LR-N18-0070, Response to Request for Additional Information (Rai), Implementation of WCAP-14333 and WCAP~15376 Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation System Instrumentation Test Times and ..

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Response to Request for Additional Information (Rai), Implementation of WCAP-14333 and WCAP~15376 Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation System Instrumentation Test Times and ...
ML18199A073
Person / Time
Site: Salem  PSEG icon.png
Issue date: 07/17/2018
From: Mcfeaters C
Public Service Enterprise Group
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
LR-N18-0070
Download: ML18199A073 (11)
v • d • e


Text

PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236 0PSEG NuclearLLC 10 CFR 50.90 LR-N 18-0070 JULI 7 2018 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Salem Generating Station, Units 1 and 2 Renewed Facility Operating License Nos. DPR-70 and DPR-75 NRC Docket Nos. 50-272 and 50-311

Subject:

Response to Request for Additional Information (RAI), Re: Implementation of WCAP-14333 and WCAP~15376 Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation System Instrumentation Test Times and Completion Times

References:

1. NRC email to PSEG, "Salem 1 and 2 - Final RAI RE: Revise TS to Adopt TSTF-411 and 418" dated June 20, 2018 (ADAMS Accession No. ML18171A321)
2. PSEG letter to NRC, "License Amendment Request for Implementation of WCAP-14333 and WCAP-1376 Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation System Instrumentation Test Times and Completion Times," dated December 18, 2017 (ADAMS Accession No. ML17352A502)
3. NRC letter to PSEG, "Salem Nuclear Generating Station, Unit Nos. 1 and 2 -

Supplemental Information Needed for Acceptance of Requested Licensing Action Re: Implementation of WCAP-14333 and WCAP-15376 (EPID L-2017-LLA-0442)," dated Ja*nuary 31, 2018 (ADAMS Accession No. ML180258916)

4. PSEG letter to NRC, "Supplemental Information to License Amendment Request for Implementation of WCAP-14333 and WCAP-15376, Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation Test Times and Completion Times," dated February 9, 2018 (ADAMS Accession No. ML18040A319)

In Reference 1, the Nuclear Regulatory Commission (NRC) requested PSEG Nuclear LLC (PSEG) to provide additional information in order to complete the review of the license amendment request (LAR) to implement changes to the Technical Specification (TS) requirements for Reactor Trip System and Engineered Safety Feature Actuation System instrumentation test and completion times per TSTF 411 and TSTF 418. Attachment 1 provides a response to the request for additional information.

Page 2

  • LR-N 18-0070 PSEG has determined that the information provided in this submittal does not alter the conclusions reached in the 10 CFR 50.92 no significant hazards determination previously submitted. In addition, the information provided in this submittal does not affect the bases for concluding that neither an environmental impact statement nor an environmental assessment needs to be prepared in connection with the proposed amendment.

There are no regulatory commitments contained in this letter.

Should you have any questions regarding this submittal, please contact Mr. Michael Wiwel at 856-339-7907.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on (Date)

Sincerely, Charles V. McFeaters Site Vice President Salem Generating Station Attachments:

1. Response to Request for Additional Information cc: Mr. D. Dorman, Administrator, Region I, NRC Mr. R. Ennis, Project Manager, NRC NRC Senior Resident Inspector, Salem Mr. P. Mulligan, Chief, NJBNE Saleni Commitment Tracking Coordinator Corporate Commitment Tracking Coordinator

LR-N18-0070 Attachment 1 Response to Request for Additional Information 1

LR-N 18-0070 Request for Additional Information (RAI)

Regarding Implementation of WCAP-14333 and WCAP-15376 Reactor Trip System Instrumentation and Engineered Safety Feature Actuation System Instrumentation Test Times and Completion Times Salem Nuclear Generating Station, Unit Nos. 1 and 2 Docket Nos. 50-272 and 50-311 By letter dated December 18, 2017 (Agencywide Documents Access and Management System

[ADAMS] Accession No. ML17352A502), as supplemented by letter dated February 9, 201.8 (ADAMS Accession No. ML18040A319), Public Service Enterprise Group Nuclear, LLC (PSEG) submitted a risk-informed license amendment request to revise Technical Specification (TS) 3/4.3.1, "Reactor Trip System Instrumentation" and TS 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation" to implement the allowed surveillance test intervals (STls),

completion times (CT), and bypass test times at Salem Generating Station (Salem) Units 1 and

2. In order to complete its review, the U.S. Nuclear Regulatory Commission (NRC) staff requests a response to the questions below Request for Additional Information (RAil 01 - Deviations to WCAP-14333 and 15376 Insert 5 of Technical Specification Task Force (TSTF) 411, Revision 1 (ADAMS Accession No. ML022470164), states, "In order to apply the WCAP-10271, as supplemented, and WCAP-15376 TS relaxations to plant specific Functions not evaluated generically, licensees must submit plant specific evaluations for NRC review and approval." Insert 4 of TSTF-418, Revision 2 (ADAMS Accession No. ML012530049), states, "In order to apply the various relaxations justified in WCAP-10271, WCAP-14333-P-A and WCAP-15376 to plant specific Functions not evaluated generically, a plant specific evaluation of those Functions must be performed."

In TS Table 3.3-1 of the LAR, Reactor Trip System (RTS) Function 20 (Reactor Coolant Pump Breaker Position Trip (above P-7)) was not generically evaluated as described above. In TS Table 3.3-3 of the LAR, the following Engineered Safety Feature Actuation System (ESFAS) functions were not generically evaluated as described above: Function 3.c.2 (Containment Ventilation Isolation, Automatic Actuation Logic), Function 6 (Safeguards Equipment Control System), Function 7.a (Vital Bus Undervoltage, Loss of Voltage), Function 7.b (Vital Bus Undervoltage, Sustained Degraded Voltage), Function 9.a (Semiautomatic Transfer to Recirculation, RWST Level Low), and Function 9.b (Semiautomatic Transfer to Recirculation, Automatic Isolation Logic). The LAR provides a plant-specific evaluation for RTS Function 20 to justify an extended completion time. The LAR also provides a plant-specific evaluation for ESFAS Functions 7a, 7b, 9a, and 9b that justifies an allowed outage time and test bypass extension. However, it is unclear to NRC staff how the unavailabilities (UA) listed in Table 4-22 of the LAR were calculated for Functions 3.c.2 and 6. For the plant-specific evaluation for ESFAS Functions 3.c.2 and 6, describe how UA values provided in Table 4-22 of the LAR were calculated.

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LR-N18-0070 PSEG Response to RAI 01 - Deviations to WCAP-14333 and 15376 As stated in Section 4.2.3 of the LAR when discussing Functions 3.c.2, 6, 7a, 7b, 9.a, & 9.b, "The acceptability of the proposed changes for the above functions was evaluated quantitatively using an application specific model as discussed in Sections 4.3.1.5 and 4.3.4." These plant-specific evaluations are discussed throughout Section 4.3 of the LAR, with the results presented in Table 4-30 of the LAR, including results for Function 3.c.2 (Containment Ventilation Isolation Automatic Actuation Logic, line "Cl" in Table 4-30) and Function 6 (Safeguards Equipment Control System, line "SEC" in Table 4-30).

The unavailability values in Table 4-22 represent important inputs into these plant-specific calculations. For Vital Bus Undervoltage (Functions 7.a/b) and Semiautomatic Transfer to Recirculation (Functions 9.a/b), modifications to the PRA were made as discussed in Section 4.3.1.5 of the LAR. For Containment Ventilation Isolation Automatic Actuation Logic (Function 3.c.2) and Safeguards Equipment Control System (Function 6), the required fault tree logic, basic events, and unavailability values for the PRA already existed, so they were not specifically discussed in the LAR.

For Containment Ventilation Isolation Automatic Isolation Logic (Function 3.c.2), the existing PRA model uses an unavailability event (RPS-LOG-TM-TRNA/8) that conservatively represents the unavailability of an entire train of RPS logic. The unavailability value for this event is based on a historical value in the Salem PRA because the most recent data update showed zero hours of applicable unavailability for these components. The impact of using this historical value is considered to be conservative and negligible based on the zero actual hours of unavailability.

This approach and impact are discussed in the DA-C1 Supporting Requirement in Table 4-13 of the LAR.

For Safeguards Equipment Control System (Function 6), the existing PRA model uses an unavailability event (ESF-LOG-TM-SEC-A/8/C) based on actual plant-specific data from the Maintenance Rule Manager that was collected and applied during the latest data analysis update. The plant-specific data included both Unit 1 and Unit 2.

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LR-N18-0070 RAI 02- Emergency Diesel Generator (EDG) Mission Time The combined American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) probabilistic risk assessment (PRA) standard (ASME/ANS RA-Sa-2009) defines mission time as the time period that system or component is required to operate in order to successfully perform its function. Regulatory Guide (RG) 1.200, Revision 2, states that licensees are to ensure mission times and their requirements are adequately discussed and documented per the ASME PRA Standard. The ASME PRA standard states, "use a minimum mission time of 24 hr.

Mission times for individual SSCs (systems, structures, and components] that function during the accident sequence may be less than 24 hr, as long as an appropriate set of SSCs and operator actions are modeled to support the full sequence mission time."

In Tables 4-9 and 4-11 of the LAR, the EOG mission time used by the licensee is 6.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in the disposition of Facts and Observations (F&Os) AS-AB, AS-87, SY-811. The justification for using 6.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> instead of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is provided in the Salem PRA Data Notebook SA-PRA-010, and the discussion of resolution for these F&Os is insufficient for the NRC staff to conclude that an appropriate set of SSCs and operator actions are modeled to justify using an EOG mission time of 6.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> instead of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. For F&O AS-87, the licensee states, "SBO scenarios are relatively insignificant risk contributors within the context of this risk evaluation." The disposition of F&O AS-87 is insufficient for the NRC staff to conclude that SBO scenarios are insignificant to risk using a 6.2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> mission time instead of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Provide one of the following to address using 6.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for EOG mission time:

a. Provide the justification documented in Section 10.0 of Salem PRA Data Notebook SA-PRA-010 that allows using 6.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for F&Os AS-AB and SY-811, and provide justification that "SBO scenarios are relatively insignificant risk contributors within the context of this risk evaluation" given that a 6.2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> mission time was used for the EDGs instead of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, OR;
b. Perform a sensitivity analysis using the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time discussed in the ASME PRA Standard and* provide updated risk metrics for using the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time.

Justify these updated risk metrics meet the guidance in RG 1.174, Revision 2, and RG 1.177, Revision 1.

PSEG Response to RAI 02 - Emergency Diesel Generator (EDG) Mission Time A surrogate emergency diesel generator (EOG) mission time was developed to quantify the risk of mitigating PRA scenarios for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The surrogate mission time was developed by calculating a time-averaged value for which the EOG would be required to run and supply AC power prior to recovery of an offsite power source. The estimation of this EOG surrogate mission time involved the convolution of EOG run-time success with non-recovery of offsite power over a time period ranging from 15 minutes to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following the initial loss of offsite power (LOOP) event. This calculation was performed using the non-recovery curve for weather-related events taken from Table 4-1 of NUREG/CR-6B90, "Reevaluation of Station Blackout Risk at Nuclear Power Plants" [2]. The weather-related curve was chosen because its non-recovery probabilities are bounding compared to the plant-centered, switchyard and grid curves. This probabilistic treatment of power availability quantifies the probability of reaching a steady-state condition as discussed in AS-AB.

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LR-N18-0070 Some of the assumptions and limitations used in this convolution exercise include the following:

  • The mathematical convolution models the conditional probability for failure to supply AC power with either a diesel generator or offsite AC power source between 15 minutes and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following the LOOP event.
  • EOG recovery is not credited.
  • This evaluation only considers the operation of a single EOG. Consideration of a second EOG would add complexity to the evaluation, but is not judged to alter the conclusions. The single EOG case is conservative because one or the other EOG has a likelihood of continuing to run.
  • The dominant contributor to risk during a given LOOP is the diesel failing to run.

Any EOG or any offsite power source provides enough power to safely shutdown and maintain a steady-state condition. The probabilistic model simulates the availability of adequate power to support the plant for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and beyond per SY-811. The EOG surrogate run-time convolution resulted in a surrogate mission time of 6.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The integrals were solved using the commercially available Mathcad [1] code.

Section 4.3.4.8 of the LAR identifies that the primary contributors to the small increases in average COF and LERF that is still well below the acceptance criteria are due to:

  • Main steam line break inside containment followed by failure of SI signal in combination with failure of operators to manually recover.

These contributors are based on the quantitative results of the internal events model (with internal flooding). While some-of the accident sequences that contribute to the small risk increase are related to LOOP and SBO, the EOG failures of concern are fail-to-start due to the increased unavailability of the UV relays. Since an EOG is required after a LOOP, and none of the changes proposed in this application would increase the frequency of a LOOP, there is no increase to the number of EOG demands. Additionally, the Salem PRA credits the ability to manually start EOGs from the control room when and if they fail to automatically start. The probabilistic credit (i.e., the human error probability) varies for different scenarios, but is significant because manually starting an EOG is in Salem procedures and training.

The changes proposed in this application could impact the ability of the EOG to start, as identified in these results, but the changes would have no direct impact on the ability of the EOG to run. Sequences with only one EOG failure that is fail-to-run would not be impacted by the changes. Sequences are possible with more than one EOG failure, where one EOG failure was a fail-to-start due to signal failures (such as UV relays), but such combinations do not appear in the delete-term cutsets for this application. In fact, the delete-term cutsets that represent the small risk increases show no occurrences of the EOG fail-to-run events with a 6.2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> mission time, so that approximation has a negligible impact on the conclusions, confirming this reasoning.

For external events discussed in the LAR and Supplement, the qualitative analysis provides a bounding calculation that does not depend on the mission time of the EOGs for the same reasons as discussed above. Given the conclusions of the qualitative evaluations that determined that conservative estimates for external event ~COF and ~LERF are all well below 5

LR-N18-0070 the acceptance guidelines for all of the signals that could be impacted by this application, the impact of a different EOG mission time would be negligible for external events.

In conclusion, the analysis in the LAR provides reasonable risk and ti risk values and insights for the scenarios analyzed.

RAI 03 - Common Cause Failure Data According to the ASME PRA Standard, the High Level Requirement for Systems Analysis requires the systems analysis to provide a reasonably complete treatment of common cause failures (CCF) and intersystem and intra-system dependencies.

In Table 4-11 of the LAR, the licensee's disposition of F&O SY-83 states, "A few CCF events were determined using sources other than the NRC/INL data." The licensee does not provide additional information as to what the source of the CCF is or why it was used. In order for the NRC staff to conclude the licensee's treatment of CCF is reasonable, provide which CCF events used data sources other than NRC/INL data, and provide justification as to why this data is reasonable to treat CCF at Salem Units 1 and 2.

PSEG Response to RAI 03 - Common Cause Failure Data A review of the PRA Data Notebook (SA-PRA-010) [3] revealed that CCF events were indeed derived using alpha factors developed by the Idaho National Laboratory (INL) [4] that were used in conjunction with the independent failure rates, as well as other factors to account for mission times and the number of intermediate combinations that were modeled. For Westinghouse Reactor Protection System common cause failures, values were obtained from Table 3 of NUREG/CR-5500 [5] for the following components:

  • Channel bistable relay failures
  • Solid State Protection System (SSPS) undervoltage driver card failures NUREG/CR-5500 is commonly used in nuclear plant PRAs and it contains a more detailed explanation of the basis for the above common-cause failure component groups (SY-83).

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LR-N18-0070 RAI 04 - Data Analysis The supporting requirement DA-C5 for HLR-DA-C in the ASME PRA standard states, "Count repeated plant-specific component failures occurring within a short time interval as a single failure if there is a single, repetitive problem that causes the failures."

In Table 4-13 of the LAR, for the disposition of F&O DA-C5, the licensee states, "the Data notebook was updated to clarify failures occurring within a short time interval can be excluded so as not to skew the data for any one SSC modeled in the PRA." Based on the ASME PRA standard, the disposition of F&O DA-C5 by the licensee is different than the requirements in the ASME PRA Standard, in that failures occurring within a short time interval should not be excluded, but rather counted as a single failure.

Provide justification for this discrepancy. Alternatively, perform a sensitivity evaluation using a single failure instead of excluding the failure, and provide and justify the updated risk metrics meet the guidance in RG 1.174, Revision 2, and RG 1.177, Revision 1.

PSEG Response to RAI 04 - Data Analysis The original wording for this Supporting Requirement (SR) is misleading and should be restated as follows:

During the 2015 update, the Data notebook was updated to clarify that repetitive failures occurring within a short time interval were only counted as a single failure so as not to skew the data for any one SSC modeled in the PRA that experienced multiple failures that were related to a single fault.

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LR-N18-0070 RAI 05 - External Hazards When a licensee requests an amendment to its license that involves a risk-informed change to technical specifications, RG 1.177, Revision 1, states that when the risk associated with a particular hazard group or operating mode would affect the decision being made, it is the Commission's policy that, if a staff-endorsed PRA standard exists for that hazard group or operating mode, then the risk will be assessed using a PRA that meets that standard.

Regulatory Guide 1.174, Revision 2, adds that a qualitative treatment of the missing modes and hazard groups may be sufficient when the licensee can demonstrate that those risk contributions will not affect the decision; that is, they do not alter the results of the comparison with the acceptance guidelines.

According to the LAR and the LAR supplement, hazards applicable to Salem Units 1 and 2 include internal events, internal fires, external floods, and seismic events. For internal events and external floods, the licensee provides separate change in risk values for each operating unit, as there are differences between the two units. In the LAR supplement, the qualitative bounding assessment for internal fires and seismic events provides change in risk values, but does not specify to which operating unit(s) the change in risk values are applicable. For the change in risk due to internal fires and seismic events, provide the follow information:

a. Clarify to which operating unit(s) the change in risk is applicable;
b. If the change in risk is only applicable to one operating unit, provide the change in risk for internal fires and seismic events for the other unit.

PSEG Response to RAI 05 - External Hazards In the LAR supplement, the qualitative bounding assessments for internal fires and seismic events provide values for changes in risk that apply to both units. The bases for the qualitative evaluations described in the supplement rely in part on the Salem Full Power Internal Events PRA Model of Record [6]. All inputs from the PRA used in the supplement apply equally to both Salem Units. For example, the seismic evaluation in the LAR uses a human error probability for failure to start ECCS drawn from the PRA model, which would be the same for both Unit 1 and Unit 2. The one difference identified in the LAR that is a relevant unit-to-unit difference is the existence of the semiautomatic switchover to recirculation in Unit 2. This difference does not impact the conclusions of the qualitative evaluations that determine that conservative estimates for external events ~CDF and ~LERF are all well below the acceptance guidelines for all of the signals that could be impacted by this application.

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LR-N18-0070 REFERENCES

1. "User's Guide with Reference Manual - Mathcad 2001 Professional", Mathsoft, Inc., Cambridge, MA, Copyright 1986-2001.
2. U.S. Nuclear Regulatory Commission, "Reevaluation of Station Blackout Risk at Nuclear Power Plants", NUREG/CR-6890, December 2005.
3. PSEG, Salem Generating Station PRA Data Notebook, SA-PRA-010, Rev. 2, December 2016.
4. U.S. Nuclear Regulatory Commission, "CCF Parameter Estimations, 2012 Update",http://nrcoe.inl.gov/results/CCF/ParamEst2012/ccfparamest.htm, November 2013.
5. U.S. Nuclear Regulatory Commission, "Reliability Study: Westinghouse Reactor Protection System, 1984-1995", NUREG/CR-5500, Volume 2, April 1999.
6. Salem Generating Station, Quantification Notebook, SA-PRA-014, Revision 1, December 2016.

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