IR 05000382/2024013

Notice of Violation; NRC Inspection Report 05000382/2024013

ML24228A261
Person / Time
Site:	Waterford
Issue date:	08/20/2024
From:	Nick Taylor NRC/RGN-IV/DORS/EB2
To:	Sullivan J Entergy Operations
References
EA-24-052 IR 2024013
Preceding documents:	ML24268A113 (24 September 2024)
Download: ML24228A261 (27)

Text

August 20, 2024

SUBJECT:

WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NOTICE OF VIOLATION; NRC INSPECTION REPORT 05000382/2024013

Dear Joseph Sullivan:

On August 9, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Waterford Steam Electric Station, Unit 3, and discussed the results of this inspection with you and other members of your staff. The results of this inspectio n are documented in the report in Enclosure 2.

The enclosed report discusses a violation associated with a finding of very low safety significance (Green). The NRC evaluated this violation in accordance with Sections 2.3.2 and 2.3.3 of the NRC Enforcement Policy, which can be found at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. The violation met the criteria for treatment as a non-cited violation; however, because the violation is associated with an ongoing degradation mechanism in the steam generator tub es for which the cause has not been discretely determined and actions have not been identified to prevent recurrence, and given that subsequent follow-up inspection to ensure compliance with your operating license wil l be needed, the NRC determined the issuance of a Notice of Violation (Enclosure 1) is appropriate in this case.

You are required to respond to this letter and should follow the instructions specified in the Notice of Violation when preparing your response. In addition to the Notice of Violation response, please include the following in your respon se: (1 ) Entergys determination as to the cause(s) of the ongoing tube wear mechanism in the replacement steam gene rators, (2 ) a summary of any corrective actions taken or planned to address these causes, (3) Entergys basis for determining the length of the interval before the next steam generator tube inspection is scheduled, and (4) actions taken or planned to ensure the technical basi s for curre nt o r future operational assessments i s technically soun d. If you have additional information that you believe the NRC should consider, you may provide it in your response. The NRCs review of your response will also determine whether further enforcement action is necessary to ensure your compliance with regulatory requirements. If you contest the violation or the significance or severity of the violation documented in this inspection report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement; and the NRC Resident Inspector at Waterford Steam Electric Station, Unit 3.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; and the NRC Resident Inspector at Waterford Steam Electric Station, Unit 3.

In accordance with 10 CFR 2.390 of the NRCs Agency Rules of Practice and Procedure, a copy of this letter, its enclosures, and your response will be made available electronically for public inspection in the NRC Public Document Room and from the NRCs ADAMS, accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary information so that it can be made available to the public without redaction.

Sincerely, Nicholas H. Taylor, Chief Engineering Branch 2 Division of Operating Reactor Safety Docket No. 05000382 License No. NPF-38

Enclosures:

1. Notice of Violation 2. Inspection Report 05000382/2024013 3. Detailed Risk Evaluation

Inspection Report

Docket No. 05000382

License No. NPF-38

Report No. 05000382/2024013

Licensee: Entergy Operations, Inc.

Facility: Waterford Steam Electric Station, Unit 3

Location: Killona, LA 70057

Inspection Dates: February 01, 2024, to August 9, 2024

Inspectors: R. Deese, Senior Reactor Analyst J. Drake, Senior Reactor Inspector R. Kopriva, Senior Project Engineer J. Mejia, Reactor Inspector C. Young, Senior Reactor Analyst

Approved By: Nicholas H. Taylor, Chief Engineering Branch 2 Division of Operating Reactor Safety

Enclosure 2 SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an Event Follow-up at Waterford Steam Electric Station, Unit 3, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

List of Findings and Violations

Failure to Perform an Adequate Steam Generator (SG) Operational Assessment Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.1] - 71153 NOV 05000382/2024013-01 Resources Open EA-24-052 The inspectors identified a Green finding and associated Notice of Violation of Technical Specification 6.5.9.b.1 when the licensee failed to ensure that all in-service SG tubes shall retain structural integrity over the full range of normal operating conditions, all anticipated transients included in the design specification, and design basis accidents by retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential.

Specifically, the licensees operational assessment in February 2022 allowed too long of an interval between primary side inspections to maintain structural integrity of steam generator tubes. As a result, two tubes in SG 31 failed during required in-situ testing in November 2023.

Additional Tracking Items

Type Issue Number Title Report Section Status URI 05000382/2023004-01 Steam Generator # 1 In-Situ 71153 Closed Tube Pressure Testing Failures.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

OTHER ACTIVITIES - BASELINE

71153 - Follow Up of Events and Notices of Enforcement Discretion

Event Report (IP Section 03.02) (1 Sample)

The inspectors evaluated the following licensees event reporting determinations to ensure it complied with reporting requirements.

(1) LER 50-382/2023-003-00, Steam Generator Tube Degradation Indicated by Failed In-Situ Pressure Testing (ADAMS Accession No. ML23364A001)

The inspection conclusions associated with this LER are documented in this report under Inspection Results section. This LER is closed.

INSPECTION RESULTS

Failure to Perform an Adequate Steam Generator (SG) Operational Assessment Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.1] - 71153 NOV 05000382/2024013-01 Resources Open EA-24-052 The inspectors identified a Green finding and associated Notice of Violation of Technical Specification 6.5.9.b.1 when the licensee failed to ensure that all in-service SG tubes shall retain structural integrity over the full range of normal operating conditions, all anticipated transients included in the design specification, and design basis accidents by retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential.

Specifically, the licensees operational assessment in February 2022 allowed too long of an interval between primary side inspections to maintain structural integrity of steam generator tubes. As a result, two tubes in SG 31 failed during required in-situ testing in November 2023.

Description: As documented in NRC Integrated Inspection Report 05000382/2023004 (ML24039A199), the inspectors identified an unresolved item (URI 05000382/2023004-01)

related to the licensees failure to meet the steam generator tube integrity performance criterion in technical specification (TS) 6.5.9.b.1, Steam Generator Program. During the fall

2023 refueling outage, while performing 100% in-service inspection (ISI) of the steam generator tubes, eddy current testing (ECT) on SG 31 identified four (4) tubes with wear flaws exceeding the condition monitoring structural limit at the tube support plates (TSP). The four deficient SG31 tubes were R1 C4, R1 C112, R1 C138, and R2 C35 (where R is row and C is column); Electric Power Research Institute guidelines required in-situ pressure testing of these tubes based on the identified flaws.

On November 5, 2023, failed in-situ pressure testing on tubes R1 C4 and R2 C35 resulted in a degraded condition for not meeting the performance criteria for steam generator structural integrity in accordance with technical specification 6.5.9.b.1, Steam Generator Program.

This event was reported as an eight-hour, non-emergency notification in accordance with 10 CFR 50.72(b)(3)(ii)(A) as a degraded condition for not meeting the performance criteria for SG structural integrity in accordance with technical specification 6.5.9.b.1, Steam Generator Program. (LER 50-382/2023-003-00, Steam Generator Tube Degradation Indicated by Failed In situ Pressure Testing Waterford Steam Electric Station, Unit 3) (ML23364A001)

The SG in-situ pressure testing failure was caused by tube-to-TSP wear on the cold leg side near the no tube lane. Nine flaws, which were distributed among four separate tubes in SG 31, failed to satisfy condition monitoring by analysis. (CR-WF3-2023-17005, ACA)

Tube R1 C4 experienced pop-through (burst) at 5243 psi when transitioning to the final 3 times delta normal operating differential pressure (3xNODP) of 5500 psi. Tube R2 C35 reached the 3xNODP test pressure of 5500 psi, which was maintained for 41 seconds before briefly dropping below 5500 psi. Once reestablished and stabilized at 5500 psi it held for 90 seconds prior to experiencing pop-through (burst) at 5504 psi criteria.

In LER 50-382/2023-003-00, Steam Generator Tube Degradation Indicated by Failed in-situ Pressure Testing Waterford Steam Electric Station, Unit 3, the licensee stated that the operational assessment (OA) developed by the vendor potentially included some nonconservative assumptions which led to erroneous wear predictions, resulting in Entergy implementing an inadequate inspection frequency.

In RF21 (2017) ECT was performed on 100% of the SG tubes. During the RF21 inspection, anti-vibration bar wear and TSP wear were identified and a total of 3 tubes in SG 31 and 24 tubes in SG 32 were plugged. The OA that was completed after the outage determined that it was acceptable to perform the next testing and inspection after three cycles in RF24 (2022).

Entergy submitted an application to revise their technical specifications to adopt TSTF-577 (Technical Specification Task Force), Revised Frequencies for Steam Generator Tube Inspections in CNRO2021-0017 (ML21182A158) dated July 1, 2021. The NRC approved the application in a letter dated December 8, 2021 (ML21313A008). TSTF-577 allows licensees with Alloy 690 steam generator tubing to extend the maximum interval between inspections from 72 up to 96 effective full power months with the caveat that the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection.

In October 2021, the licensee contracted the steam generator inspection vendor to revise the RF21 (2017) OA for an additional skip at RF24 (2022) and complete a feasibility study for another additional skip at RF25 (2023). A revised OA was received and accepted by the licensee on March 15, 2022, justifying the skip at RF24 (2022). This OA, in concert with the

adoption of TSTF-577, was used to move the SG primary inspections from RF24 (2022) to RF25 (2023).

In response to the subsequent in-situ testing failures in SG 31, the licensee completed an adverse condition analysis in CR-WF3-2023-17005. In this analysis, the licensee documented that the tube failures were caused in part by the use of non-conservative assumptions in the revised OA. These non-conservatisms adversely influenced the decision to extend the scheduled inspection intervals, and in concert with the steam generator design being vulnerable to accelerated wear conditions led to the failure of two tubes during in-situ testing.

Corrective actions: The licensee plugged the two tubes that failed the in-situ testing as well as the tubes in close proximity to the failed tubes. Additionally, all tubes with TSP wear equal to or greater than 32% through wall depth were plugged. Additionally, the licensee contracted a new vendor to perform an independent OA to provide confidence that the plant could restart and operate safely until the next scheduled inspection.

Corrective action references: CR-WF3-2023-17005

Performance Assessment:

Performance Deficiency: The inspectors determined that the licensees failure to perform an adequate operational assessment per the requirements of SEP-SG-WF3-001, Waterford-3 (W3/WF3) Steam Generator Program, Revision 4, and CEP-SG-003, Steam Generator Integrity Assessment, Revision 6 was a performance deficiency. Specifically, Waterford procedure SEP-SG-WF3-001 section 1.1 requires that the implementation of the steam generator integrity program is to be in accordance with Entergy fleet procedure CEP-SG-003, Steam Generator Integrity Assessment. CEP-SG-003 Section 8.0 requires that:

The operational assessment (OA) is a forward looking evaluation. Its purpose is to demonstrate reasonable assurance that the tube integrity performance criteria (structural and leakage) will be met throughout the period prior to the next schedule tube inspection.

Furthermore, Section 8.3.1 dictates that the operational assessment shall include justification for operating the planned interval between secondary side inspections as well as primary side inspections.

Contrary to this requirement, the licensees operational assessment performed in February 2022 did not include adequate justification for operating during the planned interval between primary side inspections.

Specifically, the operational assessment contained several non-conservatisms that led to the licensee inappropriately extending the required inspection of the steam generator tubes from RF24 (in spring 2022) to RF25 (in fall 2023). This extended inspection interval was too long to assure that all steam generator tubes continued to meet technical specification structural integrity requirements.

Screening: The inspectors determined the performance deficiency was more than minor because it could reasonably be viewed as a precursor to a significant event; if left uncorrected, would have the potential to lead to a more significant safety concern; and was associated with the Equipment Performance attribute of the Initiating Events cornerstone and

adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Significance: The inspectors used Table 2 of IMC 0609 Attachment 4, Initial Characterization of Findings to determine that the initiating events corner stone was impacted due to the potential for a steam generator tube rupture. Using Table 3, since the finding and associated degraded condition or programmatic weakness affected the initiating events cornerstone, the inspectors screened the issue using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. Given that the finding involved a degraded steam generator tube condition where one tube cannot sustain three times the differential pressure across a tube during normal full power, steady state operation, IMC 0609 Appendix A, step D.1 directs the staff to complete the screening using IMC 0609 Appendix J, Steam Generator Tube Integrity Findings Significance Determination Process. IMC 0609 Appendix J, Table 1, Steam Generator Tube Integrity SDP Matrix directs the staff to perform a detailed risk evaluation if two or more tubes cannot sustain 3 times the normal tube differential pressure (3xPNO). A detailed risk evaluation was completed which determined that the overall best estimate for the risk impacts attributable to this performance deficiency were determined to be a delta-CDF of 1.34E-7/yr and a delta-LERF of 8.34E-8/yr, both of which are associated with a finding of very low safety significance (Green). The detailed risk evaluation is documented in Enclosure 3.

Cross-Cutting Aspect: H.1 - Resources: Leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. The licensee failed to ensure the review of the operational assessment for the steam generators was reviewed by personnel with sufficient expertise to identify the nonconservative assumptions used by the vendor.

Enforcement:

Violation: Technical specification 6.5.9.b.1 requires, in part, that all in-service SG tubes shall retain structural integrity over the full range of normal operating conditions, all anticipated transients included in the design specification, and design basis accidents by retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential.

Contrary to the above, on November 5, 2023, the licensee failed to ensure that all inservice SG tubes retained structural integrity over the full range of normal operating conditions, all anticipated transients included in the design specification, and design basis accidents by retaining a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential. Specifically, in SG 31, tubes R1 C4 and R2 C35 failed to retain a safety factor of 3.0 against burst under normal steady state full power operation primary to secondary pressure differential. During in-situ testing, both tubes failed to meet the 5500-psi pressure test 2-minute hold period.

Enforcement Action: The violation met the criteria for treatment as a non-cited violation; however, because the violation is associated with an ongoing degradation mechanism in the steam generator tubes for which the cause has not been discretely determined and actions have not been identified to prevent recurrence, and given that subsequent follow-up inspection to ensure compliance with your operating license will be needed, the NRC determined the issuance of a Notice of Violation (Enclosure 1) is appropriate in this case (Enforcement Manual Section 2.3.2).

The disposition of this violation closes URI: 05000382/2023004-01.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

• On August 9, 2024, the inspectors presented the Event Follow-up results to Joseph Sullivan, Site Vice President and other members of the licensee staff.

Detailed Risk Evaluation

IMPACT ON SAFETY FUNCTIONS

The analyst considered that a condition affecting steam generator tube integrity would impact the likelihood of occurrence of the steam generator tube rupture (SGTR) event. Additionally, the analyst considered that this condition could impact probabilities associated with consequential SGTR (C-SGTR) events in which the post-accident plant pressure and/or temperature conditions resulting from accident sequences originating from other postulated events are such that the failure (rupture) of one or more steam generator tubes is induced. These cases, where one or more failed steam generator tubes constitutes a failure of the reactor coolant system pressure boundary as well as a potential pathway for bypass of containment, can represent a potential increased likelihood of a release of fission products to the environment.

EXPOSURE TIME

Following the performance of steam generator tube ISI activities in 2017, the next ISI activities should have been performed after 3 cycles of operation in April 2022, in accordance with the standards applicable for the program. The result of the performance deficiency was the extension of this ISI interval for one additional operating cycle, until November 2023. The analyst assumed that the inappropriate extension of this ISI interval allowed for a level of tube degradation to develop, at some point during this extension period, in excess of an allowable level of degradation for which the tube integrity performance criteria would be met. Since it is not known exactly when the additional level of degradation attributable to the performance deficiency reached the point of exceeding an allowable level, the analyst applied a T/2 factor to the total 19-month period associated with the performance deficiency to arrive at an exposure time of 9.5 months for purposes of this risk analysis.

OVERVIEW OF ANALYSIS APPROACH

As described in further detail below, the analyst evaluated the risk impacts of this plant condition relative to the significance metrics of core damage frequency (CDF) and large early release frequency (LERF). IMC 0609, Appendix J, Table 1, indicates that a delta-LERF in the range of 10-7 to 10-6, which would be indicative of a preliminary significance of White, should be associated with the condition of one tube that cannot sustain the tube integrity performance criterion of three times normal operating pressure (3xDPno). With the condition of two tubes not being able to sustain the 3xDPno criterion, Table 1 indicates that a detailed risk evaluation (DRE) should be performed. IMC 0609 Appendix J also indicates that any finding determined to be White using Table 1, or any finding for which a DRE is indicated, must be reviewed by a Senior Reactor Analyst.

The analyst reviewed guidance contained in IMC 0308, Attachment 3, Appendix J, Technical Basis for Steam Generator Tube Integrity Findings, and noted that Section 07 included the following guidance:

degradation below the 3 delta-P criteria is accepted as part of the plants baseline risk. the SDP risk assessment should subtract the risk at the 3PNO degree of degradation from the risk at the level of degradation found.

Enclosure 3 Accordingly, this evaluation assesses the risk impact attributable to the incremental additional level of tube integrity degradation that was in excess of a level of degradation for which the 3xDPno tube integrity performance criterion would have just been met (i.e., the baseline risk condition). This incremental level of degradation is the condition that is attributable to the performance deficiency.

The Waterford SPAR Model version Waterford TLU2 along with SAPHIRE software version 8.2.9 were used for the evaluation. This SPAR model was modified from the 8.81 version by correcting an error in which a long-term EFW makeup action was set to TRUE, adding a steam line break event tree, and including induced tube rupture sequences for secondary-side break events. The analyst included credit for the use of Diverse and Flexible Coping (FLEX) Strategies by adjusting the basic event FLX-XHE-XE-ELAP (Operators Fail to Declare ELAP When Beneficial) probability to 1.0E-2.

As a Level 1 PRA modeling resource, the SPAR model provides quantitative results associated with the impact of a condition on the core damage frequency (CDF) for the plant being modeled.

In the absence of other available Level 2 PRA modeling resources, IMC 0609 Appendix H contains guidance for estimating the impacts on LERF attributable to certain core damage sequences. As detailed below, this analysis was based on identifying a collective set of best available information on which to base an assessment of the risk posed by this condition relative to the CDF and LERF metrics of the SDP. Information derived from the analysts review and assessment of the use of the licensees Level 2 PRA modeling resources for LERF information was evaluated for inclusion among the best available information to be considered.

RISK FROM SPONTANEOUS STEAM GENERATOR TUBE RUPTURE (SGTR) EVENT

With the level of tube integrity degradation to be considered resulting in a reduction in pressure-retaining capability from 5,500 psi to 5,243 psi1, the analyst assessed that an increase in the likelihood of a nominal spontaneous SGTR event under normal operating conditions (i.e.,

approximately 1,400 psi) would be relatively minimal. The analyst assumed an estimated increase in initiating event frequency for the nominal spontaneous SGTR event of 20 percent would be applicable for this condition. This assumption was based on several considerations, including: 1) the analyst qualitatively compared the differences in levels of tube integrity degradation between this case and the most recent previous similar case involving tube integrity degradation at the San Onofre Nuclear Generating Station (SONGS) for which a 100 percent increase (doubling) of the SGTR initiating event frequency was estimated, as summarized below on page 15; 2) the analyst reviewed an analysis performed by the licensee in which increases in pressure-induced C-SGTR probabilities attributable to operating for an additional cycle with this condition were evaluated to be approximately doubled for accident conditions involving a large secondary-side break or anticipated transient without scram (ATWS), and the analyst assumed that a scaled down factor of increase for normal operating conditions versus accident conditions would be applicable; and 3) the analyst considered the non-temperature compensated testing criteria and failure pressure (4,365psi and 4,161psi, respectively) and determined that the additional level of degradation associated with difference between those two levels of performance would have minimal impact on the likelihood of failure at normal

1 The pressures at which the in-situ testing was performed and at which the two tubes failed are temperature-compensated values due to the tests being performed at ambient conditions. For example, the 3xDPno test pressure of 5500 psig is the temperature compensated equivalent of 3xDPno (which is 3x1414 psig at operating temperature, or 4242 psig) plus instrument uncertainty.

operating pressure, likely less than 10 percent increase, with 20 percent increase being an appropriately conservative assumption.

This condition was modeled by adjusting the SPAR basic event IE-SGTR (steam generator tube rupture initiating event frequency) to be increased by a factor of 20 percent. The analyst quantified the SPAR model for this condition with a 9.5-month exposure time and a truncation value of 1.0E-12, which yielded a result of 1.02E-7/yr for an increase in average annual CDF (delta-CDF). As an additional bounding analysis, an assumption that the frequency of a nominal SGTR event would be doubled would result in an increase in average annual CDF of 5.07E-7/yr delta-CDF.

Large early release frequency (LERF) is defined as the frequency of those accidents leading to significant, unmitigated releases from containment in a time frame prior to effective evacuation of the close-in population such that there is a potential for early health effects. To estimate the LERF impacts of this condition, the analyst reviewed guidance from IMC 0609 Appendix H, which identifies a LERF factor of 1.0 to be applied as a screening value for CDF associated with SGTR sequences. This screening, applied to the delta-CDF result referenced above, results in a potential delta-LERF value greater than 1E-7/yr, which requires further consideration. A 1.0 LERF factor reflects an assumption that all core damage sequences of a certain category (in this case, involving a SGTR event) result in releases of radioactivity to the environment which are characterized as both large (with regard to the quantity of radioactive source terms transported from the reactor core to the environment) and early (with regard to the timing of protective action implementation). The analyst determined the use of this value would be significantly overconservative with regard to the realistic treatment of the modeling considerations discussed below, which should be reflected in an estimation of applicable LERF factor(s) when these factors are used to estimate a LERF result as a surrogate for the output of Level 2 PRA modeling.

The analyst considered that a LERF factor used to realistically estimate the frequency of this occurrence would need to reflect consideration of the following factors and the total of their combined product:

Pctmt * Ptransport * PEOP/SAMG * Pevac

Pctmt = probability of containment failure or an open pathway bypassing containment

Ptransport = probability that, given a possible release pathway, sufficient fission product activity from the damaged core is transported via a release pathway to result in a minimum source term content++ at a point of release

PEOP/SAMG = probability that procedural actions directed in licensee EOP and SAMG procedures are unsuccessful in mitigating the potential release, both in terms of delaying the occurrence of a release condition and mitigating its magnitude

Pevac = probability that protective actions prescribed by the licensees emergency plan are ineffective prior to an unmitigated large release

++NUREG/CR-6595 Appendix A presents possible bases for minimum source term content to constitute a large release

As one point of reference, which could be considered as potential best available information on this aspect, and which could be used to inform a reasonable estimate of an overall average LERF factor associated with an event involving a SGTR, the analyst reviewed information from the licensees Level 2 PRA model for the modeled SGTR event with an unrecoverable loss of offsite power. According to the licensees model, this event has an associated conditional core damage probability (CCDP) of 5.4E-5 and a corresponding associated conditional large early release probability (CLERP) of 9.4E-8. The analyst determined that the ratio of these two values reflects an average LERF factor of 1.74E-3 to be applied for SGTR core damage sequences in order to estimate the associated LERF impacts. The analyst concluded that the use of a total/combined LERF factor 1.7E-2, which would serve as a conservative estimate of the combination (total product) of the above four factors (a combined factor which would be 10 times higher than the corresponding factor from the licensees PRA model), applied to the estimated 1.02E-7/yr delta-CDF from above, would result in an estimated average annual increase in LERF of 1.73E-9/yr delta-LERF.

RISK FROM CONSEQUENTIAL SGTR (C-SGTR) EVENTS

The analyst considered that additional tube integrity degradation could impact probabilities associated with C-SGTR events in which the post-accident plant pressure and/or temperature conditions resulting from accident sequences originating from other design basis events are such that the failure (rupture) of one or more steam generator tubes is induced. These scenarios represent the potential to introduce additional LERF due to increased potential for creating possible containment bypass pathway(s) associated with the steam generator secondary side. The analyst noted that for this additional potential LERF contribution associated with C-SGTR to be attributable to the performance deficiency, only the potential LERF that would not otherwise already be associated with these certain types of accident sequences, absent the performance deficiency, would be applicable. Only the additional LERF contribution uniquely attributable to the additional tube degradation should be considered, i.e.,

additional large and early releases that would not otherwise have occurred with a nominal/allowable level of tube degradation.

Several categories between two types of C-SGTR events will be considered, as detailed below.

Pressure-Induced Consequential SGTR (PI-CSGTR) Events

The analyst considered the following categories of modeled events that involve both core damage as well as the potential to induce a tube failure due to the higher differential pressure conditions across the tubes that are brought on by the events:

1) ATWS events that go to core damage with success of the primary pressure relief function and failure of auxiliary feedwater; 2) ATWS events with failure of the primary pressure relief function that go to core damage; and 3) Secondary-side break events (steam line or feed line breaks) that go to core damage

The SPAR model included PI-CSGTR modeling for two modeled events: steam line break outside containment and feedwater line break. To model the impact of the degraded condition, the analyst assumed an estimate of double (2x) for an increase in the probability of a PI-CSGTR occurring for these events. This estimate was based in part on the analysts review of an evaluation issued by the licensee in which increases in PI-CSGTR probabilities attributable to the subject degradation were calculated for the categories of events noted above. This condition was modeled by adjusting the SPAR basic event MSS-SLB-RP-ISGTR (induced

steam generator tube rupture has occurred) to be increased by a factor of 2x (double). The analyst quantified the SPAR model for this condition with a 9.5-month exposure time and a truncation value of 1.0E-12, which yielded a result of 3.19E-8/yr for an increase in average annual CDF (delta-CDF).

To evaluate the impact of this condition on LERF, the analyst quantified all baseline sequences from the SPAR model, including all internal event and external events (minus fire events, for which there is not current modeling in SPAR), and grouped all sequences into the above categories. The total baseline CDF contributions in each of these categories were totaled.

Baseline probabilities for C-SGTR (PPI-CSGTR) for each category were derived from results documented in NUREG-2195, Consequential SGTR Analysis for Westinghouse and Combustion Engineering Plants with Thermally Treated Alloy 600 and 690 Steam Generator Tubes. These baseline PPI-CSGTR probabilities used for each of the categories noted above were: 0.01, 0.05, and 0.02, respectively. As discussed above, the analyst assumed that an applicable factor of increase for baseline PI-CSGTR probabilities would be a factor of 2x (double) to estimate the associated conditional PI-CSGTR probabilities. Applying both the baseline and conditional PI-CSGTR probabilities to the total CDF in each category results in a delta value that can then be multiplied by a LERF factor associated with each type of sequence to arrive at a total delta-LERF associated with that category. Similar to the constituent LERF factor considerations discussed above, for the PI-CSGTR events, the additional LERF contributions uniquely attributable to additional steam generator tube integrity degradation for the above applicable core damage sequences would be represented by the combination of these factors:

Pctmt * Ptransport * PEOP/SAMG * Pevac

Pctmt = Probability that a physical pathway develops downstream of a failed steam generator tube to permit release of core fission products bypassing containment, such as a stuck open safety valve

Ptransport = Probability that, given a release pathway, sufficient fission product activity from the damaged core is transported via a release pathway (i.e., steam generator moisture separators, steam dryers, steam line piping) to result in a minimum source term content++ at a point of release. This term would need to consider the potential for scrubbing/plate out of radioactivity.

PEOP/SAMG = probability that procedural actions directed in licensee EOP and SAMG procedures are unsuccessful in mitigating the potential release

Pevac = probability that protective actions prescribed by the licensees emergency plan are ineffective prior to an unmitigated large release

The analyst assumed a range of combined/total LERF factors, ranging from 1E-3 (see value of average LERF factor discussed in spontaneous SGTR event section above) to 1.0 (an unrealistic bounding case), to represent a range of possible combinations of the combined product of the above considerations. Applying these factors, together with a 9.5-month exposure time, to the results obtained from the approach described above yielded the following range of results for estimated increase in average annual LERF (delta-LERF) per year associated with the PI-CSGTR events:

Table 1.

LERF Factor Total PI-CSGTR delta-LERF 1E-3 9.26E-12 1E-2 9.26E-11 0.1 9.26E-10 1.0 9.26E-9 Thermally Induced Consequential SGTR (TI-CSGTR) Events

The analyst considered the following categories of modeled events that can lead to post-core damage conditions that can induce a tube failure due to the circulation of hot gases from the damaged core via the RCS hot legs, which can result in thermally induced creep failure of RCS components, including steam generator tubes, representing a loss of the RCS boundary and potential containment bypass.

These types of accident sequences are generally characterized by high RCS pressure and/or low steam generator pressure and/or loss of auxiliary feedwater to the steam generator (dry),

or High/Dry/Low (H/D/L) conditions.

1) H/D/L core damage sequences involving failure of AFW function with RCS not depressurized 2) Core damage sequences with RCS not depressurized and potential faulted SG with AFW isolated to faulted SG

To evaluate the impact of this condition on LERF, the analyst quantified all baseline sequences from the SPAR model, including all internal events and external events (minus fire events, for which there is not current modeling in SPAR), and grouped all sequences in the above categories. The total baseline CDF contributions in each of these categories were totaled. Both baseline probabilities and conditional for C-SGTR (PTI-CSGTR) for each category were derived from results documented in NUREG-2195. Nominal PTI-CSGTR probabilities referenced for each of the two categories noted above were 0.2 and 0.01, respectively, which reflect an assumed nominal level of tube degradation. Since, based on discussion presented above, the applicable baseline risk case for this analysis should reflect the condition involving the maximum allowable level tube degradation (relative to the tube integrity performance testing criteria) rather than a nominal level of tube integrity degradation, the analyst selected a baseline PTI-CSGTR probability^^

of 0.6 for the H/D/L category of events. The conditional PTI-CSGTR probability applied to both categories was 0.9, consistent with conclusions documented in Section 8.1 of NUREG-2195.

Applying both the baseline and conditional TI-CSGTR probabilities to the total CDF in each category results in a delta value that can then be multiplied by a LERF factor associated with each type of sequence to arrive at a total delta-LERF associated with that category. In addition to the same factors of consideration for modeling an applicable LERF factor as presented above for the PI-CSGTR case, the TI-CSGTR case includes one additional LERF factor consideration, which would serve as an additional factor to be multiplied together with the total product of the factors previously discussed:

PRCS = probability that the post-accident temperature and pressure conditions associated with a given accident sequence do not also induce a subsequent failure of another RCS component (such as a hot leg failure or a stuck open primary relief valve), such that any release that might otherwise be attributable to a tube failure would be reduced/redirected into containment

The analyst noted that the potential, in general, for this additional factor to preclude a release attributable to a SG tube failure was documented and recognized in both the NUREG-2195 study as well as the NUREG-1935 State-of-the-Art Reactor Consequence Analyses (SOARCA)

Report. From the SOARCA report:

The PWR SBO with a TISGTR was historically believed to result in a large, relatively early release potentially leading to higher offsite consequences. However, MELCOR analysis of Surry performed for SOARCA shows that the release is small, because other reactor coolant system piping inside containment (i.e., hot leg nozzle) fails soon after the tube rupture and thereby retains the fission products within the containment.

Also, from the NUREG/CR-7110 Volume 2 SOARCA Report:

[Sensitivity studies showed that] In summary, it is not credible that the hot leg would not fail by creep rupture in the examined scenarios. Three sensitivity calculations were also performed using the SCDAP/RELAP5 code. The results of the SCDAP/RELAP5 study confirmed that: (a) TI-SGTR will not preclude hot leg creep rupture failure, and (b) hot leg creep rupture failure occurs within minutes of the TI-SGTR for a range of tube stress conditions.

For the Waterford case, the analyst noted that MAAP thermal-hydraulic analysis results provided by the licensee showed that this factor does in fact come into play for two categories of sequences comprising a majority of the total of sequences represented in category #1 above.

Specifically, for sequences involving a transient with a loss of EFW, as well as station blackout (SBO) cases involving an early loss of EFW, MAAP modeling results show that a hot leg failure occurs subsequent to a TI-CSGTR, and this precludes a large release according to the source term content definitions from NUREG/CR-6595 versus MAAP modeling predictions. The analyst considered these modeling results to be more likely credible than not, based on the other previous similar modeling results from MELCOR documented in the SOARCA report as well as in the NUREG-2195 study, which supports the notion that thermally induced failures of the hot leg and SG tube(s) can both occur sequentially.

For the remaining applicable sequences in the categories defined above, the analyst assumed a range of combined/total LERF factors, ranging from 1E-3 (see initial discussion in spontaneous SGTR event section above) to 1.0 (obviously a bounding case), to represent a range of possible combinations of the above LERF factor considerations. Applying these factors, together with a 9.5-month exposure time, to the results obtained from the approach described above yielded the following range of results for estimated increase in average annual LERF (delta-LERF) per year associated with the TI-CSGTR events:

Table 2.

LERF Factor Total TI-CSGTR delta-LERF 1E-3 1.09E-10/yr 1E-2 1.09E-9/yr 0.1 1.09E-8/yr 1.0 1.09E-7/yr

^^As a sensitivity case, use of the referenced nominal PTI-CSGTR probability of 0.2 as the baseline risk condition results in increases in the above results by a factor of 2.5 (e.g., from 1.09E-X to 2.73E-X), which does not represent a significant sensitivity relative to the established SDP significance thresholds.

EXTERNAL EVENTS

The analyst considered that the additional level of steam generator tube degradation associated with the performance deficiency could have the potential to impact the risk of a seismically-induced steam generator tube rupture. The analyst assessed the potential for a seismic event to impact the risk associated with a SGTR event in accordance with guidance from the RASP Handbook, Volume 2, Section 4. Using generic fragility values for a steam generator from Tables 4-3 and 4-4, as listed below, the probability of seismic failure for the seismic hazard vectors for Waterford given in the table below were calculated according to the equation:

Pfail(a) = [ln(a/am) / (r2 + u2)1/2]

Where: am = 2.5g, r = 0.3, u = 0.4

Table 3.

g value Mean Seismic Frequency (/yr)

0.05 2.86E-4 0.08 1.66E-4 0.15 5.70E-5 0.25 2.29E-5 0.3 1.60E-5 0.4 8.80E-6 0.5 5.35E-6 0.65 2.87E-6 0.8 1.69E-6 1 9.32E-7

Applying the above equation to each of the g values listed above, then multiplying the resulting failure probabilities by each the corresponding event frequencies listed above, results in a series of seismic SGTR frequencies, which can be summed to yield a total baseline seismic SGTR frequency of 6.52E-8/yr. Qualitatively, the analyst considered that the actual physical structural defect associated with a level of degradation that marginally reduced the pressure retaining capability of the most degraded tube from 5,500psi to 5,243psi would be unlikely to represent any significant change in the seismic fragility of the component. Conservatively, the analyst evaluated the increase in CDF associated with a reduction in the median of the component fragility (median capacity) by a factor of 50 percent from 2.5 to 1.25.

The resulting conditional seismic SGTR frequency was determined to be 1.22E-6/yr, representing an increase in SGTR frequency of 1.15E-6/yr.

From the SPAR model results for the SGTR event, the CCDP for a SGTR event was determined to be 3.6E-4. Multiplying this CCDP value by the calculated increase in SGTR frequency associated with the assumed reduction in component fragility yields a total increase in CDF of 4.15E-10/yr associated with this condition, which was determined to represent a negligible contribution to the risk significance of the condition being evaluated.

The risk associated with external event-initiated sequences that could involve any significant potential to lead to C-SGTR events was included in the SPAR results referenced above (and summarized in the table below) when evaluating the C-SGTR impacts.

The risk attributable to this condition for fire-initiated sequences is included in the summary of licensee modeling results below.

SUMMARY OF BEST ESTIMATE RESULTS

From the range of evaluation results described in the section above, the following table summarizes best estimates the delta-CDF and delta-LERF impacts attributable to the condition resulting from the performance deficiency. The C-SGTR delta-LERF values selected as best estimates from among the range of results reported above reflect the use of an average LERF factor of 0.1, which was selected by the analyst as a screening value to represent and bound an average combination of the individual LERF modeling considerations described in the above sections, which would be applicable for the majority of scenarios included among the dominant sequence types in the absence of any further available confirmatory Level 2 modeling guidance or resources. Sensitivities regarding the value of this assumed parameter are presented in the uncertainties section below.

Table 4.

Source of Risk Delta-CDF Delta-LERF SGTR 1.02E-7/yr 1.73E-9/yr PI-CSGTR 3.19E-8/yr 9.26E-10/yr TI-CSGTR N/A 1.09E-8/yr Totals: 1.34E-7/yr 1.36E-8/yr

These results do not include risk associated with fire sequences. Thebest information regarding fire risk was obtained from the licensees evaluation results, summarized below.

DOMINANT SEQUENCES/CUT SETS

The sequences involving the largest portion of total LERF risk included seismic-induced small LOCA events with loss of secondary heat sink (feedwater and condensate), which contributed to the TI-CSGTR LERF results.

The delta-CDF results were dominated by SGTR events involving a failure to isolate the ruptured generator and either a failure of the RWSP refill function or a shutdown cooling failure with failure of long-term secondary heat removal (CSP makeup).

SUMMARY OF LICENSEE MODELING RESULTS

The analyst reviewed and assessed the use of the licensees Level 2 modeling resources for purposes of estimating the delta-CDF and delta-LERF risk impacts attributable to the condition resulting from the performance deficiency. The licensees model included both TI-CSGTR and PI-CSGTR events built into the model, the probabilities of which were adjusted to reflect the impact of the degraded condition.

The licensees model also included LERF modeling built into the model, as well as risk from fire initiating events, and the summary of results below reflects consideration of the delta-CDF and delta-LERF impacts from applicable increases in both the nominal spontaneous SGTR event as well as the C-SGTR events. The licensees risk evaluation approach was to determine the increase in risk associated with plant operation over the final 1-year period of the additional fourth operating cycle with the existing tube degradation processes occurring, versus operating with a level of tube degradation that was estimated to have developed over a 3-cycle period.

The analyst considered the results summarized below as a source of best available information for the evaluation of this issue, given the relative lack of corresponding means of definitive and less uncertain independent evaluation of LERF available to the analyst. These results reflect analysis performed by the licensee, which also includes analysis performed in response to requests and challenges posed by the analyst.

Table 5.

Risk Category Total delta-CDF Total delta-LERF Fire 0 7.74E-8/yr Seismic 8.04E-9/yr 1.30E-9/yr Internal Events 3.09E-7/yr 4.68E-9/yr Totals: 3.17E-7/yr 8.34E-8/yr

UNCERTAINTY AND QUALITATIVE CONSIDERATIONS

Licensee Results

Parameter Point Est Mean 5% 95%

Total dCDF 3.17E-7 3.10E-7 1.38E-7 6.09E-7

Parameter Point Est Mean 5% 95%

Total dLERF 8.34E-8 9.08E-8 1.90E-8 9,97E-8

Because the licensees analysis results reflect the assumption of a full year of operation with a condition degraded beyond a baseline reference condition, the licensee results summarized above could be reduced by the fraction of a year (9.5 months) that is consistent with the NRCs assumption for an applicable exposure time, as discussed earlier, and could thus be considered as being conservatively high from that standpoint. Even so, the totality of the analysis approach and selection of parameters reflected in the licensee analysis, as revised based on review by the analyst, is being considered as a valid and applicable use of the modeling tools available for evaluation of this kind of issue whose risk significance is driven by LERF considerations, and the results are being considered as an appropriate measure of risk significance for the condition that is attributable to the performance deficiency.

Additionally, the analyst noted that the MAAP thermal hydraulic modeling results integrated in the licensee analysis were based in part on a modeling limitation by which the coldest hot-side tube location was used as a surrogate for the actual cold-side tube locations associated with the actual existing tube flaws of interest. This modeling substitution, which was due to only hot-side tube locations being available in the existing MAAP modeling, represents an additional source of conservatism inherent in the licensee analysis results, since hot-tube side flaw locations are more susceptible to having TI-CSGTR consequences than cold-tube side locations.

NRC Results

The analyst performed an uncertainty analysis using the Monte Carlo method with 3,825 runs for the delta-CDF results presented above in SAPHIRE. The mean value result was 1.39E-7/year, and the 5th and 95th percentile results were -5.8E-7/year and 1.14E-6/year, respectively, with 98.3 percent of the results falling within the range of less than 1.0E-6/year (Green). The analyst considered that the uncertainty distribution associated with LERF results would be similarly distributed with a corresponding dominant portion of the results remaining below the 1.0E-7/year (White) significance threshold.

Certain sensitivities/bounding cases have already been presented in the analysis sections above. Several additional sensitivity cases will be presented in this section. A summary of the range of total results presented above is provided in the following tables. These results do not include risk from fire scenarios. The best estimate of fire risk is included in the summary of the licensees modeling results above.

Table 6.

Assumed % increase in SGTR frequency Total Delta-CDF Results 10 8.26E-8/yr 20 1.34E-7/yr 50 2.85E-7/yr 100 5.39E-7/yr

Table 7.

Assumed LERF Factor for C-SGTR Events Total Delta-LERF Results 1E-3 1.85E-9/yr 1E-2 2.91E-9/yr 0.1 1.36E-8/yr 1.0 1.20E-7/yr

The TI-CSGTR evaluations reflected in the results discussed above included some additional conservatism in the conditional probability factors selected, on the basis that the proximity of the limiting steam generator tube flaws to the hot leg side of the tubesheet (i.e., the hot tube side of the U-tube bend) represents a significant factor in determining the likelihood of that location to be affected by increased post-accident temperatures, which are much higher in the hot tube side area. All of the limiting flaws identified in the Waterford tubes were on the cold tube side of

the tube bundle, and therefore less likely to represent increases in susceptibility to TI-CSGTR concerns/challenges.

Additionally, in the modeled High/Dry/Low sequences associated with the TI-CSGTR events, no credit is provided for potential recovery of the EFW function. This factor would serve to reduce overall risk, if included. From the SOARCA Report: Moreover, core damage, tube rupture, and radiological release could be delayed for many hours if auxiliary feedwater were available even for a relatively short time.

The PPI-CSGTR probabilities associated with all of the secondary-side break event frequency included in Category #3 of the PI-CSGTR events were based on the assumption that all events in this category would result in a sudden large secondary-side depressurization. In reality, only a subset of these kinds of events would result in a sudden total depressurization large enough to result in such an additional tube rupture probability. The risk results contributed from this category would thus be artificially high contributions to the total results presented.

Another source of uncertainty applicable for both the licensee and NRC analysis results presented above is associated with the reliability of thermal hydraulic modeling predictions that represent important considerations and applicable for some of the types of accident sequences that can result in TI-CSGTR conditions. As was discussed above, the potential LERF contributions from two of the three types of sequences that represented the majority of potentially significant LERF results in this category (according to the licensees evaluation) were excluded from the results based on MAAP modeling involving a predicted hot leg failure subsequent to (in addition to) a predicted TI-CSGTR. Although this sequence of events is consistent with results noted in previous studies, including the referenced MELCOR results associated with the SOARCA study, there is the potential that MAAP modeling parameters and assumptions associated with some of the applicable phenomena involved in these scenarios may not be producing the most reliable predictions. For example, it is possible that multiple/additional nominally flawed tubes may fail prior to hot leg failure, and in this case the LERF implications attributable to a SGTR condition would remain in effect. All of the results presented in this evaluation reflect the exclusion of these types of sequences from contributing to the delta-LERF attributable to the condition associated with this performance deficiency. The licensees analysis reflected additional potential delta-LERF results in the TI-CSTGR category for internal events in the range of 2-3 x 10-7/yr if all (both) of the additional sequences applicable for TI-CSGTR conditions were included in the results. Likewise, the summary of the range of total delta-LERF results presented above reflect the exclusion of these two types of accident sequences that could otherwise represent contributions to delta-LERF for TI-CSGTR scenarios.

As an additional sensitivity, if risk contributions from these sequences were included in the delta-LERF results presented in Table 7 above (i.e., disregarding the associated MAAP results),

the revised results (which again would not include risk from fire initiators) would be:

Table 8.

Assumed LERF Factor for C-SGTR Events Total Delta-LERF Results 1E-3 3.56E-9/yr 1E-2 2.00E-8/yr 0.1 1.85E-7/yr 1.0 1.83E-6/yr

For the proposed case of using a assumed average LERF factor of 0.1 as a best estimate value, the corresponding difference in results from Table 7 to Table 8 (i.e., 1.36E-8/yr to 1.85E-7/yr) represents a range of degrees to which the MAAP thermal hydraulic results referenced above are credited for the exclusion of delta-LERF results associated with those certain sequences from being attributable to the degraded condition.

A phenomenon known as loop seal clearing is also an important consideration that impacts LERF risk associated with TI-CSGTR scenarios. Under post-accident conditions, hot gases are transported from the damaged core via the hot leg to the steam generators (entering the tubes from the hot leg plenum tubesheet). If a certain volume of water remains present in the cold leg during this accident progression, then the circulation of hot gases between the reactor vessel and the steam generator occurs via a reflux pathway in the hot leg. If loop seal clearing occurs (the primary mechanism for which would be a reactor coolant pump seal LOCA), then the natural circulation of hot gases in the primary loop can be greatly increased, such that the probability of TI-CSGTR occurring is greatly increased. For the Combustion Engineering design, the nominal/baseline TI-CSGTR probability in cases where loop seal clearing occurs is postulated to be close to 1.0. In all of the analyses presented above, all of the postulated H/D/L sequences that were considered as potential contributors for TI-CGTR events were conservatively assumed to not involve loop seal clearing. Because the baseline TI-CSGTR probability associated with a loop seal clearing scenario is 1.0, there would be no delta-risk contributions for any of the identified H/D/L sequence frequency that may actually be in this loop seal clearing sub-category. Therefore, the TI-CSGTR delta-LERF results considered above are actually over-estimates of risk from this standpoint.

Additionally, the analyst reviewed information supporting an approximation that new, unflawed alloy 690 tubes are originally able to retain approximately 10,000 psi of pressure. In this case of the 3xDPno performance testing criterion being at a value of 5,500 psi, a level of tube degradation is allowed to exist such that the margin relative to this integrity criterion is allowed to be reduced from approximately 10,000 psi to 5,500 psi, and the amount of degradation associated with this amount of margin being lost is accepted as part of the plants baseline risk.

With one tube failing at 5,504 psi (very little margin lost relative to the integrity criteria), the level of degradation attributable to the performance deficiency is that which is associated with an additional reduction in performance criteria margin from 5,500 psi to 5,243 psi.

The analyst also considered the circumstances and basis for the significance determination of the most recent similar previous finding at another plant of the Combustion Engineering design that also involved degraded steam generator tube integrity issues. Specifically, the analyst reviewed and compared the conditions and significance associated with a finding issued to the San Onofre Nuclear Generating Station (SONGS), as documented in NRC Inspection Report 05000362/2012009, with the corresponding degraded plant conditions at Waterford. The following table provides a summary of this information.

Tubes Failing Location of Plant 3xDPno Integrity Excess Additional Criterion Degradation SONGS Eight (8) tubes Hot and cold Actual primary-to-secondary leakage failed by margins up tube sides of estimated at 75 gpd while operating to 45.3% (2,376 psi) U-tube bend Three tubes failed accident-induced leakage performance criterion (0.5 gpm)

by margins of more than 800% (4.5 gpm)

Waterford Two (2) tubes failed Cold tube None by margins of 0% side only and 4.7% (257 psi)

The analyst noted that the risk implications associated with the level of tube degradation conditions at SONGS would be substantially more significant in all of the risk categories discussed above, due to the degraded conditions representing a much larger departure from the allowable baseline level of degradation. The NRC determined the significance of the finding at SONGS was characterized by an estimated delta-LERF of 2.8E-7/yr, which is low in the White significance range (relative to the White threshold of 1.0E-7/yr and Yellow threshold of 1.0E-6/yr).

CONCLUSION

This evaluation included use of available information to evaluate the risk impacts of the condition attributable to the licensee performance deficiency relative to the SDP metrics of delta-CDF and delta-LERF. The means of independently quantifying a delta-LERF impact was impacted by limitations associated with the currently available modeling resources (i.e., Level 2 PRA) and evaluation guidance applicable for LERF analysis, resulting in a variety of uncertainties described above. The analysts assessment of the use of the licensees Level 2 modeling resources to quantify a delta-LERF associated with the applicable plant conditions was determined to constitute a source of best available information in this matter. As a result, the overall best estimates for the risk impacts attributable to this performance deficiency were determined to be a delta-CDF of 1.34E-7/yr and a delta-LERF of 8.34E-8/yr, both of which are associated with a finding of very low safety significance (Green).

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