ML20248B898

Updated SG Run Time Analysis Cycle 9

ML20248B898
Person / Time
Site:	San Onofre
Issue date:	05/26/1998
From:	SOUTHERN CALIFORNIA EDISON CO.
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ML20248B896	List: ML20248B892 ML20248B898 ML20248B922
References
NUDOCS 9806020015
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SOUTHERN CAllFORNIA EDISON COMPANY SAN ONOFRE UNIT 2 UPDATED STEAM GENERATOR RUN TIME ANALYSIS CYCLE 9 i

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TABLE OF CONTENTS Table of C ontents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. Page1 1.0 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . .. Page 2 .

2.0 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 3 -

Table 1_- SONGS Unit 2 '- Tubes Plugged Mid-Cycle 9 Outage - 1998 . . . . Page 7 3.0 Degradation Assessment . . . . . . . . . .................... . . . . . . . Page 8 4.0 In-Situ Pressure Testing . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . Page 9 Table 2 - San Onofre Unit 2 in-situ Pressure Test Results . . . . . . . . . . Page 11 5.0 _ Condition Monitoring Assessment . . . . . .................... . . .. . Page 12.

6.0 Probabilistic Operational Assessment Summary . . . . . . . . . . . . . . . . . . . . Page 12 Tsble 3 - San Onofre Unit 2 Cycle 9 Probability of Burst . . . . . . . . . . . . Page 15

. Table 4 - San Onofre Unit 2 Cycle 9 - Accident Leakage Evaluation . . . . Page 16 7.0 Inspection and Operational Enhancements .......... .......... . Page 16 8.0 Conclusions . . . . . . . . . . . . . . ...... .... ............ .... . . . Page 17

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9.0 References . . . . . . . . ...... .... ............. .... . . . . . . . . Page 18 Appendix 1 - History of ECT Inspectior.s and Tube Plugging

Appendix 2 - APTECH Engineering Services Report Appendix 3 - Detailed Computational Output for the Summary Table 5-2 in the APTECH Engineering Services Report (Appendix 2) t i

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1.0 INTRODUCTION

This report updates the run time analysis that was performed following the San Onofre Nuclear Generating Station (SONGS) Unit 2 Cycle 9 refueling outage. Following the refueling outage, Reference 1 was provided to the NRC and indicated the need for a mid-c'; ele steam generator tube inspection. This mid-cycle inspection has been pc.tormed and the results have been assessed. The inspections and assessments that were performed at the refueling outage and the mid-cycle outage complete the basis for the condition monitoring and operational assessment for tho entire Cycle 9 period of operation. Steam generator tube performance has been assessed by extensive eddy current examinations, pressure testing and analysis.

This run time analysis uses guidance and criteria in NRC Regulatory Guide 1.121

" Bases for Plugging Degraded Pressurized Water Reactor Steam Generator Tubes,"

Rev 0, August 1976 (Reference 2), NRC Draft Regulatory Guide DG-1074 " Steam Generator Tube Integrity," September 5,1997 (Reference 3), and applicable portions of Generic Letter (GL) 95-05 " Voltage Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking," August 3, 1995 (Reference 4). The objective of the run time analysis is to determine the duration which the San Onofre Unit 2 SGs can be safely operated within criteria in References 2, 3, and 4.

A similar run time analysis was previously provided in Referenca 1, for the period of operation between the last refueling outage and the recently completed mid-cycle i outage. That analysis indicated that tubing degradation at the top-of-tubesheet could l be monitored by eddy current testing at a normal refueling outage periodicity.

Specifically, it indicated that the structural integrity performans criteria and the accident leakage criteria guidance of References 2,3, and 4 can be met throughout a full cycle of operation without this particular inspection dunng a mid-cycle outage. i Accordingly, this particular inspection was not performed during the mid-cycle outage.

However, the similar previous run time analysis of Reference 1 indicated that the  !

degradation mechanism of axially oriented primary water stress corrosion cracking (PWSCC) of tubing at dented eggerate tube support locations should be monitored by eddy current testing during a mid-cycle inspection outage. This previous analysis l indicated that the structural integrity performance criteria and the accident leakage  !

criteria guidance of Refeiences 2,3, and 4 could be met with a mid-cycle outage.

Accordingly, an inspection of a;l tubes with a bobbin eddy current probe was performed during the recently completed mid-cycle outage. Tubes affected by this degradation mechanism were identified and removed from service. The results of the mid-cycle inspection and this run time analysis indicate that structural integrity performance criteria and accident 'eakage criteria can continue to be met during the period of operatien between the mid-cycle cutage and the next refueling outage.

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The inspection of all tubes with a bobbin probe, that was performed during the mid-cycle outage, also provided an opportunity to identify tubes affected by the degradation  ;

mechanisms of axial cracking in tubing freespans and axial cracking in tubing at undented eggcrate supports. Affected tubes were identified and removed from service.

This provided added assurance of safe operation, even though botn the previous run i time analysis of Reference 1, and this run time analysis do not indicate a need for mid-l cycle inspection for these degradation mechanisms. ,

l A mid-cycle inspection outage was performed so that the inspection interval for the i bobbin probe will be less than 1.24 effective full power years (EFPY) for the remainder of the fuel cycle. The conditional probability of tube burst for all degradation l mechanisms under postulated accident conditions,0.87x10 2, is lower than the DG 1074 criteria of 2.5x10 2 The maximum conditional probability of tube burst for an individual mechanism is 0.43x10-2 and is lower than the GL 95-05 and DG 1074 criteria of 1x102. Postulated accident leakage is acceptable.

1 Therefore, operation for the San Onofre Unit 2 steam generators for the remainder of the Cycle 9 fuel cycle (after the mid-cycle inspection outage) is acceptable.

Acceptability has been determined using guidance contained in RG 1.121, GL 95-05, and DG 1074.

2.0 BACKGROUND

2.1 Commitment On February 20,1998 Southern Califomia Edison (SCE) provided a Special Report to the U.S. Nuclear Regulatory Commission regarding inspection of steam generator l tubes that was completed at San Onofre Unit 2 on February 15,1998 (Reference 5).

Technical Specification 5.7.2.C required this report. In this report SCE made the i following commitment: l l

"The initial assessment of the inspection results indicates that operation until the next refueling outage is appropriate. SCE will submit a final assessment of the enclosed inspection results within 90 days of the end of the Unit 2 Cycle 9 mid-cycle outage to update the previous run time analysis provided in the referenced letter" (which is Reference 5 in this document).

The purpose of this evaluation is to fulfill the commitment to submit a final assessment of the steam generator inspection results for the Unit 2 Cycle 9 mid-cycle outage. Unit 2 entered Mode 2 at the end of the mid-cycle outage on February 22,1998. Thus, this assessment is due to be submitted to the NRC by May 23,1998.

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l 2.2 Steam Generator Description The San Onofre Unit 2 design includes two recirculating ASEA Brown Boveri Combustion Engineering (CE) designed and manufactured Steam Generators (SG) i

. which are vertical U-tube and shell heat exchangers. The SGs are designed and fabricated per ASME Code, Section lll through Summer 1971 Addenda. Each SG contains 9,350 Alloy 600, high temperature, mill annealed tubes which are 3/4 inch OD and have a nominal wall thickness of 0.048 inches. The tubes are explosively expanded into the tubesheet for the entire tubesheet thickness. The tubes are i arranged in rows, with all tubes in a given row having the same length. The rows are staggered, forming a triangular pitch arrangement. The shorter tubes, which have 180*

bends, are at the center of the tube bundle in the first 18 rows. All subsequent rows have double 90* bends. The vertical tube lengths are supported by seven full diameter ,

eggerates (lattice bars), and one to three partial eggcrates for the longer tubes. The j' bends and horizontal lengths are supported by batwings and vertical lattice supports, respectively.

2.3 History of Tube Degradation Two tube degradation mechanisms were identified during the first refueling outage. ,

I One of these mechanisms was related to inadequate heat treatment of portions of certain tubes. The inadequate heat treatment could be identified by eddy current bobbin testing; thus, the full length of all (100%) of the tubes was tested. The identified tubes were removed from service. The other degradation mechanism was wear of the tubing at tube supports (batwings and vertical lattice supports). The degradation '

mechanism of tubing wear has continued to be active throughout the operating lifetime of this unit.

In 1989 tube denting and cracking was identified in a single tube. This mechanism was j related to tie rod corrosion. This mechanism is possible on a small number of tubes. i This mechanism is managed by focused inspections each refueling outage.

In 1993 the following tubing degradation mechanisms were identified on the inlet (hot leg) side of the tubes:

e circumferentially oriented cracking at the top of the tubesheet.

e axially oriented cracking in the vicinity of the top of the tubesheet.  !

e axially oriented cracking at eggcrate tube supports.

These degradation mechanisms continue to occur.

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,- e in 1997 the following tubing degradation mechanisms were identified on the inlet (hot leg) side of the tubes:

e. axially oriented cracking in freespan regions (not at tube supports).

e axially oriented cracking at dented eggerate tube supports.

Also, in 1997, systematic trending of denting indicated that the number of dents in tubing at hot leg supports was increasing. Corresponding actions have been taken to improve the secondary side water chemistry environment.

2.4 Water Chemistry The following actions have been taken in the last two years to improve the secondary side water chemistry environmerit for the steam generator tubing. These actions have been reviewed by a panel of industry experts for application at San Onofre The panel concurred with the following measures:

o Chemical Cleaning of the Entire Tube Bundle (Full Bundle)

• Addition of an inhibitor (Titanium dioxide) for Inter Granular Attack / Stress Corrosion Cracking (IGA / SCC) immediately after the Chemical Cleaning, for maximum crevice penetration potential

• Use of Ethanolamines to reduce deposition of potentially corrosive deposits on the tubing e Boric Acid Addition to the secondary side to help reduce denting and stress corrosion cracking of tubing San Onofre Unit 2 has operated with all volatile chemistry since startup in August 1983 and accumulated approximately 10.9 effective full power years of operation through the end of the mid-cycle outage on February 22,1998. The condensers are seawater cooled. The feedwater system has a full-flow, deep bed, condensate polisher system that was placed in service during the second cycle of operation. The condensate polisher system is operated continuously for maximum protection of the steam generators from cooling water in-leakage. Improvements in secondary chemistry control have paralleled industry developments with implementation of the EPRI PWR Secondary Water Chemistry Guidelines (Reference 6) and subsequent revisions.

2.5 Steam Generator Tube inspections A history of ECT inspections and tube plugging is provided in Appendix 1.

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[ The following time line is provided to summarize significant historical innovations in San Onofre Unit 2 Steam Generator Tube inspections.

BOBBIN PROBE 1987 - Full Length sampling increased from 3% to 20%

1995 -Implemented examination of the Full Length of 100% of the tubing ROTATING PROBE 1984 - During the first refueling outage, used as a characterization tool for indications of significance 1989 - More wide usage as a characterization tool, and used in all tubes adjacent to tie rods 1993 - 100% examination of hot leg top-of-tubesheet expansion transitions with "3-coil" probe, including the 0.115 inch diameter pancake coil 1997 - Use of Plus-Point

• coil probe for rotating probe applications.

The most recent SG inspection was completed at the end of the mid-cycle outage during Cycle 9 in early 1998. The detailed scope and the results of that inspection were previously summarized in a Special Report to the NRC (Reference 5). The tube plugging table from that Special Report is repeated here for completeness (Table 1). )

2.6 Conservative Tube Plugging The only tubing degradation mechanism for which SCE uses an eddy current technique for sizing is mechanically induced wear of tubing at tube supports. Tubes are plugged for wear based on sizing results. Other indications of tubing degradation are plugged upon detection, without the use of a sizing technique to justify leaving affected tubes inservice. Tube plugging was performed by FRAMATOME Technologies, Inc.

Corrosion resistant, thermally treated alloy 690 material is used for plugging. Plugs are installed mechanically using a qualified rolling process. Welded alloy 690 plugs are used in a few special cases, such as when a tube is removed.

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Table 1 - SONGS UNIT 2 - Tubes Piugged MID-CYCLE OUTAGE - 1998 Steam Generator indication Orientation and Location E-088 E-089 Tubes with axially oriented ID (initiated on the inside-diameter 5 7 of the tubing wall) indications at tube support locations Tubes with axially oriented OD (initiated on the outside- 32 24 diameter of the tubing wall) indications at tube support locations Tubes with axially oriented OD indications not associated with 99 67 a tube support (freespan)

Tubes with axially oriented OD indications in the sludge pile 2 2 region near the top-of-tubesheet Tubes with axially oriented indications below the inlet top-of- 0 3 ,

tubesheet l Tubes with indications of wear at tube support locations 16 4 Tubes with circumferentially oriented indications at tight radius 0 1 u-bend locations Tubes with volumetric indications at miscellaneous locations 3 1 Miscellaneous preventative plugging 2 3 Total 159 112 2.7 Operational Leakage Monitoring Primary-to-secondary leakage monitoring at San Onofre has been reviewed against available guidance to ensure that leakage monitoring measures are effective at detecting leakage and reducing the potential for tube rupture. Detection of low level leakage is accomplished primarily by chemical sampling and the condenser air ejector radiation alarm. Nitrogen-16 monitoring is available to assist in diagnosis of low-level j leakage. Action levels and leakage limits in San Onofre Abnormal Operating j Instructions are consistent with the "EPRI PWR Primary-to-Secondary Leak Guidelines" l (Reference 7).

Evaluating the potential for tube rupture, including the detection, measurement, and assessment of rapidly increasing leakage is required by San Onofre procedures. San Onofre procedures require unit shutdown for rates of change of steam generator tube leakage equal to 60 gpd in any one hour period. Operator responses to leakage and rates of change of leakage are specified in San Onofre procedures. These procedures '

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and responses have been reviewed against available guidance and historical leakage -

events.

3.0 DEGRADATION ASSESSMENT l

3.1 Circumferential Indications Circumferential stress corrosion cracking initiated at both the outside and inside surface of the SG tubing was first detected at the tube expansion transition in the hot legs of the San Onofre Unit 2 SGs during the 1993 inspection. Rotating coilinspection has been routinely performed for this region since that time. SCE data analysis guidelines have been continually updated to incorporate industry experience and evolving technology. No indications of this type were identified in a similar examination of a sample of tubes on the cold leg side of the steam generators. SCE has used EPRI sizing techniques that are available and appropriate for San Onofre to determine that indications have met the structural criteria of RG 1.121.

3.2 Free Span AxialIndications Subsequent tc a tube rupture in March of 1993 at Palo Verde Unit 2 (CE System 80) it was determined that upper bundle deposits may act as a precursor to free span axial cracking. Thermal hydraulic evaluations of steam generators completed since the tube rupture indicate that certain upper bundle regions have higher potential for deposit accumulation. Axial indications have recently been reported in the free span region of ABB/CE designed units with more operation time than San Onofre Unit 2.

The San Onofre Unit 2 and 3 SG tube bundle regions most susceptible to deposit accumulation were estimated. This was done by review of industry experience and  ;

computer modeling of thermal hydraulic conditions. (Reference 8)  ;

in 1997 SCE implemented inspection plan changes to include rotating Plus-Point

• probe inspection of 20% of the tubes in selected regions in both San Onofre Unit 2 ,

I SGs. The region was defined based on thermal-hydraulic considerations. No indications were found in SG 88. In response to axial indications in SG 89, the sampling program of 609 tubes was expanded to an approximate total of 1409 tubes.

Tho results in the expanded sample indicated no need for further sample expansion in the selected region of the tube bundles.

Axial cracking was identified in freespan parts of the tubing during the 1997 and 1998 examinations. The location of this cracking could not be readily correlated with results of the thermal hydraulic evaluation of tube bundle regions susceptible to deposit accumulation.

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- 3.3 Axial Indications at Eggcrates and in the Sludge Pile SCE has utilized a bobbin coil technique for detection of outside-diameter-initiated, stress corrosion cracking (ODSCC) indications at these locations. The technique used is EPRI qualified in accordance with Appendix H of the EPRI PWR Steam Generator Examination Guidelines (Reference 9). SCE has only used the detection portion of this qualification. SCE has conservatively " plugged on detection," and it.us has not used the sizing portion of this qualification to leave tubes in service. However, the sizing portion of this qualification provides one tool in estimation of the structural integrity significance of such indications per RG 1.121.

Further, SCE has enhanced detection capabilities in the sludge pile by performing rotating Plus-Point

• coil inspection of all tubing in the vicinity of hot leg expansion transitions.

3.4 Axial indications at Dented Hot Leg Eggcrate Support intersections SCE uses the full length bobbin exam of 100% of the tubes to identify dents at tube support intersections and dings in tubing freespan. SCE uses the voltage normalization technique in widest industry usage, consistent with EPRI Guidelinos and GL 95-05 (all bobbin frequency channel voltages normalized to 4 volts on the prime frequency for 20% drill holes). For the 1997 and 1998 inspections SCE implemented a practice of inspection with the rotating Plus-Point

• coil of all hot leg dents and dings that are greater than 5 volts by bobbin.

3.5 Tubing Wear San Onofre Unit 2 experiences tubing wear that is typical for this particular design of ABB/CE SGs. A technique that is qualified in accordance with Appendix H of the EPRI PWR Steam Generator Examination Guidelines (Reference 9) is used for detection and sizing of indications.

4.0 IN-SITU PRESSURE TESTING In-situ pressure testing was conducted during the most recent inspection to verify that RG 1.121 structural margins were maintained. Thirteen in-situ pressure tests were completed. A summary table of :ocations tested and results was previously provided in a special report to the NRC (Reference 5). This information has been supplemented to include information on the eddy current indications at each location and is included here as Table 2.

4.1 Criteria '

The methodology and criteria for screening candidate eddy current indications for in-situ pressure testing was obtained from available industry guidance (References 10 and 11). The selection process incbded redew of bobbin and rotating probe data for 4

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i estimated maximum through ' wall depth, maximum voltage, and length. Finally, lead

(- ECT oata analyst recommendations were considered.

in-situ testing target pressures include an adjustment for testing at ambient temperature -

rather than the maximum design temperature.of 650*F. Acceptance criteria are those specified by regulatory guidance, 4.2 _

Results

- All of the tubes in-situ pressure tested ~during the mid-cycle outage r'c.nonstrated leaktightness and structural integrity at all test pressures, i

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5.0 CONDITION MONITORING ASSESSMENT The purpose of this " backward looking" assessment is to confirm that adequate tube 1 integrity has been maintained during the operating period before the inspection. A qualified " depth-sizing" technique was only available for the degradation mechanism of mechanically induced wear at tube supports. All available eddy current information '

was considered for other degradation mechanisms.

5.1 Methodology and Results The first step was review of eddy current depth-sizing information for mechanically induced wear at tube supports. All these indications met criteria for structural and leakage integrity.

The next step for other degradation mechanisms was a review of bobbin and rotating probe daia for estimated maximum through wall depth, maximum voltage, and length.

Also, lead ECT data analyst recommendations were considered.

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This review was then used in consonance with the previously described tube selection process for in-situ pressure testing. Leakage and burst testing was used to obtain condition monitoring information on both the most significant eddy current indications and Wo some less significant indications to demonstrate that the results were j bounding for other indications. Results of in-situ pressure testing were consistent with expectations formed during the tube selection process. This is considered an indication of the effectiveness of the selection process. All of the tubes in-situ pressure tested during the mid-cycle outage demonstrated leaktightness and structural integrity at all test pressures.

5.2 Analysis The results of the Condition Monitoring indicate that applicable performance criteria were met throughout the previous period of operation.

6.0 PROBABILISTIC OPERATIONAL ASSESSMENT

SUMMARY

The purpose of this " forward looking" assessment is to demonstrate reasonable assurance that tube integrity performance criteria will be met throughout the period prior to the next scheduled inspection.

The significance of corrosion degradation to the performance of steam generator tubing at San Onofre Unit 2 was evaluated in a Probabilistic Operational Assessment.

Probabilistic methods were applied to make projections throughout an assumed operating period of the structural and leakage integrity of the steam generator tubing l

r o e under postulated accident conditions (MSLB). A detailed report of this assessment is provided as Appendix 2. However, a brief overview of it is provided below.

l 6.1 Degradation Modes Testing of steam generator tubing at San Onofre Unit 2 has indicated corrosion degradation. Eddy current inspection data and pulled tube examinations have been tools in characterizing the degradation. Five modes of corrosion were considered in this assessment:

(1) Circumferential degradation at the top of the tubesheet (2) Axial degradation at the top of the tubesheet (3) Axial freespan degradation (4) Axial ODSCC/lGA at undented eggerate intersections (5) Axial PWSCC at dented eggcrate intersections 6.2 Methods The basic calculational technique employed in the Probabilistic Operational Assessment is one of simulating the processes of crack initiation, crack growth, leakage, and detection via eddy current inspection. Monte Carlo simulation methods .

also provide an approach for accounting for the various sources of uncertainty. I Several probabilistic run time models were employed. Modeling included two operational periods, because there are 2 distinctly different types of inspections. It was necessary to determine the most appropriate operational period between inspections during this cycle for these 2 different inspections:

(a) Inspection of the vicinity of expansion transitions at the top of the tubesheet is the principal detection tool for circumferential and axial degradation in this location. Results indicate that a full cycle of operation is an appropriate interval between these inspections.

(b) Inspection of the full length of the tubing with a standard differential bobbin probe is the principal detection tool for axial degradation in the remainder of the tubing. Results indicate that inspection during a mid-cycle outage is appropriate for these inspections.

6.3 Structuralintegrity Assessment Description The Probabilistic Operational Assessment provides a projection of the structural integrity of the steam generator tubing. This projection is commonly referred to as

" conditional probability of burst" (POB). It is generally defined as the probability that the burst pressures associated with one or more indications of degradation will be less than the maximum pressure differential across the tubing associated with a postulated MSLB that is assumed to occur at the end of an assumed period of operation, just prior

! to a tubing inspection.

6.3.1 Criteria for Structural uegrity Performance The conditional POB criteria - . is applicable to any one degradation mechanism is 1 x 10:2 The conditional POB cuteria that is applicable to the total conditional POB for all degradation mechanisms is 2.5 x 10-2 6.3.2 Structuralintegrity Assessment Results 1 The dominant contributor to the conditional probability of burst is axial degradation at  !

I dented eggerate supports. This is largely a function of the eddy current probability of detection (POD).

The Operational Assessment results for conditional POB are shown in Table 3 and are well within the above POB criteria.

6.4 Accident Leakage Assessment Description The Probabilistic Operational Assessment also provides a projection of the leakage integrity of the steam generator tubing. The basis of this projection is a probabilistic calculation for each degradation mechanism of its postulated accident condition (MSLB) leak rate for the end of an operating period, just prior to inspection. Modeling projects maximum crack depths for this point in time, identifies those that have reached l the full tube thickness (through wall), and finally models their corresponding leakage. I Monte Carlo methods provide a way to account for ur. certainties, and accordingly, the calculated leakage is an upper 95-percent probability at an upper 95-percent confidence bound.

l Table 3 - San Onofre Unit 2 Cycle 9 - Probability of Burst (POB)

Degradation Mechanism Projected Duration Probability of Burst

- (EFPY) at Postulated MSLB (95% Confidence)

Circumferential 2.0 0.0005 ODSCCIPWSCC at Expansion Transitions Axial ODSCC at 2.0 0.0033 Expansion Transitions Axial ODSCC at 1.24 0.0003 Undented Eggcrate Intersections Axial PWSCC at Dented 1.24 0.0043 >

Eggcrate Intersections l Freespan Axial ODSCC 1.24 0.0003 6.4.1 Criteria for Accident Leakage Assessment The criteria are that calculated potential primary-to-secondary leak rate during postulated design basis accidents other than a steam generator tube rupture should not exceed 1 gallon per minute.

6.4.2 Accident Leakage Assessment Results l The projected MSLB accident leak rates are shown in Table 4.

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Table 4 - San Onofre Unit 2 Cycle 9 - MSLB Accident Leakage Evaluation Degradation Mechanism ! Projected Duration 95/95 Leak Rate at (EFPY) Postulated MSLB (GPM at 600 F Circumferential 2.0 0.38 ODSCC/PWSCC at Expansion Transitions Axial ODSCC at 2.0 0.009 l

Expansion Transitions Axial ODSCC at 1.24 0 Undented Eggcrate Intersections Axial PWSCC at Dented 1.24 0 Eggerate intersections Freespan Axial ODSCC 1.24 0 ,

The maximum total projected 95%/95% probability / confidence leak rate is less than 0.39 gallons per minute at the end of a full cycle. Note that this total was computed for a cycle that includes a mid-cycle inspection outage. This projected leak rate is a very small fraction of the total charging pump capacity of the San Onofre Unit 2 primary system and is bounded by the primary-to-secondary leak rate assumption of 0.5 gallons per minute per steam generator used in the MSLB licensing event, as stated in the San Onofre 2/3 Updated Final Safety Analysis Report (UFSAR) Section 15.1.3.1 A.

7.0 INSPECTION AND OPERATIONAL ENHANCEMENTS Significantly shortening the operational period between inspections to address axial cracking in the tubing freespans and axial cracking of tubing at supports will provide assurance that the requirements of RG 1.121 will be met throughout the present operating cycle.

Inspection practices at San Onofre have been routinely updated to incorporate industry experience and recommendations. One such example is the use of a rotating probe at hot leg dented eggerate tube support intersections for improved POD for indications.

Further, thorough in-situ pressure testing has been implemented. These actions will serve to decrease the potential for a tube failing to meet criteria in regulatory guidance.

In 1997 three tubes were removed from a steam generator and characterized in the laboratory. Section 5.0 of Reference 1 explains how this increased understanding of the applicable degradation mechanisms.

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Actions have been taken to improve the secondary side water chemistry environment for the steam generator tubing. These actions have been reviewed by a panel of industry experts for application at San Onofre. The expert panel concurs with these measures. These actions are: 1) Chemical cleaning of the entire tube bundle (Full Bundle),2) Addition of an inhibitor (titanium dioxide) for IGA / SCC immediately after the chemical cleaning, for maximum crevice penetration potential,3) Use of Ethanolamines to reduce deposition of potentially corrosive deposits on the tubing, and 4) boric acid addition in the secondary side to help reduce denting of tube supports and stress corrosion cracking of tubing.

Plant operators have procedures consistent with EPRI guidelines to detect and respond to changes in steam generator primary to secondary leakage. Specifically, they have guidance for shutdown of the unit prior to a significant leak or tube rupture, should tube degradation exceed expected values.

State of the art probabilistic models have been developed to demonstrate that the completed mid-cycle inspection outage for the steam generators will maintain the safety margins in regulatory guidance throughout the remainder of Cycb 9 operation. A probabilistic leakage model has been developed to assess the end of inspection interval leakage that would result from postulated accident conditions. The leakage model demonstrates that the postulated leakage for Cycle 9 is bounded by the primary-to-secondary leakage assumption of 0.5 gallons per minute per steam generator used in the MSLB licensing event, UFSAR 15.1.3.1 A.

8.0 CONCLUSION

S lt is SCE's conclusion that the San Onofre Unit 2 steam generators will fully support safe operation throughout the full Cycle 9 operating period.

This report demonstrates that the operation, inspection, and repair program described herein constitutes a conservative approach which ensures that adequate structural and leakage integrity is maintained for normal operations, transients, and postulated accident conditions throughout the full Cycle 9 operating period for the San Onofre Unit 2 steam generators.

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9.0 REFERENCES

1. Letter from Southern California Edison to the US Nuclear Regulatory Commission "Special Report: Steam Generator Run Time Analysis for Cycle 9, San Onofre Nuclear Generating Station, Unit 2," Dated September 25,1997.

2. Regulatory Guide 1.121, " Bases for Plugging Degraded Pressurized Water Reactor Steam Generator Tubes," Rev 0, August 1976.

3. NRC Draft Regulatory Guide DG-1074 " Steam Generator Tube Integrity,"

September 5,1997.

4. NRC Generic Letter 95-05, " Voltage Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking," August 3,1995.

5. Letter from Southern California Edison to the US Nuclear Regulatory Commission "Special Report: Inservice inspection of Steam Generator Tubes, [

San Onofre Nuclear Generating Station, Unit 2," Dated February 20,1998.

6. EPRI Guidelines, TR-102134-R4, Revision 4, "PWR Secondary Water Chemistry Guidelines," dated November 1996.

7. EPRI Guidelines, TR-104788 " Primary to Secondary Leak Guidelines " dated ,

May 1995.

8. ~ ABB-CE Report, " Tube Bundle Tharmal-Hydraulic Analysis to Assist the Development of Eddy Current Test Plans for the Songs Unit 2 Steam Generators," A-SONGS-9419-1118, REV. 00; dated October 15,1996.

9. EPRI Guidelines, TR-107569-V1R5, "PWR Steam Generator Examination Guidelines: Revision 5, Volume 1: Requirements" dated September 1997.

10. EPRI Draft Guidelines, Draft TR-107620, " Steam Generator In Situ Pressure Test Guidelines", dated December 1997.

11. Combustion Engineering Owners Group Guidelines, Draft Supplement 1 - CE NPSD-1005-P, "In Situ Pressure Testing Candidate Tube Selection and Leak RateTesting Guidelines", dated October 1997.

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1 SAN 'ONOFRE UNIT 2 STEAM GENERATOR'

' EDDY CURRENT & TUBE PLUGGING HISTORY.

Exam' BOBBIN : ROTATING PROBE L TUBES; L RESULTS .& COMMENTS DateL EXAM EXAM PLUGGED:

MFG 100 % - 21 Preservice Shop Plugs 1984 <1 % - 1 Leak Outage, Improper Annealing 1985 100% - 330 Batwing Wear improper Annealing. Pulled 2 tubes 1986 SG 88: 6% - 17 Batwing Wear 1987 6% - 142 Batwing Wear 1989 23 % Approx. 84 HL Expan. Trans. 62 Batwing Wear (Tie Rod Related) Tie Rod Denting 1991 23% < 84 HL Expan. Trans. (Tie 41 Batwing Wear Rod Related) Tie Rod Denting j 1993 66 % 100% HL Expan. Trans. 32 Circ SCC - HL Expan. Trans.

Approx. 668 tubes for Freespan Axial Check Approx.184 tubes for Bobbin Follow up 1995 100 % 100% HL Expan. Trans. 45 Circ SCC - HL Expan. Trans.

7% CL Expan. Trans.

Approx 160 tubes for Bobbin Follow up 1997 100% 100% HL Expan. Trans. 332 Circ SCC - HL Expan. Trans.

7% CL Expan. Trans. Axial SCC - Sludge Pile & Supports &

20% Row 1&2 U-bends Freespan Approx. 2018 tubes for Pulled 3 tubes Freespan AxialCheck 1916 HL Dents & Dings Approx 304 tubes for Bobbin Follow up 1998 100 % 100% Row 1,2 & 3 271 Axial SCC - Sludge Pile & Supports &

U-bends Freespan 2829 HL Dents & Dings Tight Radius U-bend Approx 1014 tubes for Cracking Bobbin Follow up TOTAL TUBES - Each = 9350 PLUG MARGIN - 1000 Tubes each S/G TOTAL PLUGS - S/G 88 = 636 (6.8%)

S/G 89 = 657 (7.0%)

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