operation have elapsed since the reactor was last subcritical for

> 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

Determine E from a sample taken in MODE 1 after a minimum of 2 EFPD and 20 days of MODE I operation have elapsed since the reactor was last subcritical for 2 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

184 days SAN ONOFRE--UNIT 2 3.4-49 Amendment No. 127

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.

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

APPLICABILITY:

MODES 1, 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 satisfying the tube repair criteria and not pl ugged

-j n accordance with the Steam Generator Program.

A.l Verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection.

AND A.2 Plug the affected tube(s) in accordance with the Steam Generator Program.

7 days Prior to entering MODE 4 following the next refueling outage or SG tube inspection H.

Required Action and associated Completion Time of Condition A not met.

OR SG tube integrity not maintained.

B.1 Be in MODE 3.

AND B.2 Be in MODE 5.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 36 hours SAN ONOFRE--UNIT 2 3.4-51 Amendment No. 220

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEI LLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the Steam Generator Program.

In accordance with the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program.

Prior to entering MODE 4 following a SG tube inspection SAN ONOFRE--UNIT 2 3.4-52

. Amendment No. 220

Secondary Specific Activity 3.7.19 3.7 PLANT SYSTEMS 3.7.19 Secondary Specific Activity LCO 3.7.19 APPLICABILITY:

The specific activity of the secondary coolant shall be

0.10 pCi/gm DOSE EQUIVALENT I-131.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Specific activity not A.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months within limit.

AND A.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.19.1 Verify the specific activity of the 31 days secondary coolant is within limit.

SAN ONOFRE--UNIT 2 3.7-35 Amendment No. 127

Procedures, Programs, and Manuals 5.5 5.5 Procedures, Programs, and Manuals (continued) 5.5.2.8 5.5.2.9 5.5.2.10 5.5.2.11 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.

Int~grated leak test requirements for each system at refueling cycle intervals or less.

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.

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.

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 evaluation 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.

SAN ONOFRE--UNIT 2 5.0-13 Amendment No. 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 integrity.

SG tube integrity shall 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 (including startup, operation in the power range, hot standby, and cool down 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.

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.

+48, 204

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.

I.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 shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, 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 d.l, 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 first 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.

Provi sions for monitori ng operationa 1 primary to secondary LEAKAGE.

SAN ONOFRE--UNIT 2 1}.0-15 Amendment No. 220

SCE ATTACHMENT 10

K SOUTHERN CALIFORNIA EDISON An EDISON IV'L,'477IO\\'L Copn(i ny SONGS Unit 2 Return to Service Report ATTACHMENT 6-Appendix D Operational Assessment of Wear Indications In the U-bend Region of San Onofre Unit 2 Replacement Steam Generators

Table of Contents E xe cutiv e S u m m a ry...........................................

............................ 4 1

Intro d u ctio n................................................................

5 2

Overall Analytical Methodology...............................................................................................

6 2.1 Outline of Methodology.....................................................................................................

6 2.2 Thermal-Hydraulic Analysis............................. I...................................................................... 7 2.2.1 M e th o d s..........................................................................................................................

7 2.2.2 Results Summary......................................................................................................

9 2.3 Flow-Induced Vibration Analysis.........................................................................................

10 2.3.1 M e th o d s........................................................................................................................

1 0 2.3.2 FIV Results Summary.................................................................................................

17 2.4 Determination of Tube Support Effectiveness from Eddy Current Data.............

17 2.4.1 Out-of-plane Vibration............................................................................................

17 2.4.2 In-p la ne V ib ratio n.........................................................................................................

19 2.5 Tube W ear Progression....................................................................................................

19 2.5.1 M e th o d s.......................................................................................................................

19 2.5.2 Application to SONGS Steam Generators..............................................................

23 2.5.3 Results Summary..................................................

24 2.5.4 W ear Projection Uncertainty....................................................................................

26 2.6 Evaluation of the Potential for In-Plane Vibration............................................................

27 2.6.1 Methodology Benchmarking Using Unit 3 Findings.................................................

28 3

Operational Assessment........................................................................................................

82 3.1 Tube W ear at AVBs.....................................

......... 82 3.1.1 Structural Limits.......................................................................................................

82 3.1.2 Evaluation Method....................................................................................................

83 3.1.3 Results for Active Tubes.........................................

84 3.1.4 Results for Plugged Tubes....................................................................................

84 3.1.5 Evaluation for 18 Months of Operation....................................................................

85 3.2 Tube-to-Tube W ear in U-bend Free Span........................

................ 85 3.2.1 Eddy Current Inspection Results.............................................................................

85 3.2.2 Flow-Induced Vibration Analysis Results.................................................................

85 3.2.3 Assessment of Tube-to-Tube W ear Mechanism.....................................................

87 3.3 Potential for In-Plane Vibration.....................................................................................

88 3.4 Operational Assessment Conclusion...............................................................................

89 4

R e fe re n c e s..................................................................................................................................

9 6 5

Nomenclature...............................................

......................98 Appendix A.

Tube-to-Tube W ear in Unit 2 U-bend Free Span....................................................

100 Supplier Status Stamp VP 1814-AA086-M0190 Rev 4 ICN/A No:

INo:

cN/

REINDCMN ORENO 80A85REFERENCE DOCUMENT-INFORMATrION ONLY 'EIVIRP IOM MANUAL MFG MAY PROCEED: E-IYES i-NO QN/A STATUS - A status is required for design documents and is optional for reference documents. Drawings are reviewed and approved for arrangements and conformance to specification only. Approval does not relieve the submitter from the responsibility of adequacy and suitability of design, materials, and/or equipment represented.

' 1. APPROVED

2. APPROVED EXCEPT AS NOTED - Make changes and resubmit

[]3. NOT APPROVED - Correct and resubmit for review. NOT for field use, APPROVAL: (PRINT / SIGN / DATE)

, RE:

E. GRIBBLE 10/02/12 FLS:

Other.

SCE DE(123)5 REV. 3 07111

REFERENCE:

S0123-XXIV-37.8.26 SG-SGMP-12-10, Revision 3 Page 2 of 131 1814-AA086-M0190, REV. 4 Page 2 of 131

Executive Summary This report documents the operational assessment (OA) of the tube wear indications in the U-bend region of San Onofre Nuclear Generating Station (SONGS) Unit 2 steam generators (SG) based on inspection results from the 2012 outage (U2C17). This evaluation is a supplement to the OA which uses traditional/probabilistic methods. This evaluation is based on well-established methodology on flow-induced vibration of SG tubes., It utilizes the available test data on in-plane and out-of-plane instability and wear rate resulting from out-of-plane vibration of the tubes against anti-vibration bars (AVB).

Evaluation was performed for three degradation mechanisms: tube wear at AVBs, tube-to-tube wear in the U-bend free span as reported in two tubes in SG 2E089 during U2C17, and the potential for in-plane vibration of the tubes leading to tube-to-tube wear as has been reported in the Unit 3 SGs.

Evaluation of the AVB wear mechanism focused on projecting the flaw depths of AVB wear indications in active tubes (those remaining in service) and in plugged tubes until the next inspection. SCE is planning to perform a Unit 2 mid-cycle inspection, after operating for 150 effective days of operation at 70% power. Since the next inspection is planned to be within five months of operation in Cycle 17, projections were carried out at 70% power for an operating duration of six months allowing additional margin. Projected wear depths in the active tubes are compared against allowable depths to satisfy the SG performance criteria. This comparison confirmed that SG performance criteria will be satisfied during the next operating period. The wear projections of plugged tubes confirmed that severance of such tubes will not occur during the next cycle.

An evaluation of the tube-to-tube wear reported in two tubes in SG 2E089 showed that, most likely, the wear did not result from in-plane vibration of the tubes since all available eddy current data clearly support the analytical results that in-plane vibration could not have occurred in these tubes.

There is evidence of proximity in these tubes from pre-service inspection results. Hence, the tube-to-tube wear is most likely a result of out-of-plane vibration of the two tubes in close proximity to the level of contact during operation (see Appendix A). The evaluation shows that similar conditions are unlikely in other tubes. An evaluation was performed for an undetected flaw that may be left in service, comparable in size to the detected TTW flaws. This evaluation showed that the SG performance criteria will be satisfied during the next cycle.

Eddy current data (lack of wear scar extension beyond the width of.the AVBs in any of the AVB wear indications) clearly suggests that in-plane vibration has not occurred in the Unit 2 SGs during the first operating cycle. The methodology was benchmarked using the Unit 3 results; this indicated that the U-bend free span tube wear in Unit 3 resulted from in-plane vibration of the given tube or in-plane vibration of the neighboring tube with matching wear indication. The active and plugged tubes in the Unit 2 RSGs were evaluated using the same methodology for the potential for in-plane instability. The results show that none of the tubes will be subject to in-plane instability. Therefore, tube-to-tube wear from in-plane vibration will not occur in the next operating cycle and SG performance criteria will be satisfied until the nextinspection.

j This evaluation concludes that, for the assessed degradations, the SG performance criteria will be satisfied during the planned operating period of five months at 70% power. The evaluations also support the satisfaction of the performance criteria for an operating duration of 18 calendar months at 70% power, for these degradation mechanisms.

SG-SGMP-12-10, Revision 3 Page 4 of 131 1814-AA086-M0190, REV. 4 Page 4 of 131

Table 2-7. Summary of ATHOS Results

____________________Suawaer sy of ATH091 Aestfs.l Parinndar________Al 40 Andysh Case Nu~pmbe Raranlar owe 141 1.6 28 3-6 3.6 3-0c 3-d41

ww 11LGo 10,A U-) he 2 W3A)5 U

e 2B 8

IMA

,k-ft7 7l i

. 9 1

.177, F19 -9177 1 - R9 [~ f M -1 7 1-31 11 9 7,7 tu ý iurJ 9NoeAde W.A.

2LDWLU 2LUiWIJ 2EIJDWC 2LUýII 2EUULC L W3I IL 2EMU 2L M a8EIK.

2LYU J

" K; c1 F LggCd Tim,"~'

.3 2-S 101 v1s 101 113

-01 21$

131 2'8 J

Ici raung Con didoman dATHOS 4aloubiod Thmnff al yd rauic C hw ac t orha1 tN39 pjMWI2% jpei3OGp~ti 17r29 MeC 5716.

1042E 11426

'24,8 1214 f

'2*4p 121461 1396

'3 A9 6 P-irmwyFIcrj6Ra* M~nnlr W.779 77,22C 77.?20 77.472 77,075 7tk18

?e 9e 77,81) 77'elo W 77737 77,757 kinuy Pitwr,ar puils UN___

2200 2w0

=2___

moo___

203 220 2200

02__

=20 2i203 vneryI1Net Ieporatuml.If M802 E711.49 57,0113 15M6T e 5535 w0 -I Kc1 57 MI2S 50161 V35.33650765 Fen wer;Stswi Fow rx3:sI'.Vitirf I.M3 It~1f

ý Vf 1

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0 160 04110 04eC c 45 2046 0

§303 0300 wC.Jall I.10!2S 3.28 I6.32

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12. lC8 12.0;9 12-267 12.283 12-3m 12.302

'2.383 12.38 1 12367

'2.384

eximnQjs*y' týSS66 CAM63 3 98 0.26&M 32632-0.36M8 c.3C8 0 3M-7 0.3LFF3 06113 0.6260 MaXkTAM VOW F r c Ion DOMIR CP4 FA.

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12M' 12Uý 1195 UPI' 1).22

' 1, 2 ER*.W vs i 10 ric (I

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tc iat V 'f lI.XU beund mAe ti) ATHOS Ww vU ýIwv.twjvvrkLm~ts4ta~

T r

t~ww SG-SGMP-12-10, Revision 3 Page 37 of 131

3 Operational Assessment The operational assessment is the forward-looking evaluation to assess if the steam generators will meet the structural, operating leakage, and accident condition leakage performance criteria until the next scheduled inspection.

This operational assessment covers three tube degradation mechanisms, namely, tube wear at AVBs, tube-to-tube wear in the U-bend free span, and the potential for in-plane vibration that can lead to tube-to-tube wear as has been observed in the Unit 3 SGs. These mechanisms are covered in the following subsections.

3.1 Tube Wear at AVBs 3.1.1 Structural Limits This operational assessment deals with the tube wear indications reported in the U-bend region of the SONGS Unit 2 SGs. Tube degradation in the U-bend has resulted from wear at the AVB locations and wear from the interaction of two adjacent tubes in the same column. The structural limits for AVB wear are discussed in this sub-section.

Material properties of the tubes in the SONGS Unit 2 and Unit 3 SGs were provided by SCE (Reference 8). The parameters (mean and standard deviation) of the sum of yield and ultimate stress at temperature (6500F) were very close between the Unit 2 and Unit 3 tube populations.

Hence, these parameters were determined for the combined population of both units and used in the current calculation. The mean value Was found to be 116.22 ksi and the standard deviation was 2.42 ksi.

Operating conditions during the next cycle were provided by SCE for both full power and several part power conditions (Reference 9). Although SCE is planning to operate Unit 2 at part power until the next inspection, in the current calculation, the more conservative steam pressure at full power was used to determine the primary-to-secondary pressure differential. The full power steam pressure in the next cycle would be 926 psia. Since the primary side pressure is 2250 psia, the primary-to-secondary pressure differential for full power steam pressure in the next cycle would be 1324 psi.

The AVBs in the SONGS RSGs have a width of 0.59 inch and a thickness 0.114 inch. In the Unit 2 RSGs, the wear indications at the AVBs do not extend beyond the width of the AVBs. Hence, an axial length of 0.6 inch is used as the flaw length in this assessment.

Inspection results based on bobbin probe inspection are used in the current evaluation. For the detection and sizing of tube wear at an AVB location, SCE has applied the inspection technique described by Examination Technique Specification Sheet (ETSS) 96004.1 (Reference 25). It is anticipated that the same technique will be applied at the next inspection of the SGs. The actual-to-reported wear depth correlation, and its uncertainty associated with this ETSS, was used in the current calculation to determine the condition monitoring limits that would be applicable at the next inspection.

Tube wear at AVB locations can be either single-sided wear resulting from the interaction of the tube with an adjacent AVB or double-sided wear resulting from the interaction of the tube with both of the adjacent AVBs at'the given location. A one-sided AVB flaw will become through-wall at a circumferential extent of 56 degrees. The total circumferential extent of a two-sided AVB flaw that becomes through-wall is 112 degrees or less. Since this is below the applicable threshold value of 135 degrees, the axial thinning correlation can be used to evaluate the burst pressure for SG-SGMP-12-10, Revision 3 Page 82 of 131 1814-AA086-M0190, REV. 4 Page 82 of 131

AVB wear indications. For flaws of circumferential extent greater than 135 degrees, the uniform thinning correlation would be applicable. Hence, the structural and condition monitoring limits for such flaws can be calculated based on the correlation for axial thinning provided in the Electric Power Research Institute (EPRI) Flaw Handbook (Reference 26).

The limiting performance criterion for burst is that the tube must meet three times the normal full power pressure differential (3APNop) between the primary side and the secondary side. In the next fuel cycle, assuming full power steam pressure, the 3APNOP will be 3972 psi. The structural limit for axial thinning for a 0.6 inch long flaw is 66% through-wall (TW). Applying the uncertainties for burst relation, material properties, and inspection technique (including eddy current analysis),

the condition monitoring (CM) limit at 95% probability at 50% confidence is calculated as 54% for the bobbin inspection results. The condition monitoring limits as a function of axial length of the flaw are shown in Table 3-1 and are plotted in Figure 3-1. The table and the figure show the CM limit based on bobbin inspection, which is the inspection of record for this degradation mechanism.

As noted above, the CM limit is 54% (maximum) depth from bobbin inspection. The actual maximum depth of such a flaw is expected to be below 60% (at 95% probability). Hence, a flaw of this size will not result in leakage either at normal operating conditions or at limiting accident conditions. Thus an indication satisfying the performance criterion for burst will also satisfy the performance criteria for leakage at normal operating and accident conditions.

3.1.2 Evaluation Method As discussed in more detail in Section 2, the analytical methodology involves projection of the flaw size (depth) of indications reported at the current inspection to the next inspection. This evaluation is performed for the most limiting tubes on an individual basis. ATHOS results provide the thermal-hydraulic boundary conditions -- flow velocity, density, and void fraction along the length of the tube. These are used in the FIV analysis to generate the excitation ratios for out-of-plane and in-plane vibration of the tube for various tube support conditions. The support conditions define whether or not a support location such as an AVB intersection is effective, meaning that the structure provides adequate support with respect to motion of the tube due to vibration. The actual tube support boundary conditions for a tube are deduced from U2C17 inspection results based on the presence or absence of a wear indication at the support location.

Presence of a wear indication suggests the absence of adequate support; and hence, such locations are treated as ineffective support locations for that tube. The absence of a wear indication at a'given structure is generally treated as a supported location. However, there are exceptions to this, such as an AVB location without wear indication nestled between wear indications in adjacent AVB locations in the same tube. In, addition, evaluations have been performed to demonstrate that raising the number of unsupported locations does not significantly affect the projected wear depths at the next inspection (Reference 3).

The vibration analysis results and support conditions are used to make wear projection in the next operating cycle. This calculation is based on empirical test results and involves several input assumptions related to tube-to-AVB gap, wear coefficient for the tube and the AVB, the AVB twist, etc. The expected ranges of these parameters are known from test data and experience.

Wear depth projection is made taking into consideration the inspection results at the current outage (U2C17). After setting the inputs to match the U2C17 inspection results for a given flaw, the wear calculations are extended to determine the projected wear depth at the next inspection.

SG-SGMP-12-10, Revision 3 Page 83 of 131 1814-AA086-M0190, REV. 4 Page 83 of 131

Thus, the depth of an AVB wear indication is projected at the next inspection. In order to meet the performance criteria (operational assessment), the projected wear depth must remain below the condition monitoring limit.

3.1.3 Results for Active Tubes The tubes left in service with the deepest wear indications in the U-bend are shown in Table 3-2.

The fourth column in this table lists the bobbin reported wear depth and the fifth column shows the expected or "true" depth based on the correlation between metallurgical and,NDE wear depth for the inspection technique (Reference 25). Both of these values are in %TW. The penultimate column of the table shows the projected wear depth at six months of operation in the next cycle, without accounting for method uncertainty. As shown in Section 2.5.4, the uncertainty associated with the wear projection method may be expressed using the normalized standard deviation of 0.20 in the estimated growth rate. This uncertainty was applied to the projected wear depth to calculate the wear depth with uncertainty as shown in the last column of Table 3-2.

The deepest AVB indication returned to service in the Unit 2 SGs has a reported wear depth of 28% TW by bobbin probe, in Tubes R119C89 and R121C91 in SG 2E089.

Applying the methodology described in Section 2, these flaws are calculated to grow to a maximum wear depth of 32% at the next planned mid-cycle inspection based on the 70% power operating condition in Cycle 17. The projected flaw depth is well below the condition monitoring limit of 54%

TW. There is considerable margin from the CM limit.' Hence, these tubes are predicted to satisfy the SG performance criteria during the next operating period. The projected flaw depths of all of the remaining flaws in the active tubes are smaller than 30% TW; and hence, they also will satisfy the performance criteria. Operating experience with SGs indicate that wear at indications below the detection threshold or in tubes not exhibiting AVB wear will not develop large AVB wear scars that could threaten tube integrity within a five-month operating period. SCE is planning to perform a Unit 2 mid-cycle inspection after operating for 150 effective days of operation at 70% power.

3.1.4 Results for Plumged Tubes Tube wear projection evaluation was carried out for flaws in the limiting plugged tubes. Stainless steel rope stabilizers were installed in many of the plugged tubes prior to plugging. Testing performed by Mitsubishi Heavy Industries (MHI) indicated that the stabilizers would not improve tube damping in the in-plane mode. Although stabilizers are expected to provide a benefit for the out-of-plane mode of vibration, since the quantification of the impact was not available, no beneficial impact from stabilizers was applied in the current evaluation.

The results of the evaluation for the limiting plugged tubes (tubes with the largest wear indications) are shown in Table 3-3. This table is quite similar to. Table 3-2, including the calculation of projected wear depth with uncertainty. It may be noted that the increase in wear depth during the first 6 months of Cycle 17 is small. The projected maximum wear depth for the AVB wear indications is 39% TW. Unlike the active tubes, the acceptance criteria for plugged tubes are much broader. Plugged tubes do not need to meet the condition '!monitoring limits applicable to active tubes. A conservative criterion for plugged tubes may be that the projected wear depth should remain below 100% through-wall. As can be noted from Table 3-3, none of the indications in the plugged tubes approach the 100% TW depth, the maximum projected wear depth being 39%. Hence, the plugged tubes meet the acceptance criteria for the next operating cycle.

SG-SGMP-12-10, Revision 3 Page 84 of 131 1814-AA086-M0190, REV. 4 Page 84 of 131

3.1.5 Evaluation for 18 Months of Operation The results discussed in Sections 3.1.3 and 3.1.4 were for six months of operation in the next fuel cycle (17). Even though SCE is planning to perform a mid-cycle inspection of the Unit 2 RSGs after five months of operation in the next cycle, the wear projection was carried out for an operating duration of 18 months in the next cycle. The results for both active tubes and plugged tubes are shown in Table 3-4. It may be noted that the maximum projected wear depth with uncertainty for active tubes is 34% TW which is well below the CM limit of 54%. Similarly, the maximum projected wear depth for plugged tubes is 43% TW which is well below the criterion value of 100% TW. These wear depths satisfy the acceptance criteria established in Section 3.1.1. Therefore, it is acceptable to operate the SGs for 18 months in the next cycle with this degradation mechanism (tube wear at AVBs).

3.2 Tube-to-Tube Wear in U-bend Free Span 3.2.1 Eddy Current Inspection Results Free span wear in the U-bend was reported (from +Point inspection) in two tubes during the U2C17 outage. They were in Tubes R111C81 and R113C81 in SG 2E089. These are adjacent tubes in the same column. In both tubes, the wear is located between AVB9 and AVB10 in the cold leg. The matching wear locations confirm that the wear resulted from contact between the two tubes. The wear depths in both tubes were shallow at 14% TW and the axial extents were six inches by eddy current inspection. An ultrasonic inspection (UT) was also performed on these tubes. The UT results indicated flaw depths of 7% TW.

Bobbin inspection identified AVB wear at five locations in Tube R 111 C81 (at AVBs 5, 6, 7, 8, and

10) and at three locations in Tube R113C81 (at AVBs 5, 6, and 7). Subsequent review of +Point data at all AVB intersections in these tubes confirmed the bobbin reported indications and in addition revealed low level wear indications from AVB4 through AVB10. There were no low level wear indications at the other AVBs. Therefore, both of these tubes had ineffective support at seven continuous AVB locations from AVB4 through AVB10.

None of the AVB wear scars extended beyond the width of the AVBs. In-plane motion of a tube against an AVB results in the wear scar. extending beyond the width of the AVB (this was observed extensively in the Unit 3 RSGs). Since the AVB wear scars on two of the Unit 2 tubes with TTW were contained within the width of the AVBs, it indicates that the tube motion was not in-plane in either tube. This observation and conclusion were true for not only these two tubes but all tubes in the Unit 2 SGs. Thus the eddy current inspection data suggests that the AVB wear indications in Unit 2 did not result from in-plane vibration of the tubes.

A reanalysis of the pre-service inspection (PSI) data performed by Westinghouse in 2012 revealed proximity signals in these two tubes suggesting that the tubes were close to one another during the PSI. The PSI inspection was performed with the SGs in horizontal condition. No proximity signal was reported during the U2C17 inspection.

3.2.2 Flow-Induced Vibration Analysis Results The flow-induced vibration analysis was performed considering many postulated boundary conditions regarding how AVBs can support the SG tubes in SONGS Unit 2. A detailed discussion of the FIV analysis is provided in Section 2.3. For the two tubes with free span wear, as discussed above, there are seven continuous ineffective AVB support locations (from 4 SG-SGMP-12-10, Revision 3 Page 85 of 131 1814-AA086-M0190, REV. 4 Page 85 of 131

through 10). The support conditions for these two tubes, derived from the eddy current inspection results, are depicted in the following chart.

SG Row Col 07C B12 Bl1 B1O FSc B09 B08 B07 806 BO5 804 FI 803 802 B01 07H SG99 113 81 X

14 X

X 5

5 16 X

SG89 111 81 7

14 X

18 13 8

141 X

X - Low level wear observed on +pt data from WEC review This condition is covered by Case 61 (see Table 2-8). The out-of-plane excitation ratio (ER) for this case at 100% power is 2.12 showing that these tubes were unstable in the out-of-plane mode during Cycle 16. The ER for other FASTVIB cases with different numbers of ineffective AVB support locations is shown in the following table. As a point of clarification, no benefit from stabilization was included in the calculation of the results shown in the last two columns.

Out-of-Plane Excitation Ratio Case Number of 100% Power 80% Power 70% Power Number Ineffective AVBs Excitation Ratio Excitation Ratio Excitation Ratio 38 4

0.99 0.75 0.69 55 6

1.60 1.40 1.35 61 7

2.12 1.83 1.77 67 8

2.72 2.41 2.32 71 9

3.88 3.27 3.15 The in-plane stability ratio (IPSR) for Case 61 is 0.72 at 100% power in Cycle 16. The value of less than 1 indicates that the tubes were stable against in-plane vibration. The following table shows the IPSR for other support conditions and power levels. No benefit from stabilization was included in the calculation. It may be noted that these tubes will be stable in-plane at full power even with eight ineffective AVB supports. The IPSR calculation is based on a value of 7.8 for the instability constant (03). This is considered to be conservative in that the value of 03 is expected to be higher such that the true IPSR values may indeed be lower since the higher the value of 03, the smaller the stability ratio.

In-Plane Stability Ratio Case Number of 100% Power 80% Power 70% Power Number Ineffective AVBs Stability Ratio Stability Ratio Stability Ratio 38 4

0.33 0.16 0.20 55 6

0.53 0.39 0.35 61 7

0.72 0.52 0.47 67 8

0.81 0.60 0.54 71 9

1.15 0.83

< 0.83 SG-SGMP-12-10, Revision 3 Page 86 of 131 1814-AA086-MO190, REV. 4 Page 86 of 131

Thus, the vibration analysis indicates that the two tubes with free span wear were stable against in-plane vibration during Cycle -16. This further corroborates the evidence from eddy current test data showing no evidence of in-plane vibration in these tubes.

This paragraph provides a plausible explanation about how the tube-to-tube contact and wear may. have occurred in the two tubes. The PSI data showing proximity of these tubes offers an insight. When one considers the proximity of the tubes and the fact that the tubes were vibrating out-of-plane, one can draw the conclusion that it is this combination that led to tube-to-tube wear in these tubes. The explanation is that the tubes were in contact as a result of tube expansion from heat up and pressurization during plant operation and that as a result of the out-of-plane vibration of these tubes due to fluidelastic excitation and turbulence, the free span wear occurred with the tubes fretting against each other at the contact location. Appendix A provides additional information that supports this plausible explanation.

3.2.3. Assessment of Tube-to-Tube Wear Mechanism As discussed in the previous paragraphs, all available data suggest that the tube-to-tube wear in the U-bend free span did not result from in-plane vibration of the tubes. There is strong indication that it resulted from out-of-plane vibration of the two tubes in close proximity to the level of actual contact during operation.

It is expected that if the two tubes continue to wear, they may lose close proximity (i.e., contact during plant operation). It is not clear whether the loss of contact has already occurred or how much longer they will maintain contact and wear against each other. When loss of contact occurs, the wear arrest will result. The two tubes have been stabilized and plugged. The stabilizer will reduce the potential for, and the severity of, out-of-plane vibration. Stabilization will also tend to reduce the wear rate, if they remain in contact. Since the tubes are plugged, they can neither burst nor lead to primary-to-secondary leakage and hence, cannot challenge SG performance criteria.

Tube-to-tube wear in the free span was reported only in the two tubes. It is understandable that this-is the case since close proximity of the tubes to the level of contact during operation as well as out-of-plane vibration of the tubes is required for this wear mechanism to occur. If there are other tubes with. similar conditions, they would have exhibited tube-to-tube wear. If indeed there are a few other tubes with similar conditions, the lack of reported wear suggests that the wear progression has remained below the detection threshold. Hence, wear rates in such potential cases were even smaller. SCE is planning to perform a Unit 2 mid-cycle inspection after operating for 150 effective days of operation at 70% power. Since the reported free span wear was 14% by eddy current inspection and 7% by UT inspection after one full cycle of operation, a lower wear rate for only five months of operation at reduced power will result in only very small wear depths until the next inspection. As discussed in the last paragraph, when the wear depth increases, the tubes will lose contact and the wear will arrest itself.

Thus, it is extremely unlikely that other tubes in these SGs will exhibit free span wear similar to those reported in two tubes during U2C17. If there are a few remaining tubes with similar conditions, the wear rates and wear depths in such tubes will be even smaller than in the reported cases. An evaluation was conducted as described below.

An evaluation was carried out for a hypothetical undetected flaw left in service. The evaluation projected its size at the next inspection and compared it to the condition monitoring (allowable) limit for burst. The size of the undetected flaw at the beginning of cycle (BOC) was assumed to be the same as the size of the detected TTW flaws in SG 2E089. These flaws had a depth of 14% TW and an axial length, of 6 inches (Reference 27) from +Point inspection using SG-SGMP-12-10, Revision 3 Page 87 of 131 1814-AA086-M0190, REV. 4 Page 87 of 131

ETSS 27902.2.

These dimensions were conservatively used as the BOC conditions for the undetected flaw. The growth rate of these TTW flaws were calculated based on the operating length of 22 calendar months for Cycle 16. Using a conservative 6-month operation until the next inspection, a depth growth of 14% times 6/22 or 4% TWwas calculated. Similarly, a growth value of 6 inches times 6/22 or 2 inches was calculated fo r axial length. These values were rounded up, conservatively. Please note that the next cycle of operation will be at 70% power; however, no credit was taken for the potentially lower growth rate resulting from the reduction in power level. The size of the undetected flaw at the next inspection was determined by adding the growth values to the BOC conditions.

This yielded the projected flaw size as 18% TW and 8 inches in axial length.

The allowable depth for an, 8-inch long flaw was determined based on the 3APNoP value of 3972 psi (see Section 3.1.1). The EPRI Flaw Handbook (Reference 26) methodology for axial thinning was used in conjunction with the material properties of tubes in the SONGS RSGs and the NDE uncertainties for the ETSS 27902.2 (Reference 28).

The calculation yielded an allowable limit of 48% TW.

Since the projected wear depth of 18% TW is lower than the allowable limit, the burst performance criterion will be satisfied. The projected flaw depth is far below 100% TW and hence, no leakage will occur either during normal operation or during a postulated accident condition.

1ý The evaluation was extended for an operating length of 18 months in Cycle 17. The projected dimensions of the undetected flaw for this operating length are 26% TW and 11 inch axial length.

The condition monitoring limit for an 11 inch long flaw is 48% TW. Since the projected flaw depth is less than the allowable limit, and well below 100% TW, the burst and leakage criteria will be satisfied for an operating length of 18 months as well.

Therefore, the SG performance criteria will be satisfied for this degradation mechanism until the next inspection.

3.3 Potential for In-Plane Vibration As discussed in Section 3.2, all available information indicates that in-plane vibration has not occurred in the Unit 2 SGs during their first cycle of operation. This section addresses the potential for in-plane vibration to occur during operation until the next inspection. Figure 3-2 shows a simplified diagram of the operational assessment methodology for this degradation mechanism.

Justification for the use of eddy current data to determine the support conditions in the U-bend is discussed in Section 2.4. It was also shown that an effective support at an AVB location will remain effective for several fuel cycles because the tube wear rate from out-of-plane vibration at such an AVB location will be negligible. Section 2.4.2 also shows that a contact force is not required to prevent in-plane vibration, but a small; AVB gap is sufficient to provide effective support. Benchmarking of the methodology against Unit 3 findings is discussed in Section 2.6.1.

By applying the methodology, it showed that the TTW indications in Unit 3 resulted from in-plane vibration of the given tube or from in-plane vibration of the neighboring tube. The same methodology was applied to the evaluation of Unit 2 RSGs.

All tubes in the Unit 2 SGs that will be returned to service were evaluated for the potential for in-plane vibration to occur in the next cycle. This flow-induced vibration evaluation was discussed in Section 2.6. It showed that there are no tubes in the Unit 2 SGs that are likely to become unstable in the in-plane vibration mode during the upcoming operating cycle. This is not surprising because the operation in the first cycle was at full power when no tubes were subjected to in-plane vibration. The next cycle of operation will be at 70% power. The vibration potential in the U-SG-SGMP-12-10, Revision 3 Page 88 of 131 1814-AA086-M0190, REV. 4 Page 88 of 131

bend decreases significantly as the power is reduced. Since the tubes were stable in-plane at 100% power, they will be stable in-plane at 70% power with additional margin. Evaluation of the most limiting tubes in the Unit 2 RSGs was discussed in Section 2.6. The results for the limiting tubes are shown in Table 2-10. Please note that all of these limiting tubes have already been stabilized and plugged, most of them preventively. The evaluation showed that the in-plane stability ratios of all tubes in Unit 2 are less than 1 at 70% power. Hence, in-plane vibration will not occur in the Unit 2 SGs during the upcoming operating cycle at power levels up to 70%.

Since all active tubes will be stable against in-plane vibration in the next cycle, tube-to-tube wear due to in-plane vibration in the U-bend free span, as has been observed in Unit 3, will not occur in Unit 2 during the next cycle of operation. SG performance criteria will be satisfied for this degradation mechanism until the next inspection.

3.4 Operational Assessment Conclusion Three degradation mechanisms were evaluated as described in the prior subsections. They are tube wear at AVBs, tube-to-tube wear in the U-bend free span observed in two tubes in the Unit 2 SGs during the current refueling outage, and the potential for in-plane vibration that can lead to tube-to-tube wear in the U-bend free span as has been reported in the Unit 3 SGs. SCE is planning. to perform a Unit 2 mid-cycle inspection after operating for 150 effective days of operation at 70% power. The operational assessment was performed in conformance with the EPRI Guidelines. It clearly demonstrates that for a 5-month operating period at 70% power the SGs will meet the performance criteria established in the Steam Generator Program Guidelines, NEI 97-06 (Reference 1), for both burst strength and for primary-to-secondary leakage during normal operation and accident conditions.

The evaluations also show that, for these degradation mechanisms, the SG performance criteria will be satisfied for the duration of 18 months and hence, it is acceptable to operate the Unit 2 SGs for a period of 18 months in the next fuel cycle at 70% power.

SG-SGMP-12-10, Revision 3 Page 89 of 131 1814-AA086-M0190, REV. 4 Page 89 of 131

Table 3-1. Condition Monitoring Limit for Axial Thinning Axial Thinning Length (inch)

CM Limit Depth (Bobbin: ETSS 96004.1) 0.3

.62.6%

0.4 58.5%

0.5 56.1%

0.6 54.5%

0.7 53.5%

0.8 52.6%

0.9

.51.9%

1 51.3%

1.125 50.8%.

1.2 50.5%

1.5 49.7%

2 48.9%

2.5 48.5%

3 48.2%

SG-SGMP-12-10, Revision 3 Page 90 of 131 1814-AA086-M0190, REV. 4 Page 90 of 131

Table 3-2. Wear Projection Results for Active Tubes with Limiting AVB Wear Indications Max Wear Depth, %

Max Depth @ at 70% Power After 6 Months Tube SG Tube ECT Expected FASTVIB No Seq Without With No Status Reported Value Case AVBs Uncertainty Uncertainty R97C87 88 Active 25 27.4 38 4

27.4 27.4 R119C89 89 Active 28 30.3 46 5

31.2 31.5 R121C91 89 Active 28 30.3 37 4

31.0 31.2 R131C91 89 Active 21 23.5 17 2

23.5 23.5 R129C93 89 Active 22 24.5 47

5 25.8 26.2 R126C90 89 Active 21 23.5 45 5

24.0 24.2

Baseline Case 29 being stable, Case 47 was used for wear projection SG-SGMP-12-10, Revision 3 Page 91 of 131 1814-AA086-M0190, REV. 4 Page 91 of 131

Table 3-3. Wear Projection Results for Plugged Tubes with Limiting AVB Wear Indications Max Wear Depth, %

Max Depth @ at 70% Power After 6 Months Tube SG Tube ECT Expected FASTVIB No Seq Without With No Status Reported Value Case AVBs Uncertainty Uncertainty R112C88 88 Plugged 35 37.2 47 5

37.9 38.1 R133C91 88 Plugged 35 37.2 38 4

38.1 38.4 R114C90 88 Plugged 22 24.5 48 5

25.4 25.7 RI11C91 88 Plugged 26 28.4 38 4

28.4 28.4 R116C86 88 Plugged 29 31.3 46 5

32.4 32.8 R117C93 88 Plugged 27 29.4 47 5

30.4 30.7 R115C85 88 Plugged 27 29.4 48 5

30.6 31.0 R114C86 88 Plugged 21 23.5 53 6

24.5 24.8 R112C88 88 Plugged 35 37.2 55 6

38.5 38.9 R128C94 88 Plugged 32 34.3 60 7

35.7 36.2 R120C92 88 Plugged 32 34.3 66 8

36.2 36.8 R121C83 89 Plugged 24 26.4 16 2

26.4 26.4 R117C89 89 Plugged 26 28.4 46 5

29.2 29.5 R108C90 89 Plugged 27 29.4 53 6

30.7 31.1 R117C81 89 Plugged 29 31.3 55 6

32.7 33.2 R134C90 89 Plugged 26 28.4 56 6

30.6 31.3 R114C88 89 Plugged 24 26.4 56 6

28.9 29.7 R117C85 89 Plugged 24 26.4 62 7

28.1 28.7 R122C82 89 Plugged 27 29.4 66 8

31.0 31.5 R112C84 89 Plugged 27 29.4 67 8

31.2 31.8 R111C81 89 Plugged 18 20.5 38 4

20.6 20.6 SG-SGMP-12-10, Revision 3 Page 92 of 131 1814-AA086-M0190, REV. 4 Page 92 of 131

Table 3-4. Wear Projection Results for Limiting AVB Wear Indications for 18 Months of Operation Max Wear Depth, % Max Depth @ at 70% Power After 18 Months Tube SG Tube ECT Expected FASTVIB No Seq Without With No Status Reported Value Case AVBs Uncertainty Uncertainty R97C87 88 Active 25 27.4 38 4

27.4 27.4 R119C89 89 Active 28 30.3 46 5

32.8 33.6 R121C91 89 Active 28 30.3 37 4

32.0 32.5 R131C91 89 Active 21 23.5 17 2

23.5 23.5 R129C93 89 Active 22 24.5 47*

5 28.0 29.2 R126C90 89 Active 21 23.5 45 5

24.9 25.4 R112C88 88 Plugged 35 37.2 47 5

38.5 38.9 R133C91 88 Plugged 35 37.2 38 4

39.8 40.7 R114C90 88 Plugged 22 24.5 48 5

27.2 28.1 R111C91 88 Plugged 26 28.4 38 4

28.4 28.4 R116C86 88 Plugged 29 31.3 46 5

34.7 35.8 R117C93 88 Plugged 27 29.4 47 5

32.4 33.4 R115C85 88 Plugged 27 29.4 48 5

32.8 33.9 R114C86 88 Plugged 21 23.5 53 6

26.3 27.2 R112C88 88 Plugged 35 37.2 55 6

41.5 42.9 R128C94 88 Plugged 32 34.3 60 7

39.0 40.6 R120C92 88 Plugged 32 34.3 66 8

39.5 41.2 R121C83 89 Plugged 24 26.4 16 2

26.4 26.4 R117C89 89 Plugged 26 28.4 46 5

30.7 31.5 R108C90 89 Plugged 27 29.4 53 6

33.2 34.5 R117C81 89 Plugged 29 31.3 55 6

35.2 36.5 R134C90 89 Plugged 26 28.4 56 6

34.4 36.4 R114C88 89 Plugged 24 26.4 56 6

33.2 35.4 R117C85 89 Plugged 24 26.4 62 7

31.0 32.5 R122C82 89 Plugged 27 29.4 66 8

33.8 35.3 R112C84 89 Plugged 27 29.4 67 8

34.4 36.1 R111C81 89 Plugged 18 20.5 38 4

20.6 20.6 Baseline Case 29 being stable, Case 47 was used for wear projection SG-SGMP-12-10, Revision 3 Page 93 of 131 1814-AA086-MO190, REV. 4 Page 93 of 131

Condition Monitoring Limitfor Volumetric Indications -Axial Thinning 70%

60%

50%

40%

C.

0 c 30%

20%

10%

0%

FLAW DIMENSIONS PLACING THE FLAW BELOW THE CM LIMIT CURVE SATISFY CM 0

0.5 I

1.5 Axial Length, inch 2

2.5 3

1 CM Limit Depth (Bobbin ETSS 96004.1)

I Figure 3-1. Condition Monitoring Limit for Axial Thinning SG-SGMP-12-10, Revision 3 Page 94 of 131 1814-AA086-MO190, REV. 4 Page 94 of 131

-Yes-OA successful In concept, this analysis is repeated for every tube; in practice, for every limiting tube Figure 3-2. Operational Assessment Methodology for the Potential for In-Plane Vibration SG-SGMP-12-10, Revision 3 Page 95 of 131 1814-AA086-MO190, REV. 4 Page 95 of 131

SCE ATTACHMENT 11

SOUTHERN CALIFORNIA EDISON0 An EDISO.N I*T'ERis "1I'JO:\\1 L Compainy SONGS Unit 2 Return to Service Report ATTACHMENT 6-Appendix C Operational Assessment for SONGS Unit 2 SG for Upper Bundle Tube-to-Tube Wear Degradation at End of Cycle 16

Controlled Document TABLE OF CONTENTS Section Page Executive Summary....

iv 1

Introduction 1-1 2

Structural Requirements..................................................................................................

2-1 2.1 B ackground......................................................................................................

2-1 2.2 Structural and Leakage Integrity..................................

2-1 2.3 T ube B urst M odel.............................................................................................

.. 2-3 2A Leak R ate C alculation..............................................

............................................ :.2-3 3

Probabilistic Analysis,......................................................................................................

3-1 3.1 A ssessm ent O verview.................................................................................

............ 3-1 3.2 A nalysis A ssum ptions..............................................................................................

3-2 3.3 State of Degradation - Wear Index..........................................................................

3-3 3.4 Probabilistic Model..........................................

.............. 3-5 3.5 Verification and Validation...............................................

.................................. 3-6 4

Analysis Input Parameters................................................................................................

4-1 4.1 Tubing Properties...................................................

4-1 4.2 O perating P aram eters..............................................................................................

4-2 4.3 Degradation Characterization...................................................................................

4-2 4.4 P robability of D etection..........................................

.................................................. 4-4 4.4.1 Inspected P opulation....................................................................................

4-4 4.4.2 Undetected Population.................................................................................

4-5 4.5 Tube-to-Tube Wear Initiation....................................

4-6 4.6 Degradation Growth Rates.....................................................................................

4-10 4.6.1 -AVB and TSP Growth Models....................................................................

4-10 4.6.2 TTW Growth Model.........................................

4-11 4.7 Effect of Power Reduction......................................................................................

4-12 4.8 Measurement Uncertainty.....................................................................................

4-13 5

Operational Assessment...................................................................................................

5-1 5.1 A na lysis C a se s........... :.............................................................................................

5-1 5.2 S im ulatio n R e su lts....................................................................................................

5-1 5.3 Structural Margin Evaluation....................................................................................

5-2 5.4 Leakage E valuation.......................................

I........................................................... 5-3 6

Summary of Results........................................................................................................

6-1 R eferences R -1 Appendix A - Report Acronyms.....................................................................................

A-1 Intertek APTECH AREVA NP, Inc.

AES 12068150-2Q-1 September 2012 iii Page 5 of 66 1814-AU651-M0145, Rev. 1

Controlled Document EXECUTIVE

SUMMARY

The San Onofre Unit 2 (U2) plant has two new steam generators that replaced the original CE-70 design. The replacement steam generators are MHI Model 116TT1 and began operation in Year 2010. The generators have completed one cycle of operation (Cycle 16) with duration of 1.718 years at power (20.6 months). In the first cycle of operation, the U2 tubing has experienced substantial wear degradation at points of contact with anti-vibration bar (AVB) U-bend supports. There were 4348 indications detected at AVB contact points with a maximum NDE depth of 35%TW during the end-of-cycle (EOC) 16 tube examinations. To a much lesser extent, wear at tube support plates (TSP) was also detected (364 indications) with a maximum NDE depth of 20%TW.

While U2 was in refueling, San Onofre Unit 3 (U3) had a forced outage due to a leak in one of the steam generators after 338 days (0.926 years at power or 11.1 months). The leak was due to tube-to-tube wear (TTW) at freespan locations within the U-bend region. Tube-to-tube wear in U3 was caused by in-plane motion of tubes within a defined region of the bundle. The in-plane motion was due to conditions that created fluid-elastic instability (FEI) of one or more tubes. Subsequent examination of U2 steam generators specifically looking for TTW revealed two indications in 2SG89. Because of the generic designs of both units, and the nature of the FEI, the possibility of having further initiation and progression of TTW in U2 must be addressed in this OA.

This report describes the OA performed for the limiting steam generator (2SG89) in U2 for a simulated population of TTW degradation indications. The OA is a forward-looking process and provides an estimate of the operational period for which the steam generators will maintain tube integrity for both burst strength and through-wall leakage to meet industry margin requirements (Ref. 1). The U2 0Afor TTW degradation was performed in a "traditional" manner following established industry assessment guidelines. It is traditional in that the general assessment process follows industry practices for applying current and past NDE inspection data to predict tube integrity at the next inspection. This is performed through empirical models for degradation growth and in combination with engineering models for determining burst pressure and through-Intertek APTECH AREVA NP, Inc.

AES 12068150-2Q-1 September 2012 iv Page 6 of 66 1814-AU651-M0145, Rev. 1

wall leak rates (Ref. 2). The non-traditional aspect of the OA model is the use of pattern recognition based models to characterize the presence and severity of TTW indications based on wear indices defined by the state of AVB and TSP wear for a specific tube. The U3 inspection data from the critical wear area were used to develop predictive models for TTW initiation and growth. The "wear index" defining the state of wear at tube supports in both U2 and U3 steam generators is the method by which initiation and growth of TTW observed at U3 are correlated to U2.

A fully probabilistic model representing the high-wear region of the tube bundle was used to evaluate TTW for Cycle 17. Calculated tube burst and leakage probabilities were obtained by Monte Carlo simulation for initiation and growth of TTW. The results for burst and leakage were compared with the structural and leakage performance margin requirements of NEI 97-06 (Ref. 1). The performance standards for assessing tube integrity to the required margins are delineated in the EPRI Integrity Assessment Guidelines (Ref. 2). This assessment established the probability of burst for the worst-case tube due to TTW predicted for the defined high-wear region.

The U3 wear behavior was used to establish the initiation and growth of TTW indications in U2 steam generators. An empirical correlation based on a wear index parameter (measure of the state of wear degradation in each tube) provided the method for scaling the U3 wear behavior to U2. Two OA analysis cases were evaluated based on the sizing techniques used to define the U3 TTW depths. Case 1 evaluated the situation where voltage based sizing for Eddy Current Testing Examination Sheet ETSS 27902.2 was used to establish the TTW depth distributions and the correlated wear rate with wear index. The results for Case 1 indicate that the SIPC margin requirements are satisfied for a Cycle 17 length of 1.33 years at 70% power level. For Case 2, where the TTW depths were resized by AREVA using a more realistic calibration standard, the SIPC margins will be met for a cycle length of 1.48 years at 70% power level. The plan for U2 is to operate for a short run (about 5 months) at a 70% reduced power level to provide additional margins to the industry requirements for tube integrity.

Tube burst at 3xNOPD is the limiting requirement for cycle length. Therefore, the accident-induced leakage requirements will be satisfied provided that burst margins at 3xNOPD are maintained during the operating cycle.

Intertek APTECH AREVA NP, Inc.

AES 12068150-2Q-1 September 2012 V

Page 7 of 66 1814-AU651-M0145, Rev. 1

Controlled Document Section 2 STRUCTURAL REQUIREMENTS

2.1 BACKGROUND

In 2006, SONGS adopted the NEI 97-06 "Steam Generator Program Guidelines" (Ref. 1),

through a change to the plant Technical Specification, Section 5.5.2.11 Steam Generator Program. The program guidelines specify both condition monitoring (CM) and operational assessment (OA) as a means to manage tube degradation. The preparation of a CM evaluation is a vital element of the NEI guidance and requirements. Condition monitoring provides a comparison between the as-found condition of the steam generators and performance criteria established in Ref. 2. The evaluation of NDE results determines the state of the steam generator tubing for the most recent period of operation relative to structural and leakage integrity performance criteria.

The CM results for U2 at EOC 16 were acceptable for all detected degradation mechanisms including TTW (Ref. 3).

Operational Assessment involves projecting the condition of the steam generator tubes to the time of the next scheduled inspection outage and determining their acceptability relative to the tube integrity performance criteria. All detected degradation mechanisms shall be evaluated, including secondary side inspection results. This OA addresses the TTW degradation mechanism. The required margins for an acceptable OA are discussed in Section 2.2.

2.2 STRUCTURAL AND LEAKAGE INTEGRITY The structural integrity performance criteria (SIPC) and accident-induced leakage performance criteria (AILPC) applicable to any degradation mechanism including TTW are as follows (Ref. 1):

Intertek APTECH AREVA NP, Inc.

AES 12068150-2Q-1 September 2012 2-1 Page 11 of 66 1814-AU651-M0145, Rev. 1

Structural Integrity -

"All in-service 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 cool down 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 -

"The primary to secondary accident leakage rate for the limiting design basis accident shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all steam generators and leakage rates for an individual steam generator."

For SONGS, the accident-induced leak rate is 0.5 gallons per minute (gpm) per generator cumulative for all degradation mechanisms.

The acceptance performance standard for structural integrity is (Ref. 2):

The worst-case degraded tube shall meet the SIPC margin requirements with at least a probability of 0.95 at 50% confidence.

The worst-case degraded tube is established from the estimation of lower extreme values of structural performance parameters (e.g., burst pressure) representative of all degraded tubes in the bundle for a specific degradation mechanism.

Intertek APTECH AREVA NP, Inc.

AES 12068150-2Q-1 September 2012 2-2 Page 12 of 66 1814-AU651-M0145, Rev. 1

The acceptance performance standard for accident leakage integrity is (Ref. 2):

The probability for satisfying the limit requirements of the AILPC shall be at least 0.95 at 50% confidence.

The analysis technique for assessing the above conditions for TTW is a fully probabilistic assessment of all tubes in the at-risk region of the U2 steam generators.

2.3 TUBE BURST MODEL Tube-to-tube wear indications involve axial volumetric degradation with limited circumferential extent as shown in Figure 2-1. Given the structurally significant length and depth dimensions, the burst pressure for TTW is computed from the burst relationship for axial wear given in Ref. 4:

Pb = 0.58(Sy +Su)(t/Ri) 1L+2t)1+ 291 psi+ZGB (2-1) where Pb is the estimated burst pressure, Sy is the yield strength, Su is the tensile strength, t is the wall thickness, Ri is the tube inner radius, L is the characteristic degradation length, d is the characteristic wear depth, and d/t is the fractional normalized depth. Relational uncertainty in Eq. 2-1 is represented by the standard normal deviate, Z, (-00 < Z <cc), and TB, the standard error of regression (aB = 282 psi). The burst equation, when used with the structural significant dimensions (LST and dsT), produces consistently conservative burst pressure estimates compared with tube burst data.

2.4 LEAK RATE CALCULATION Leakage predictions for wear-related degradation are subject to large uncertainties. Wear profiles at incipient leakage can vary significantly from simple slits to large holes caused by the blowout of thin membranes. For these situations, absolute leakage rates are not generally Intertek APTECH AREVA NP, Inc.

AES 12068150-2Q-1 September 2012 2-3 Page 13 of 66 1814-AU651-M0145, Rev. 1

Controlled Document computed. Rather, the probability of though-wall penetration is established from projected maximum depths and ligament rupture calculations. A ligament rupture is where the indication pops-through the remaining wall without causing tube burst. For TTW, leakage at limiting accident conditions (i.e., main steam line break) will not be controlling on cycle length. The requirements for burst at SIPC will be set by the distribution of maximum depths being significantly smaller than those necessary to produce ligament rupture (pop-through) events under accident pressures.

Intertek APTECH AES 12068150-2Q-1 AREVA NP, Inc.

September 2012 2-4 Page 14 of 66 1814-AU651-M0145, Rev. 1

/

~

-f--

Figure 2 Idealized Wear Profile for Volumetric Degradation with Limited Circumferential Extent (Ref. 4)

Intertek APTECH AES 12068150-2Q-1 AREVA NP, Inc.

September 2012 2-5 Page 15 of 66 1814-AU651-M0145, Rev. 1

v t e Letter Sequence Other
TAC:MD9160, (Approved, Closed) TAC:MD9161, Steam Generator Tube Integrity (Approved, Closed)
Initiation Request, Request, Request Acceptance... Administration Questions 4 November 2008 8 December 2008 26 February 2009 Answers 5 February 2009 Results Approval, Approval Other: ML082250168, ML13030A456
MONTHYEAR2008-08-13 [Table View]

ML13030A456

Text

SUBJECT:

Dear Mr. Ridenoure:

Enclosures:

Subject:

Dear Mr. Collins:

2.0 INTRODUCTION

SUMMARY

SUMMARY

SUMMARY

2.0 INTRODUCTION

3.0 BACKGROUND

12.0 CONCLUSION

13.0 REFERENCES

RESPONSE

RESPONSE

REFERENCE:

SUMMARY

2.1 BACKGROUND

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