ML13030A467
| ML13030A467 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 01/30/2013 |
| From: | Southern California Edison Co |
| To: | Atomic Safety and Licensing Board Panel |
| SECY RAS | |
| Shared Package | |
| ML130310300 | List: |
| References | |
| RAS 24062, 50-361-CAL, 50-362-CAL, ASBLP 13-924-01-CAL-BD01 | |
| Download: ML13030A467 (147) | |
Text
SCE ATTACHMENT 25
10/3/2012 I
1 SOUTHERN CALIFORNIA
.jEDISON An EDISON INTERNATIONAL Company SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONAL Company SONGS U2C17 STEAM GENERATOR OPERATIONAL ASSESSMENT Page 1
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__EDISON 10/3/2012 SONGS U2C1 7 Steam Generator Operational Assessment I, If4-_
/b/.34 Prepared by:
Richard A. Coe Steam Generator Recovery Project f
Reviewed by:
Allen L. Matheny Integrity Assessment Program Element Manager Steam Generator Program
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10/-3)/,2-Reviewed by:
Reviewed by:
Tom Yackle Steam Generator Recovery Project St2ea Pr Short Steam Generator Recovery Project r~
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Reviewed by:
Approved by:
David I Calhoun' Steam Generator Recovery Project Ste~p eft Chun Manner, Systems Engineer-Mechanical Steam Generator Program SL2 Page 2
SOUTHERN CALIFORNIA EDISON~
An EDIS\\% Ilk IR N TI Cumpaný SONGS U2C17 Steam Generator Operational Assessment 10/3/2012 Record of Revision Revision PageslSectionsl No.
Paragraphs Changed Brief Description I Change Authorization 0
Initial Issue Initial Issue I
I ________________
i I.
d Page 3
SOUTHERN CALIFORNIA 10/3/2012 EDISON° An EDISON INTERNATIONAL_ Cmpaný SONGS U2C17 Steam Generator Operational Assessment Table of Contents Page RECO RD O F REVISIO N..........................................................................................................................
3 LIST O F TABLES.....................................................................................................................................
5 LIST O F FIG URES...................................................................................................................................
6 LIST O F APPENDICES............................................................................................................................
7 ABBREVIATIO NS AND ACRO NYM S..................................................................................................
8 EXECUTIVE SUM MARY..........................................................................................................................
9 1.0 PURPO SE.....................................................................................................................................
9 2.0 SONGS STEAM GENERATOR DESIGN FEATURES............................................................
9 3.0 O PERA TIO NAL ASSESSM ENT.............................................................................................
12 3.1 OA for Degradation M echanism s Other than TTW....................................................
14 3.2 TTW OA Using Tube-to-AVB Support Conditions and Contact Force.......................
15 3.3 "Traditional" Probabilistic OA for TTW........................................................................
16 3.4 Determ inistic TTW OA...............................................................................................
17 3.5 Evaluation of Leakage Integrity.................................................................................
18 3.6 Sum m ary of All OA Conclusions.................................................................................
19
4.0 REFERENCES
20 Page 4
SOULHERN cALIFORNIA 10/3/2012 EDISON A\\n EDISON INTF\\.i7I()\\ 11 Conipaný SONGS U2C17 Steam Generator Operational Assessment List of Tables Page TABLE 3-1: OA APPROACH AND RESULTS COMPARISON......................................................
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v SOuthERN CALIFORNIA 10/3/2012 EDISON0 An EDISO.1 INTERN.ATIONALO Cumpansý SONGS U2C17 Steam Generator Operational Assessment List of Figures Page FIGURE 2-1: AVB ARRANGEMENT FOR SONGS STEAM GENERATORS...................................
10 FIGURE 2-2: DETAILS OF AVBS, RETAINING BARS, BRIDGES, AND RETAINER BARS.......
11 FIGURE 3-1: TRADITIONAL OPERATIONAL ASSESSMENT RESULTS....................................... 17 Page 6
SOUTHERN CALIFORNIA 10/3/2012 EDISON An EDISON, I\\TfR\\"ATIOh\\
ID Cupamn SONGS U2C17 Steam Generator Operational Assessment List of Appendices Appendix-A: SONGS U2C17 Outage - Steam Generator Operational Assessment*
Appendix-B: SONGS U2C1 7 Steam Generator Operational Assessment for Tube-to-Tube Wear*
Appendix-C: Operational Assessment for SONGS Unit 2 SG for Upper Bundle Tube-to-Tube Wear Degradation at End of Cycle 16 Appendix-D: Operational Assessment of Wear Indications in the U-bend Region of San Onofre Unit 2 Replacement Steam Generators
- [Proprietary Information Redacted]
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D sothen cai~on~a10/3/2012 SSOUTHERN CALIFORNIA10322 EDISON° An EDISON INTERNATIONALD Cumpaný SONGS U2C17 Steam Generator Operational Assessment ABBREVIATIONS AND ACRONYMS 2E-089 Unit 2 Steam Generator E-089 AILPC Accident-Induced Leakage Performance Criteria ASME American Society of Mechanical Engineers ATHOS Analysis of Thermal-Hydraulics of Steam Generators AVB Anti-Vibration Bar CE Combustion Engineering ECT Eddy Current Testing EFPY Effective Full Power Year EOC End of Cycle (fuel)
EPRI Electric Power Research Institute ETSS Examination Technique Specification Sheet FEI Fluid Elastic Instability FOSAR Foreign Object Search and Retrieval gpd Gallons Per Day gpm Gallons Per Minute MHI Mitsubishi Heavy Industries, Ltd.
NEI Nuclear Energy Institute NODP Normal Operating Differential Pressure NRC Nuclear Regulatory Commission OA Operational Assessment POB Probability of Burst RCS Reactor Coolant System SCE Southern California Edison SIPC Structural Integrity Performance Criteria SG Steam Generator SONGS San Onofre Nuclear Generating Station SR Stability Ratio T/H Thermal-Hydraulic TS Technical Specifications TSP Tube Support Plate TTW Tube-to-Tube Wear U2C17 Unit 2 Cycle 17 UNS Unified Numbering System WEC Westinghouse Electric Company Page 8
1 SOUTHERN CALIFORNIA 10/3/2012 JEDISON An EDISON\\ I\\FtRV\\'AOTI(
Cunmpan SONGS U2C1 7 Steam Generator Operational Assessment EXECUTIVE
SUMMARY
On January 31, 2012, a leak was detected in a Unit 3 Steam generator (SG) at San Onofre Nuclear Generating Station (SONGS). Southern California Edison (SCE) operators promptly shut down the unit in accordance with approved operating procedures. The resulting small radioactive release to the environment was well below the allowable federal limits. Subsequently, on March 27, 2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter [1] to SCE describing actions that the NRC and SCE agreed would be completed prior to returning Units 2 and 3 to service. Since that time, SCE's technical team supplemented by a team of experts in the field of thermal-hydraulics and in SG design, manufacture, operation, and maintenance have performed extensive investigations into the causes of the tube leak and have assisted in the development of compensatory measures and corrective actions that will prevent a loss of SG tube integrity.
As required by the SONGS Technical Specifications (TS) [3], SONGS SG Program [2], and industry guidelines
[51, 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 tube-to-tube wear (TTW) at SONGS, SCE commissioned three independent OAs [Appendices B, C, and D] by experienced vendors applying diverse methodologies. The non-TTW degradation mechanisms have been addressed by a separate OA included in this report [Appendix-A]. Each of these methodologies demonstrates that SCE has implemented compensatory measures and corrective actions to ensure that Unit 2 will operate safely with substantial conservative margin.
This report contains the OAs that have been performed to demonstrate that those compensatory measures and corrective actions will prevent a loss of SG tube integrity.
1.0 PURPOSE In accordance with the SONGS SG Program [2] an OA is performed to ensure that SG tubing meets established performance criteria for structural and leakage integrity during the interval prior to the next planned inspection.
The OA projects and evaluates tube degradation mechanisms which have affected the SGs. The performance criteria are defined in plant TS [3] [4] and are based on NEI-97-06 [5].
This summary of the OAs establishes operational limits for Unit 2 and provides reasonable assurance, as required by NRC regulations, that Unit 2 will operate safely.
2.0 SONGS STEAM GENERATOR DESIGN FEATURES 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 (6) 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 (See Figure 2-1 and Figure 2-2).
Note: The SG design information is provided in References [6] [7] [8] [9] [10] [11] [12].
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ESOUTHERN CALIFORNIA EDISONC An EDISOS SmINrTERaoOprTIONALto CAtsspane n
SONGS U2C17 Steam Generator Operational Assessment 10/3/2012 Figure 2-1: AVB Arrangement for SONGS Steam Generators Anti-Vibration Bar (AVB)
Tube Tube Support Plate (TSP)
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JSOUTHERN CALIFORNIA EDISON An EIDON h\\TERVITIONAL Cuin\\pa\\
SONGS U2C17 Steam Generator Operational Assessment 10/3/2012 Figure 2-2: Details of AVBs, Retaining Bars, Bridges, and Retainer Bars Page 11
SOUTHERN CALIFORNIA 10/3/2012 EDISON° An EDISON INTERNATIONAL CumpanN SONGS U2C17 Steam Generator Operational Assessment 3.0 OPERATIONAL ASSESSMENT As defined in NEI 97-06, 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 [5]. The CA 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.
As documented in the "SONGS U2C17 Steam Generator Condition Monitoring Report" [13], the Unit 2 SGs satisfied the three performance criteria specified in the TS for the previous operating period. The SG Program requires an OA to be completed for the next inspection interval within 90 days after initial entry into MODE 4 (MODE is defined in the station TS). This summary of the OhAs establishes operational limits for Unit 2 and provides reasonable assurance, as required by NRC regulations, that Unit 2 will operate safely.
The structural integrity performance criteria (SIPC) and accident-induced leakage performance criteria (AILPC) applicable to wear mechanisms are [14]:
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."
The acceptance standard for structural integrity is [14]:
The worst-case degraded tube shall meet the SIPC margin requirements with at least a probability of 95%
at 50% confidence.
The acceptance standard for accident leakage integrity is [14]:
The probability for satisfying the limit requirements of the AILPC shall be at least 95% at 50% confidence.
The OA may utilize either a deterministic (also known as simplified arithmetic) or a probabilistic methodology.
SCE has assessed all tube wear mechanisms in Unit 2, including TTW. Given the significance of TTW observed in Unit 3, SCE used the experience and expertise of multiple independent companies that routinely perform OAs for the US nuclear industry. AREVA, Westinghouse Electric Company (WEC), and Intertek developed independent OAs to address the TTW found at SONGS. These diverse analyses fulfilled the TS requirement to ensure that SG tube integrity is maintained until the next SG inspection.
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I SOUTHERN CALIFORNIA 10/3/2012 EDISON 1/2n EDIS*\\ IN\\MTRV\\ TIO',,L Cumrnpamn SONGS U2C1 7 Steam Generator Operational Assessment Section 3.1 provides a summary of the OA prepared by AREVA evaluating all degradation mechanisms found in Unit 2 SGs with the exception of TTW. This OA demonstrates there is reasonable assurance that the SIPC and AILPC for non-TTW will be satisfied for 18 months at 100% power.
Section 3.2 provides a summary of the OA prepared by AREVA. This OA deterministically evaluates the potential for TTW for the limiting condition of no in-plane support. The OA also evaluates probabilistically the potential for in-plane Fluid Elastic Instability (FEI) occurring in Unit 2 based on an analysis of the contact forces between tubes and AVBs. The deterministic results demonstrate all tubes are stable (will not experience Thermal-Hydraulic (T/H) conditions that cause FEI) at 70% power for 18 months of operation without relying on the AVBs for in-plane support. Therefore, this OA demonstrates that the SIPC and AILPC for TTW will be satisfied for 18 months at 70% power. The probabilistic results demonstrate a low probability of FEI at 70%
power for approximately 8 months of operation even when additional conservatisms are introduced.
Section 3.3 provides a summary of the OA prepared by Intertek following "traditional" industry guidelines for assessing SG tube degradation. This OA evaluates the probability that TTW caused by FEI will not exceed the SG SIPC. This OA demonstrates there is a reasonable assurance that the SIPC and AILPC for TTW will be satisfied for 16 months at 70% power level.
Section 3.4 provides a summary of the OA prepared by WEC based on an alternate interpretation of the inspection results. This OA determines the TTW in Unit 2 was caused by out-of-plane vibration between two tubes in close proximity. The OA evaluates the potential for in-plane instability and concludes the Unit 2 SG tubes were stable in-plane at 100% power. This OA demonstrates there is reasonable assurance that the SIPC and AILPC for TTW will be satisfied for 18 months at 70% power.
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SOutHERN CALIFORNIA 10/3/2012 EDISON0 An E0DISOGIN fTER TIO\\AI
- Cumpan, SONGS U2C17 Steam Generator Operational Assessment 3.1 OA for Degradation Mechanisms Other than TTW The "SONGS U2C17 Outage - Steam Generator Operational Assessment" report [Appendix-A] addresses all degradation mechanisms found in Unit 2 SGs with the exception of TTW. Due to the relatively large number of AVB and TSP wear indications, identified during the U2C17 outage, a probabilistic approach was used to complete the OA for these mechanisms, which included:
Tube Wear at AVB Locations Tube Wear at TSP Locations Tube Wear at Retainer Bar Locations Tube Wear as a Result of Foreign Object Wear The objective of this OA is to ensure that structural and leakage performance criteria will be met over the length of the upcoming inspection interval. The OA tube structural integrity requirement is that the projected worst case degraded tube for each existing degradation mechanism shall meet the limiting structural performance parameter with a 95% probability at 50% confidence [3].
AVB and TSP Wear Because the tube wear indications are flat and long in the axial direction, the limiting requirement for the inspection interval length is structural integrity (i.e. tube burst at 3x NODP). The projected accident-induced leak rates for tube wear will not be limiting since leakage due to ligament pop-through will not precede burst condition at 3x NODP.
The OA uses a probabilistic method to calculate the growth at End of Cycle (EOC) of each indication by randomly sampling from the growth rate distribution yielding one estimate of the EOC depth for each indication. The burst pressure of the worst case degraded tube is calculated and compared with the value of 3 times NODP. This process is repeated thousands of times in order to develop a probability of burst for the worst case degraded tube. If the probability of burst of the worst case degraded tube is less than 5%, then the plugging criteria and inspection interval are satisfactory.
The projected EOC probabilities of burst for the population of indications in each damage mechanism category were calculated for Unit 2 at 100% power for a full cycle of operation (1.577 Effective Full Power Years, EFPY).
The projected EOC probabilities are compared with the 95% probability 50% confidence EPRI guidelines [14]
criteria to demonstrate the OA structural integrity criteria for AVB and TSP wear are satisfied for a full fuel cycle of operation at 100% reactor power.
Retainer Bar Wear Because of the potential for continued retainer bar wear of Unit 2, tubes adjacent to retainer bars have been removed from service. Tubes with retainer bar wear indications were stabilized with U-bend cable stabilizers.
The tubes on either side of all retainer bars, at each end of the retainer bars, and at the center of the retainer bars, were also stabilized with U-bend cable stabilizers. These corrective actions provide reasonable assurance that retainer bar wear will not challenge the structural and leakage integrity performance criteria during the remaining life of the SGs. In addition, the stabilization of these tubes provides reasonable assurance that a tube severance event will not occur as a result of retainer bar wear. The SG Program [2] will monitor the tubes adjacent to these plugged tubes during future SG inspections.
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J SOUIIERIN CALIFORNIA 10/3/2012
- EDISON, An EDI)SON\\ IRT"',IIO\\;AL Compam, SONGS U2C17 Steam Generator Operational Assessment Foreign Object Wear All Unit 2 SG tubes were examined full length with Eddy Current Testing (ECT) bobbin coil probes. Two adjacent tubes in SG 2E-089 were identified with foreign object wear indications. The foreign object was identified as weld slag and retrieved from the SG. No other foreign objects were found. The foreign object is not indicative of degradation of secondary side internals.
Because the foreign object has been removed, no potential exists for degradation to progress at these locations.
After removal of the object, the affected indications were inspected with ECT. Since the indications are below the SONGS plugging limit and the object was removed, these tubes are left in service.
Based on ECT inspections, secondary side visual examinations, and FOSAR, no foreign objects capable of causing tube degradation remain in the Unit 2 SGs. There is reasonable assurance that foreign objects will not cause the structural or leakage integrity performance criteria to be exceeded prior to the next tube inspection in each SG.
OA for Degradation Mechanisms Other than TTW Conclusion The OA demonstrates there is reasonable assurance that the SIPC and AILPC for non-TTW will be satisfied for 18 months at 100% power.
3.2 TTW OA Using Tube-to-AVB Support Conditions and Contact Force The "SONGS U2C1 7 Steam Generator Operational Assessment for Tube-to-Tube Wear" [Appendix-B] assesses the TTW degradation mechanism deterministically, without taking credit for in-plane support. The OA also implements a probabilistic approach using tube to AVB contact forces for defining an effective tube support. The OA predicts the probability of in-plane FEI and compares this value to the probabilistic SIPC (95% probability at 50% confidence).
The deterministic approach uses Stability Ratios (SRs) as the criterion for susceptibility to FEl. The SR is calculated conservatively using Thermal-Hydraulic (T/H) and tube support conditions on the secondary side of the SG. The T/H conditions are determined using an ATHOS computer model.
The deterministic approach demonstrates in-plane stability (SR less than 1.0) at 70% power with no effective in-plane AVB supports. This demonstrates TTW will not occur and SIPC limits will be met.
As discussed above, a SR of less than 1.0 indicates the SG tubes will be stable. To demonstrate margin, a probabilistic evaluation was performed assuming instability may occur at a calculated SR as low as 0.75. In the probabilistic approach, the number of effective AVB supports for each tube uses a probabilistic contact force distribution and criteria for determining whether a support is effective for a given contact force. A finite element model of tubes, AVBs, tube-to-AVB gaps, and support structures is used to calculate contact forces at AVB locations. Tube wear inputs to the finite element model are determined from actual wear observed in Units 2 and
- 3. Results from published technical literature, confirmed by benchmarking the FEI probability model to Unit 3 TTW, indicate that effective supports have a contact force that exceeds a specified value.
SRs are determined for each U-bend tube as a function of the number of consecutive ineffective supports and power level. The distributions of contact forces are calculated for each AVB location in the bundle. Tube wear at AVB locations decreases the contact force at those locations. The required contact force for an AVB support to be considered effective is calculated for each AVB location.
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SOutHERN CALIFORNIA 10/3/2012 EDISON° An EDISON INTER V.AtTIONAI O CompanN SONGS U2C17 Steam Generator Operational Assessment Using the above as inputs, Monte Carlo trials of a SG are simulated. The probability of instability is the number of trials where the SG contained one or more unstable tubes divided by the total number of trials.
TTW OA Using Tube-to-AVB Support Conditions and Contact Force Assessment Conclusion The deterministic approach demonstrates FEI will not occur. Using a SR of <1.0 at 70% power, the SIPC and AILPC are satisfied for an 18 month inspection interval. The probabilistic approach also demonstrates that there is safety margin in the planned inspection interval of 150 cumulative days at power. The approach demonstrates that if instability is assumed to initiate at a calculated SR of 0.75, rather than a value of 1.0, the SIPC acceptance standard is satisfied for approximately 8 months at 70% power.
3.3 "Traditional" Probabilistic OA for TTW The "Operational Assessment for SONGS Unit 2 SG for Upper Bundle Tube-to-Tube Wear Degradation at End of Cycle 16" [Appendix-C] uses established industry methods for assessing degradation mechanisms. This OA uses empirical models for degradation growth and engineering models for determining burst pressure and through-wall leak rates. The non-traditional aspect of this OA is to characterize the presence and severity of TTW degradation indications using wear indices defined by the state of AVB and TSP wear for a specific tube.
Unit 3 wear data establish the initiation and growth of TTW indications in Unit 2 SG. An empirical correlation using a wear index (a measure of the state of wear degradation in each tube) provides the method for comparing the Unit 3 wear to Unit 2. A probabilistic model representing the high-wear region of the tube bundle evaluates TTW for inspection interval. Tube burst and leakage probabilities are calculated by Monte Carlo simulation for initiation and growth of TTW.
Two OA cases are evaluated using the sizing techniques that define the Unit 3 TTW depths. Case 1 evaluates eddy current indication sizing using EPRI ECT Examination Technique Specification Sheet (ETSS) 27902.2 to establish the TTW depth distributions. In Case 2, the TTW depths were determined using a more representative calibration standard.
"Traditional" Probabilistic OA for TTW Conclusion The results for Case 1 indicate that the SIPC margin requirements are satisfied for an inspection interval of 16 months at 70% power. In Case 2, the SIPC margins are met for a cycle length of 17 months at 70% power. The results of this analysis are displayed in Figure 3-1. The figure identifies the probability of burst as a function of operating cycle length (inspection interval) and power.
The SIPC (Tube burst at 3xNOPD) is the limiting requirement for the inspection interval. The AILPC is satisfied since burst margins at 3xNOPD are maintained during the inspection interval.
This OA demonstrates there is a reasonable assurance that the SIPC and AILPC for TTW will be satisfied for 16 months at 70% power level.
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I SO uIHERN CALIFORNIA E'DISON0 An EDISSG*,
SeGra*tiorOpr17altionalAss Cempsnme SONGS U2C17 Steam Generator Operational Assessment 10/3/2012 Figure 3-1: Traditional Operational Assessment Results Operational Assessment for TTW for Cycle 17 0.16 0.14 0.12 0
m S0.1
'o 0.08 0.06 a.
0.04 0.02 0 W_~
1.00 1.05 1.10 1.15 1.20 1.25 1.30 1.35 1.40 1.45 1.50 1.55 1.60 Cycle Length, (Years at Power) 3.4 Deterministic TTW OA A deterministic TTW OA [Appendix-D] was completed for tube wear at AVBs and TTW. Tube wear projections for in-service tubes confirm the SG performance criteria will be satisfied during the inspection interval. Tube wear projections for plugged tubes confirm that severance will not occur during the inspection interval.
Evaluation of TTW of the two tubes in SG 2E-089 concludes the wear did not result from in-plane vibration of the tubes. ECT data demonstrate the tube wear indications at AVBs did not extend beyond the width of the AVBs in Unit 2. Wear extending beyond the width of AVBs was strongly correlated with Unit 3 tubes with TTW. In-plane SRs indicate that the two Unit 2 tubes with TTW are stable at 100% power. Pre-service inspection data indicates these two tubes were in close proximity prior to SG operation. The OA postulates that during operation out-of-plane vibration and/or turbulence caused the two tubes to wear.
The potential for in-plane vibration leading to TTW in Unit 2 is evaluated by calculating in-plane SRs. The OA methodology predicts in-plane vibration in Unit 3 and confirms the absence of in-plane vibration in Unit 2.
This OA projects the depth of indications to the next inspection using current inspection data. ATHOS results provide the T/H inputs for flow velocity, density, and void fraction along the length of the tube. These conditions are used in the Flow Induced Vibration analysis to generate the SR for out-of-plane and in-plane vibration of the Page 17
SOUTHERN CALIFORNIA 10/3/2012 EDISON An EDISON INTERV ATIOVAL.
Cumpan\\
SONGS U2C17 Steam Generator Operational Assessment 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. Presence of tube-to-AVB wear indicates an ineffective support.
The vibration analysis results and support conditions are used to make wear projections in the next operating cycle. This calculation is based on empirical test results and involves several input assumptions related to tube-to-AVB gap, the AVB twist, and the wear coefficient between the tube and AVB. The expected ranges of these parameters are known from test results, published data and experience. Wear depth projection is made taking into consideration the inspection results at the current outage. After setting the inputs to match the inspection results for a given indication, the wear calculations are extended to determine the projected wear depth at the next inspection.
Deterministic TTW OA Conclusion The OA demonstrates there is reasonable assurance that the SIPC and AILPC for TTW will be satisfied for 18 months at 70% power.
3.5 Evaluation of Leakage Integrity The AREVA non-TTW OA [Appendix-A], Section 6.3, discussed the evaluation of leakage integrity for both in-service and plugged tubes. Since the preparation of the AREVA non-TTW OA, SCE plugged five additional tubes.
The five additional tubes resulted in a negligible change to the postulated operational and accident-induced leakage attributed to all of the tube plugs using the methodology from the AREVA non-TTW OA.
The operational leakage performance criterion is met through the plant monitoring program. The accident-induced leakage performance criterion is met by projecting leakage attributed to all degradation mechanisms along with postulated plug leakage and comparing the projected leakage to the allowable accident-induced leak rate limit.
For tubes retumed to service, the onset of pop-through and leakage for axially oriented indications with limited circumferential extent - the nature of the degradation identified in the Unit 2 SGs - is coincident with burst. None of the identified degradation mechanisms in Unit 2 are projected to exceed the structural performance criteria prior to the next scheduled inspection. The accident-induced leakage is only attributed to postulated plug leakage through out-of-service tubes. There is reasonable assurance the accident-induced leakage performance criteria will not be exceeded prior to the next inspection of the Unit 2 SGs.
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J SOUTHERN CALIFORNIA 10/3/2012 EDISON0 An EDISOt)\\ h\\ TI'\\ " 7IO,',l 2 ('ompinx SONGS U2C17 Steam Generator Operational Assessment 3.6 Summary of All OA Conclusions The OA provide reasonable assurance, as required by NRC regulations that Unit 2 will operate safely at 70%
power for 150 cumulative days. The OAs (See Table 3-1) summarized in Sections 3.1 and 3.2 conclude the SIPC and AILPC are satisfied. The alternative OA methodologies summarized in Sections 3.3 and 3.4 also confirm the SG tube integrity will be maintained during the inspection interval.
Table 3-1: OA Approach and Results Comparison OA for Degradation TTW OA With No "Traditional" OA Description Mechanisms Other Effective AVB Probabilistic OA D
i Than TrW Supports Prepared for TTW Reference A
B C
D Appendix Degradation Mechanisms All but TTW TTW TTW TTW & AVB Wear Addressed Type Probabilistic Deterministic Probabilistic Deterministic Thermal Power 100%
70%
70%
70%
Assumption Resulting 18 months 18 months 16 months 18 months Inspection Interval As identified in Table 3-1 above, the OAs result in an acceptable inspection interval of at least 16 months at 70%
power. These OAs determined that at 70% power, the T/H conditions that cause FEI will be eliminated from the SONGS Unit 2 SGs. As discussed in Section 3.2, an additional probabilistic evaluation, assuming a calculated SR of 0.75, was performed to demonstrate margin. The approach assumes instability initiates at a calculated SR of 0.75 (rather than a SR of 1.0). Using this approach, the SIPC acceptance standard is satisfied for approximately 8 months at 70% power.
Accordingly, the 150 cumulative day inspection interval being implemented by SCE demonstrates substantial conservative margin using any of the OA methodologies.
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SOUTHERN CALIFORNIA 10/3/2012 EDISON0 An EDISON INTERNATIONAL Curnpany SONGS U2C17 Steam Generator Operational Assessment
4.0 REFERENCES
- 1.
Confirmatory Action Letter 4-12-001 - "San Onofre Nuclear Generating Station, Units 2 and 3, Comments to Address Steam Generator Tube Degradation," March 27, 2012
- 2.
SONGS Steam Generator Program, S023-SG-1
- 3.
SONGS Technical Specifications Sections 5.5.2.11, "Steam Generator (SG) Program," Amendment 204
- 4.
SONGS Technical Specifications Section 3.4.12, "RCS Operational Leakage," Amendment 204
- 5.
NEI 97-06, "SG Program Guidelines," Rev. 3, January 2011
- 6.
AREVA NP Document 51-9176667-001, "SONGS 2C17 & 3C17 Steam Generator Degradation Assessment."
- 7.
SCE Drawing S023-617-1 -D 116 Rev. 2, "San Onofre Nuclear Generating Station Unit 2 & 3 Replacement Steam Generators - Design Drawing - Tube Bundle 1/3" (MHI Drawing L5-04FU051 Rev.
1)
- 8.
SCE Drawing S023-617-1-D507 Rev. 5, "San Onofre Nuclear Generating Station Unit 2 & 3 Replacement Steam Generators - Design Drawing - Anti-Vibration Bar Assembly 1/9" (MHI Drawing L5-04FU 111 Rev. 2)
- 9.
SCE Drawing S023-617-1-D542 Rev. 9, "San Onofre Nuclear Generating Station Unit 2 & 3 Replacement Steam Generators - Design Drawing - Anti-Vibration Bar Assembly 7/9" (MHI Drawing L5-04FU 117 Rev. 9)
- 10.
SCE Drawing S023-617-1-D296 Rev. 3, "San Onofre Nuclear Generating Station Unit 2 & 3 Replacement Steam Generators - Design Drawing - Tube Support Plate Assembly 3/3" (MHI Drawing L5-04FU 108 Rev. 3)
- 11.
SCE Drawing S023-617-1-D17 Rev. 2, "San Onofre Nuclear Generating Station Unit 2 & 3 Replacement Steam Generators - Design Drawing - Tube Bundle 2/3" (MHI Drawing L5-04FU052 Rev.
1)
- 12.
SCE Drawing S023-617-1-Dl 18 Rev. 4, "San Onofre Nuclear Generating Station Unit 2 & 3 Replacement Steam Generators - Design Drawing - Tube Bundle 3/3" (MHI Drawing L5-04FU053 Rev.
3)
- 13.
AREVA NP Document 51-9182368-003, "SONGS 2C17 Steam Generator Condition Monitoring Report"
- 14.
EPRI Report 1019038, "Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines: Revision 3", November 2009.
Page 20
SCE ATTACHMENT 26
SOUTHERN CALIFORNIA njEDISON0 An L!)ISOQ\\
- 1T*R\\ '110:\\iL Compuny SONGS Unit 2 Return to Service Report ATTACHMENT 6 - Appendix A SONGS U2C17 Outage -
Steam Generator Operational Assessment
[Proprietary Information Redacted]
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Table of Contents Page SIG NATURE BLOCK.............................................................................................................................
2 RECO RD O F REVISIO N.......................................................................................................................
3 LIST O F TABLES..................................................................................................................................
5 LIST O F FIG URES................................................................................................................................
6 1.0 PURPOSE.................................................................................................................................
7 2.0 ABBREVIATIONS AND ACRO NYMS...................................................................................
7 3.0 SCO PE......................................................................................................................................
9 4.0 PERFO RMANCE CRITERIA..................................................................................................
9 5.0 BACKGRO UND.......................................................................................................................
10 5.1 Steam Generator Design...........................................................................................
10 5.2 Tube-to-Tube W ear Finding......................................................................................
10 5.3 Condition Monitoring Assessment Sum m ary.............................................................
11 6.0 O PERATIO NAL ASSESSM ENT...........................................................................................
15 6.1 Input Param eters......................................................................................................
15 6.2 Evaluation of Structural Integrity...............................................................................
18 6.2.1 AVB W ear and TSP W ear.......................................................................
18 6.2.2 Retainer Bar W ear..................................................................................
28 6.2.3 Tube-to-Tube W ear.................................................................................
28 6.2.4 Foreign Object W ear................................................................................
29 6.3 Evaluation of Leakage Integrity................................................................................
29 6.4 Secondary Side Internals.........................................................................................
30 7.0 O PERA TIONAL ASSESSM ENT CO NCLUSIO N..................................................................
30
8.0 REFERENCES
31 1814-AU651-M0157, REV. 0 Page 4 of 32 Page 4
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment 1.0 PURPOSE In accordance with the SONGS Steam Generator Program [18] and EPRI Steam Generator Integrity Assessment Guidelines [2], an operational assessment (OA) must be performed to ensure that steam generator (SG) tubing will meet established performance criteria for structural and leakage integrity during the operating period prior to the next planned inspection. The OA evaluates and projects tube degradation mechanisms which have affected the SGs to date. The performance criteria are defined in plant Technical Specifications [13] [14]. The performance criteria are based on NEI 97-06 [1] (see Section 4.0 below).
This report documents the OA performed during the SONGS Unit 2 C17 Refueling Outage. This OA addresses the detected tube degradation OTHER THAN tube-to-tube wear (TTW). TTW will be addressed in a separate OA [15]. This OA concludes that operation at full power for a full cycle of 1.577 Effective Full Power Years (EFPY) is justified based on detected tube degradation other than TTW. The OA for TTW [15] may prescribe operation at reduced power and/or a shorter inspection interval. The more conservative OA shall govern plant operation.
2.0 ABBREVIATIONS AND ACRONYMS The following table provides a listing of abbreviations and acronyms used throughout this report.
Table 2-1: Abbreviations and Acronyms Abbreviation or Definition Acronym 01C to 07C Tube Support Plate Designations for Cold Leg (7 Locations) 01H to 07H Tube Support Plate Designations for Hot Leg (7 Locations) 2E-088 Unit 2 Steam Generator 88 2E-089 Unit 2 Steam Generator 89 3E-088 Unit 3 Steam Generator 88 3E-089 Unit 3 Steam Generator 89 3 NOPD 3 Times Normal Operating Pressure Differential AILPC Accident Induced Leakage Performance Criterion ASME American Society of Mechanical Engineers AVB Anti-Vibration Bar C
Column CE Combustion Engineering CL or C/L Cold Leg CM Condition Monitoring DA Degradation Assessment ECT Eddy Current Testing EFPD Effective Full Power Days EOC End of Operating Cycle EPRI Electric Power Research Institute 1814-AU651 -MOI 57, REV. 0 Page 7 of 32 Page 7 1814-AU651-MO157, REV. 0 Page 7 of 32 Page 7
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment 3.0 SCOPE This evaluation pertains to the SONGS Unit 2 replacement steam generators which are reactor coolant system components. This report addresses all tube degradation mechanisms except for TTW. The OA for TTW will be addressed separately. In accordance with Reference 10, the OA documented in this report is required to be completed prior to plant entry into Mode 2 during start up from the current outage.
Note that the required SG condition monitoring (CM) assessment is documented in a separate report
[11] and is summarized below in Section 5.3.
4.0 PERFORMANCE CRITERIA The Unit 2 performance criteria, based on NEI 97-06 [1] are shown below. The structural integrity and accident-induced leakage criteria were taken from Section 5.5.2.11 [13] from the Unit 2 Technical Specifications. The operational leakage criterion was taken from Section 3.4.13 [14] of the Unit 2 Technical Specifications.
Structural Integrity Performance Criterion (SIPC): 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 cooldown, and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.
- Accident Induced Leakage Performance Criterion (AILPC): 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.
Operational Leakage Performance Criterion (OLPC): RCS operational leakage shall be limited to 150 gallons per day primary to secondary leakage through any one steam generator."
1814-AU651-MO157, REV. 0 Page 9 of 32 Page 9
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment 6.2 Evaluation of Structural Integrity The fundamental OA structural integrity criteria is that the projected worst case degraded tube for each existing degradation mechanism must meet the limiting structural performance parameter with a 95%
probability and 50% confidence [2]. Due to the relatively large number of AVB wear and TSP wear indications identified during the U2C1 7 outage, a probabilistic approach for analysis of the full bundle is necessary and was used to perform the OA for these mechanisms in accordance with Section 8.3 of Reference 2.
6.2.1 AVB Wear and TSP Wear With the finding of TTW in Unit 2, over 300 tubes were preventatively plugged in Unit 2 in the region deemed most susceptible to fluid-elastic instability. These tubes contained a significant number of AVB wear indications. Therefore, the number of AVB wear indications returned to service for the next operating interval is significantly less than the number of indications reported during the U2C1 7 inspection. The quantities of indications detected and returned to service are shown in Table 6-3.
The typical deterministic approach for performing an OA for wear is to identify the worst case flaw during the current outage, apply an upper bound growth rate to reflect growth during operation prior to the next inspection, and compare the resulting depth (i.e., the end-of-cycle (EOC) depth) to the CM limit curve. This is generally appropriate for degradation mechanisms which involve a small number of indications. However, when a large number of indications of a particular mechanism are expected to develop or are left in-service, it is not conservative to perform a deterministic OA evaluation of this type.
A probabilistic approach addresses the fact that the presence of a large number of in-service flaws increases the probability that one or more of the flaws will grow to a structurally significant depth by the EOC. Hence, this evaluation approach will yield a lower plugging limit for a SG which has a large population of flaws than would a typical deterministic approach. For the Unit 2 AVB wear and TSP wear, it is prudent to use a probabilistic approach. Consequently, the OA for AVB and TSP wear was performed using AREVA's full tube bundle probabilistic OA tool [6].
AREVA's full-bundle probabilistic OA tool was developed specifically for wear at support structures using the flaw model from Section 5.3.3 of Reference 3 and the Monte Carlo approach from Reference
- 2. This tool receives as key inputs: 1) the population of wear flaws identified, 2) the growth rate distribution anticipated during the next operating period, 3) Non-Destructive Examination (NDE)
Examination Technique Specification Sheet (ETSS) regression and uncertainty parameters, 4) a conservative estimation of the number of flaws present, but not detected, during the U2C1 7 outage inspection, and 5) newly initiated flaws expected during the next operating period. The tool "grows" each flaw that is left in-service by randomly sampling from the growth rate distribution, yielding one estimate of the EOC depth for each flaw. In addition, the entire population of expected newly initiated flaws is added to the EOC flaw population. From this EOC combined population the burst pressure of the worst case degraded tube is calculated and compared with the value of 3 NOPD. This process is repeated thousands of times (via a Monte Carlo process) in order to develop a probability of survival for the worst case degraded tube. This value must be at least 95% to satisfy the fundamental OA criteria.
If the result is less than 95%, a lower plugging limit must be implemented. The calculation also considers uncertainties associated with material strength, ECT sizing, the ratio of maximum flaw depth to structurally significant flaw depth, and the burst equation itself. Within the full bundle OA tool, AVB and TSP wear are evaluated using the EPRI Flaw Handbook [3] degradation model for axial part-throughwall degradation less than 1350 in circumferential extent, subjected to pressure loading of 3 NOPD. The basis for the use of this flaw model is discussed in the CM assessment [11].
1814-AU651-MO157, REV. 0 Page 18 of 32 Page 18
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment 6.2.1.1 Growth Rates One of the underlying assumptions implemented within the full bundle OA tool is that growth rates going forward are random with respect to the current wear depth. Because the Unit 2 SGs have operated for only one cycle and have only one in-service inspection, it is not known if or to what extent this behavior will manifest itself in the future. Consequently, AVB wear was evaluated as two separate populations: flaws >20%Through Wall (TW) in one population, and flaws <20%TW in the other population. Flaws >20%TW are assumed to continue to grow at a rate based on their growth during the first operating cycle. In the evaluation, this forces deeper flaws to grow at a higher rate. Likewise, flaws <20%TW are grown at a rate based on their growth during the first cycle. TSP wear flaws sized
>10%TW were similarly evaluated as a separate population from those sized <10%TW. Because there are very few TSP flaws sized >20%TW, a cutoff value of 1 0%TW was chosen. The selections of the breakpoints at 20%TW for AVB wear and 1 0%TW for TSP wear were based on AREVA Engineering experience and the numbers of flaws being returned to service in each depth category.
For AVB wear, 2E-088 has the limiting growth distribution. Therefore, the 2E-088 growth distribution was applied to both SGs. Due to the relatively small population of TSP wear indications, the growth rate distribution used in the OA was based on a combined data set from both SGs.
Prior to developing a growth rate distribution, the measured depths of the wear reported must be adjusted to account for the tendency of the EPRI sizing technique in ETSS 96004.1 to undersize flaw depth. This systematic sizing bias need not be considered when growth rate distributions are developed from two consecutive inspections because the sizing bias drops out when calculating depth change.
However, because only one inspection result is available this adjustment is necessary. Another way to understand this is to recognize that prior to initial operation of the SGs the actual flaw depths were zero.
To obtain an unbiased estimate of the growth during the first cycle of operation, the best estimate of actual depth during the U2C1 7 outage is required. Consequently, the through wall depths were adjusted upward by applying the sizing regression for ETSS 96004.1.
In addition, an adjustment was also made to account for the fact that, as the flaw deepens, the wear contact area increases. The volume of tube material removed is proportional to the wear work rate [19].
If the wear work rate is assumed to be constant (i.e., constant volume removal), then the growth rate, as measured in terms of through wall depth, will decrease because more tube material must be removed for a given increase in flaw depth. Based on an evaluation of tube geometry, with constant work rate and a second operating period of the same length as the first period, the growth in depth would be about 60% of the growth in the first cycle. Therefore, based on the assumption of constant volume loss, the first operating period growth rate could be adjusted by a factor of 0.6 to reflect the expectation of constant volume growth rate. For tapered wear such as that observed at the TSPs, this factor would be expected to be even lower since a tapered wear scar would also grow in length with increasing depth. For the OA, full credit for this growth rate reduction was not taken. Instead, a factor of 0.7 was applied to the AVB and TSP wear growth rates. Data from recent replacement steam generators with tube-to-support wear and multiple inspections support the constant volume loss assumption.
Because the upcoming operating period could be at a reduced power level due to TTW, the effect of power level on growth rate of AVB and TSP wear was also evaluated. A reduction in power level will change the velocities and densities on the secondary side of the tube bundle. The growth rate for wear indications is expected to be roughly proportional to the square of the dynamic pressure (where dynamic pressure = pV2; density times the square of velocity) [19]. As power level is decreased, the density increases. However, the increase in density is more than offset by the decrease in velocity.
1814-AU651-MO157, REV. 0 Page 19 of 32 Page 19
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Therefore, if there is any noticeable change in growth rate, it is expected to be a decrease in the observed growth rate. For this OA, no adjustment to the growth rate was made to account for any potential change in power level.
The growth rate distributions applicable to AVB wear and TSP wear are provided in Figure 6-1 through Figure 6-4. The AVB wear growth rates are based upon the data for 2E-088 which exhibited a slightly higher growth rate than 2E-089. For TSP wear, the data from the two SGs were combined due to the relatively low number of TSP wear indications.
6.2.1.2 Structural Depths and Lengths Structural depths and lengths were obtained for 22 AVB wear indications that were line-by-line sized with the +PointTM probe using EPRI ETSS 10908.4. These structurally equivalent dimensions correspond to a rectangular flaw which would burst at the same pressure as the measured flaw; determined using the methods described in Section 5.1.5 of Reference 3. The selection of indications for line-by-line sizing was based on depth of the indication with emphasis placed on the deeper indications. Since the results of the operational assessment are highly dependent on the deepest flaws returned to service, use of the structural lengths and depths from 22 of the deeper indications is justified. The structural depths were compared to the maximum depths for each flaw to obtain a ratio of structural to maximum depth. The ratio of structural depth to maximum depth ranged from a low of 0.76 to a high of 0.94. The average and the standard deviation of this ratio are 0.882 and 0.052, respectively. These values were used as inputs to the full bundle OA tool for the AVB wear evaluations.
Using the distribution of structural to maximum depth ratios, the OA tool randomly applies a ratio value, sampled from this normal distribution, to each postulated maximum depth at the EOC. The sampled ratio value is constrained to a minimum and maximum of 0.8 and 1.0, respectively. For TSP wear, a fixed value of 1.0 was conservatively used for the ratio of structural to maximum depth.
For the structural length, a fixed value of 0.7" was used for AVB wear. This is conservative since the width of the AVB is only 0.59". This conservative value was selected based on the observation that some of the AVB wear flaws in Unit 3 extended outside the confines of the AVB intersection. This phenomenon in Unit 3 is believed to be due to the in-plane motion of the affected tubes. No AVB wear indications in Unit 2 were observed to extend outside the AVB intersection. However, based on the Unit 3 observation and the fact that shallow TTW was observed in Unit 2, a conservative length of 0.7" was applied for AVB wear indications in Unit 2.
The structural length for TSP wear was set to a fixed value of 1.6" which is longer than the 1.38" thickness of the TSPs. Again, this conservative value was selected based on the observation that some of the TSP wear flaws in Unit 3 extended outside of the TSP intersection.
6.2.1.3 Initiation and Depth Distribution of New Indications Based on industry experience with other replacement SGs experiencing relatively large quantities of wear during early operation, it is likely that another operating period of equal length at SONGS would produce fewer new wear flaws than the number reported during the U2C17 inspection. However, for this OA it was assumed that the cumulative number of wear flaws will trend linearly with the cumulative operating EFPY. In addition, it was conservatively assumed that the depth distribution of new indications anticipated after a full fuel cycle of operation will be the same as that observed during the U2C1 7 outage for the flaw category under evaluation (i.e., AVB wear >20%TW, AVB wear <20%TW, etc.). Again, the OA for AVB and TSP wear is being performed as if a full cycle of operation at 100%
power will occur prior to the next inspection. For each category, the flaw population used to model growth was also used to model new flaw size. Figure 6-5 and Figure 6-6 provide histograms illustrating the overall U2C1 7 depth distribution of each degradation mechanism.
1814-AU651-MO157, REV. 0 Page 20 of 32 Page 20
A AREVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment 6.2.1.4 Results of Probabilistic OA for AVB Wear and TSP Wear The fundamental OA structural integrity criterion is that the projected worst case degraded tube for each existing degradation mechanism must meet the limiting structural performance parameter with a 95% probability and 50% confidence. The results of the probabilistic OA for AVB wear and TSP wear are provided in Table 6-3. The values provided in the table represent the projected probability of non-burst for the entire population of flaws in the specified group. These values compare directly with the 95/50 OA criteria. Note that the combined probability of non-burst is simply the product of the probabilities for the different groups evaluated (e.g., 0.9997 x 0.9921 x 0.9996 x 0.9992 = 0.9906). In all cases, the OA structural integrity criteria for AVB and TSP wear is satisfied for a full cycle of operation at 100% reactor power. The operational assessment for TTW will be documented separately.
In the TTW OA, the permissible reactor power level and inspection interval may be reduced from that evaluated in this document. The more conservative OA shall govern plant operation.
Table 6-3: Projected Probability of Non-Burst End-of-Cycle No. of Indications No. of Indications Tube Degradation Flaw Detected Returned to Service Probability of Non-Burst*
Category 2E-088 2E-089 2E-088 2E-089 2E-088 2E-089 AVB Wear >20%
66 64 24 22 0.9997 0.9996 AVB Wear <20%
1691 2527 1157 1407 0.9921 0.9902 TSP Wear >10%
77 59 68 31 0.9996 0.9997 TSP Wear,;10%
148 80 127 49 0.9992 0.9996 AVB & TSP ar Cobied 1982 2730 1376 1509 0.9906 0.9891 Wear Combined
- Results shown are for a full cycle of operation (1.577 EFPY) at full power. The operational assessment for TTW will be documented separately. In the TTW OA, the permissible reactor power level and inspection interval may be reduced from that evaluated in this document. The more conservative OA shall govern plant operation.
1814-AU651-MOI 57, REV. 0 Page 21 of 32 Page 21 1814-AU651-MO157, REV. 0 Page 21 of 32 Page 21
A AREVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Figure 6-1: Adjusted Growth Rate Distribution, AVB Wear >20%TW 1
SG88 AVB >20%
0.8 SG89 AVB >20%
Both SG AVB >20%
0.6 E
0.4 0.2 0
o-O 0
2 4
6 8
10 12 14 16 Adjusted Growth Rate (Percent Throughwall per EFPY) 1814-AU651-MO1 57, REV. 0 Page 22 of 32 Page 22 1814-AU651-MO157, REV. 0 Page 22 of 32 Page 22
A AREVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Figure 6-2: Adjusted Growth Rate Distribution, AVB Wear <20%TW 1
SG88 AVB <=20%
0.8 SG89 AVB <=20%
Both SG AVB <=2096 0.6 E 0.4 0.2 0
0 1
2 3
4 5
6 7
8 9
10 Adjusted Growth Rate (Percent Throughwall per EFPY) 1814-AU651-MO1 57, REV. 0 Page 23 of 32 Page 23 1814-AU651 -M01 57, REV. 0 Page 23 of 32 Page 23
A AREVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Figure 6-3: Adjusted Growth Rate Distribution, TSP Wear >10%TW 1
0.8 0.6 0.4 0.2 0
0 2
3 4
5 6
7 8
9 Adjusted Growth Rate (Percent Throughwall per EFPY) 10 1814-AU651-M0157, REV. 0 Page 24 of 32 Page 24
A AREVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Figure 6-4: Adjusted Growth Rate Distribution, TSP Wear <10%TW 1
SG8R TSP <=10%
0.8 SG--
89 TSP <=10%
0.6 E
0.4 0.2 0
0 1
2 3
4 5
6 7
8 9
10 Adjusted Growth Rate (Percent Throughwall per EFPY) 1814-AU651 -MOl 57, REV. 0 Page 25 of 32 Page 25 1814-AU651-MO157, REV. 0 Page 25 of 32 Page 25
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Figure 6-5: AVB Wear Depth Histogram 800 700 600 500*-
- 400
- 1 300 200
<ý6 8
10 E SG88 0 SG89 mmN 12 14 16 18 20 22 24 26 28 30 32 AVB Wear Depth In Percent Throughwall 100 0
34 36
>36 1814-AU651-MOI 57, REV. 0 Page 26 of 32 Page 26 1814-AU651-MO157, REV. 0 Page 26 of 32 Page 26
A AR EVA Document No.: 51-9182833-002 SONGS U2C17 Outage - Steam Generator Operational Assessment Figure 6-6: TSP Wear Depth Histogram 100 80
- 5G88 Q SG89 g60 VE Is Z 40 20
<=6 8
10 12 14 16 18 20 22 24 26 28 30 32 34 36
>36 TSP Wear Depth in Percent Throughwall 1814-AU651-MOI 57, REV. 0 Page 27 of 32 Page 27 1814-AU651-MO157, REV. 0 Page 27 of 32 Page 27
SCE ATTACHMENT 27
SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONAL Company Proprietary Information Withhold from Public Disclosure Richard 1. St. Onge Director. Nuclear Regulatory Affairs and Emergency Planning January 9, 2013 10 CFR 50.4 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
Subject:
Docket No. 50-361 Response to Request for Additional Information (RAI 15)
Regarding Confirmatory Action Letter Response (TAC No. ME 9727)
San Onofre Nuclear Generating Station, Unit 2
References:
- 1. Letter from Mr. Elmo E. Collins (USNRC) to Mr. Peter T. Dietrich (SCE), dated March 27, 2012, Confirmatory Action Letter 4-12-001, San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation
- 2. Letter from Mr. Peter T. Dietrich (SCE) to Mr. Elmo E. Collins (USNRC), dated October 3, 2012, Confirmatory Action Letter - Actions to Address Steam Generator Tube Degradation, San Onofre Nuclear Generating Station, Unit 2
- 3. Letter from Mr. James R. Hall (USNRC) to Mr. Peter T. Dietrich (SCE), dated December 26, 2012, Request for Additional Information Regarding Response to Confirmatory Action Letter, San Onofre Nuclear Generating Station, Unit 2
Dear Sir or Madam,
On March 27, 2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) (Reference 1) to Southern California Edison (SCE) describing actions that the NRC and SCE agreed would be completed to address issues identified in the steam generator tubes of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3. In a letter to the NRC dated October 3, 2012 (Reference 2), SCE reported completion of the Unit 2 CAL actions and included a Return to Service Report (RTSR) that provided details of their completion.
By letter dated December 26, 2012 (Reference 3), the NRC issued Requests for Additional Information (RAIs) regarding the CAL response. Enclosure 2 of this letter provides the response to RAI 15. of this submittal contains proprietary information. SCE requests that this proprietary enclosure be withheld from public disclosure in accordance with 10 CFR 2.390(a)(4). provides a notarized affidavit from Mitsubishi Heavy Industries (MHI), which sets forth the basis on which the information in Enclosure 2 may be withheld from public disclosure Proprietary Information Withhold from Public Disclosure Decontrolled Upon Removal From Enclosure 2 P.O. Box 128 San Clemente, CA 92672 1,7.07
Proprietary Information Withhold from Public Disclosure Document Control Desk January 9, 2013 by the NRC and addresses with specificity the considerations listed by paragraph (b)(4) of 10 CFR 2.390. Proprietary information identified in Enclosure 2 was extracted from the source document MHI Report L5-04GA561, Retainer Bar Tube Wear Report, which is addressed in the affidavit. Enclosure 3 provides the non-proprietary version of Enclosure 2.
There are no new regulatory commitments contained in this letter. If you have any questions or require additional information, please call me at (949) 368-6240.
Sincerely,
Enclosures:
- 1. Notarized Affidavit
- 2. Response to RAI 15 (Proprietary)
- 3. Response to RAI 15 (Non-proprietary) cc:
E. E. Collins, Regional Administrator, NRC Region IV R. Hall, NRC Project Manager, San Onofre Units 2 and 3 G. G. Warnick, NRC Senior Resident Inspector, San Onofre Units 2 and 3 R. E. Lantz, Branch Chief, Division of Reactor Projects, NRC Region IV Proprietary Information Withhold from Public Disclosure Decontrolled Upon Removal From Enclosure 2
ENCLOSURE 1 Notarized Affidavit
MITSUBISHI HEAVY INDUSTRIES, LTD.
AFFIDAVIT I, Jinichi Miyaguchi, state as follows:
- 1. I am Director, Nuclear Plant Component Designing Department, of Mitsubishi Heavy Industries, Ltd. ("MHI"), and have been delegated the function of reviewing the referenced MHI technical documentation to determine whether it contains information that should be withheld from public disclosure pursuant to 10 C.F.R. § 2.390 (a)(4) as trade secrets and commercial or financial information that is privileged or confidential.
- 2.
In accordance with my responsibilities, I have determined that the following MHI documents and drawings contain MHI proprietary information that should be withheld from public disclosure pursuant to 10 C.F.R. § 2.390 (a)(4). The drawings in their entirety are proprietary and those pages of the documents containing proprietary information have been bracketed with an open and closed bracket as shown here "[ ]" / and should be withheld from public disclosure.
MHI documents and drawings Document: L5-04GA561, L5-04GA564, L5-04GA571, L5-04GA585, L5-04GA591 Drawings: L5-04FU101 thru 108
- 3. The information identified as proprietary in the enclosed document has in the past been, and will continue to be, held in confidence by MHI and its disclosure outside the company is limited to regulatory bodies, customers and potential customers, and their agents, suppliers, and licensees, and others with a legitimate need for the information, and is always subject to suitable measures to protect it from unauthorized use or disclosure.
- 4.
The basis for holding the referenced information confidential is that it describes unique design, manufacturing, experimental and investigative information developed by MHI and not used in the exact form by any of MHI's competitors.
This information was developed at significant cost to MHI, since it is the result of an intensive MHI effort.
- 5. The referenced information was furnished to the Nuclear Regulatory Commission
("NRC") in confidence and solely for the purpose of information to the NRC staff.
- 6. The referenced information is not available in public sources and could not be gathered readily from other publicly available information.
Other than through the provisions in paragraph 3 above, MHI knows of no way the information could be lawfully acquired by organizations or individuals outside of MHI.
- 7.
Public disclosure of the referenced information would assist competitors of MHI in their design and manufacture of nuclear plant components without incurring the costs or risks associated with the design and the manufacture of the subject component. Therefore, disclosure of the information contained in the referenced document would have the following negative impacts on the competitive position of MHI in the U.S. and world nuclear markets:
A.
Loss of competitive advantage due to the costs associated with development of technologies relating to the component design, manufacture and examination.
Providing public access to such information permits competitors to duplicate or mimic the methodology without incurring the associated costs.
B.
Loss of competitive advantage of MHI's ability to supply replacement or new heavy components such as steam generators.
I declare under penalty of perjury that the foregoing affidavit and the matters stated therein are true and correct to the best of my knowledge, information and belief.
Executed on this 2
day of
('I U
. 2012.
Jinichi Miyaguchi, U
Director-Nuclear Plant Component Designing Department Mitsubishi Heavy Industries, LTD 22 0 AUG. -2, 2012J n
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i" Sworn to and subscribed Before me this.
day of A 3U ic 2012 Notary Public My Commission Expires
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Registered Number 2 2 0 Date 2.2 12 NOTARIAL CERTIFICATE This is to certify that JINICHI MIYAGUCHI, Director-Nuclear Plant Component Designing Department MITSUBISHI HEAVY INDUSTRIES, LTD has affixed his signature in my very presence to the attached document.
MASAHIKO KUBOTA Notary 44 Akashimachi,.Chuo-Ku, Kobe, Japan Kobe District Legal Affairs Bureau
ENCLOSURE 3 SOUTHERN CALIFORNIA EDISON RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING RESPONSE TO CONFIRMATORY ACTION LETTER DOCKET NO. 50-361 TAC NO. ME 9727 Response to RAI 15 (NON-PROPRIETARY)
Page 1
RAI 15
In Reference 1, Section 8.3.2, page 48 - How will the continued integrity of the non-stabilized, preventively-plugged tubes adjacent to the retainer bars be ensured? "Integrity" in this context refers to the tubes remaining intact and unable to cause damage to adjacent tubes.
RESPONSE
The integrity of the non-stabilized, preventively-plugged tubes is ensured by limiting the wear resulting from retainer bar vibration. The limited vibration amplitude of the tubes and retainer bars, combined with stabilizer deployment, prevents developing a displacement/wear geometry that could sever any of the tubes adjacent to retainer bars, either in the short term or long term.
Wear mechanism of tubes adjacent to retainer bars There are 94 tubes in each steam generator adjacent to retainer bars. Each of these tubes has 7 hot leg tube support plate (TSP) support locations, 12 anti-vibration bar (AVB) support locations, and 7 cold leg TSP support locations. All 188 of these tubes in the Unit 2 steam generators (94 tubes per steam generator) were examined. No evidence of wear was found on any of these tubes at AVB and TSP intersections. Retainer bar wear was found on a total of 6 tubes with 7 wear locations (one tube in SG 2E-089, Row 120 Column 132, had retainer bar wear at two retainer bar locations, remaining 5 tubes had retainer bar wear at one location).
The maximum wear depth of 90% tube wall thickness was found on SG 2E-089, Row 119 Column 133, in a location adjacent to a retainer bar.
The cause of tube wear at retainer bar locations has been evaluated by MHI. Wear marks at the AVB intersections would be evidence of out-of-plane displacement of the U-bend. Wear marks on the TSP intersections, especially the top TSP, would be evidence of in-plane displacement of the U-bend. The absence of wear at the AVBs and TSPs of all 188 tubes adjacent to the retainer bar is evidence that the tubes adjacent to the retainer bar are not vibrating. MHI concluded that the tube wear adjacent to retainer bars is caused by retainer bar vibration rather than tube vibration.
During steam generator operation, retainer bars are subject to flow induced vibration. MHI's analysis of the dynamic response of retainer bars to operating conditions found that the vibration amplitude is limited and much smaller than the tube diameter of 0.75". Consequently, these retainer bar motions may damage the wall of an adjacent tube but cannot sever these tubes. The retainer bar natural frequencies and vibration amplitudes for the first five modes are shown in Table 1 and the lowest three mode shapes are shown in Figure 1. The first mode moves in a direction parallel to the tubes. The second and third retainer bar modes are perpendicular to adjacent tubes. The maximum amplitude of the first mode due to steam generator operating conditions is between [
]. Maximum amplitude of the second mode during steam generator operating conditions is between [
]. All higher modes have negligible vibration amplitudes.
Page 2
Table 1 - Retainer Bar Natural Frequencies and Vibration Amplitudes Mode 1 Mode 2 Mode 3 Mode 4 Mode 5 Frequency, Hz
-1 Amplitude Figure 1 - Retainer Bar Vibration Mode Shapes Page 3
Integrity of tubes adjacent to retainer bars The six tubes with retainer bar wear indications in Unit 2 steam generators have been plugged, regardless of wear depth. To ensure that these tubes remain intact, Y2" diameter braided stainless steel cable stabilizers have been installed in these six tubes.
As a preventive measure to ensure that no in-service tubes are subject to retainer bar wear, all tubes adjacent to retainer bars have been plugged.
Additionally, stabilizers have been deployed in six tubes at each retainer bar. Figure 2 shows a typical deployment. Three tubes on each side of the retainer bar have been stabilized: one tube near the center of the retainer bar and two tubes near both ends of the retainer bar. The stabilizers will arrest tube wear at the wear surface of the stabilizers. Since the tubes adjacent to retainer bars have no evidence of significant vibration and the retainer bar vibration amplitude is limited, the stabilizer deployment pattern prevents any possible retainer bar or tube displacement/wear geometry that could sever any of the tubes adjacent to the retainer bars.
o In-service tubes Stabilized, preventively-plugged tubes
- Non-stabilized, preventively-plugged tubes Note:Additionally, all tubes with retainer bar wear were stabilized.
Figure 2 - Typical Stabilizer Deployment to Arrest Retainer Bar Wear The integrity of the non-stabilized, preventively-plugged tubes is ensured by the limited vibration amplitude of the tubes and retainer bars, along with the number and arrangement of stabilized, preventively-plugged tubes at each retainer bar.
Future inspections of retainer bars The steam generator retainer bar wear issue has been entered into the SONGS Corrective Action Program (CAP). An effectiveness review requires visual inspection of the smaller diameter retainer bars and welds during the upcoming Unit 2 mid-cycle outage. In addition, all in-service tubes will be inspected by eddy current testing in the upcoming Unit 2 mid-cycle outage. This inspection will confirm that the non-stabilized, preventively-plugged tubes adjacent to the retainer bars are not damaging adjacent in-service tubes.
Page 4
SCE ATTACHMENT 28
i~;~~~\\:FJI E Ui5TSORN
An EDISON INTERNATIONAL Company January 21, 2013 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
Subject:
Docket No. 50-361 Response to Request for Additional Information (RAI 11)
Regarding Confirmatory Action Letter Response (TAC No. ME 9727)
San Onofre Nuclear Generating Station, Unit 2 Richard J. 81. Onge Director, Nuclear Regulatory Affairs and Emergency Planning 10 CFR 50.4
References:
- 1. Letter from Mr. Elmo E. Collins (USNRC) to Mr. Peter T. Dietrich (SCE), dated March 27, 2012, Confirmatory Action Letter 4-12-001, San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation
- 2. Letter from Mr. Peter T. Dietrich (SCE) to Mr. Elmo E. Collins (USNRC), dated October 3, 2012, Confirmatory Action Letter - Actions to Address Steam Generator Tube Degradation, San Onofre Nuclear Generating Station, Unit 2
- 3. Letter from Mr. James R. Hall (USNRC) to Mr. Peter T. Dietrich (SeE), dated December 26,2012, Request for Additional Information Regarding Response to Confirmatory Action Letter, San Onofre Nuclear Generating Station, Unit 2
Dear Sir or Madam,
On March 27,2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) (Reference 1) to Southern California Edison (SCE) describing actions that the NRC and SeE agreed would be completed to address issues identified in the steam generator tubes of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3. In a letter to the NRC dated October 3, 2012 (Reference 2), SCE reported completion of the Unit 2 CAL actions and included a Return to Service Report (RTSR) that provided details of their completion.
By letter dated December 26, 2012 (Reference 3), the NRC issued Requests for Additional Information (RAls) regarding the CAL response. Enclosure 1 of this letter provides the response to RAI 11.
P.O. Box 128 San Clemente, CA 92672
Document Control Desk January 21, 2013 There are no new regulatory commitments contained in this letter. If you have any questions or require additional information, please call me at (949) 368-6240.
Sincerely,
Enclosures:
1.
Response to RAI 11 cc:
E. E. Collins, Regional Administrator, NRC Region IV J. R. Hall, NRC Project Manager, SONGS Units 2 and 3 G. G. Warnick, NRC Senior Resident Inspector, SONGS Units 2 and 3 R. E. Lantz, Branch Chief, Division of Reactor Projects, NRC Region IV
ENCLOSURE 1 SOUTHERN CALIFORNIA EDISON RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING RESPONSE TO CONFIRMATORY ACTION LETTER DOCKET NO. 50-361 TAC NO. ME 9727 Response to RAI 11 Page 1
RAI11 Please submit an operational impact assessment for operation at 700/0 power. The assessment should focus on the cycle safety analysis and establish whether operation at 70%
power is within the scope of SCE's safety analysis methodology, and that analyses and evaluations have been performed to conclude operation at 70%
power for an extended period of time is safe.
The evaluation should also demonstrate that the existing Technical Specifications, including limiting conditions for operation and surveillance requirements, are applicable for extended operation at 700/0 power.
RESPONSE
Note: This response includes information requested in RAI 14 associated with the operational impact assessment for operation at 700~ power. RAI 14 states: "Provide a summary disposition of the U2C17 calculations relative to the planned reduction in power operation."
SCE has evaluated the extended reduced power operation for its impacts on the Unit 2 Cycle 17 reload core design and safety analysis. The power levels evaluated range from 50%
to 100%
rated thermal power, which bounds the planned operation at the 700/0 power level. The assessments were performed in accordance with NRC approved SONGS reload methodology and topical reports referenced in the UFSAR and Technical Specification (TS) 5.7.1.5, and the SONGS Core Reload Analyses and Activities Checklist procedure.
The impacts of extended reduced power operation on Unit 2 Cycle 17 core design and reload analyses, including UFSAR Chapter 15 safety analyses are summarized in Table 1, the impact assessment table. The impact assessment table is organized consistent with the SONGS Core Reload Analyses and Activities Checklist procedure.
For each analysis, the Reload Checklist item number is listed in the second column from the left; when applicable, the second column also lists the UFSAR Chapter 15 safety analysis section number. The determination of impact for each analysis is summarized in the right column of the table.
Safety Analysis Methodology The NRC approved safety analysis methods, as described in TS 5.7.1.5, are used to establish the core operating limits specified in the Core Operating Limits Report (COLR) which encompass from Mode 6 up to Mode 1 operation at the rated thermal power. Therefore, operating at the 70%
power level is within the scope of SCE safety analysis methodology. No change to the safety analysis methodology is required for extended reduced power operation.
Safety Analysis The reload and safety analyses determined to be impacted by extended reduced power operation were re-analyzed. The conclusions of the reload analyses, including safety analyses, for extended reduced power operation are as follows: (1) All safety analyses results meet the established acceptance criteria, and (2) The radiological dose consequences for all safety analyses remain bounded by the dose consequences reported in the UFSAR.
Page 2
Technical Specifications The existing TS, including limiting conditions for operation (LCD) and surveillance requirements, are applicable for extended operation at 70%
power. The impact assessment for TS surveillance requirements is described in the following section.
Impact Assessment for Technical Specification Surveillance Requirements The TS surveillance requirements were evaluated for the impacts of reduced power operation.
The evaluation concluded all TS surveillance requirements under the reactor core design and monitoring program that would have been performed at approximately 82%
power or at full power will be performed with the plant operating at approximately 70%
power. The evaluation is summarized in Table 2.
Two surveillance procedures related to monitoring Reactor Coolant System (RCS) flow were revised to (1) reduce the minimum power required to perform the surveillances from 85%
to 680/0 power, and to (2) account for the slightly increased RCS flow uncertainty at reduced power operation. No other surveillances were identified to be impacted by plant operation at 700/0 power.
Conclusions Extended reduced power operation at 70%
powerhas been evaluated and determined to be acceptable with respect to Unit 2 Cycle 17 reload core design and safety analysis. Reload analyses needed to support reactor startup and operation at 70%
power have been completed.
All TS LCD and surveillance requirements under the reactor core design and monitoring program normally performed at or above 70%
power will be performed with the plant operating at approximately 70%
power. The above evaluations demonstrate that the existing TSs, including limiting conditions for operation and surveillance requirements, are applicable for extended operation at 70%
power.
Page 3
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 1 0.1 Reload Ground Rules (RGR) Review No change to analysis is required. No change to Rated Thermal Power (RTP). RGR still addresses 0% to 100%
RTP operation. RGR addresses the full range of power independent and power dependent operating parameters, including those applicable at reduced power. The RGR Analysis Value defines the maximum or minimum value which must be bounded in the safety analysis. The number is not necessarily equivalent to the value used in an analysis (or Technical Specification) but will be conservative with respect to that value. The RGR Analysis Value includes applicable uncertainties and margins for which the safety analyses must be bounding.
2 1.1.3 Design Models and Depletions Re-analysis was performed to determine impact, and all results were acceptable.
Calculation revised to document depletion at 50%
power from Beginning of Cycle (BOC) to End of Cycle (EOC) and comparison to 100% power. SONGS Unit 2 Cycle 17 (S2C17) at 50%
power results in radial power distributions (at the same power level and burnup) essentially identical to depleting the core at 100% power.
As the radial power distributions and distortion factors have been determined to be valid, no downstream analyses are impacted.
Impact of extended reduced power operation on generic axial shapes and scram curves is addressed in Item 10 (1-0 HERMITE model.)
3 1.1.4 Design Parameters and FR Versus No change to analysis is required. Radial power distributions and generic axial shapes Power remain applicable. Individual Control Element Assembly (CEA) worth, CEA bank worth, scram worth, peaking factors, distortion factors that are strongly dependent on the radial power distribution remain applicable. Extended reduced power operation results in less Pu-239 inventory. As such, generic bounding parameters (i.e., Fuel Temperature Coefficient (FTC), Moderator Temperature Coefficient (MTC), kinetics parameters) remain applicable. Critical Boron Concentrations (CBC) at Beginning of Cycle (BOC) are not affected. CBC at End of Cycle (EOC) is similar. Therefore, bounding boron concentration requirements and Inverse Boron Worths (IBW) are not impacted. Representative design parameter and Fr values for Reload Analysis Report (RAR) are not impacted.
Page 4
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 4 1.1.5 Physics Input to LOCA, TORC, and No change to analysis is required for the physics inputs to LOCA analysis and TORC FATES Analysis (including Pin code analysis. BOC, limiting boron concentration, reactivity are not affected. Radial Census) power distribution and peaking data remain applicable. Generic LOCA and TORC input parameters remain applicable.
Re-analysis was performed for the physics input to Fuel Performance Analysis (FATES) code analysis. Radial fall-off curves, Fr, and fast flux data were regenerated for reduced power operation. Generic axial shapes remain applicable.
5 1.1.6 Physics Input to Fuel Mechanical Re-analysis was performed to determine impact, and all results were acceptable.
Design Calculation revised to provide power history data for AREVA Lead Fuel Assembly (LFA) mechanical design analysis. Also updated maximum core residence time for Westinghouse analysis. Other generic parameters for Westinghouse mechanical design analysis remain applicable due to similar radial power distribution.
6 1.1.7 Physics Input to ASGT No change to analysis is required. Physics Input to Asymmetric Steam Generator Transient (ASGT) is performed at EOC with most negative Technical Specification MTC.
Calculations performed at multiple power levels (900/0, 70%,50 %
, and 200~). Due to similar power distributions, results remain applicable.
7 1.1.8 Physics Input to Post-Trip Steam Line No change to analysis is required. Analysis performed at EOC. Radial power distributions Break Analysis (at the same power level and burnup) are essentially identical. The MTC is tuned to the most negative Tech Spec value (-3.7E-4 LlklkloF). Cooling down adds reactivity. More reactivity is added cooling from 100% power (higher T-fuel and T-mod) than reduced power to lower temperatures (e.g., 545°F, 300°F, 200°F, 68°F) 8 1.1.9 Physics Input to CEA Ejection Analysis No change to analysis is required. Physics data in this analysis were generated at multiple power levels and the reduced power operating range is covered. Since the reduced power operation results in power distributions essentially identical to those from 100% power operation, the data generated from the original analysis are applicable to reduced power operation.
9 1.1.10 Physics Input to CEA Withdrawal No change to analysis is required. Calculations performed at multiple power levels.
Radial power distributions (at the same power level and burnup) are essential identical.
CEA worth remains applicable since it is strongly dependent on power distribution.
Limiting axial power shapes from axial shape index (ASI) search remain applicable.
Page 5
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 10 1.1.11 1-0 HERMITE Model Re-analysis was performed to determine impact, and all results were acceptable. Analysis is revised to establish applicability of the generic axial shapes used in the design analyses and applicability of the SCRAM curves used in the design analyses. Analysis also shows that depletion at reduced power leads to essentially the same limiting shapes from ASI search as those selected for the analyses of the design depletions.
11 1.1.12 Physics Input to Steam Line Break No change to analysis is required. This EOC event begins at 0%
power. Radial power Return-to-Power for Cycle N-1 distributions (at the same power level and burnup) are essentially identical.
Configuration 12 1.1.13 FRVersus Temperature for Cooldown No change to analysis is required. Bounding distortion factors were determined based on Events multiple CEA configurations, temperature ranges at BOC and EOC. Radial power distributions (at the same power level and burnup) are essentially identical.
13 1.1.14 Boron Requirement for SITs and No change to analysis is required. The case run for this calculation is performed at hot BAMU Tanks zero power (HZP). The Xenon starting condition is Hot Full Power (HFP) which is conservative.
14 1.1.15 LOCA and Non-LOCA Source Term No change to analysis is required. This analysis tests the Cycle 17 conditions of interest against the parameters required for applicability of the LOCA and Alternative Source Term (AST) source terms. The power level is used as a maximum not to be exceeded. Running Cycle 17 at reduced power results in less "short half-life" nuclides. Increase in "long half-life" nuclides due to extended calendar time is bounded by the lower production from extended reduced power.
15 1.1.16 Tritium Production No change to analysis is required. Reduced power results in a decrease in tritium production. The analysis at 100% power is conservative.
16 1.1.17 STAR Physics Verification No change to analysis is required. This analysis uses BOC (HZP) conditions (Mode 3) for an assessment for S2C17 inclusion in the Startup Test Activity Reduction (STAR) program.
17 1.1.18 Digital Setpoints Physics Data No change to analysis is required. The case sets encompass LCO and Limiting Safety System Settings (LSSS) ASI ranges. Power level does not impact axial shapes significantly, so reduced powers are covered by the case set.
Page 6
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 18 1.1.19 Physics RAR Inputs Re-analysis was performed to determine impact, and all results were acceptable. RAR has been updated to reflect actual Cycle 16 EOC burnup and Cycle 17 reduced power operation.
19 1.2.1 Fuel Performance Analysis (FATES)
Re-analysis was performed to determine impact, and all results were acceptable.
Reduced power results in fuel performance data that is not bounded when compared to the Generic Fuel Performance data generated for ZIRLOTM in Cycle 14 (data used in LOCA Analysis). A revision to the Fuel Performance and Setpoints Analyses was performed to determine the appropriate penalty factors such that the Generic Fuel Performance data remained bounding.
20 1.2.2 T-H Input Summary No change to analysis is required. Calculation is a collection of input data that are not impacted by reduced power.
21 1.2.4 T-H Limiting Assembly and CETOP No change to analysis is required. Power is not an input. Calculation is a benchmark of Benchmarking Analysis CETOP to TORC computer codes at reference departure from nucleate boiling (DNBR) points rather than a benchmark at a given power. This benchmark is mainly driven by power distributions from physics. Physics Models & Depletions has validated the power distributions used in the original calculation.
22 1.2.5 Mechanical Design Analysis (Fuel Re-analysis was performed to determine impact, and all results were acceptable.
Vendor)
Westinghouse performed calculations to determine the impact of reduced power on the fuel mechanical design.
AREVA performed calculations to determine the impact of reduced power on the Lead Fuel Assembly fuel mechanical design.
23 1.2.6 Power Operating Limit Partial No change to analysis is required. The calculation is driven by a large family of axial Derivative Verification shapes, which are not impacted by the power reduction.
24 1.2.7 Setpoints Input Summary Re-analysis was performed to determine impact, and all results were acceptable.
Calculation has been revised to address the increased reactor coolant system (RCS) flow uncertainty at reduced power.
25 1.2.8 RCS Flow Uncertainties Re-analysis was performed to determine impact, and all results were acceptable. Has been reanalyzed. RCS flow uncertainty increases due to reduced delta-temperature and increased secondary calorimetric power uncertainty.
Page 7
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 26 1.2.9 Fuel Mechanical Design Verification No change to analysis is required. The objective of the fuel mechanical design verification calculation is to document the design of the fuel based on the fuel vendor Bill of Materials, Design Drawings and the design and material specifications transmitted from the fuel vendor. Reduced power operation has no impact on this analysis.
27 1.2.11 Secondary Calorimetric Power No change to analysis is required. Intermediate powers were explicitly analyzed in the Uncertainty original calculation.
28 1.2.12 Delta-T/Turbine Power Uncertainties No change to analysis is required. The analysis uses a reference power error of 1.30/0 at full power. The increase in reference power (i.e., secondary calorimetric power) associated with performing delta-Uturbine power calibrations at reduced power would increase the uncertainties. The bounding results include -0.500/0 of conservatism; therefore, the analysis of record (AOR) remains bounding. Intermediate powers were explicitly analyzed in the original calculation.
29 1.2.13 Cycle Independent Data and Setpoints No change to analysis is required. CIDSAL provides cycle independent values to use or to Assumptions List (CIDSAL) be verified in downstream analyses. Reduced power operation does not impact the requirements for downstream analysis verification. None of the calculations explicitly performed in the analysis section are dependent upon nominal plant operating conditions or the power shapes/distributions at reduced power operation.
30 1.2.16 Core Protection Calculator (CPC)
No change to analysis is required. Intermediate powers were explicitly analyzed in the Calibration Allowances original calculation. Due to less decalibration, full power bounds lower power levels.
31 1.2.17 Fuel Duty Index No change to analysis is required. Full power bounds lower power levels.
32 1.2.18 T-H MSCU Verification No change to analysis is required. Power is not an input. Calculation is a verification of response surface at reference DNBR points rather than a benchmark at a given power.
33 1.2.19 CEA STAR Verification No change to analysis is required. Radial power distributions (at the same power level and burnup) are essentially identical. At reduced power the plan is to continue to operate with all rods out. The duration and depth of lead bankCEA insertion beyond the typical all-rods-out position is monitored per the core follow procedure with notification/action to review the conservative CEA life analysis when insertion exceeds an insertion assumption within the analysis.
Page 8
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 34 1.3.1 Summary of Transients Re-analysis was performed to determine impact, and all results were acceptable.
Calculation was revised to perform an evaluation of all Updated Final Safety Analysis Report (UFSAR) Chapter 15 events for extended reduced power operation.
35 1.3.2 CENTS Cycle Update and Action No change to analysis is required. Calculation and associated computer files already Modules accommodate power levels from 0 to 100 percent.
36 1.3.3 (15.10.1.3.1.1)
Main Steam Line Break (MSLB)
No change to analysis is required. Pre-trip SLB is analyzed @100%
power (with Pre-Trip uncertainty). The generic physics inputs remain unchanged. Since the VOPT is generated on the rate of change in power setpoint (DELSPV), the actual trip occurs at the same power rise, independent of the starting power level. As this is a Required Over Power Margin (ROPM) event, the actual initial power level chosen is not significant to the event.
37 1.3.4 (15.10.1.3.1.2)
MSLB Post-Trip No change to analysis is required. This event is limiting at hot zero power (HZP). HZP cases show greatest return to power since there is minimum initial stored energy, decay heat and scram worth at HZP conditions. There is no impact to the HZP cases since HZP physics inputs and initial conditions do not change. A reactivity balance for reduced power showed that net reactivity change remained negative.
38 1.3.5 (15.10.4.1.4)
Chemical Volume Control System No change to analysis is required. This is a BOC event that is not analyzed in Mode 1.
(CVCS) Malfunction - Boron Dilution The reactivity addition due to a boron dilution event is less adverse than the CEA Withdrawal event at Power and therefore Mode 1 and the higher power portion of Mode 2 are not explicitly addressed.
39 1.3.6 (15.10.4.1.1)
CEA Bank Withdrawal from Subcritical No change to analysis is required. Event is evaluated at subcritical conditions. Note that (CEAW @ SC) this event is ~eing re-evaluated to address the extended shut down.
40 1.3.6 (15.10.4.1.1)
CEA Bank Withdrawal at Low Power No change to analysis is required. Event is evaluated at hot zero power conditions.
(CEAW @ HZP) 41 1.3.6 (15.10.4.1.2)
CEA Bank Withdrawal at Power No change to analysis is required. CEAW at reduced power is enveloped by CEAW @
(CEAW @ Power, 50% & 100%)
50% Power and CEAW @ 1000/0 Power; and the results are acceptable.
42 1.3.8 (15.10.1.1.3)
Increased Main Steam Flow (IMSF)
No change to analysis is required. The system response is the same as IMSF+SF.
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Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM 43 44 45 46 47 48 49 CHECKLIST ITEM (UFSAR SECTION) 1.3.8 (15.10.1.2.3) 1.3.9 (15.10.4.3.2) 1.3.10 (15.10.3.3.1) 1.3.10 (15.10.3.3.2) 1.3.11 (15.10.2.1.3) 1.3.11 (15.10.2.2.3) 1.3.12 (15.10.6.3.2)
DESCRIPTION IMSF with Single Failure (SF)
CEA Ejection Reactor Coolant Pump Shaft Seizure Reactor Coolant Pump Sheared Shaft (RCPSS)
Loss of Condenser Vacuum (LOCV)
LOCV with Single Failure Steam Generator Tube Rupture (SGTR)
SUMMARY
OF IMPACT ASSESSMENT No change to analysis is required. IMSF+SF (fast &slow) analyzed @1000/0 power. The generic physics inputs remain unchanged. The fast case credits the VOPT which is generated on the rate of change in power (DELSPV) setpoint, as such the actual trip occurs at the same power rise, independent of the starting power level. Since the fast case is a Required Over Power Margin (ROPM) event, the actual initial power level chosen is not significant to the event. The limiting event is the slow trip, which is initiated from a Power Operating Limit. As such, the actual initial power level chosen is not significant to the event.
Re-analysis was performed to determine impact, and all results were acceptable. The event is normally analyzed at multiple power levels. It was reanalyzed to address reduced power data from the fuel performance analysis.
No change to analysis is required. Bounded by Reactor Coolant Pump Sheared Shaft (RCPSS).
No change to analysis is required. This is a margin/ fuel failure calculation event. The thermal margin loss for this event is initiated by the loss of flow from one pump (either seized rotor or sheared shaft). The reduction of thermal margin due to the loss of flow from one pump is not a function of the initial power (Le., is constant at any power level).
In addition, at reduced power, the initial thermal margin is larger than at the 100% power condition. Therefore, the analysis at full power is bounding.
No change to analysis is required. Bounded by LOCV+SF No change to analysis is required. This event is driven by plant response and not by detailed core physics. There are two criteria (peak RCS pressure and peak secondary pressure). At lower powers, there is less internal energy in the reactor core, which translates into a slower RCS pressure transient that is more rapidly mitigated by main steam safety valves (MSSVs). The peak secondary pressure event is evaluated at multiple power levels to establish the allowed power level as a function of the number of gagged MSSVs (Tech Spec 3.7.1).
No change to analysis is required. The SGTR is a slow event and not sensitive to initial power. Furthermore, at lower powers there is a higher secondary pressure that translates to lower primary-to-secondary rupture flow (Le., lower activity release).
Page 10
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 50 1.3.13 (15.10.1.1.4)
Inadvertent Opening of a Steam No change to analysis is required. See IOSGADV+SF Generator Safety or an Atmospheric Dump Valve (IOSGADV) 51 1.3.14 (15.10.1.2.4)
IOSGADV with Single Failure No change to analysis is required. The IOSGADV+SF is analyzed at a power level of 1 MWt.
52 1.3.15 (15.10.9.1.1)
Asymmetric Steam Generator No change to analysis is required. The ASGT event was analyzed in the AOR at multiple Transient (ASGT) power levels (900~, 700~, 50%, and 20%).
53 1.3.16 (15.10.1.1.1)
Decrease in Feedwater Temp (DFWT)
No change to analysis is required. Since feedwater heating is reduced at reduced power, the potential loss in feedwater heating is also reduced. Impact at reduced power is also mitigated by increased mass in RCS and Steam Generators (SGs) and increased recirculation in SGs at lower power.
54 1.3.17 (15.10.1.2.1)
DFWT with Single Failure No change to analysis is required. Since feedwater heating is reduced at reduced power, the potential loss in feedwater heating is also reduced. Impact at reduced power is also mitigated by increased mass in RCS and Steam Generators and increased recirculation in SGs at lower power.
55 1.3.18 (15.10.1.1.2)
Increase in Feedwater Flow (IFF)
No change to analysis is required. Primary to secondary heat transfer is dominated by heat of vaporization (Hfg) which is considerably greater than steam generator enthalpy rise resulting from sensible heat. Consequently, cool downs resulting from Increases in Feedwater Flow events are limited by Increases in Main Steam Flow events. Further, Increases in Steam Flow events occur more rapidly as changes in Feed Water are mitigated by the liquid mass and recirculation flow in the steam generators. Further factors that mitigate Increasing Feedwater Flow events at reduced power include greater RCS /
SG mass, increased recirculation flow in the steam generators, greater steam generator pressure and earlier reactor trip from increased feedwater flow - steam flow mismatch.
56 1.3.18 (15.10.1.2.2)
IFF with Single Failure No change to analysis is required. The most adverse single failure postulated for IFF is the opening of all Steam Bypass Control System (SBCS) valves. Because the Increase in Main Steam Flow (lMSF) event postulates the opening of all SBCS valves and assumes that Main Feedwater flow increases to match steam flow, the IFF with Single Failure is the essentially the same event as the IMSF event. Therefore, conclusions regardinglMSF are applicable to IFF with Single Failure.
Page 11
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 57 1.3.19 (15.10.2.1.1)
Loss of External Load (LOL)
No change to analysis is required. The system response to the Loss of External Load, Turbine Trip, and the Loss of Condenser Vacuum are essentially the same. Therefore, the relationship between the events will remain the same at reduced power. As such these events remain bounded by LOCV.
58 1.3.19 (15.10.2.2.1)
LOL with Single Failure No change to analysis is required. The system response to the Loss of External Load with single failure, Turbine Trip with single failure, and the Loss of Condenser Vacuum with single failure are essentially the same. Therefore, the relationship between the events will remain the same at reduced power. As such these events remain bounded by LOCV+SF.
59 1.3.19 (15.10.2.1.2)
Turbine Trip (TT)
No change to analysis is required. The system response to the Loss of External Load, Turbine Trip, and the Loss of Condenser Vacuum are essentially the same. Therefore, the relationship between the events will remain the same at reduced power. As such these events remain bounded by LOCV.
60 1.3.19 (15.10.2.2.2)
TT with Single Failure No change to analysis is required. The system response to the Loss of External Load with single failure, Turbine Trip with sinqle failure, and the Loss of Condenser Vacuum with single failure are essentially the same. Therefore, the relationship between the events will remain the same at reduced power. As such these events remain bounded by LOCV+SF.
61 1.3.20 (15.10.2.1.4)
Loss of Normal AC Power (LONAC)
No change to analysis is required. See LONAC+SF 62 1.3.20 (15.10.2.2.4)
LONAC with Single Failure No change to analysis is required.
Operation at lower power level is less challenging with respect to maintaining an adequate heat sink.
63 1.3.21 (15.10.2.2.5)
Loss of Normal Feedwater (LONF or No change to analysis is required. See LOFW+SF LOFW) 64 1.3.21 (15.10.2.3.2)
LOFW with Single Failure No change to analysis is required.
Operation at lower power level is less challenging with respect to maintaining an adequate heat sink.
Page 12
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM 65 66 67 68 69 CHECKLIST ITEM (UFSAR SECTION) 1.3.22 (15.10.2.3.1) 1.3.23 (15.10.5.1.1) 1.3.23 (15.10.5.2.1) 1.3.24 1.3.25 (15.10.4.1.5)
DESCRIPTION Feedwater System Pipe Breaks (FSPB or FWLB)
CVCS Malfunction CVCS Malfunction with Single Failure Pressurizer Spray Malfunction Reactor Coolant Pump (RCP) - Start Up of an Inactive Loop
SUMMARY
OF IMPACT ASSESSMENT No change to analysis is required. Peak primary and secondary pressure events were analyzed at the least negative MTC value and main feedwater enthalpy corresponding to full power. The slightly higher MTC corresponding to reduced power is offset by the lower main feedwater enthalpy at reduced power. Operation at lower power level is less challenging with respect to maintaining an adequate heat sink. The energy in the plant is less at reduced power relative to full power, and therefore pressurizer overfill is bounded by the full power response.
No change to analysis is required. See CVCS Malfunction+SF.
No change to analysis is required. The energy in the plant is less at reduced power relative to full power, and therefore pressurizer overfill is bounded by the full power response.
Operation at lower power level is less challenging with respect to maintaining an adequate heat sink.
No change to analysis is required. See Core Protection Calculator (CPC) Dynamic Filter Analysis.
No change to analysis is required. Modes 1 and 2 were not analyzed because operation in these Modes is only allowed with all 4 RCPs running.
70 I
1.3.27 (15.10.4.3.2)
ICEA Ejection (peak pressure analysis) I No change to analysis is required. The event is limiting at hot zero power (HZP).
71 72 73 1.4 (15.10.6.3.3)
(15.10.5.1.2)
(15.10.5.2.2)
Emergency Core Cooling System (ECCS) Analyses including LBLOCA, SBLOCA and LTC Inadvertent Operation of ECCS at Power (IOECCS)
IOECCS with Single Failure Re-analysis was performed to determine impact, and all results were acceptable. Impact assessment addressed in analyses performed by Fuel Vendors.
No change to analysis is required. The system response to the IOECCS and CVCS malfunction. events are essentially the same. Therefore, the relationship between the events will remain the same at reduced power. As such this event continues to be bounded by CVCS malfunction event.
No change to analysis is required. The system response to the IOECCS with single failure and CVCS malfunction with single failure events are essentially the same.
Therefore, the relationship between the events will remain the same at reduced power.
As such this event continues to be bounded by CVCS malfunction event with single failure.
Page 13
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 74 (15.10.6.3.1 )
Primary Sample or Instrument Line No change to analysis is required. Mass releases are driven by energy in the primary Break (PSILB) system which is highest following operation at HFP. The event does not fail fuel, and there is no ROPM requirement:
75 (15.10.6.3.4)
Inadvertent Opening of a PSV (IOPSV)
No change to analysis is required. The IOPSV event is bounded by small break LOCA.
76 1.5.1 Applicability Evaluation of Source No change to analysis is required. There is no change to core activity inventory source Terms in Dose Analyses term.
77 1.5.2 Cycle Specific Dose Analysis No change to analysis is required. No Cycle 17 event-specific dose analysis was performed, therefore no impact for reduced power.
78 1.5.4 Applicability Evaluation of Dose Re-analysis was performed to determine impact, and all results were acceptable.
Revised Analyses to document that the currently modeled radial peaking factors are conservatively greater than the increased radial peaking factors at reduced power.
The transient analyses and mass release analyses are evaluated at the current 8%
steam generator (SG) tube plugging limit.
The dose calculation uses mass release data per the transient analyses and their assumed 8%
SG tube plugging models. The calculation is revised with discretionary conservatism to model 20%
SG tube plugging in the calculation of the RCS dilution volume and mass considered for non-LOCA events which have clad damage. Evaluated RCS dilution mass at RCS temperatures for both 50%
and 1000/0 power, which envelopes powers between 50%
and 100%
The mass release calculations are evaluated for a core inlet temperature (Tcold) of 560F, which maximizes core average temperature (Tave). Currently modeled mass release values in the Summary of Transients (SOT) correspond to full power operation. The SOT did not identify an increase in the amount of steam released from the secondary side because it remains more limiting compared to operation at lower power level due to lower sensible heat in the RCS and lower post trip decay heat.
Page 14
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 79 n/a Fuel Corrosion and Oxide Thickness No change to analysis is required.
(BOA Code) analysis The Westinghouse BOA code analysis for cycles 15, 16 and 17 was performed as part of the Zinc Injection project. This calculation compared predicted values for corrosion and oxide thickness, Fuel Duty Index and crud dryout to the Westinghouse Chemistry Guideline limits.
Maximum values of Fuel Duty Index and Crud Dryout are driven by fresh fuel operating at high power. Operation at reduced power would be bounded by the 100% power cases run in the analysis of record (AOR).
Maximum values of corrosion and oxide thickness are driven by both power level and effective full power days (EFPD). The AOR assumed a core operating strategy which would maximize corrosion and oxide; running fuel for three full cycles, a total of 1830 EFPD. Table 2-1 of the AOR showed that the maximum predicted oxide thickness for U2C17 is 28.4 microns, well below the 100 micron limit. Operation at reduced power for longer time would not significantly change the fuel rod corrosion rate, and there is
.substantial margin to the 100 micron limit.
80 n/a AREVA Lead Fuel Assembly (LFA)
Re-evaluation was performed to determine impact, and all results were acceptable.
compatibility Compatibility was verified by AREVA as documented in revised U2C17 Reload Analysis Report (RAR).
81 n/a WEC Lead Fuel Assembly (LFA)
Re-evaluation was performed to determine impact, and all results were acceptable.
compatibility Compatibility was verified by Westinghouse as documented in revised U2C17 RAR.
82 n/a AREVA and WEC Chemistry Re-evaluation was performed to determine impact, and all results were acceptable.
concurrence Concurrence for reduced power operation was performed by Westinghouse and AREVA as documented in revised U2C17 RAR.
83 1.6.1 Reload Analysis Report (RAR)
Re-analysis was performed to determine impact, and all results were acceptable. Revised to address extended operation at reduced power.
84 1.6.2 Engineering Change Package (ECP)
Re-evaluation was performed to determine impact, and all results were acceptable.
and 10CFR50.59 Review 10CFR50.59: New 10CFR50.59 review issued to address the extended operation at reduced power.
ECP: Affected Section Change (ASC) issued to address the extended operation at reduced power.
Page 15
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 85 2.1.2 Physics Input to FLCEA Drop Analysis No change to analysis is required. Power distributions at the same power level and and PFDTME Verification burnup are essentially identical. Analysis performed at multiple power levels.
86 2.1.3 Physics Input to PLCEA Drop Analysis No change to analysis is required. Power distributions at the same power level and burnup are essentially identical. Analysis performed at multiple power levels.
87 2.1.5 Physics Input to CEA Deviation Within No change to analysis is required. Power distributions at the same power level and CPC Deadband burnup are essentially identical. Analysis performed at multiple power levels.
88 2.1.9 Refueling Boron Concentration No change to analysis is required. Analyzed at BOC, Mode 6.
89 2.1.10 CIDSAL Physics Verification No change to analysis is required. Radial power distributions (at the same power level and burnup) are essentially identical. T-inlet program remain unchanged.
90 2.2.1 (15.10.4.1.3)
CEA Misoperation - Deviation within No change to analysis is required. Power distributions at the same power level and Dead Band (DWDB) burnup are essentially identical. Analysis performed at multiple power levels.
91 2.2.2 (15.10.4.1.3)
No change to analysis is required. Power distributions at the same power level and Power ~ 50%
burnup are essentially identical. Event scenario is defined at
~ 500/0 Power. Scenarios at
>50%
power are discussed in "CEA Misoperation - Single Part Length CEA Drop (PLR Drop) - Power> 500/0."
92 2.2.3 (15.10.4.1.3)
CEA Misoperation - Single Full Length No change to analysis is required. Power distributions at the same power level and CEA Drop (FLCEA Drop) burnup are essentially identical. Analyzed at multiple power levels.
93 2.2.3 (15.10.4.1.3)
CEA Misoperation - Single Part Length No change to analysis is required. Power distributions at the same power level and CEA Drop (PLCEA Drop) - Power>
burnup are essentially identical. Analyzed at multiple power levels.
500/0 94 2.2.3 (15.10.4.1.3)
CEA Misoperation - Sub Group CEA No change to analysis is required. Power distributions at the same power level and Drop burnup are essentially identical. Analyzed at multiple power levels.
95 2.2.4 AOPM Analysis No change to analysis is required. Power distributions at the same power level and burnup are essentially identical. Analyzed at multiple power levels.
96 2.2.5 Transient Thermal Margin Summary No change to analysis is required. Analyzed at multiple power levels.
Page 16
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM CHECKLIST ITEM DESCRIPTION
SUMMARY
OF IMPACT ASSESSMENT (UFSAR SECTION) 97 2.2.6 (15.10.3.1.1)
Partial Loss of RCS Flow (PLOF)
No change to analysis is required. Bounded by TLOF.
98 2.2.6 (15.10.3.2.2)
PLOF with Single Failure No change to analysis is required. Bounded by RCPSS.
99 2.2.6 (15.10.3.2.1)
Total Loss of Forced ReactorCoolant No change to analysis is required. The total loss of coolant flow event was analyzed for a Flow (TLOF) bounding scenario at 100%
power and a MTC of +0.5x10-4 i1p/oF. This scenario bounds all powers from 0 to 100%.
100 2.2.6 (15.10.3.3.3)
TLOF with Single Failure No change to analysis is required. Bounded by RCPSS.
101 2.2.7 CPC Dynamic Filter Analysis (including No change to analysis is required. The bounding events considered include CEA the Pressurizer Spray Malfunction)
Withdrawal, Excess Load events, etc. As the system response time for these events has not chanqed, the dynamic filter analysis remains conservative.
102 2.3.4 MSOUA Database and Files No change to analysis is required. The impact of RCS flow uncertainty changes has been captured in MSOUA Post-Processor.
103 2.3.5 CPC Reload Data Block (ROB) Update No change to analysis is required. Reduced power has been implemented through CPC Type 2 addressable constants, and not CPC ROB.
104 2.3.6 MSOUA Post Processor Re-analysis was performed to determine impact, and all results were acceptable.
Calculation has been revised for RCS flow uncertainty and the change in UNCERT from the FATES fuel performance analysis.
105 2.3.7 Core Operating Limits Supervisory No change to analysis is required. Calculation is a prediction of operating margin at full System (COLSS) & CPC Operating power. Reduced power increases operating margin.
Margin Assessment 106 2.3.8 COLSS Database No change to analysis is required. No changes are being made to the manner in which COLSS functions or responds. Therefore the cycle independent constants do not require change. The installed Primary i1T power Block I constants were verified to be bounding.
The cycle specific constants that are impacted by reduced power operation have been addressed in the COLSS As-built Database and Test Cases calculation.
107 3.1.1 Full Core Load Map No change to analysis is required. Fuel management not changed.
Page 17
Table 1 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Reload and UFSAR Chapter 15 Safety Analyses ITEM 108 109 110 111 112 113 114 115 116 117 CHECKLIST ITEM (UFSAR SECTION) 3.1.3 3.1.4 3.1.5 3.1.6 3.1.7 3.1.8 3.1.9 3.1.10 3.2.1 3.
2.2 DESCRIPTION
As-Built Models and Depletions CECOR Coefficients As-Built Mini Depletion Decay Heat Simulator Data Special Nuclear Material Database Update Plant Physics Data Book Startup Physics Test Predictions COLSS As-built Database and Test Cases CEFAST Database Analysis
SUMMARY
OF IMPACT ASSESSMENT Re-analysis was performed to determine impact, and all results were acceptable.
Calculation was revised to address extended reduced power operation and to verify Lead Fuel Assembly (LFA) compatibility operational requirements.
Impacted, and all results were acceptable. Calculation was revised to address extended reduced power operation.
Re-analysis was performed to determine impact, and all results were acceptable.
Calculation revised to address extended reduced power operation.
No change to analysis is required. Decay heat was evaluated at end of Cycle 16 condition. The calculation specifically addresses outage times past 99 days.
Re-analysis was performed to determine impact, and all results were acceptable.
Calculation revised to address extended reduced power operation.
No change to analysis is required. The change to Cycle 17 operating power will have no effect on prior cycle spent fuel and its characteristics.
Re-analysis was performed to determine impact, and all results were acceptable.
Data Book has been revised to address extended reduced power operation.
Re-analysis was performed to determine impact, and all results were acceptable.
Calculation has been revised to address changes to startup testing power plateaus.
Re-analysis was performed to determine impact, and all results were acceptable.
Calculation has been revised to address extended reduced power operation impact on the cycle specific COLSS reload constants for DNBR &Linear Heat Rate (LHR) penalties.
Re-analysis was performed to determine impact, and all results were acceptable.
Calculation has been revised to address extended reduced power operation impact on the cycle specific CPC reload constants for DNBR & Local Power Density (LPD) penalties.
Page 18
Table 2 SONGS Unit 2 Cycle 17 Reduced Power Operation - Summary of Impact Assessment of Core Design and Monitoring Technical Specification Surveillance Requirements Surv#
Surveillance Topic Power Applicability and Summary of Impact Assessment for Surveillance Frequency Performing at 68-70% Power 3.1.3.1 Reactivity Balance Every 31 EFPD Steady state power (not full power) is required 3.1.4.1 MTC within positive limit Prior to Mode 1 Performed at Hot Zero Power and projected to BOC 700/0 conditions 3.1.4.2 MTC within negative limit Within 14 EFPD of peak Boron @
Peak boron occurs at BOC, - performed at Hot Zero Power RTP and projected to HFP EOC conditions 3.1.4.2 MTC within negative limit Within +/- 30 EFPD of Steady state power (not full power) is required; projected to 2/3 of expected core burnup HFP EOC conditions 3.2.2.1 CPC & COLSS Fxy >
Between 40% - 850/0 (Le., prior to 680/0-700/0 is within the power range required for measured Fxy (CECOR) exceeding 850/0) surveillance 3.2.2.1 CPC & COLSS Fxy >
Every 31 EFPD Steady state power (not full power) is required Measured Fxy (CECOR) 3.2.3.3 CPC Azimuthal Tilt>
Every 31 EFPD Steady state power (not full power) is required Measured Tilt (CECOR) 3.3.1.2 RCS Flow in CPCs <
Every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (not required until Procedure changed to perform surveillance at ~ 68% power Measured RCS Flow 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after power> 850/0 RTP) 3.3.1.5 RCS Flow by calorimetric Every 31 days (not required until Procedure changed to perform surveillance at ~ 68°A, 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after power> 850/0 RTP) power, and to require additional margin when surveillance is performed during extended operation at < 950/0 power 3.3.1.11 CPC Shape Annealing Prior to exceeding 850/0 A minimum ASI change, rather than a specific power level, Matrix (SAM) Verification is required N/A Startup Test Activity Normally performed after reaching Results are already adjusted from actual test conditions to Reduction Program full power RTP conditions as a part of the test method Reactivity Balance HZP - HFP Page 19
SCE ATTACHMENT 29
i~~~~(\\~Jvl E Ui5TSORN
An EDISON INTERNATIONAL Company January 18, 2013 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
Subject:
Docket No. 50-361 Response to Request for Additional Information (RAI 13)
Regarding Confirmatory Action Letter Response (TAC No. ME 9727)
San Onofre Nuclear Generating Station, Unit 2 Richard,. St. Onge Director, Nuclear Regulatory Affairs and Emergency Planning 10 CFR 50.4
References:
- 1. Letter from Mr. Elmo E. Collins (USNRC) to Mr. Peter T. Dietrich (SCE), dated March 27, 2012, Confirmatory Action Letter 4-12-001, San Onofre Nuclear Generating Station, Units 2 and 3, Commitments to Address Steam Generator Tube Degradation
- 2. Letter from Mr. Peter T. Dietrich (SCE) to Mr. Elmo E. Collins (USNRC), dated October 3, 2012, Confirmatory Action Letter - Actions to Address Steam Generator Tube Degradation, San Onofre Nuclear Generating Station, Unit 2
- 3. Letter from Mr. James R. Hall (USNRC) to Mr. Peter T. Dietrich (SCE), dated December 26, 2012, Request for Additional Information Regarding Response to Confirmatory Action Letter, San Onofre Nuclear Generating Station, Unit 2
Dear Sir or Madam,
On March 27,2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) (Reference 1) to Southern California Edison (SCE) describing actions that the NRC and SCE agreed would be completed to address issues identified in the steam generator tubes of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3. In a letter to the NRC dated October 3, 2012 (Reference 2), SCE reported completion of the Unit 2 CAL actions and included a Return to Service Report (RTSR) that provided details of their completion.
By letter dated December 26, 2012 (Reference 3), the NRC issued Requests for Additional Information (RAls) regarding the CAL response. Enclosure tof this letter provides the response to RAI 13.
P.O. Box 128 San Clemente, CA 92672
Document Control Desk January 18, 2013 There are no new regulatory commitments contained in this letter. If you have any questions or require additional information, please call me at (949) 368-6240.
Sincerely,
Enclosure:
1.
Response to RAI 13 cc:
E. E. Collins, Regional Administrator, NRC Region IV J. R. Hall, NRC Project Manager, SONGS Units 2 and 3 G. G. Warnick, NRC Senior Resident Inspector, SONGS Units 2 and 3 R. E. Lantz, Branch Chief, Division of Reactor Projects, NRC Region IV
ENCLOSURE 1 SOUTHERN CALIFORNIA EDISON RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING RESPONSE TO CONFIRMATORY ACTION LETTER DOCKET NO. 50-361 TAC NO. ME 9727 Response to RAI13 Page 1 of 4
RAI13 The installation of new steam generators involved changes to the steam generator heat transfer characteristics, which could affect the performance of the plant under postulated loss of coolant accident conditions. Please explain how the existing ECCS analysis accounts for these changes, and how considerable steam generator tube plugging has been addressed in the ECCS evaluation. Provide the ECCS evaluation that will apply to the planned operating cycle.
RESPONSE
Note: Response (2) below includes information requested in RAI 14 associated with the Emergency Core Cooling System (ECCS) evaluation. RAI 14 states: "Provide a summary disposition of the U2C17 calculations relative to the planned reduced-power operation."
(1) Evaluation of Impact of Replacement Steam Generators on Emergency Core Cooling System (ECCS) Performance Analyses Replacement steam generators (RSGs) were installed in SONGS Units 2 and 3 for Cycle 16.
The Cycle 16 ECCS performance for SONGS Units 2 and 3 with the RSGs was evaluated to demonstrate conformance to the ECCS acceptance criteria for light water nuclear power reactors contained in 10 CFR 50.46. The evaluation considered the impact of the RSGs on the Analyses of Record (AORs) for Large Break Loss-of-Coolant Accident (LBLOCA), Small Break Loss-of-Coolant Accident (SBLOCA), and post-Loss-of-Coolant Accident (LOCA) Long-Term Cooling (LTC), which are based on the original steam generators (OSGs).
The impact of the RSGs on the SONGS Units 2 and 3 ECCS performance AORs was evaluated through a two-step process. First, the design data of the RSGs, including thermal hydraulic characteristics, were compared to those of the OSGs as modeled in the ECCS performance AORs. Second, differences in design data, which were identified from the comparison, were evaluated for their impact on ECCS performance. The scope of the comparison considered all design features of the steam generators (SGs) that are modeled in the ECCS performance analysis. The most significant parameters are discussed below.
(i)
Rated Thermal Power The OSGs and the RSGs were evaluated at the same core power level, as there was not a power uprate associated with installation of the RSGs.
(ii)
RSG Tube Plugging and RCS Volume The RSGs have more RCS volume than the OSGs. The amount of assumed tube plugging in the RSGs is less than the OSGs. These factors result in a net increase in the total reactor coolant system (RCS) volume. This is a beneficial feature since, for example, it results in more RCS inventory available to drain into the reactor vessel during a SBLOCA, thereby delaying the time that the core begins to uncover. A larger water volume increases the amount of water available to flow through the core during the blowdown period of a LBLOCA. This increases the amount of stored energy removed from the core during the blowdown period. The increase in water volume has an insignificant impact on the post-LOCA LTC analysis. The maximum number of plugged tubes per SG for the RSG was assumed to be 779 tubes (80/0) per SG for the RSG Cycle 16 ECCS evaluation.
Page 2 of 4
(iii) RSG Heat Transfer Characteristics The maximum assumed number of plugged tubes per SG is used in conjunction with the total number of tubes per SG to establish the minimum number of unplugged tubes per SG This is used to establish SG primary side volume, tube bundle flow area, and tube bundle heat transfer area. The RSGs have more tubes (9,727 versus 9,350) than the OSGs and a smaller value for the maximum number of plugged tubes (779 versus 2,000). RSG tubes have a larger average heated length (729.56 in. versus 680.64 in.) than the OSG tubes.
These features result in larger values for the RSG for heat transfer area, tube bundle flow area, and tube bundle water volume. This is beneficial in the short and long term for SBLOCAs, which rely upon the steam generators for RCS heat removal.
The RSG tube bundle material is Inconel 690 whereas the OSG tube bundle material is Inconel 600. While the thermal conductivity of Inconel 690 is less than that of Inconel 600, the impact is not significant in the context of ECCS performance. First, the RSGs have larger heat transfer areas which compensate for the decrease of thermal conductivity.
Second, after the subcooled forced convection mode of SG heat transfer early in a LOCA transient, the primary coolant-to-wall resistance, and not the wall resistance, is the limiting resistance for SG heat transfer during a LOCA. Therefore, the difference in thermal conductivity does not have a significant impact on ECCS performance given the overall design of the RSGs relative to the OSGs and the nature of SG heat transfer during a LOCA.
Sensitivity studies have shown that the impact due to SG heat transfer area changes is insignificant for LBLOCAs. Heat transfer characteristic differences have an insignificant impact on post-LOCA LTC.
(iv) RSG Pressure Drop / Flow Resistance The RSGs have a smaller flow resistance and, consequently, a smaller pressure drop than the OSGs based on the same set of conditions and the maximum number of plugged tubes assumed by the ECCS performance analyses. A smaller total SG pressure drop is beneficial for ECCS performance.
The evaluation of the impact of the RSGs on the SONGS Units 2 and 3 ECCS performance analyses demonstrates that the RSGs have a beneficial impact on ECCS performance.
Consequently, the results and conclusions of the SONGS Units 2 and 3 ECCS performance AORs for LBLOCA, SBLOCA, and post-LOCA LTC, performed for the OSGs, are applicable to SONGS Units 2 and 3 for operation with the RSGs.
(2) ECCS performance evaluations for SONGS Unit 2 Cycle 17 An ECCS performance analysis was performed for SONGS Unit 2 Cycle 17 to demonstrate conformance to the ECCS acceptance criteria for light water nuclear power reactors. The major changes evaluated in the Unit 2 Cycle 17 ECCS performance analysis are discussed as follows.
Page 3 of 4
(i)
Increase in TCOLD The RCS temperature at the inlet to the core, i.e., TCOLD, has increased for Unit 2 Cycle 17 to 550°F from the previous Unit 2 Cycle 16 value of 541°F ("TCOLD Restoration"). The effect of the change in TCOLD is bounded by the Unit 2 Cycle 17 ECCS performance analysis.
(ii)
SG Tube Plugging The maximum number of plugged tubes per SG for Unit 2 Cycle 17 operation is 30/0, which is bounded by the maximum number of plugged tubes per SG (80/0) assumed in the RSG ECCS performance evaluation.
(iii) Extended Operation at Power Levels Between 500/0 and 1000/0 SONGS Unit 2 Cycle 17 safety analyses and LOCA analyses were evaluated for acceptability of plant operating at power levels between 500/0 and 1000/0, which bounds the planned operation at 700/ 0 power level. The impact of the extended reduced power operation was evaluated to determine the continued applicability of SONGS Units 2 and 3 ECCS performance AORs. It was concluded that the power operation range between 500/ 0 and 1000/0 remains bounded by the current SONGS Units 2 and 3 ECCS performance AORs for LBLOCA, SBLOCA, and post-LOCA LTC.
Page 4 of 4
SCE ATTACHMENT 30
NEI 97-06 [Rev. 3]
Steam Generator Program Guidelines January 2011
TABLE OF CONTENTS EXECUTIVE
SUMMARY
....................................................................................................... i 1
INTRODUCTION.......................................................................................................... 1
1.1 PURPOSE.........................................................................................................................1
1.2 BACKGROUND.................................................................................................................1
1.3 LICENSEE RESPONSIBILITIES.........................................................................................2
1.4 REGULATORY REQUIREMENTS......................................................................................3
1.4.1
10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, and Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants.............................................................3
1.4.2
10 CFR § 50.65, Maintenance Rule................................................................4
1.4.3
10 CFR § 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, and § 50.73, Licensee Event Report System.........4
1.4.4
10 CFR § 100, Reactor Site Criteria...............................................................5
1.4.5
Alternate Source Term...................................................................................5
1.4.6
Plant Technical Specifications.......................................................................5
1.5 EPRI STEAM GENERATOR GUIDELINES.......................................................................5
2
PERFORMANCE CRITERIA........................................................................................ 7
2.1 STRUCTURAL INTEGRITY PERFORMANCE CRITERION.................................................7
2.2 ACCIDENT-INDUCED LEAKAGE PERFORMANCE CRITERION........................................8
2.3 OPERATIONAL LEAKAGE PERFORMANCE CRITERION.................................................9
3
STEAM GENERATOR PROGRAM............................................................................. 10
3.1 DEGRADATION ASSESSMENT........................................................................................10
3.2 INSPECTION...................................................................................................................11
3.3 INTEGRITY ASSESSMENT..............................................................................................11
3.4 STEAM GENERATOR TUBE PLUGGING AND REPAIRS..................................................12
3.5 PRIMARY-TO-SECONDARY LEAK MONITORING.........................................................12
3.6 MAINTENANCE OF STEAM GENERATOR SECONDARY-SIDE INTEGRITY....................12
3.6.1
Secondary-Side Visual Inspection...............................................................13
3.7 SECONDARY-SIDE WATER CHEMISTRY......................................................................13
3.8 PRIMARY-SIDE WATER CHEMISTRY...........................................................................13
3.9 FOREIGN MATERIAL EXCLUSION................................................................................13
v
NEI 97-06 (Rev. 3)
January 2011 3
STEAM GENERATOR PROGRAM The purpose of a Steam Generator Program is to ensure tube integrity. The program contains a balance of prevention, inspection, evaluation and repair, and leakage monitoring measures. NEI 97-06 and its referenced EPRI guidelines are the documents that define The Steam Generator Program referred to in steam generator technical specifications. It is mandatory that licensee Steam Generator Programs address:
Degradation assessment
Inspection
Integrity assessment
Tube plugging and repairs
Primary-to-secondary leak monitoring
Maintenance of secondary side integrity
Secondary side water chemistry
Primary side water chemistry
Contractor oversight
Self assessment
Reporting Further information on each of these topics is provided in sections 3.1 to 3.12 below.
3.1 DEGRADATION ASSESSMENT Prior to the pre-service and subsequent planned steam generator inspections, licensees perform a Degradation Assessment. The assessment addresses the reactor coolant pressure boundary within the steam generator, e.g., plugs, sleeves, tubes and the components that support the pressure boundary, such as secondary-side components. The assessment considers operating experience. EPRI Steam Generator Integrity Assessment Guidelines [6] provides an acceptable method of performing Degradation Assessments.
The overall purpose of the Degradation Assessment is to ensure that appropriate inspections are performed during the upcoming outage, and that the requisite information for integrity assessment is provided. Some of the important features of the Degradation Assessment include:
Identifying existing and potential degradation mechanisms
Choosing techniques to test for degradation based on the probability of detection and sizing capability 10
NEI 97-06 (Rev. 3)
January 2011
Establishing the number of tubes to be inspected
Establishing the tube integrity limits for condition monitoring and operational assessment 3.2 INSPECTION Each licensee plans and conducts inspections according to the Degradation Assessment and follows the inspection guidance contained in the EPRI PWR Steam Generator Examination Guidelines [2].
Some of the important features of steam generator tube inspections include:
Sampling as supported by the degradation assessment
Obtaining the information necessary to develop degradation, condition monitoring and operational assessments
Qualifying the inspection program by determining the accuracy and defining the elements for enhancing NDE system performance, including technique, analysis, field analysis feedback, human performance and process controls 3.3 INTEGRITY ASSESSMENT Licensees assess tube integrity after each steam generator tube inspection. The assessment includes:
Condition Monitoring - A backward-looking assessment which confirms that adequate steam generator tube integrity has been maintained during the previous inspection interval
Operational Assessment - A forward-looking assessment which demonstrates that the tube integrity performance criteria will be met throughout the next inspection interval These assessments accounts for uncertainties to provide a conservative assessment of the condition of the tubing relative to the performance criteria. Licensees follow the guidance contained in the EPRI Steam Generator Integrity Assessment Guidelines [6] for determining the evaluation methods and uncertainty considerations used to evaluate tube integrity.
Licensees may use activities such as in-situ pressure testing or pulling tubes as a direct means of verifying that performance criteria have been satisfied. Licensees follow the guidance contained in the EPRI Steam Generator In Situ Pressure Test Guidelines [7] for screening and selecting candidate tubes, as well as for test methods and testing parameters.
If a licensee determines that the structural integrity or accident leakage performance criteria have not been satisfied during the prior operating period, an evaluation, in accordance with the licensee corrective action program, is performed. In this event, the licensee takes actions in accordance with plant technical specifications, including notifying the NRC as applicable. If a risk-based assessment is necessary, guidance may be found in Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific 11
NEI 97-06 (Rev. 3)
January 2011 Changes to the Licensing Basis [12]. Note that a risk based approach is not allowed by current technical specifications as of the date of this revision. Using this approach would require NRC approval.
3.4 STEAM GENERATOR TUBE PLUGGING AND REPAIRS Licensees qualify and implement plugging and repair methods in accordance with industry standards. The qualification of the plugging and repair techniques considers the specific steam generator conditions and mockup testing. Repair methods are those means used to reestablish the RCS pressure boundary integrity of steam generator tubes without removing the tube from service. Plugging a steam generator tube is not a repair. The purpose of a repair is typically to reestablish or replace the reactor coolant pressure boundary; a plug removes a tube from service.
Licensees clearly identify engineering prerequisites and plant conditions prior to performing the plugging or repair. Process controls ensure proper performance of the plugging and repair including the consideration of post maintenance testing. Additionally, licensees perform a pre-service inspection of the plugging or repair consistent with the EPRI PWR Steam Generator Examination Guidelines [2].
The EPRI PWR Steam Generator Tube Plug Assessment Document [8] and the EPRI PWR Steam Generator Sleeving Assessment Document [9] provide further guidance for maintenance and repair of tubing.
Alternate repair criteria and repair methods are reviewed and approved by the NRC prior to implementation. New plugging designs or methods do not require prior approval by the NRC.
3.5 PRIMARY-TO-SECONDARY LEAK MONITORING Licensees establish primary-to-secondary leak monitoring procedures in accordance with the EPRI PWR Primary-to-Secondary Leak Guidelines [3] and in accordance with technical specifications.
Primary-to-secondary leak monitoring is an important defense-in-depth measure that assists plant staff in monitoring overall tube integrity during operation. Monitoring gives operators information needed to safely respond to situations in which tube integrity becomes impaired and significant leakage or tube failure occurs. Additionally, operational leakage is an important tool for assessing the effectiveness of a Steam Generator Program. Plants assess any observed operational leakage to determine if adjustments to the inspection program or integrity assessments are warranted.
3.6 MAINTENANCE OF STEAM GENERATOR SECONDARY-SIDE INTEGRITY Secondary-side steam generator components that are susceptible to degradation are monitored if their failure could prevent the steam generator from fulfilling its intended safety-related function.
The monitoring includes design reviews, an assessment of potential degradation mechanisms, industry experience for applicability, and inspections, as necessary, to ensure degradation of these components does not threaten tube structural and leakage integrity or the ability of the 12
NEI 97-06 (Rev. 3)
January 2011 plant to achieve and maintain safe shutdown. Additional guidance is provided in the EPRI Steam Generator Integrity Assessment Guidelines [6].
3.6.1 Secondary-Side Visual Inspection The program defines when secondary-side visual inspections are to be performed, the scope of inspection, and the inspection procedures and methodology to be used. Additional guidance on secondary side inspections is provided in the Steam Generator Integrity Assessment Guidelines
[6].
3.7 SECONDARY-SIDE WATER CHEMISTRY Each licensee has procedures for monitoring and controlling secondary-side water chemistry to inhibit secondary-side corrosion-induced degradation in accordance with the EPRI PWR Secondary Water Chemistry Guidelines [4].
3.8 PRIMARY-SIDE WATER CHEMISTRY Each licensee has procedures for monitoring and controlling primary-side water chemistry to inhibit primary-side corrosion-induced degradation in accordance with the EPRI PWR Primary Water Chemistry Guidelines [5].
3.9 FOREIGN MATERIAL EXCLUSION 3.9.1 Control and Monitoring of Foreign Objects and Loose Parts The program includes procedures to preclude the introduction of foreign objects into either the primary or secondary side of the steam generator whenever it is opened (e.g., for inspections, maintenance, repairs, and modifications).
Such procedures include, as a minimum:
Detailed accountability for all tools and equipment used during any activity when the primary or secondary side is open
Appropriate controls and accountability for foreign objects such as eyeglasses and personal dosimetry
Cleanliness requirements
Accountability for components and parts removed from the internals of major components (e.g., reassembly of cut and removed components)
The potential for introduction of loose parts or foreign objects from secondary-side systems is also considered.
13
NEI 97-06 (Rev. 3)
January 2011 3.10 CONTRACTOR OVERSIGHT The licensee performs oversight of contracted work. When the licensee contracts portions of the Steam Generator Program work scope, the responsibility for program implementation and compliance with requirements always remains with the licensee. It is the licensees responsibility to plan, direct, and evaluate all steam generator activities. It is imperative that the licensee oversee not only the contractual, but also the technical aspects of any contracted work.
Critical aspects of this oversight include but are not limited to the following:
Review and approve the scope of work to be performed by a contractor
Review and approval of the Degradation Assessment
Review and approval of the contractors examination procedures
Monitoring of the contractors examination work progress
Review and approval of the contractors deliverables
Review and approval of the tube integrity assessment (CM/OA) and associated support documents 3.11 SELF-ASSESSMENT Licensees perform self-assessments of their Steam Generator Program. This review is performed by knowledgeable utility personnel or a contractor with independent experts selected by the licensee on a periodic basis. An INPO steam generator review visit can be used in lieu of the self-assessment. The self-assessment identifies areas for program improvement, along with program strengths. The assessment, or a combination of assessments, includes all the major program elements described in Section 3.
3.12 REPORTING 3.12.1 Reports to the NRC NRC reporting by licensees is specified in plant technical specifications.
3.12.2 Non-Regulatory Reports Non-regulatory reports include internal reports that document information within the plants Steam Generator Program and external reports intended to be shared with other utilities.
3.12.3 Internal Reports Internal reports include Degradation Assessments, tube integrity assessments, NDE results, and results of self-assessments. Internal reports are retained in accordance with plant requirements.
14
NEI 97-06 (Rev. 3)
January 2011 15 3.12.3.1 External Reports External reports are necessary to share information on degradation mechanisms, NDE technique applications, operating experience, and other items. This experience is shared through the EPRI SGMP through various reports. Reports are submitted to the EPRI SGMP on the following items:
Any confirmed tube degradation of a type or in a location that has not been previously experienced in a U.S. steam generator
In situ tests that result in leakage or burst
NDE and metallurgical data on any pulled steam generator tubes
Any approved technical justifications for deviation from NEI 03-08, or NEI 97-06 and its referenced EPRI Guidelines
Any significant steam generator operating experience that has generic implications for the industry
Steam generator inspection results (submitted to the EPRI SGMP through timely updating of the Steam Generator Degradation Database)
Detailed reporting requirements are contained in the governing EPRI SGMP guidelines.
SCE ATTACHMENT 31
July 18, 2012 Mr. Peter Dietrich 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 - NRC AUGMENTED INSPECTION TEAM REPORT 05000361/2012007 and 05000362/2012007
Dear Mr. Dietrich:
The U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your San Onofre Nuclear Generating Station (SONGS). The enclosed report documents the inspection results, which were discussed with you and other members of your staff during a public exit meeting on June 18, 2012.
The Augmented Inspection Team (AIT) was established to review the causes, safety implications, and your staffs actions following an event that occurred on January 31, 2012, involving a reactor coolant leak identified in a Unit 3 steam generator and a subsequent identification that multiple steam generator tubes in Unit 3 had experience substantial and unusual wear, eight of which failed pressure testing. The SONGS Unit 3 steam generators were new and had been in operation for less than one operating cycle. At the time of the event, SONGS Unit 2 was shutdown in a refueling outage with steam generators that had been in service for one operating cycle.
This augmented inspection was chartered to review the circumstances surrounding the tube degradation; review the licensees actions following discovery of the conditions; evaluate the licensees determination of the causes of the unusual steam generator tube wear; review the steam generator modeling; and, assess the differences between Unit 2 and Unit 3 steam generators. The charter is available in ADAMS at ML12075A258. It is not the responsibility of an AIT to determine compliance with the NRC rules and regulations or to recommend enforcement actions, this will be done through subsequent NRC inspection or review.
The team concluded that plant operators responded to the January 31, 2012, steam generator tube leak in accordance with procedures and in a manner that protected public health and safety. Plant safety systems worked as expected during the event.
UNITED STATES NUCLEAR REGULATORY COMMISSION RE GIO N I V 1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511
The NRC team identified ten items requiring additional review for regulatory action. These items are documented as unresolved items in the enclosed report. The NRC will conduct subsequent inspections or reviews to determine what, if any, regulatory actions result from the unresolved items.
SONGS Unit 3 steam generators had experienced excessive vibration of tubes in the U-bend region of the steam generators to the extent that the tubes rubbed against each other (tube-to-tube interactions) causing excessive wear and loss of structural integrity. Your staff determined that the vibration was caused by the steam conditions in the U-bend region of the steam generators by a phenomenon called fluid elastic instability. The NRC inspection team concluded that the steam generators design and configuration did not provide the necessary margin to prevent this phenomenon.
Although the steam generator tube degradation from this phenomenon observed in Unit 2 steam generators was not as severe, the NRC team concluded that both units steam generators were of similar design with similar thermal hydraulic conditions and configurations. Therefore, SONGS Unit 2 steam generators are also susceptible to this phenomenon.
Accordingly, as documented in NRC Confirmatory Action Letter dated March 27, 2012, (ML12087A323), you are required to submit in writing to NRC for review and acceptance, your actions and plans to prevent recurrence of loss of tube integrity before the resumption of power operations in both SONGS Units 2 and 3.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Elmo E. Collins Regional Administrator Docket No.: 50-361, 50-362 License No: NPF-10, NPF-15
Enclosure:
- 1. Inspection Report 05000361/2012007 and 05000362/2012007 Attachment(s):
- 1. Supplemental Information
- 2. Sequence of Events
i EXECUTIVE
SUMMARY
On March 19, 2012, an Augmented Inspection Team (AIT) was dispatched to San Onofre Nuclear Generating Station to gather facts and understand the circumstances surrounding the January 31, 2012 Unit 3 primary-to-secondary leak and failure of eight steam generator tubes to maintain structural integrity as required by plant technical specifications during testing the week of March 13, 2012. The primary-to-secondary leak was the result of a single tube in Unit 3 steam generator 3E0-88 failing to maintain structural integrity.
Specifically the AIT was chartered to review the circumstances surrounding the tube degradation; review the licensees actions following discovery of the conditions; evaluate the licensees determination of the causes of the unusual steam generator tube wear; review the steam generator modeling; and, assess the differences between Unit 2 and Unit 3 steam generators.
The team determined that plant operators responded to the event in a manner that protected public health and safety and all safety systems performed their functions to support the safe shutdown and cooldown of the plant. However, the loss of steam generator tube integrity is a serious safety issue that must be resolved prior to further power operation.
The AIT identified ten unresolved items that warranted additional follow-up: (1) adequacy of the post trip/transient procedure; (2) evaluation and disposition of the Unit 3 loose parts monitor alarms; (3) design of retainer bar; (4) control of original design dimensions; (5) evaluation of and controls for divider plate repair; (6) atmospheric controls of Unit 3 steam generators during shipment; (7) no tube bundle support used during shipping; (8) evaluation and disposition of accelerometer readings during shipping; (9) adequacy of Mitsubishis thermal-hydraulic model; and (10) change of methodologies associated with 10 CFR 50.59 review. Consistent with existing NRC inspection processes, these unresolved issues will be inspected and dispositioned during follow-up inspection efforts to determine if there are any violations of regulatory requirements.
The AIT inspection concluded that: (1) SCE was adequately pursuing the causes of the unexpected steam generator tube-to-tube degradation. In an effort to identify the causes, SCE retained a significant number of outside industry experts, consultants, and steam generator manufacturers, including Westinghouse and AREVA to perform thermal-hydraulic and flow induced vibration modeling and analysis; (2) The combination of unpredicted, adverse thermal hydraulic conditions and insufficient contact forces in the upper tube bundle caused a phenomenon called fluid-elastic instability which was a significant contributor to the tube to tube wear resulting in the tube leak. The team concluded that the differences in severity of the tube-to-tube wear between Unit 2 and Unit 3 may be related to the changes to the manufacturing/fabrication of the tubes and other components which may have resulted in increased clearance between the anti-vibration bars and the tubes; (3) Due to modeling errors, the SONGS replacement generators were not designed with adequate thermal hydraulic margin to preclude the onset of fluid-elastic instability. Unless changes are made to the operation or configuration of the steam generators, high fluid velocities and high void fractions in localized regions in the u-bend will continue to cause excessive tube wear and accelerated wear that could result in tube leakage and/or tube rupture; (4) The thermal hydraulic phenomena
TABLE OF CONTENTS EXECUTIVE
SUMMARY
.......................................................................................................... i
SUMMARY
OF FINDINGS.....................................................................................................
1.0 Description of Event (Charter Item 1)......................................................................
1.1 Sequence of Events........................................................................................
1.2 System Descriptions........................................................................................
1.3 Resident Inspectors Assessment of Steam Generator Tube Leak Event Response........................................................................................................
1.4 Description of Steam Generator Inspections at SONGS Unit 2......................
1.5 Description of Steam Generator Inspections at SONGS Unit 3......................
1.6 In-Situ Pressure Testing................................................................................
2.0 Probable Cause Evaluation (Charter Item 2).........................................................
2.1 SCE Cause Evaluation..................................................................................
2.2 Mitsubishi Cause Evaluation..........................................................................
3.0 Operational Differences in Configuration and Operation between Unit 2 and 3 (Charter item 3).......................................................................................................
4.0 Design and Manufacturing Differences (Charter Item #4) (Mitsubishi Charter Item
- 1)..............................................................................................................................
5.0 Quality Assurance/Quality Control (Charter Item 5) (Mitsubishi Charter Item 4) 5.1 SONGS Quality Assurance/Quality Control...................................................
5.2 Mitsubishi Quality Assurance/Quality Control................................................
5.3 Quality Assurance Conclusion.......................................................................
6.0 Implementation of Steam Generator Industry Information (Charter Item 6)
(Mitsubishi Charter Item 3)....................................................................................
7.0 Packing, Shipping, Handling, and Receipt Inspection (Charter Item 7)..............
8.0 Thermal-hydraulic and Flow Induced Vibration Modeling (Charter Item 8)........
9.0 Risk Assessment (Charter Item 9).........................................................................
10.0 Assess Quality Assurance, Radiological Controls, and Safety Culture Components (Charter Item 10).....................................................................................................
11.0 Operational impacts from Unit 3 to Unit 2 (Charter Item 11)................................
12.0 Divider Plate Manufacturing and Weld Issues (Mitsubishi Charter Item 2).........
13.0 Office of Nuclear Reactor Regulation (NRR) Review of SONGS 50.59 Evaluation-63 14.0 Exit Meeting Summary............................................................................................
ATTACHMENT 1 SUPPLEMENTAL INFORMATION...................................................... A1 ATTACHMENT 2 SEQUENCE OF EVENTS.................................................................... A2
Enclosure Description of G-Value Parameter (Conceptual Drawing - For Illustration Purposes Only)
Based on discussions with licensee personnel and documentation reviews, the team noted that Sumitomo implemented measures to improve the quality of the tube bending process which resulted in less deviation of G-values and a reduction in the amount and variability of tubing ovality. Based on the statistical analysis of G-value data collected during fabrication of the Unit 2 and Unit 3 steam generators, Mitsubishi concluded that the G-values standard deviation gradually decreased since the fabrication of the first steam generator.
Another dimensional control under consideration was the variability of anti-vibration bar dimensions. Mitsubishis fabrication procedures required inspection of various dimensions of the anti-vibration bars to control the gap between the anti-vibration bars and the tubes. These dimensions were: thickness in the straight sections, twisting and flatness of the straight sections after bending, and thickness of the anti-vibration bar tip (i.e. nose) after bending. Among these dimensions, the twisting and flatness of the straight sections after bending were verified using a Go or No-Go approach based on the acceptance criteria in Mitsubishis procedures but no specific measurements were required to be maintained by procedure. Additionally, the acceptance criteria for anti-vibration bar dimensions remained the same throughout the fabrication of Unit 2 and Unit 3 replacement steam generators. Mitsubishi conducted a preliminary statistical analysis of the available dimensional data for anti-vibration bars and the team concurred that there were minor differences in the statistical distribution of these dimensions in Unit 2 and Unit 3 steam generators.
Engineering Change Package (10 CFR 50.59): The team determined that the licensees evaluation for changes in the updated final safety analysis reports design methodologies for the replacement steam generators was consistent with SONGS
Enclosure procedures for the implementation of 10 CFR 50.59 requirements. The licensees evaluation contained in Engineering Change Packages 800071702 and 800071703 for the Unit 2 and Unit 3 replacement steam generators, respectively, determined that the replacement of the original steam generators did not affect the current licensing basis to the extent of needing prior approval from the NRC as required by 10 CFR 50.59.
In the 50.59 screening evaluation associated with the engineering change package for the Unit 2 and Unit 3 replacement steam generators, the licensee determined that the proposed activity did not adversely affect a design function, or the method of performing or controlling a design function described in the updated final safety analysis report. The licensee also determined that the steam generator replacement activity did not change a procedure in a manner that adversely affected how an updated final safety analysis report design function is performed or controlled.
Additionally, the licensee determined that the steam generator replacement activity did not involve a test or experiment not described in the updated final safety analysis report. The licensee evaluated the following updated final safety analysis report design functions in the 50.59 screening:
Steam Generator Design Functions Reactor Coolant System Structural Integrity Emergency Core Cooling System Performance Non-Loss of Coolant Accident Transients Containment Pressure-Temperature Analysis Low Temperature Overpressure Protection Reactor Protection System, Engineered Safety Features Actuation System, Core Operating Limit Supervisory System, and Core Protection Calculations Nuclear Steam Supply System Performance Non-Safety Related Control Systems Performance However, the 50.59 screening evaluation identified three methods of analysis described in the updated final safety analysis report that were affected by the proposed steam generator replacement and required further evaluation against the criteria in 10 CFR 50.59. The affected methodologies are described below:
Seismic Analysis of Reactor Vessel Internals - The original analysis of SONGS Unit 2 and Unit 3 reactor vessel internals with the original steam generators was performed with the methodology described in Combustion Engineering Topical Report CENPD-178, Structural Analysis of Fuel Assemblies for Combined Seismic and Loss of Coolant Accident. Subsequent to the submittal of this report, Combustion Engineering revised the methodology by modifying modeling techniques, computer codes, testing methods, and acceptance criteria in response to changes in licensing requirements. Consequently, the original report was resubmitted to the NRC as CENPD-178-P, Revision 1-P, August 1981. This revision was approved by the NRC in a Letter from H. Bernard to A. Scherer, Acceptance for Referring of Licensing Topical Report CENPD-178, dated August 6, 1982. The licensee used this revised methodology for the replacement
Enclosure steam generators and considered it as a methodology approved by the NRC for the intended application.
Reactor Coolant System Structural Integrity - The structural analysis of the original steam generators used ANSYS software for the thermal and stress analyses while the replacement steam generators were analyzed using ABAQUS software. ANSYS was described in the updated final safety analysis report as a large-scale, general-purpose, finite element program for linear and nonlinear structural and thermal analysis of the reactor coolant loop components. The licensee considered ABAQUS to be similar to ANSYS. The licensee compared both programs using thermal and stress sample problems. The comparison demonstrated that the results varied from theoretical solutions by no more than 1 percent, and ABAQUS and ANSYS results themselves were also within 1 percent of each other. The variability of results was determined to be within the margin of error for the subject type of analysis.
Tube Wall Thinning Analysis - The original steam generator analysis used CEFLASH computer program for the main steam line break mass-energy blowdown analysis, whereas the replacement steam generator analysis used manual calculations to represent the main steam line break blowdown loads by applying the maximum possible tube differential pressure, which bounded the pressure calculated by CEFLASH.
For loss of coolant accident analysis, the original steam generator used STRUDL computer program to calculate displacement histories and then ANSYS computer program to calculate tube stresses. The tube stresses for the replacement steam generators were determined using ANSYS computer program based on the blowdown forces. For the original steam generators the combination of loads analyzed was primary loop pipe break plus design basis earthquake and main steam line break plus design basis earthquake. For the replacement steam generators, the loss of coolant accident, design basis earthquake, and the main steam line break events were combined as one limiting event, which SCE considered to be a more conservative method of evaluation relative to the original steam generators. The licensee determined that the results of the tube wall thinning analysis for the replacement steam generators were conservative or essentially the same and the methodology used did not represent a departure from a method of evaluation described in the updated final safety analysis report.
Further discussion is contained in Section 13.0 of this report on the methodology used by the licensee for the reactor coolant system structural integrity and tube wall thinning analysis.
The team noted that a key methodology for the design of the replacement steam generators was the thermal-hydraulic code used to model the flow conditions in the steam generators. Mitsubishis FIT-III thermal-hydraulic code was accepted by SCE for the design of the replacement steam generators. The team noted that the updated final safety analysis report did not describe the thermal-hydraulic code used for the design of the original steam generators and therefore the use of the FIT-III thermal-hydraulic code did not constitute a change in methodology or a
Enclosure change in an element of a methodology described in the updated final safety analysis report. The updated final safety analysis report did describe the computer code CRIB as the code used to analyze overall steam generator performance. As described in the updated final safety analysis report, CRIB was used to establish the recirculation ratio and fluid mass inventories as a function of power level in the original steam generators.
With regard to the major design changes between the original and replacement steam generators, the updated final safety analysis report did not specify how the original steam generators relied on special design features such as the stay cylinder, tubesheet, tube support plates, or the shape of the tubes to perform the intended safety functions. The description of the original steam generators was focused on the overall thermal performance characteristics and the applicable codes and standards used for fabrication. The updated final safety analysis report provided a brief description of the egg-crate tube support plate design and its function to prevent concentration of impurities in the tube-to-tube support plate gap, which could lead to tube degradation. The updated final safety analysis report also described degradation issues of the egg-crate tube support plate design as a result of flow-accelerated corrosion and the corrective actions taken to mitigate this degradation mechanism.
Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, November 2000, allows the use of NEI 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision 1 for methods that are acceptable for complying with 10 CFR 50.59. Per NEI 96-07, changes affecting structures, systems, or components that are not explicitly described in the updated final safety analysis report can have the potential to adversely affect structure, system, or component design functions that are described and thus may require a 10 CFR 50.59 evaluation. Consistent with this guidance, SCEs 50.59 screening evaluated the differences in subcomponents between the original steam generators and replacement steam generators as to whether the differences adversely affected the design function (reactor coolant pressure boundary) of the steam generators. The replacement steam generators were designed and fabricated in accordance with quality assurance requirements, and 10 CFR 50.59 does not require the licensee to presume deficiencies in the design or fabrication.
- c. Conclusions The team determined that no significant differences existed in the design requirements of Unit 2 and Unit 3 replacement steam generators. Based on the updated final safety analysis report description of the original steam generators, the team determined that the steam generators major design changes were reviewed in accordance with the 10 CFR 50.59 requirements.
The team identified two unresolved items:
Evaluation of Retainer Bar Vibration during the Original Design of the Replacement Steam Generators Evaluation of changes in Dimensional Controls during the Fabrication of Unit 2 and Unit 3 Replacement Steam Generators
Enclosure Additionally, an unresolved item related to a change in a method of evaluation used for the stress analysis calculations is discussed in Section 13 of the report.
5.0 Quality Assurance/Quality Control (Charter Item 5) (Mitsubishi Charter Item 4)
The team reviewed numerous documents from both SCE and Mitsubishi (including sub-contractors, such as Sumitomo) associated with the design, fabrication, and manufacturing of the steam generators for both units. The team reviewed SCE and Mitsubishis quality assurance program, procedures and implementation activities for the control of purchased material, equipment, and services; inspections; procurement document control; and corrective action and nonconformance activities. Specifically, the team reviewed a sample of Mitsubishi nonconformance reports, audit, survey, all SONGS condition action requests, audits, surveillances, stop work orders, and supplier deviation requests associated with the design and manufacturing of the steam generators. The team concluded that these portions of SCE and Mitsubishis quality assurance program regarding its safety-related activities were appropriately controlled and implemented.
5.1 SONGS Quality Assurance/Quality Control
- a. Inspection Scope The team reviewed SCEs implementation of their quality assurance program to determine if it complied with the requirements of 10 CFR 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants. The team reviewed SONGS implementing procedures, quality assurance manual, vendor audits, procurement specifications, corrective action requests, and numerous other documents, as well as interviewed a number of quality assurance/control and engineering personnel to determine the appropriateness of activities affecting quality conducted during fabrication, manufacturing and delivery of the replacement steam generators.
- b. Observations and Findings No findings were identified.
(1) Policies and Procedures for Supplier Selection and Control The team reviewed Quality Assurance Manual, Section 17.2.7, Control of Purchased Material and Services, which defines the process used to ensure that purchased material, source material, and subcontracted services conform to applicable codes and standards. Section 17.2.7.2 of the quality assurance manual provided measures for the approval and control of suppliers and describes the methods that SCE uses to conduct technical and quality assurance evaluations of potential suppliers. Specifically, SCE evaluated an audit performed by Dominion (DA 2002-92, Dominion Audit of Mitsubishi Heavy Industries). The evaluation was performed and documented in accordance with SONGS policies and implementing procedures that govern the control of purchased material, equipment, and services.
The results of SCE Evaluation MHI-01-04, Evaluation and Review of Contractor,
Enclosure
- a. Inspection Scope The team conducted and overall review of Mitsubishi thermal-hydraulic design documents and drawings used in the manufacture of the Units 2 and 3 steam generators. The team developed an independent ATHOS model to run simulations for various operating conditions to assess thermal-hydraulic phenomena in the steam generators and assess differences in key parameters based on changing operating conditions. The objective of the modeling was to understand the interactions of the key parameters to compare ATHOS modeling results to the degradation trends found during the eddy current inspections.
The team reviewed portions of the vibration modeling. Two key outputs of the thermal-hydraulic code are inputs to the vibration model, the ATHOS model results for fluid velocity and void fraction were used to predict increases or decreases in vibration forces and amplitude.
- b. Observations and Findings The team identified one unresolved item for which additional information is required to determine if a performance deficiency exists or if the issue constitutes a violation of NRC requirements.
(1)
Introduction:
The team identified an unresolved item associated with the adequacy of Mitsubishis FIT-III thermal-hydraulic code. The FIT-III code predicted non-conservative low velocity and low void fraction results which were used as inputs to the vibration code FIVATS. These non-conservative thermal-hydraulic results lead Mitsubishi to conclude that margins to instability were significantly larger than they actually were.
==
Description:==
Replacement steam generators were designed and manufactured in accordance with SONGS Design Specification SO23-617-1and ASME Section III, Rules for Construction of Nuclear Facility Components. The replacement steam generators had enhanced materials and maintenance.
The tube bundle, comprised of 9727 u-tubes, is supported by a set of seven tube support plates which are maintained and spaced by a network of tie-rods. The ends of the u-tubes were welded onto the tube sheet lower face cladding and were full depth expanded in the tube sheet holes. The u-bends are supported by a set of 6 anti-vibration bars, having a maximum of 12 contact points, in the center of the bundle. For shorter tubes near the periphery, a fewer number of anti-vibration bars are present.
One of the major enhancements of the replacement steam generators was the use of Alloy-690 tubing versus Alloy-600 for corrosion resistance. Alloy-690 has lower heat conductivity so, to achieve the same power, the heat transfer surface area must be increased by at least 10 percent. This required more tubes to be used in the replacement steam generators. The increased number of tubes resulted in a more tightly compacted tube bundle and elimination of the stay cylinder. The increase in the number of tubes could lead to increases in primary reactor coolant flow through
SCE ATTACHMENT 32
SCE ATTACHMENT 33
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SOUTHERN CALIFORNIA
!~.~:;;:\\., EDISO N An EDISON INTERNATIONAL Company January 24, 2013 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
Subject:
Docket No. 50-361 Response to Request for Additional Information (RAI 18)
Regarding Confirmatory Action Letter Response (TAC No. ME 9727)
San Onofre Nuclear Generating Station, Unit 2 Richard I, St. Onge Director, Nuclear Regulatory Affairs and Emergency Planning 10 CFR 50.4
References:
- 1. Letter from Mr. Elmo E. Collins (USNRC) to Mr. Peter T. Dietrich (SeE), 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. Letter from Mr. Peter T. Dietrich (SCE) to Mr. Elmo E. Collins (USNRC), dated October 3, 2012, Confirmatory Action Letter - Actions to Address Steam Generator Tube Degradation, San Onofre Nuclear Generating Station, Unit 2
- 3. Letter from Mr. James R. Hall (USNRC) to Mr. Peter T. Dietrich (SCE), dated December 26,2012, Request for Additional Information Regarding Response to Confirmatory Action Letter, San Onofre Nuclear Generating Station, Unit 2
Dear Sir or Madam,
On March 27,2012, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) (Reference 1) to Southern California Edison (SCE) describing actions that the NRC and SeE agreed would be completed to address issues identified in the steam generator tubes of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3. In a letter to the NRC dated October 3, 2012 (Reference 2), SCE reported completion of the Unit 2 CAL actions and included a Return to Service Report (RTSR) that provided details of their completion.
Byletter dated December 26, 2012 (Reference 3), the NRC issued Requests for Additional Information (RAls) regarding the CAL response. Enclosure 1 of this letter provides the response to RAI 18.
P.O. Box 128 San Clemente, CA 92672
Document Control Desk January 24, 2013 There are no new regulatory commitments contained in this letter. If you have any questions or require additional information, please call me at (949) 368-6240.
Sincerely,
Enclosures:
1.
Response to RAI 18 cc:
E. E. Collins, Regional Administrator, NRC Region IV R. Hall, NRC Project Manager, SONGS Units 2 and 3 G. G. Warnick, NRC Senior Resident Inspector, SONGS Units 2 and 3 R. E. Lantz, Branch Chief, Division of Reactor Projects, NRC Region IV
ENCLOSURE 1 SOUTHERN CALIFORNIA EDISON RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING RESPONSE TO CONFIRMATORY ACTION LETTER DOCKET NO. 50-361 TAC NO. ME 9727 Response to RAI 18 Page 1
RAI18 Reference 1, Section 11.1, page 52 - SeE proposes to upgrade the vibration and loose parts monitoring system (VLPMS) as a defense-in-depth measure to enhance plant monitoring capability to facilitate early detection of a steam generator tube leak and ensure immediate and appropriate plant operator and management response.
Fluid Elastic Instability (FEI) was identified as a main cause of the tube wear for both the Unit 2 and 3 steam generators. The FEI experienced is due to a combination of the conditions of steam quality, secondary side fluid velocity in the vicinity of the tube bundle, and steam void fraction, and the degree of such fluid elastic instability is related to the damping provided by internal support structures. According to your report, "steam quality directly affects the fluid density outside the tube, affecting the level of hydrodynamic pressure that provides the motive force for tube vibration. When the energy imparted to the tube from hydrodynamic pressure (density times velocity squared, or pv2) is greater than the energy dissipated through damping, FEI will occur." However, the proposed plant VLPMS enhancement does not appear to directly monitor steam quality, secondary side fluid velocity, or steam void fraction.
Please provide the following information to address the effectiveness of the enhanced VLPMS:
a.
Describe the specific purpose of using the enhanced VLPMS equipment for monitoring steam generator performance. For example, is it to be used for monitoring acoustic noise indicative of flow velocity, steam quality, and void fraction, or for the measurement of metallic noise indicative of vibration of tubes against each other or against tube support structures? Exactly how will this be done? What is the theory of operation? If it will be used to monitor an increase in pv2 leading to the onset of FEI, provide a description of the correlation of the velocity of steam voids through the secondary side of the steam generator and the relative changes in characteristics of the signal output from the various VLPMS accelerometers. If it is to be used for detecting actual tube vibration, provide a description of the process that will be used for discerning actual tube vibration noise from background noise, and the required threshold identification criteria that will be applied to reach the conclusion that tube vibration is occurring.
b.
Identify the ranges of amplitudes and frequencies of the acoustic noise signal's from each accelerometer that are indicative of an approach to the conditions leading to FEI or actual tube vibration, and the reasons for selection of the more sensitive accelerometers.
Also, discuss the required response time of the signal processing equipment needed to detect and continuously monitor either fluid velocities within the steam generator or tube impact noise, depending on the intended use of the enhanced VLPMS, and the actual response time capabilities of the equipment, from sensor through processed signal output, that is being proposed for use.
c.
Discuss the acceptance criteria (e.g., magnitude of signal, plant power level, etc.) that will be used to establish the setpoints for the alarms described in Section 11 of your report: "The signals from these sensors are compared with preset alarm setpoints."
Provide a description of how the alarm setpoints were established, and at what point during the start-up of Unit 2 will these alarm setpoints be calibrated into the VLPMS. If the setpoints have not yet been determined, provide a description of your plan for determining and implementing these settings.
Page 2
d.
Describe the planned operator actions and any changes to the procedures for responding to alarms or signals potentially indicative of tube-to-tube contact, including time limits for analyzing the signals and taking any necessary action including plant shutdown. Describe the lessons learned that have been drawn from the signals of potential metal-to-metal contact experienced in Unit 3 and how these lessons have been factored into current procedures.
e.
A description of how you determined that acoustic noise monitoring and predictive signal processing was the best method for monitoring either the onset of FEI or actual tube vibration, including a list of other methods (e.g., time domain reflectivity probes calibrated for steam void propagation monitoring) that had been considered for enhancing steam generator tube monitoring during start-up of Unit 2, and the reasons for their rejection.
RESPONSE
The purpose of the upgraded vibration and loose parts monitoring system (VLPMS) is to provide additional monitoring capabilities for steam generator (SG) secondary side acoustics. The upgraded VLPMS is capable of recording secondary side acoustic signals via accelerometers mounted on the external shell of the SGs at locations near the upper tube bundle and tubesheet. The upgraded VLPMS will be used as a backward looking analysis tool in subsequent inspection outages should unexpected wear be discovered. The upgraded VLPMS will enable SCE to evaluate historical SG secondary side acoustic signal data for events which may help with the understanding of the causes of unexpected tube wear.
The Unit 2 Return to Service (RTS) report describes the upgrades to the VLPMS in Section 11.1 as an additional action to provide monitoring capabilities for secondary side acoustic signals.
SCE did not propose the upgrade of the VLPMS as a defense-in-depth measure nor as a means of monitoring steam quality, secondary side fluid velocity, or steam void fraction.
. Corrective measures to control these secondary side parameters are addressed in Section 8 of the RTS report. The defense-in-depth measures being taken in support of Unit 2 return to service are described in Section 9 of the RTS report.
The theory of operation of the VLPMS data acquisition equipmentis provided as follows:
The Vibration and Loose Parts Monitoring System (V&LPMS) is a stand-alone system designed to perform loose parts detection and vibration monitoring functions. The loose part detection function is designed to fulfill the requirements of the loose parts detection system as set forth in Regulatory Guide 1.133. The design objective of the loose parts detection portion of the V&LPMS is to detect the presence of loose parts in the reactor coolant system (RCS) and annunciate an alarm in the control room when a loose part is detected.
The system consists of loose parts and vibration sensors, preamplifiers and a computerized data acquisition and processing system. The sensors and preamplifiers are located inside the containment and the data acquisition and processing equipment is housed in a cabinet located in the control room cabinet area. The equipment located inside containment consists of piezo-electric sensors, preamplifiers and associated cabling at each of the following natural collection regions of each unit to detect loose parts:
Page 3
Upper reactor vessel; vessel head on head lift rig stopper Lower reactor vessel; outside wall Steam generator E088; outside wall Steam generator E089; outside wall The RCS component vibration monitoring, reactor internal vibration monitoring, and vibration data analysis features are on-demand functions. The on-demand features provided with the VLPMS allow the selection of any two loose parts, vibration or reactor internal vibration channels for vibration monitoring or analysis. The on-demand data acquisition and analysis features also allow a live channel signal or historical data from the historical data file to be selected for time domain and/or frequency domain analysis, displayed, stored and/or printed.
The upgrades to the VLPMS consist of:
Relocation of existing VLPMS accelerometers (2 per SG) from the support skirt to locations above and below the SG tubesheet. These will remain as VLPMS sensors to meet Regulatory Guide 1.133, "Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors" Installation of increased sensitivity accelerometers (2 per SG) at locations above and below the tubesheet Installation of increased sensitivity accelerometers (2 per SG) on an 8 inch hand hole on the side of the SGs to monitor for secondary side noises at the upper tube bundle Relocation of the accelerometers enhances the acoustic monitoring of the SG secondary side by placing accelerometers closer to the upper tube bundle.
The new accelerometers have an increased sensitivity of25 pC/g compared with 10 pC/g for the existing accelerometers. The acceptance criteria used to establish the setpoints for the alarms associated with the upgraded VLPMS accelerometers is the same as used with the Regulatory Guide 1.133 accelerometers. After Unit 2 reaches 700/0 power, background data is collected and alarm thresholds are established to compensate for high background noise as discussed in Regulatory Guide 1.133, section C.1.b, "System Sensitivity."
Operator actions for VLPMS alarms are controlled by the VLPMS trouble annunciator operations alarm response procedure. Upon an alarm, the VLPMS automatically records data for all of the VLPMS accelerometer channels. The Control Room Shift Technical Advisor is instructed by this procedure to immediately notify the system engineer supervisor for any loose parts channel alarms associated with the SGs. The Control Room Operator documents the VLPMS alarm in the site Corrective Action Program (CAP). The CAP requires an'operability determination to be made within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of event discovery. Each loose parts alarm associated with SGs will be independently reviewed by an offsite vendor.
Following identification of tube-to-tube wear (TTW) caused by Fluid Elastic Instability (FEI) in Unit 3 and two indications of TTW in Unit 2, a review of the VLPMS alarms for the previous operating cycle of both units was performed. No potential metal-to-metal contact alarms were recorded for Unit 2. Potential metal-to-metal contact alarms were recorded for Unit 3. Analysis of data from Unit 3 VLPMS events concluded most of the events were the result of RCS temperature changes. A number of events were not directly associated with RCS temperature Page 4
changes and were reviewed by on-site as well as independent off site personnel. The independent review concluded these alarms were caused by: "...true metallic impacts and not false indications from electrical noise or fluctuations in background noise." The review found the acoustic signals were similar to those that occur when the SGs shift during ReS temperature transients. None of the VLPMS alarms were attributed to SG tube vibration.
Since the VLPMS is not designed to detect tube to tube contact, the absence of tube vibration related VLPMS alarms is consistent with the capabilities of its design. The approach in the Unit 2 RTS plan is to eliminate the causes of TTW caused by FEI. Reducing power reduces SG secondary side thermal-hydraulic parameters to values within the industry's experience. While the RTS plan does not require a direct method to measure tube vibration, SeE determined it was appropriate to upgrade the existing VLPMS as discussed above.
Page 5
SCE ATTACHMENT 34
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 December 26, 2012 Mr. Peter T. Dietrich 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, UNIT 2 - REQUEST FOR ADDITIONAL INFORMATION REGARDING RESPONSE TO CONFIRMATORY ACTION LEITER (TAC NO. ME9727)
Dear Mr. Dietrich:
On March 27,2012 (Agencywide Documents Access and Management System (ADAMS)
Accession No. ML12087A323), the U.S. Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) to Southern California Edison (SCE) regarding the San Onofre Nuclear Generating Station (SONGS), Units 2 and 3. The CAL confirms certain actions that SCE will take to address steam generator tube degradation issues at both units. The CAL also confirms that SCE will not resume power operation at either unit until the NRC completes its review of those actions and formally communicates its permission to restart in written correspondence.
By letter dated October 3,2012 (ADAMS Accession No. ML12285A263), SCE submitted its response to the CAL for SONGS Unit 2. The NRC staff is conducting its detailed review of SCE's CAL response for SONGS Unit 2 and has determined that additional information is needed in order to complete our evaluation. The staff's questions are provided in the enclosed request for additional information (RAI). The staff previously issued these RAI questions in draft form, on November 30,2012 (ADAMS Accession No. ML12338A110), on December 10,2012 (ADAMS Accession No. ML12345A427), and on December 20, 2012 (ADAMS Accession No. ML12356A198). Based upon clarifying discussions on RAI questions 1-31 between NRC and SCE at a public meeting on December 18, 2012, the enclosed final version of these questions is unchanged from the previous draft versions. In that meeting, SCE stated that it expects to provide responses to RAI questions 1-31 by mid-January of 2013. Please provide an estimated date for your response to RAI question 32. The NRC staff expects to issue additional RAls to SCE as our review continues.
P. Dietrich
-2 If you have any further questions regarding this letter, please contact me at (301) 415-4032 or via e-mail at randy.hall@nrc.gov.
Sincerely, Btl c 4.J &"~r ~
all, Senior Project Manager Sa Ono Special Projects Branch Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-361
Enclosures:
Request for Additional Information cc w/Enci Distribution via Listserv
OFFICE OF NUCLEAR REACTOR REGULATION REQUEST FOR ADDITIONAL INFORMATION SOUTHERN CALIFORNIA EDISON SAN ONOFRE NUCLEAR GENERATING STATION, UNIT 2 RESPONSE TO MARCH 27, 2012, NRC CONFIRMATORY ACTION LETTER DOCKET NO. 50-361 TAC NO. ME9727 By letter dated October 3, 2012, (Agencywide Documents Access and Management System (ADAMS) Accession No. ML12285A263), Southern California Edison (SCE) submitted its response to the NRC Confirmatory Action Letter (CAL) dated March 27, 2012, for San Onofre Nuclear Generating Station (SONGS), Unit 2. The details of SCE's response to the CAL are provided in Enclosure 2 to that October 3, 2012, letter (Reference 1). The NRC staff is conducting its detailed review of SCE's CAL response for SONGS Unit 2 and has determined that additional information is needed in order to complete our evaluation. The staff's additional questions are stated in this request for additional information (RAI) below. The staff previously issued these RAI questions in draft form, on November 30,2012 (ADAMS Accession No. ML12338A110), on December W, 2012 (ADAMS Accession No. ML12345A427), and on December 20,2012 (ADAMS Accession No. ML12356A198). Based upon clarifying discussions between NRC and SCE at a public meeting on December 18, 2012, the final version of these questions is unchanged from the previous draft versions.
- 1. The Operational Assessment (OA) in Attachment 6, Appendix A (Reference 2), reports the 3 times normal operating pressure differential as being 4290 psi for 100% power conditions. This is the same value assumed in the Condition Monitoring Assessment provided in Attachment 2. This value is significantly higher than the values ranging from 3972-3975 psi for 100% power reported in Attachment 6, Appendices B, C, and D (References 3-5). Describe the reason for the differences.
- 2. The Operational Assessment in Attachment 6, Appendix C (Reference 4), pages 3-2 and 4-12, appears to state that tube-to-tube wear (TIW) growth rates are based on the maximum TTW depths observed in Unit 3 at EOC 16 divided by the first Unit 3 operating period (0.926 years at power). Provide justification for the conservatism of this assumption. This justification should address the following:
- a. Reference 4, page 3-2 defines "wear index" for a degraded tube and states that the existence of TTW and distribution of TTW depths are strongly correlated to the wear index. This is pictured in Figures 4-4 in terms of TTW initiation. This figure shows that TTW is not expected to have initiated until a threshold value of wear index is reached. This threshold value varies from tube to tube according Enclosure
- 2 to a cumulative probability distribution shown in the figure. This figure illustrates that TTW is not expected to have initiated until sometime after BOC 16. This suggests that the observed TTW depth at EOC 16 developed over a smaller time interval than the 0.926 years assumed in the analysis.
- b. An independent analysis in Reference 3 also indicates an extremely low probability of instability onset at BOC 16 as illustrated in Figure 8-3. Reference 3, page 106 interprets this figure as indicating that the probability of instability only reaches 0.22 after 3 months and only becoming "high" after 4 months.
- c. Reference 3 also considered a variety of different wear rate models to estimate how long it took to develop the observed TTW depths at Unit 3 after instability occurred. These analyses are documented in Appendix A of Reference 3 and produced estimates in the range of 2.5 to 11 months.
- 3. Regarding Reference 4, describe the sensitivity of the results in Figure 5-4 to the definition of "wear index." If alternate definitions significantly affect the results, what is the justification for the definition being used?
- 4. Regarding Reference 4, does the definition of "wear index" include summing the depths of 2-sided wear flaws at a given AVB intersection? If not, explain why SCE's approach is conservative.
- 5. Regarding Reference 4, third paragraph from the bottom of page 4-3, why is non detected wear only assigned to no degradation detected (NOD) tubes and not to NOD tube/AVB intersections in tubes with detected wear at other intersections?
- 6. Regarding Reference 4, page 4-5, it seems that depths of undetected flaws are assumed to be associated with probability of detection (POD).::. 0.05. Why is this conservative? Is there a possibility that some undetected flaws may be associated with higher values of POD?
- 7. Regarding Reference 4, page 4-5, what is meant by the words, "each active wear location" in the 1350 NOD tubes? How are the "active wear" locations determined?
- 8. It is stated in Reference 4, page 4-6, second paragraph that, "It has been observed that the number of AVB supports that develop wear in the second cycle of operation can increase dependant on the number of worn AVB indications at the beginning of the second cycle. These data were used in the OA to add AVB locations at the start of Cycle 17 from a statistical representation of this data." Provide a more complete description of the model used to add AVB locations that will develop wear during the
- 3 second cycle. Confirm that this model applies to both the 560 tubes with existing tube support wear and the 1350 NOD tubes.
- 9. It is stated in Reference 4, at the top of page 4-9 that the simulation results of the bench marking process are shown in Figure 4-6. Provide additional detail on what Figure 4-6 is showing and how it relates to the benchmarking process. As part of this additional detail, explain the meaning of the ordinate label "number of observations" in the figure.
- 10. Technical Specification (TS) 3.4.13.d allows 150 gallons per day primary to secondary leakage. The Return to Service Report (Enclosure 2 of Reference 1), Section 9.4.1 states, "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." Does this mean that a reactor shutdown would be commenced upon any valid indication of primary to secondary leakage? Provide a description of the action levels in the procedure. Discuss any additional actions, planned or taken, such as simulator testing, operator training, and/or any evaluations to assess potential impacts of the revised procedure.
- 11. Please submit an operational impact assessment for operation at 70% power. The assessment should focus on the cycle safety analysis and establish whether operation at 70% power is within the scope of SCE's safety analysis methodology, and that analyses and evaluations have been performed to conclude operation at 70% power for an extended period of time is safe. The evaluation should also demonstrate that the existing Technical Specifications, including limiting conditions for operation and surveillance requirements, are applicable for extended operation at 70% power.
- 12. Operation at a lower power level could introduce additional uncertainty in measuring reactor coolant flow. Please provide a detailed evaluation of RCS flow uncertainty, identify how RCS flow uncertainty is affected by operation at 70% power, and discuss the overall treatment of the RCS flow uncertainty, actual and indicated, in the context of the remaining safety analyses. Provide similar information for secondary flow uncertainty. as well.
- 13. The installation of new steam generators involved changes to the steam generator heat transfer characteristics, which could affect the performance of the plant under postulated loss of coolant accident conditions. Please explain how the existing ECCS analysis accounts for these changes, and how considerable steam generator tube plugging has been addressed in the ECCS evaluation. Provide the ECCS evaluation that will apply to the planned operating cycle.
- 4
- 14. Provide a summary disposition of the U2C17 calculations relative to the planned reduced-power operation.
- 15. In Reference 1, Section 8.3.2, page 48 - How will the continued integrity of the non stabilized, preventively-plugged tubes adjacent to the retainer bars be ensured?
"Integrity" in this context refers to the tubes remaining intact and unable to cause damage to adjacent tubes.
- 16. Reference 1, Section 9.3, page 50 - Provide additional information concerning the "Operational Decision Making" process and describe how it would be applied if the proposed criterion is exceeded. Provide the procedural action statement.
- 17. Reference 1, Section 9.4.1, page 50 - Provide the procedural action levels/statements.
- 18. Reference 1, Section 11.1, page 52 - SCE proposes to upgrade the vibration and loose parts monitoring system (VLPMS) as a defense-in-depth measure to enhance plant monitoring capability to facilitate early detection of a steam generator tube leak and ensure immediate and appropriate plant operator and management response.
Fluid Elastic Instability (FEI) was identified as a main cause of the tube wear for both the Unit 2 and 3 steam generators. The FEI experienced is due to a combination of the conditions of steam quality, secondary side fluid velocity in the vicinity of the tube bundle, and steam void fraction, and the degree of such fluid elastic instability is related to the damping provided by internal support structures. According to your report, "steam quality directly affects the fluid density outside the tube, affecting the level of hydrodynamic pressure that provides the motive force for tube vibration. When the energy imparted to the tube from hydrodynamic pressure (density times velocity squared, or pv2) is greater than the energy dissipated through damping, FEI will occur."
However, the proposed plant VLPMS enhancement does not appear to directly monitor steam quality, secondary side fluid velocity, or steam void fraction.
Please provide the following information to address the effectiveness of the enhanced VLPMS:
- a. Describe the specific purpose of using the enhanced VLPMS equipment for monitoring steam generator performance. For example, is it to be used for monitoring acoustic noise indicative of flow velocity, steam quality, and void fraction, or for the measurement of metallic noise indicative of vibration of tubes against each other or against tube support structures? Exactly how will this be done? What is the theory of operation? If it will be used to monitor an increase 2
in pv leading to the onset of FEI, provide a description of the correlation of the velocity of steam voids through the secondary side of the steam generator and the relative changes in characteristics of the signal output from the various VLPMS accelerometers. If it is to be used for detecting actual tube vibration,
- 5 provide a description of the process that will be used for discerning actual tube vibration noise from background noise, and the required threshold identification criteria that will be applied to reach the conclusion that tube vibration is occurring.
- b. Identify the ranges of amplitudes and frequencies of the acoustic noise signals from each accelerometer that are indicative of an approach to the conditions leading to FEI or actual tube vibration, and the reasons for selection of the more sensitive accelerometers. Also, discuss the required response time of the signal processing equipment needed to detect and continuously monitor either fluid velocities within the steam generator or tube impact noise, depending on the intended use of the enhanced VLPMS, and the actual response time capabilities of the equipment, from sensor through processed signal output, that is being proposed for use.
- c.
Discuss the acceptance criteria (e.g., magnitude of signal, plant power level, etc.)
that will be used to establish the setpoints for the alarms described in Section 11 of your report: "The signals from these sensors are compared with preset alarm setpoints." Provide a description of how the alarm setpoints were established, and at what point during the start-up of Unit 2 will these alarm setpoints be calibrated into the VLPMS. If the setpoints have not yet been determined, provide a description of your plan for determining and implementing these settings.
- d. Describe the planned operator actions and any changes to the procedures for responding to alarms or signals potentially indicative of tube-to-tube contact, including time limits for analyzing the signals and taking any necessary action including plant shutdown. Describe the lessons learned that have been drawn from the signals of potential metal-to-metal contact experienced in Unit 3 and how these lessons have been factored into current procedures.
- e. A description of how you determined that acoustic noise monitoring and predictive signal processing was the best method for monitoring either the onset of FEI or actual tube vibration, including a list of other methods (e.g., time domain reflectivity probes calibrated for steam void propagation monitoring) that had been considered for enhancing steam generator tube monitoring during start-up of Unit 2, and the reasons for their rejection.
- 19. Reference 1, Section 11.2, page 52 - Provide additional details on how the GE Smart Signal System will be used in the context of tube-to-tube wear and/or the circumstances associated with tube-to-tube wear. What information/data will the system be evaluating?
For what purpose?
- 20. Reference 3, page 17 of 129, refers to tube-to-support design clearance of 2 mils diametral. Confirm that this is the nominal diametral clearance under ambient conditions, or clarify the statement otherwise.
- 21. Reference 3, page 44 of 129, states that the plugged tubes have an effect on local thermal/hydraulic conditions upon returning to power and have been included in the
- 6 stability ratio calculations. The staff interprets this to mean the effect of the plugged tubes on the calculated thermal/hydraulic conditions were considered in the stability ratio calculations and that the stability ratio calculations included the plugged (and stabilized) tubes. Is this correct? Clarify, if not.
22, Reference 3, page 57 of 129, first full paragraph beginning with the words "Figure 6-1" The third sentence states, "", it is not practical to use an individual run of the quarter model as a single Monte Carlo trial for contact forces," However, the staff was unable to ascertain from the subsequent discussion exactly what was done as an alternative? Nor was the staff able to discern this from Reference 6, Appendix 9, Provide or cite by reference a more complete description of how the cumulative distributions of contact forces were determined, For example, what is a "run?" What does it mean to "combine runs?" How were zones employed in order to provide a more practical approach? Are all tubes in a given zone assumed to have the same initial clearances, final clearances, and contact forces? Do all AVB #5 in a zone have the same cumulative distribution of contact forces? Is a Monte Carlo performed for each zone?
23, Reference 3 - Provide figures similar to Figures 6-19 and 6-20 for Unit 3, SG E-088, and Unit 2, SG E-088, 24, Reference 3, page 59 of 129, last paragraph - The sentence, "AVBs 2,3,11 and 10 near row 27 have sporadic dents in the vicinity of the noses of AVBs 1, 4, 9 and 12" does not appear to make sense, Provide further clarification relative to the discussion of Figure 6-20, 25, Reference 3, page 59 of 129 - There is a statement in the last paragraph that reads, "Patterns of dents and associated high contact forces are in good agreement with the final quarter model calculations," Provide or show this comparison.
26, Reference 3, page 107 of 129, second to last paragraph - Provide additional details of the wear growth model at the tube supports, Were cumulative probability functions of observed wear rates constructed and randomly sampled when developing the contact force probability distributions at each intersection? Was total gap at each intersection (prior to applying temperature and allowing the model to settle, leading to the development of contact forces) assumed to be the sum of the manufacturing gap and the maximum wear depth?
- 27. Reference 6, Appendix 8, "SG Tube Flowering Analysis", page 8-2 (307 of 474) - MHI concludes, in part, that the tube-to-AVB gaps in the center columns increase due to hydrodynamic pressure by [ ] when the manufacturing tolerance dispersion is not taken into account. MHI also concludes that the gap increase due to hydrodynamic pressure is small when the manufacturing tolerance dispersion is taken into account. Discuss whether this latter finding may Simply reflect the hydrodynamic pressures acting to
- 7 relieve the tube-to-AVB contact forces caused by the manufacturing tolerance dispersion, such that the gaps are relatively unchanged relative to the case were the hydrodynamic pressure is not considered. Reference 6, Appendix 9, "Simulation of Manufacturing Dispersion for Unit-2/3," does not seem to make specific mention of whether the calculated tube-to-AVB contact forces directly considered the effect of the hydrodynamic effect on tube-to-tube contact forces, but the staff understands that they did not. If the staff's understanding is correct, explain how the resulting contact forces are conservative.
- 28. Reference 5, Section 2.6.1 - What is the estimated growth rate of the tube-to-tube wear in steam generator 3EO-88, tube R 1 06C78? Describe how it was determined.
- 29. Reference 5, Figures 2-12 and 2 Provide similar figures for Case 78 (all AVBs missing).
- 30. Reference 1, Figure 8 Provide similar figure for maximum interstitial velocities.
- 31. In References 7 and 8 (specifically, in Section 7.2 of Reference 7 and in Section 8.0 of Reference 8), AREVA used Revision 3 of the Electric Power Research Institute "Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines," in part, to assess the most limiting structural integrity performance criteria (e.g., the more limiting structural limit determined from (a) the three times the normal operating differential pressure criterion or (b) the safety factor of 1.2 on combined primary loads and 1.0 on axial secondary load criterion). In some cases, it appears that the limits in the Integrity Assessment Guidelines may have been based on specific tests and plant data. Please discuss whether you have confirmed the applicability of the limits in the Integrity Assessment Guidelines (in particular, those related to when non-pressure loads need to be considered) to the SONGS replacement steam generators.
'32. SONGS Unit 2 Technical Specification (TS) 3.4.17 requires that steam generator structural integrity be maintained in Modes 1, 2, 3, and 4 (Power Operation, Startup, Hot Standby, and Hot Shutdown, respectively). Limiting Condition for Operation (LCO) 3.4.17, "Steam Generator (SG) Tube Integrity," requires that steam generator tube integrity shall be maintained and all steam generator tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program in MODES 1, 2, 3, and 4. The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for LCO 3.4.17. Surveillance Requirement (SR) 3.4.17.1 requires "Verify SG tube integrity in accordance with the Steam Generator Program."
The structural integrity performance criterion is described in SONGS Unit 2 TS 5.5.2.11.b.1 as follows:
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, cool down and all anticipated transients
- 8 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. [emphasis added]
As described in the SONGS Unit 2 license, SCE "is authorized to operate the facility at reactor core power levels not in excess of full power (3438 megawatts thermal)," which is also defined as Rated Thermal Power (RTP).
In SCE's operational assessment (OA) that evaluated tube degradation caused by mechanisms other than tube-to-tube wear (Reference 2), on Page 30 of 32, SCE concluded that "there is reasonable assurance that the performance criteria for the non
[tube-to-tube wear] TTW degradation will be met if Unit 2 were to operate for a full fuel cycle of 1.S77 EFPY [effective full power years] at 100% reactor power." Thus it appears that in Reference 2, SCE considered the requirements of TS S.S.2.11.b.1 by addressing the licensed full power condition.
In contrast, SCE performed three other operational assessments that evaluated tube degradation due to tube-to-tube wear (References 3-S), but it appears that in these ~As, SCE addressed structural integrity requirements for TTW only at 70% reactor power, instead of at 100% reactor power. For example, in Reference 3, Section 10.0, "Conclusions," page 117 of 129, SCE states: "A 70% operating power level returns the Unit 2 steam generators to within the operational envelope of demonstrated successful operation... Operation at 70% power assures in-plane stability (SR<1) without dependence on any effective in-plane supports for U-bends."
Therefore, it appears that SCE has not provided an operational assessment that addresses compliance with TS S.S.2.11.b. for tube-to-tube wear, without reliance on compensatory measures (e.g., limiting reactor power to 70% RTP).
Please clarify how the information submitted by SCE demonstrates that the structural integrity performance criterion in TS 5.5.2.11.b.1 is met for operation within current licensed limits up to the licensed RTP, or provide an operational assessment that includes an evaluation of steam generator TTW for operation up to the RTP.
REFERENCES
- 1. letter from Peter 1. Dietrich, SCE, to Elmo E. Collins, USNRC, "Docket No. SO-361, Confirmatory Action letter - Actions to Address Steam Generator Tube Degradation,
- 9 San Onofre Nuclear Generating Station, Unit 2," October 3, 2012; Enclosure 2, "San Onofre Nuclear Generating Station Unit 2 Return to Service Report, Revision 0."
(ADAMS Accession No. ML12285A263; ADAMS Package No. ML122850320)
- 2. Attachment 6 to Reference 1, "SONGS U2C17 Steam Generator Operational Assessment," Appendix A, Revision 2, "SONGS U2C17 Outage - Steam Generator Operational Assessment," prepared by Areva NP Inc. Document No. 51-9182833-002 (NP), Revision 2), October 2012. (ADAMS Accession No. ML12285A267)
- 3. Attachment 6 to Reference 1, "SONGS U2C17 Steam Generator Operational Assessment," Appendix B, Revision 0, "SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear," prepared by Areva NP Inc. Document No. 51 9187230-000 (NP), Revision 0), October 2012. (ADAMS Accession Nos.
ML12285A267, ML12285A268, and ML12285A269)
- 4. Attachment 6 to Reference 1, "SONGS U2C17 Steam Generator Operational Assessment," Appendix C, "Operational Assessment for SONGS Unit 2 SG for Upper Bundle Tube-to-Tube Wear Degradation at End of Cycle 16," prepared by Intertek APTECH for Areva, Report No. AES 12068150-2Q-1, Revision 0, September 2012.
(ADAMS Accession No. ML12285A269)
- 5. Attachment 6 to Reference 1, "SONGS U2C 17 Steam Generator Operational Assessment," Appendix 0, "Operational Assessment of Wear Indications In the U-Bend Region of San Onofre Unit 2 Replacement Steam Generators," prepared by Westinghouse Electric Company LLC, Report No. SG-SGMP-12-10, Revision 3, October 2012. (ADAMS Accession No. ML12285A269)
- 6. Attachment 4 to Reference 1, "MHI Document L5-04GA564, Tube Wear of Unit-3 RSG Technical Evaluation Report," Revision 9, October 2012, prepared by Mitsubishi Heavy Industries, LTD. (ADAMS Accession Nos. ML12285A265, ML12285A266, and ML12285A267)
- 7. Attachment 2 to Reference 1, AREVA NP Inc., Engineering Information Record, Document No. 51-9182368 - 003 (NP), "SONGS 2C17 Steam Generator Condition Monitoring Report." (ADAMS Accession No. ML12285A263)
- 8. Attachment 3 to Reference 1, AREVA N P Inc., Engineering I nformation Record, Document No. 51-9180143 - 001 (NP), "SONGS Unit 3 February 2012 Leaker Outage Steam Generator Condition Monitoring Report." (ADAMS Accession No. ML12285A264)
- concurred via email OFFICE NRR/DORLILPSP/PM NRR/DORLlLPL4/LA NRR/DORLILPSP/BC NRR/DORLILPSP/PM NAME JRHali*
JBurkhardt (SFigueroa for)*
DBroaddus (BBenney for)
JRHall (BBenney for)
DATE 12/21/12 12/26/12 12/26/12 12/26/12
SCE ATTACHMENT 35
Steam Generator Management Program: Steam Generator Integrity Assessment Guidelines Revision 3 1019038 Final Report, October 2008 Non-Proprietary Version EPRI Project Manager H. Cothron ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, PaloAlto, California 94304-1338 - P0 Box 10412, Palo Alto, California 94303-0813 - USA 800.313.3774 8 650.855.2121 - askepd@epn.com
- www.epd.com
9 PRIMARY-TO-SECONDARY LEAKAGE ASSESSMENT 9.1 Introduction This section provides requirements for primary-to-secondary leakage assessment and documents methods to calculate leakage. For CM, degradation detected during an inspection shall be evaluated against the accident-induced leakage performance criterion. Degradation length or depth measured for CM purposes is adjusted for NDE measurement uncertainties. Leakage at normal operating conditions is monitored during plant operation and shall be compared to the operational leakage performance criteria. Operational assessment shall be performed to provide assurance that the leakage integrity performance criteria will be met until the next scheduled SG inspection. Degradation length or depth estimated at the EOC is not a measured parameter and therefore no NDE measurement uncertainties need be applied.
9.2 Accident Induced Leakage The allowable tube leakage limit is defined by the accident leakage performance criterion in Section 2. Leakage limits shall be met for all design basis accidents, other than a steam generator tube rupture, and shall not exceed the leakage assumed in the plant accident analysis in terms of the total leakage for all steam generators and the leakage rate for an individual steam generator. The maximum leakage limit is further limited to not exceed 1 gpm per steam generator unless an approved specific alternate repair criteria is being implemented.
Consequently, it is useful to identify the limiting accident for leakage. The limiting accident may depend on the type of tubing degradation of interest, for example, high axial loads are significant for circumferential degradation but not for axial degradation. The limiting accident is defined by the combination of accident specific loads and the accident specific leakage limit leading to the smallest allowable flaw size. It is this flaw size that must meet CM and OA requirements.
Typically, the limiting accident for leakage is simply the accident producing the largest tube loads. However, this may not always be the case. There may be accidents with a low allowable leakage limit combined with loads that, while less than the maximum, lead to the smallest allowable flaw size for leakage. -Accident specific loads and accident specific leakage limits must be evaluated to identify the limiting leakage accident. This can be a difficult exercise since leakage limits based on dose assessments must be combined with accident loads that may be grouped under umbrella transients for convenience and economy. In the absence of more detailed information it is conservative to construct a bounding case by combining the lowest allowable accident leakage with the largest accident tube loads. For plants with accident analyses that assume the same accident leakage for all design basis accidents, other than steam -
generator tube rupture, the limiting accident for leakage is not necessarily the accident producing 9-1
Primary-to-Secondary Leakage Assessment the largest tube loads. Prior to each outage, the limiting leakage accident and allowable leakage value shall be confirmed.
Several plants have made commitments to the NRC Regulatory Guide 1.183 [30] which provides an alternate source term approach for the parameters and assumptions to be met for accident analysis. This would enable plants to increase accident induced leakage limits. These limits require approval by the NRC prior to implementation.
This section provides recommended approaches for calculating both leakage through cracks in steam generator tubes and flaw sizes leading to 100 %TW throughwall penetration under combined accident loads and thus accident leakage contributions. Applications to CM and OA leakage integrity evaluations are discussed. Note that the effect of contributing primary loads other than pressure and axial secondary loads that must be treated as primary loads in OTSG's shall be included in leakage integrity evaluations. In practice this reduces to consideration of axial tensile and bending loads when evaluating circumferential cracking and the circumferential extent of volumetric degradation.
9.3 Operational Leakage The allowable operational leakage limit is defined in plant Technical Specifications and Section
- 2. Primary-to-secondary leakage that develops during operation shall be evaluated per the latest revision of the PWR Primary-to-Secondary Leak Guidelines [31].
The following information generalizes the relationship between operational and accident-induced leakage limits and is provided by the NRC in Regulatory Issue Summary 2007-20 [32]:
The loading conditions on the tubes during an accident may be different than the loading conditions on the tubes during normal operation. As a result, the primary-to-secondary leak rate observed during normal operation may change under accident conditions. In some cases, the primary-to-secondary leak rate may increase as a result of the accident, while in other cases it may decrease. If the loading conditions during an accident result in an increase in the primary-to-secondary leak rate (when compared to the normal operating leak rate), it may be necessary to restrict the normal operating leak rate to less than the normal operating leakage rate limit. This applies not only to units that assume the primary-to-secondary leak rate observed during the accident is the same as the normal operating primary-to-secondary leak rate limit, an assumption that is permitted by the NRC's Standard Review Plan; but also to other units since the increase in primary-to-secondary leak rate going from normal operating conditions to accident conditions can result in significant increases in the leak rate (depending on the accident). The actual amount that the leak rate may increase is a function of several factors including the type of flaw that is leaking. For example, the leak rate from a crack may increase significantly (e.g., by an order of magnitude depending on through-wall crack length) under accident conditions [32].
If operational leakage causes a forced outage, a root cause evaluation shall be performed and included as part of the OA report for the forced outage. A forced outage can result from incorrect assumptions or errors in past analyses.
9-2
Primary-to-Secondary Leakage Assessment If operational leakage is less than shut-down levels and is consistent with that predicted by the OA, no adjustments to OA methodologies are required; however in situ pressure tests may be required. If operational leakage is not predicted by the OA, assessment strategies shall be modified accordingly.
During an inspection outage following operational leakage of greater than 5 GPD in any SG, the following steps shall be taken to establish information about the leak:
- 2. If possible, determine the source of the leakage: This is typically performed by a hydrostatic test, bubble test, or helium leak test to identify suspect tube(s) locations on the tubesheet.
Quantify the rate (for example, drops per minute or gallons per minute [liters per minute]) of leakage. Correlate the calculated leakage (pressure/temperature adjusted leakage) versus the operational leakage. Determine if results have accounted for the observed operational leakage, while recognizing that an accurate comparison of operating and shutdown leakage measurements is difficult. If the source of the leakage cannot be identified using the methods described above, 100% eddy current examination should be considered. If the eddy current examination locates the potential leakage, proceed with Step 4. If the leakage has not been identified, an evaluation of the actions within Step 6 should be considered.
- 3. Examine leaking location(s): This inspection is typically performed by bobbin coil eddy current examination to establish axial location within the SG.
- 4. Examine to determine extent, orientation, and morphology: This is typically performed by rotating coil or array coil technology. Refer to the SGMP PWR Steam Generator Examination Guidelines [1].
- 5. Review prior inspection history: Review the information contained in the-database and the actual historical bobbin and rotating data to establish factual information about the data. If the leakage is originating from a plug or sleeve, review the installation records for that location. Evaluate if installation parameters were met and identify any inconsistencies or nonconforming conditions.
- 6. Perform a root cause evaluation that includes all SG program elements in accordance with the utility's program(s). This evaluation should address the need to perform eddy current and/or secondary-side visual inspections. Also consider supplementing the root cause team with industry peers. The root cause team shall identify immediate, short-term, and long-term actions to correct any process deficiencies.
- 7. Execute root cause ciorective actions
- 9. Perform required repairs.
9-3
Maintenance of Secondary Side Integrity 10.5 Secondary Side Inspections For recirculating steam generators, FOSAR shall be performed at a minimum each time sludge lancing is performed. Because of the design of once through steam generators, foreign object intrusion is not expected; therefore, FOSAR shall be performed when loose parts are identified or there is reason to expect that they were introduced into the steam generator secondary side.
Secondary side visual examinations should be performed to assist in the verification of tube integrity. The personnel performing secondary side visual inspections and FOSAR activities shall be trained in the use of the equipment and procedures utilized. This training shall include FME control.
Secondary side visual inspections shall include licensee commitments in accordance with NRC GL 97-06, such as visual inspections to detect potential degradation to the wrapper and tube support plates to ensure tube structural integrity is maintained.
An assessment of secondary side tube integrity shall include consideration of operating experience (OE) from all SG models, while paying particular attention to OE from similar SG designs.
An evaluation shall be performed to document the maximum interval between secondary side inspections. This evaluation shall be based on the plant's historical foreign objects, wear indications, maintenance activities, and the planned primary side inspection intervals. The evaluation shall contain the following elements:
" Location and description of historical foreign objects
" Description of those foreign objects with associated wear indications
- High flow, or susceptible areas
" Secondary side inspection limitations
- Trends for foreign object associated wear When scheduling sludge lancing and FOSAR, the following should be considered:
- Sludge lancing tends to sweep foreign material that is in-bundle toward the annulus, which may allow for easier retrieval.
" Foreign object visibility is often increased when the sludge pile is minimized or removed prior to FOSAR.
" If it is desired to visually confirm a suspected foreign object's position as it relates to a reported wear indication, it may be easier to do so prior to sludge lancing, as sludge lancing has the potential to move the foreign object away from the wear scar.
Several plants have experienced problems with foreign objects after steam generator replacement. During assembly and shipment, SGs are typically kept on their side. When the SGs are set in place during installation, foreign material and debris could fall to the tubesheet and become accessible. Therefore, FOSAR should be performed during the SG replacement 10-5
Maintenance of Secondary Side Integrity outage, after the SGs are installed. In addition, many replacement steam generators have incorporated foreign object strainers, typically as part of the feed ring design, to minimize foreign objects from entering the SG tube bundle region during operation [44]. These strainers should be routinely inspected and considered when performing as assessment of secondary side tube integrity.
Depending on the SG design and foreign object properties (mass, size, etc.), foreign objects entering the secondary side of the SG may locate on the tubesheet within the shell-to-tube bundle annulus region or the blowdown lane (tube lane). SG tubes are typically susceptible to foreign object damage in regions of high secondary feedwater velocity. Therefore the tubes near the shell-to-tube bundle annulus region (the periphery tubes) are typically most susceptible to flow induced foreign object tube wear/damage. When performing FOSAR, the minimum regions to be examined shall include the shell-to-tube bundle annulus region (including periphery tubes) and the tube lane. The scope of the inspection shall be defined in the DA.
Visual inspection of the periphery tubes may be achieved by articulating the camera angle to view into the bundle from the annulus region, without inserting the video equipment into the bundle. Visual inspections conducted in this manner provide reasonable assurance that foreign objects with potential to damage tubes located on the secondary face of the tubesheet will be identified, to the extent practical. The above inspection recommendation may not apply to SGs with unique design features such as the main feedwater entering the tube bundle over a baffle plate in the preheater.
In such cases, the SG design should be taken into consideration in defining the inspection scope.
All foreign material that has the potential to challenge tube integrity shall be removed from the SGs if reasonably achievable within the limitations of the equipment. Items that are irretrievable and/or could cause damage to tubes by removing them shall be evaluated. Important details to include in the evaluation:
- 1. An estimation of the material and size of the object (diameter, length, and weight)
- 2. Location of the object (Tube row/column, Top of Tubesheet (HL/CL), TSP, etc)
- 3. The estimated axial location of the contact
- 4. Whether or not the object is firmly lodged or able to move
- 5. Whether or not tube wear is a result of the object
- 6. Evaluation of potential wear rate if the object moves and contacts tubes for the planned inspection interval. This evaluation should include conservative assumptions regarding the object's size, the material of the object, tube vibration amplitudes and cross flow fluid velocities.
- 7. Whether historical NDE (e.g. eddy current data, etc) shows the presence of the object or tube degradation.
When irretrievable foreign material has been identified, it should be inspected in future primary side and secondary side inspections. Irretrievable foreign material that has been determined to have caused tube wear based on NDE, or tube wear is potential based on engineering analysis, shall be inspected in future scheduled SG inspections. Engineering analysis shall determine the inspection interval. Foreign material removed from the steam generators shall also be documented. The type of material entering the SGs and potential for tube damage shall be included in the analysis when determining the interval between primary or secondary side 10-6
Maintenance of Secondary Side Integrity inspections. The EPRI Steam Generator Degradation Database (SGDD) provides a means for documenting and trending foreign material and associated tube damage. It is recommended that (in addition to the SGDD) the licensee maintains and controls documentation related to foreign material tracking.
When potential loose parts (PLPs) are identified during the ECT inspection, they shall be further dispositioned. Options for dispositioning include performing a visual inspection in the area where the PLP was identified by ECT, reviewing historical and current ECT data for PLP signals and wear, bounding the area with a qualified technique, reviewing past visual recordings in the area, and performing an engineering analysis to justify no tube integrity impact without need for search and/or retrieval.
If secondary side inspection confirms the presence of foreign objects, the description and location of the parts shall be documented for consideration during eddy current examination. If primary side eddy current inspections are scheduled, the tubes in the area of the foreign objects should be examined with probes/techniques capable of detecting tube wear. Visual inspections may be considered as an alternative to eddy current inspection, but only if the visual quality and coverage is sufficient to convincingly demonstrate that tube damage is not present in the areas that could have been affected by the part(s). If a part is small enough to enter the tube bundle, visual inspection coverage should include the entire circumference of the tubes in areas potentially affected by the part. Tube integrity shall be evaluated with qualified technique(s) if tube damage is detected (i.e., not superficial surface marks) or considered potential based on visual inspection.
When a foreign object is reported, it is possible that either primary or secondary side inspections are not available. For example, the secondary side integrity assessment could recommend performing FOSAR when primary side inspections and secondary side cleaning are not planned.
A similar case is where primary side inspections are performed with no secondary side inspections planned. In either case, planning should include consideration in the event foreign material is identified. When both primary and secondary inspections are performed, these activities should be coordinated to ensure that potential foreign objects identified by eddy current are able to be investigated by the secondary side crew. Similarly, foreign objects identified by the secondary side crew should be communicated to the eddy current leads to evaluate eddy current data for wear, if necessary. Figure 10-2 illustrates recommended logic that should be considered in the event that foreign material is reported by NDE such as ECT and/or SSI.
10-7
SCE ATTACHMENT 36
NUREG-0800 (Formerly NUREG 7510871
- pa 11cou 4,
U.S. NUCLEAR REGULATORY COMMISSION STANDARD REVIEW PLAN OFFICE OF NUCLEAR REACTOR REGULATION 15.6.3 RADIOLOGICAL CONSEQUENCES OF STEAM GENERATOR TUBE FAILURE MPWR)
REVIEW RESPONSIBILITIES Primary - Accident Evaluation Branch (AEB)
Secondary - Reactor Systems Branch (RSB)
I.
AREAS OF REVIEW This SRP section covers the review of the radiological consequences of a postulated steam generator tube failurf accident at a pressurized water reactor (PWR) facility and includes the following:
(1)
A review of the sequence of events and plant procedures for recovery from the accident, as described by the applicant, with and without offsite power available, to assure that the most severe case of radioactive releases has been considered.
(2)
A review of the models and assumptions used by the applicant for the calculation of the thyroid and whole-body doses for the postulated accident.
(3)
An independent calculation by the staff of the thyroid and whole-body doses for the accident (4)
A comparison of the doses calculated by the applicant and by the staff with the appropriate exposure guidelines, as stated in subsection II below, and (5)
An evaluation of the technical specifications on the primary and secondary coolant iodine activity concentration.
The review includes two cases for the reactor coolant iodine concentration corresponding to (1) a preaccident iodine spike and (2) a concurrent iodine spike.
The potential for fuel failures resulting from the postulated accident is routinely evaluated by the RSB and such information is provided to the AEB as an additional source of iodine activity in the reactor coolant for consideration in the evaluation of the radiological consequences.
Rev. 2 -
July 1981 USNRC STANDARD REVIEW PLAN Standard review plans are prepared for the guidance of the Office of Nuclear Reactor Regulation staff responsible for the review of applications to construct and operate nuclear power plants. These documents are made available to the public as part of the Commission's policy to Inform the nuclear Industry and the general public of regulatory procedures and policies. Standard review plans are not substitutes for regulatory guides or the Commission's regulations and compliance with them is not required. The standard review plan sections are keyed to the Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants.
Not all sections of the Standard Format have a corresponding review plan.
Published standard review plans will be revised periodically, as appropriate. to accommodate comments and to reflect new informa-tion and experience.
Comments and suggestions for Improvement will be considered and should be sent to the U.S. Nuclear Regulatory Commission.
Office of Nuclear Reactor Regulation, Washington. D.C. 2(M.
II.
ACCEPTANCE CRITERIA The acceptance criteria are based on the relevant requirements of 10 CFR Part 100 as it relates to mitigating the radiological consequences of an accident. The plant site and the dose mitigating engineered safety features are acceptable with respect to the radiological consequences of a postulated steam generator tube failure accident at a PWR facility if the calculated whole-body and thyroid doses at the exclusion area and the low population zone outer boundaries do not exceed the following exposure guidelines:
(1) for the postulated accident with an assumed preaccident iodine spike in the reactor coolant and for the postulated accident with the highest worth control rod stuck out of the core the calculated doses should not exceed the guideline values of 10 CFR Part 100, Section 11 (Ref. 1), and (2) for the postulated accident with the equilibrium iodine concentration for continued full power operation in combination with an assumed accident initiated iodine spike, the calculated doses should not exceed a small fraction of the above guideline values, i.e., 10 percent or 2.5 rem and 30 rem, respectively, for the whole-body and thyroid doses.
The methodology and assumptions for calculating the radiological consequences should reflect the regulatory positions of Regulatory Guide 1.4 (Ref. 2) except for the atmospheric dispersion factors which are reviewed under SRP Section 2.3.4.
Plant technical specifications are required for iodine activity in the'primary and secondary coolant systems. These specifications are accept-able if the calculated potential radiological consequences from the steam generator tube failure accident are within the exposure guidelines for the above two cases.
III. REVIEW PROCEDURES The reviewer selects and emphasizes specific aspects of this SRP section as appropriate for a particular plant.
The judgment which areas need to be given attention and emphasis during the review is based on a determination if the material presented is similar to that recently reviewed on other plants and whether items of special safety significance are involved.
At the construction permit (CP) stage, the review i's limited to a brief survey of the pertinent portions of the SAR regarding.the plant design and the appli-cant's accident evaluation to determine that there are no unusual features which would prevent limitation of radiological consequences to acceptable levels by appropriate limits on coolant activity concentrations.
The detailed review of the radiological consequences of a steam generator tube failure is done at the operating license (OL) stage when system parameters and accident analyses are fully developed.
Standard technical specifications for each of the three PWR vendors' NSSS include limits on the primary and secondary coolant activities which are used in the staff's independent dose calculations (Ref. 3, 4, and 5).
If the appli-cant proposes to use these standard limits and the plant is one of the standard NSSS/BOP plants for which the tube failure accident has been evaluated generi-cally with the standard coolant activity and leakage limits, the reviewer need not reevaluate the offsite doses from this accident provided that the atmospheric dispersion factors (X/Q'values) for the site under-review do not 15.6.3-2 Rev. 2 - July 1981
exceed the limiting X/Q values used in the generic review of the standard plant tube failure accident.
The review of the steam generator tube failure accident at the OL stage includes the following:
- 1.
Review of the applicant's description of the tube failure accident, with and without offsite power.
This includes a review of the sequence of events, the bases for the occurrence, and assurance of an adequate degree of conservatism.
- 2. Review of the signals available to the reactor operator that indicate the occurrence of the accident and the state of-the system throughout the recovery period.
Automatic and required manual operations by the operator as a function of time are reviewed.
The AEB reviewer verifies with the RSB the acceptability of the applicant's description of events, including operator actions, to assure that the most severe case has been considered with respect to the release of fission products and calculated doses.
- 3. The post-accident thermohydraulic characteristics and radiological consequences of-this accident are plant-specific. The reviewer, deter-mines post-accident thermohydraulic profiles and compares these with those presented by the applicant. The purpose of such comparison is not to attain an exact match but to confirm the validity of the applicant's calculated results.
- 4. The appropriate atmospheric dispersion factors (X/Q values) for the staff's independent dose analysis will be determined by the assigned meteorologist in accordance with SRP Section 2.3.4.
- 5. Determination of the initial primary and secondary coolant activity concentrations.
The reviewer assumes the primary and secondary coolant activity concentrations allowed by the technical specifications (SAR Chapter 16 or the standard technical specifications given in References 3, 4, and 5) as equilibrium conditions prior to the accident.
- 6. Determination of iodine spiking effects.
For the dose calculations the following two cases of'iodine spiking are analyzed:
(a) A reactor transient has occurred prior to the postulated steam generator tube failure accident and has raised the'primary coolant iodine concentration to the maximum value permitted by the standard technical specifications (i.e., a preaccident iodine spike case).
The primary coolant iodine concentration for this case is obtained from Figure 3.4-1 of the NSSS vendor standard technical specification (Ref. 3, 4, or 5) or from the plant-specific technical specifications proposed in Chapter 16 of the applicant's SAR.
(b) The reactor trip or the primary system depressurization associated with the postulated accident creates an iodine spike in the primary system (Ref. 6 and 7).
The increasing primary coolant iodine concen-tration is estimated using a spiking model which assumes that the iodine release rate from the fuel rods to the primary coolant (expressed in curies per unit time) increases to a value 500 times greater than the release rate corresponding to the iodine concentra--
tion at the equilibrium value stated in the NSSS vendor standard 15.6.3-3 Rev. 2 - July 1981
technical specifications or from the plant-specific technical specifications (i.e., concurrent iodine spike case).
- 7.
Evaluation of the effects of fuel failure.
As a result of the steam generator tube rupture accident, fuel failures can occur, releasing fission products into the reactor coolant and thus making additional activity available for release to the atmosphere. The RSB reviews the effects of the accident on the core thermal margins and the associated amount of fuel failures, assuming that the highest worth control rod is stuck at its fully withdrawn position.
The RSB, as a secondary review branch, informs the AEB of the fuel failure estimate. If the accident is predicted to cause such fuel failure, the dose analysis will be performed with the corresponding iodine activity but without a concurrent iodine spike.
- 8. Determination of the primary to secondary system leakage in the unaffected steam generators.
The operating primary-to-secondary leakage is assumed to exist in the unaffected steam generators.
at the maximum rate allowed by the standard technical specifications (Ref. 3, 4, and 5).
This value is 1 gpm.
However, a lower value may be needed to limit the consequences of other events such as a control rod ejection accident.
j
- 9.
Determination of the coolant flow through the failed tube.
In conjunction with review step (3) above the flow rates through the two ends of the failed tube are calculated using a suitable flow model, taking credit for critical flow where appropriate.
- 10.
Determination of the iodine transport to the atmosphere.
The iodine transport model to be used is described in Reference 8. A fraction of the iodine in the primary coolant escaping to the secondary system is assumed to become airborne immediately due to flashing and atomization.
Credit may be given for. "scrubbing" of iodine contained in the steam phase and in the atomized primary coolant droplets suspended in the steam phase for release points which are below the steam generator water level.
That fraction of the primary coolant iodine which is not assumed to become airborne immediately enters the secondary system water and is assumed to become airborne at a rate determined by the steaming rate and iodine partition coefficient.
An iodine partition coefficient of 100 between steam generator water and steam phases may be conservatively assumed unless the applicant presents reasonable evidence that the use of some other value is justified.
- 11.
Calculation of the exclusion area and low population zone boundary doses.
The reviewer performs an independent calculation of the doses for the steam generator tube failure accident, using the two iodine concentrations in item (6) above. A breathing rate of 3.47 x 10-4 m3/sec is used in the calculation of thyroid doses for the first 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following the steam generator tube failure and the dose conversion factors are in accordance
-with Regulatory Guide 1.4 (Ref. 3).
- 12.
Review of dose calculations. The whole-body and thyroid doses calculated by.the staff and by the applicant are compared with the acceptance criteria stated in subsection II. If the doses calculated by the staff are not within the exposure guidelines (i.e., they are not less than 10 percent of 10 CFR Part 100, Section 11), then the staff will pursue 15.6:3-4 Rev. 2 - July 1981
alternatives with the applicant to reduce the doses to within the guideline values.
IV. EVALUATION FINDINGS The reviewer verifies that sufficient information has been provided by the applicant and that the applicant's analysis and the staff's independent calculations support conclusions of the following type, to be included in the AEB safety evaluation report at the operating license stage:
The steam generator tube failure accident has been evaluated with and without a concurrent loss of offsite power.
The assumptions used in our analysis are listed in Table The calculated doses are presented in Table The staff concludes that the distances to the exclusion area and to the loe population zone outer boundaries for the (insert PLANT NAME) site, in conjunction with the operation of the dose mitigating ESF systems, are sufficient to provide reasonable assurance that the calculated radiological consequences of a postulated steam generator tube failure accident do not exceed: (a) the exposure guidelines as set forth in 10 CFR Part 100, Section 11 for the accident with an assumed preaccident iodine spike or with the highest worth control rod stuck out of the core and (b) 10 percent of these exposure guidelines, for the accident with an equilibrium iodine concentration in combination with an assumed accident generated iodine spike.
The staff conclusion is based on (1) the staff review of the applicant's analysis of the radiological consequences, (2) the independent dose calcu-lation by the staff using conservative assumptions including atmospheric dispersion factors as discussed in Chapter 2 of this report, (3) the appli-cant's analysis and the staff's independent dose calculations which were performed using the guidelines of Regulatory Guide 1.4, and (4) the (insert NSSS VENDOR) Standard Technical Specifications for the iodine concentration in the primary and secondary coolant system, and for the primary to secondary leakage in the steam generators. The staff will review the (PLANT NAME) specific technical specifications to assure that the dose guidelines stated above are not exceeded.
The following paragraph is inserted prior to the last paragraph if fuel damage is found to be a possible consequence of the accident:
The steam generator tube failure accident has also been evaluated with
% fuel damage in the core as a result of the most reactive control rod remaining fully withdrawn.
The resulting doses, listed in Table 15.
are within the guidelines of 10 CFR Part 100.
At the construction permit stage, the following paragraph is included in the staff's safety evaluation report:
On the basis of our experience with the evaluation of steam generator tube failure accidents for pressurized water reactor plants of similar design, we have concluded that the consequences of these accidents can be controlled by limiting the permissible primary and secondary coolant system radioactivity concentrations so that potential offsite doses are small. At the operating license stage the staff will include appropriate 15.6.3-5 Rev. 2 - July 1981
limits on primary and secondary coolant activity concentrations in the technical specifications.
V. IMPLEMENTATION The following provides guidance to applicants and licensees regarding the staff's plans for using this.SRP section.
Except in those cases in which the applicant proposes an acceptable alternative method for complying with specified portions of the Commission's regulations, the method described herein will be used by the staff in its evaluation of conformance with Commission regulations.
Implementation schedules for conformance to parts of the method discussed herein are contained in the referenced regulatory guides.
VI.
REFERENCES
- 1.
10 CFR Part 100, Section 11, "Determination of Exclusion Area, Low Population Zone, and Population Center Distance."
- 2.
Regulatory Guide 1.4, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors."
- 3.
Standard Technical Specifications for Combustion Engineering PWRs, NUREG-0212.
- 4.
Standard Technical Specifications for Westinghouse PWRs, NUREG-0452.
- 5.
Standard Technical Specifications for Babcock and Wilcox PWRs, NUREG-0103.
CONF-770708, 3 717 (1977).
- 7. A. K. Postma and P. S. Tam, "Iodine Behavior in a PWR Cooling System Following a Postulated Steam Generator Tube Rupture Accident," NUREG-0409, USNRC, January 1978.
- 8.
R. R. Bellamy, "A Regulatory Viewpoint of Iodine Spiking During Reactor Transients," Trans. Am. Nucl. Soc., 28 (1978).
15.6.3-6 Rev. 2 - July 1981
SCE ATTACHMENT 37
EI=>>I2II Steam Generator Integrity Assessment Guidelines Revision 2 Effective December 6, 2006, this report has been made publicly available in accordance with Section 734.3(b)(3) and published in accordance with Section 734.7 of the U.S. Export Administration Regulations. As a result of this publication, this report is subject to only copyright protection and does not require any license agreement from EPRI. This notice supersedes the export control restrictions and any proprietary licensed material notices embedded in the document prior to publication.
Technical Report
8 OPERATIONAL ASSESSMENT 8.1 Introduction Operational Assessment (OA) involves projecting the condition of the SG tubes to the time of the next scheduled inspection outage and determining their acceptability relative to the tube integrity performance criteria of NEI 97-06 [2]. All detected degradation mechanisms shall be evaluated, including secondary side inspection results. Forms of degradation that have been found at prior inspections but have not been observed at the current inspection should be considered. Intervals between inspections of the SGs depend on the results of this analysis. NEI 97 -06 [2] requires that an OA be performed after each SG inspection. The purpose of this and the following chapters is to provide guidance for performing an OA and evaluating the results. The focus of this chapter is structural integrity. Leakage integrity is covered in Chapter 9.
The fundamental objective of an OA is to ensure that structural and leakage performance criteria will be met over the length of the upcoming inspection interval. It shall be demonstrated that the degradation detection sensitivity and/ or NDE sizing uncertainty combined with degradation growth rates leads to the expectation that structural and leakage integrity criteria will be met at the end of the next inspection interval. In terms of structural integrity, the fundamental OA requirement is that the projected worst case degraded tube for each existing degradation mechanism shall meet the limiting structural performance parameter with 0.95 probability at 50% confidence.
During actual operation of a given SG in a given cycle, for the degradation mechanism of interest, one tube has the lowest structural performance parameter associated with it. However, this is one of many possible outcomes for the given starting condition. A fully probabilistic analysis leads to a distribution of possible outcomes of SG operation for all degradation sites both detected and undetected for a given degradation mechanism. The "projected worst case degraded tube" is defined as the degraded tube with the 5 th percentile structural performance parameter at 50% confidence of the distribution of lower extreme values of structural performance parameters. This parameter is, almost exclusively, the burst pressure or axial tensile strength since plastic collapse in bending is not relevant. The term mechanism is used to differentiate between types of degradation based on their characterizing evaluation factors such as probability of detection, integrity projection formulae, NDE sizing uncertainty, growth rate distribution, and limiting structural integrity performance criterion geometric feature or features.
Using the definition of the projected worst case degraded tube to perform the OA is mathematically equivalent to demonstrating that the probability of violating the structural performance criteria is no greater than 0.05 at 50% confidence. Conversely, the probability of meeting the performance criteria is at least 0.95 at 50% confidence. As shown in the following 8-1
Operational Assessment section, fully probabilistic OA analyses are rarely required since simplified bounding techniques are almost always applicable.
8.2 Projection of Worst Case Degraded Tube There are two general approaches to the projection of the worst case degraded tube, direct calculation and use of simplified bounding techniques. Direct calculation involves consideration of the entire flaw population for a given degradation mechanism and associated procedures to project the distribution of EOC extreme value structural integrity parameters so that the 5 th percentile value may be obtained. Direct calculation methods are referred to herein as fully probabilistic. However, most OAs can be performed using less complicated bounding approaches to project the worst case degraded tube at the end of the inspection interval of interest. Simplified methods of projecting the worst case degraded tube are designed to bound fully probabilistic calculations that consider the entire projected flaw population and the variety of possible outcomes for a given cycle of operation. In the simplified bounding techniques, the worst case flaw is projected using conservative assumptions coupled with uncertainties that are combined using either the Arithmetic, Simplified Statistical or Monte Carlo calculation strategies. Depending on available information and margins, the OA strategy may range from a simple bounding approach to a fully probabilistic analysis.
It is important to note that there are two basic repair strategies or options for detected degradation, Repair on Detection and Repair on NDE Sizing. Repair on Detection means that no detected degradation is intentionally left in service, hence, the basic issue for performing the OA is to account for the undetected flaw population. Although an inspection expansion may not be required by the EPRI Examination Guidelines (i.e., degradation not considered "active"), if a less than 100% inspection is being performed and degradation is detected, the OA shall consider the uninspected population. If degradation is identified in a less than 100% inspection, one can not assume that the worst case flaw has been identified.
For a Repair on NDE Sizing scenario, detected degradation is intentionally left in service if the size determined by NDE is below a certain level. Practically, this level is the technical specification repair limit, typically 40%TW NDE maximum depth, although some plants have slightly higher NRC-approved technical specification repair limits. The most important consideration in this scenario is accounting for the NDE sizing uncertainties of the flaws left in service.
The 40% TW NDE maximum depth repair limit is usually only applied to tube wear at supports and cold leg thinning degradation at tube supports. Other types of degradation may remain in service according to NRC approved Alternate Repair Criteria (ARC). Some examples of ARCs are:
Bobbin Voltage ARC for Axial ODSCC/IGA at Drilled Tube Support Plate Intersections Depth Based +Point Sizing of Axial PWSCC at Drilled Tube Support Plate Intersection Bobbin Based Depth Sizing of First Span Volumetric IGA in an OTSG Plant Various Tubesheet Crevice Degradation ARCs where SLB Leakage is the Limiting Issue since Burst is Prevented by the Presence of the Tubesheet.
8-2