RS-17-147, Response to Request for Additional Information Regarding LaSalle County Station Fourth Inservice Inspection Interval Relief Request 14R-01
| ML17317A543 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 11/10/2017 |
| From: | Gullott D Exelon Generation Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| CAC MF9758, CAC MF9759, EPID L-2017-LLR-0057, RS-17-147 | |
| Download: ML17317A543 (30) | |
Text
4300 Winfield Road
'- Warrenvi Ile, IL 60555 Exelon Generation
- 630 657 2000 Office RS-17-147 10 CFR 50.55a November 10, 2017 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 LaSalle County Station, Units 1 and 2 Renewed Facility Operating License Nos. NPF-11 and NPF-18 NRC Docket Nos. 50-373 and 50-374
Subject:
Response to Request for Additional Information Regarding LaSalle County Station Fourth Inservice Inspection Interval Relief Request 14R-01
References:
- 1) Letter from D. M. Gullott (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, "LaSalle County Station, Units 1 and 2, Fourth 10-Year Interval Inservice Inspection Program Relief Requests," dated May 30, 2017 (ADAMS Accession No. ML17150A449)
- 2) Letter from P. R. Simpson (Exelon Generation Company, LLC) to U.S. Nuclear Regulatory Commission, "Response to Request for Supplemental Information Regarding LaSalle County Station Fourth Inservice Inspection Interval Relief Request 14R-01," dated July 20, 2017 (ADAMS Accession No. ML17201Q396)
- 3) Letter from B. Vaidya (U.S. Nuclear Regulatory Commission) to B. C. Hanson (Exelon Generation Company, LLC), "LaSalle County Station, Units 1 and 2, Request for Additional Information Regarding Relief Request 14R-01, Requests Approval of Alternative Risk-Informed Inservice Inspection Interval Program and Examination Criteria for Examination Category 8-F, 8-J, C-F-1, and C-F-2 Pressure Retaining Piping Welds in Accordance with ASME Code Case N-578-1, 'Risk-Informed Requirements for Class 1, 2, or 3 Piping, Method B,Section XI, Division 1,' (CAC Nos. MF9758 and MF9759; EPID L-2017-LLR-0057)," dated October 12, 2017 (ADAMS Accession No. ML17261A078)
In a letter dated May 30, 2017 (Reference 1), Exelon Generation Company, LLC (EGC) requested approval of a request associated with the fourth Inservice Inspection (ISI) interval for the LaSalle County Station (LSCS), Units 1 and 2. The fourth interval of the LSCS ISI Program began on October 1, 2017, and is currently scheduled to end on September 30, 2027, and will comply with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV)
Code,Section XI, 2007 Edition with the 2008 Addenda. Relief Request 1419-01 of Reference 1 requested approval of alternative risk-informed ISI program and examination criteria for
November 10, 2017 U.S. Nuclear Regulatory Commission Page 2 Examination Category B-F, B-J, C-F-1, and C-F-2 pressure retaining piping welds in accordance with ASME Code Case N-578-1, "Risk-Informed Requirements for Class 1, 2, or 3 Piping, Method B,Section XI, Division 1." Reference 1 was supplemented by a letter dated July 20, 2017 (Reference 2), to support the U.S. Nuclear Regulatory Commission (NRC) to complete the acceptance review.
In Reference 3, the NRC requested additional information to complete its review of Relief Request 14R-01. The requested information is provided in the attachments of this letter. Attachment 1 provides the responses to Probabilistic Risk Assessment (PRA) Request for Additional Information (RAI) 1 through RAI 3. Attachment 2 provides the response to PRA RAI 4.
There are no regulatory commitments contained within this letter.
Should you have any questions concerning this letter, please contact Ms. Lisa A. Simpson at (630) 657-2815.
Respectfully, David M. Gullott Manager Licensing Exelon Generation Company, LLC Attachments:
- 2) Response to Request for Additional Information NRC PRA RAI 4 cc: NRC Regional Administrator, Region III NRC Senior Resident Inspector, LaSalle County Station Illinois Emergency Management Agency Division of Nuclear Safety
ATTACHMENT 11111211111MM 14r
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Amnw ExeLon Generation RISK MANAGEMENT TEAM DOCUMENTATION NO. LS-LAR-09 REV: 1 PAGE 1 of 26 FTION: LaSalle County Station (LSCS)
UNIT(S) AFFECTED: 1 & 2 TITLE: RAI Response in Support of RI-ISI Relief Request No. 14R-01
SUMMARY
LSCS is pursuing an Inservice Inspection (ISI) Program relief request for continuation of the LaSalle Risk-Informed ISI (RI-ISI, or RISI) program for another 10 year interval.
The purpose of this document is to provide additional information (RAI 1 and RAI 3) regarding PRA model changes made post-peer review that are considered PRA Maintenance in accordance with ASME/ANS RA-Sa-2009, March 2009, "Standard for Level 111-arge Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications." and to provide explanations for delta (A) Core Damage Frequency (CDF) and A Large Early Release Frequency (LERF) (RAI 2). RAI 4 response is outside the scope of this support application. Rev. 1 addresses a submittal review comment associated with RAI 3.
This is a Category I Risk Management Document in accordance with ER-AA-600-1012 Risk Management Documentation Revision 13, which requires independent review and approval.
[ Review required after periodic update
[ X ) Internal RM Documentation [ ] External RM Documentation Electronic Calculation Data Files: NIA Method of Review: [ X J Detailed ( ] Alternate ( ] Review of External Document This RM documentation supersedes: LS-LAR-09 Rev. 0 Prepared by: Felipe Gonzalez J~f.~.-~..o*.-, 1 1119/17 (RAis 1 and 3) Print $ign Date Prepared by: Jahn E. Steinmetz I r Lt. / 11!9/17 (RAIs 1 and 3) Print ,/ Sign Date Prepared by: Wes Brinstield _ I N/A 1 N/A (RAI 1 Part 111) Print Sign Date Prepared by: David Bidwell t NIA 1 NIA (RAI 2) _- Print Sign Date Reviewed by: Joseph Renner N/A NIA (RAI 2) Print Sign Date Reviewed by: Grant Teagarden 2-<e~~~ ....~ 1 1119117 (RAIs 1 and 3) Pnnt Signer Date Reviewed by: Don Vanover J ~'~ '--"~` ~ I'`~~ ' -~1-~^- l 11/10/17 All Print Sign l Date Approved by: Eugene Kelly ~f I 111; 0117 All Print Sign Date LS-LAR-09 Rev. 1
LaSalle RI-ISl RAI Response RM DOCUMENTATION NO. LS-LAR-09 EV: 0 PAGE I of 25 STATION: LaSa,le County Station (LSCS)
UNIT(S) AFFECTED: 1 &.2 TITLE: RAI Response in Supraort of RI-ISI Relief Request No. 14R-01
SUMMARY
L.SCS is pursuing an Inservice Insoection (ISI) Program relief request for continuation of the LaSalle Risk-Informed ISI (RI-ISI. or RISI) program for another 10 year interval.
The purpose of this document ;s to provide additional information (RAI I and RAI 3) regarding PRA model changes made post-peer review that are considered PRA Mainterance, in accordance with ASME/ANS RA-Sa-2009. March 2009, 'Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Appliuitions,' and to provide explanations for delta (A) Core. Damage Frequency (CDF) and A Large Early Release Frequency (LERF) (RAI 2). RAI 4 response is outside the scope of this support application.
This Is a Category I Risk Management Document in accordance with ER-AA-600-1012 Risk Management Documentation Revision 13 whichlwmires independent review and approval.
Review required after periodic update X I Internal RM Documentation External RM Documentation Electronic Calculation Data Files: WA Method of Review , [ X I Detailed [ j Alternate f Review of External Document This RM documentation supersedes: N/A
'Of Prepared by: Felipe Gonzalez /,,-, 1 10/31/17 (RAls 1 and 3) Print jgn Date Prepared by: John E_ Steinmetz I 4-- ' 0/31/1?
, - I I JILL41 (RAls I and 3) _ - "rint Sign Date 4
Prepared by: Wes Brinsfield I 10131117 (RAI I Part 111) Print Date Prepared by: David Bid[well (RAI 2) Print Sii;n date r
Reviewed by: ptRenner 10!31/17 (RAI 2) Print Sign gate Reviewed by: Grant Tea garden,_ - - k, - / ._ 1 W31/17 (RAls I and 3) Print __sign_7_ ate Reviewed by: Don Vanover I b.V4a%,A*jt10_ tArift eft"63 All Print Sil Date Eugene M. Kelly"" 10/31/17 Approved by: ire Ketly StIn Date LS-LAR-09 Rev. 1
LaSalle RI-ISI RAI Response This support application provides a response to the NRC request for supplemental information below. This question was transmitted to EGC by letter dated October 12, 2017.
REQUEST FOR ADDITIONAL INFORMATION RELIEF REQUEST 14R-01, REQUESTS APPROVAL OF ALTERNATIVE RISK-INFORMED INSERVICE INSPECTION INTERVAL PROGRAM AND EXAMINATION CRITERIA FOR EXAMINATION CATEGORY 8-F, 8-J, AND C-F-2 PRESSURE RETAINING PIPING WELDS IN ACCORDANCE WITH ASME CODE CASE N-578-1, "RISK-INFORMED REQUIREMENTS FOR CLASS 1, 21 OR 3 PIPING, METHOD 13, SECTION XI, DIVISION 1."
LASALLE COUNTY STATION, UNITS 1 AND 2 (CAC NOS. MF9758 AND MF9759 By letter dated May 30, 2017 (Agency-wide Documents Access and Management System (ADAMS) Accession No. ML17150A449), as supplemented by letter dated July 20, 2017 (ADAMS ML17201Q396), Exelon Generation Company, LLC (the licensee), submitted its Fourth 10-Year Interval In-Service Inspection Program Relief Requests for LaSalle County Station, Units 1 and 2. In accordance with 10 CFR 50.55a(z)(1), the licensee is requesting relief on the basis that the proposed alternative utilizing Electric Power Research Institute (EPRI) Topical Report JR) 112657, "Revised Risk-Informed In-service Inspection Evaluation Procedure,"
Revision B-A (ADAMS No. ML013470102), along with two enhancements from ASME Code Case N-578-1, "Risk-Informed Requirements for Class 1, 2, or 3 Piping, Method B,Section XI",
will provide an acceptable level of quality and safety. To complete this review, the U.S. Nuclear Regulatory Commission (NRC) staff requests responses to the following questions:
Probabilistic Risk Assessment (PRA) RAI 1 - Logic Model Enhancement Identified as PRA Maintenance In the letter dated July 20, 2017, (ADAMS No. ML17201Q396), the licensee identified four changes to the PRA model as shown below. The licensee classified each change as PRA maintenance rather than a PRA upgrade with respect to the definitions provided in American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) RA-Sa-2009, "Addenda to ASME RA-S-2008 Standard for Level 1/1-arge Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications" (the PRA Standard). In order for the NRC staff to confirm that the changes qualified as maintenance as opposed to upgrades, provide the following:
I. 2011 PRA Model Change, "Deleted loss of bus 241Y and 242Y as initiating events and added loss of bus 241X, 242X and 251 as initiating events."
According to Section 1-A.3.5 of the PRA Standard, replacement of point estimates with system fault trees for support system initiators constitutes an upgrade, although this may be permitted as maintenance rather than upgrade if the contribution is not risk significant:
- a. Discuss whether the added initiating events were incorporated as point estimates or fault trees. If any were fault trees:
3 LS-LAR-09 Rev. 1
LaSafle M-0 RAI Response
- i. Discuss whether the initiator frequencies rose or fell after the incorporation of the fault trees and, if they did rise, describe whether they were risk-significant and provide an explanation of this fluctuation.
ii. Discuss whether any potential interactions with other systems were included in the PRA model (e.g., interactions to ensure that any Common Cause Failures (CCFs) have been addressed) and provide details of these interactions.
2011 PRA Model Change, "Created a new event tree for isolated Turbine Building and Auxiliary Building floods."
Provide the justification for citing the impact of this new event as "small".
III. 2011 PRA Model Change, "Converted the Human Reliability Analysis (HRA) calculations to the EPRI HRA Calculator software platform. The HRA Calculator was also used to facilitate the Human Error Probability (HEP) dependence analysis."
- a. In adopting the HRA Calculator, describe whether, the exact same methods, steps and sequence that were used in the pre-existing, manual HRA calculations were exactly mirrored when adopting the HRA Calculator (e.g., Human Cognitive Reliability (HCR)/Operator Reliability Experiments (ORE) Method (HCR/ORE) for the diagnostic phase, Technique for Human Error Rate Prediction (THERP) for the execution phase).
- b. Describe whether the independent review of the HRA was performed by an experienced HRA analyst who is not a licensee employee nor a contractor involved in the incorporation of the HRA Calculator, and provide a description of the analyst's professional profile.
IV. 2011 PRA Model Change, "The fault trees related to recovery of alternating current (AC) power in the intermediate timeframe were enhanced by modifying the gate names and descriptors to clarify that the intermediate timeframe is 2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />.
Also, the conditional probability that the battery fails was changed and was or'ed [OR Gated] with the operator action to load shed."
- a. Explain why clarification was needed regarding the "intermediate timeframe is 2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />." Describe whether the intermediate timeframe in the PRA model was changed to "2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />" from some other values, and provide justification, as necessary, to support a change in timeframe.
- b. Describe whether this change is comparable to example I-A.3.13 (Revised Modeling of Station Blackout) in the PRA standard and if so, explain why this change is considered maintenance as opposed to an upgrade.
4 LS-LAR-09 Rev. 1
PRA RAI 2 - Evaluation of the Change in Risk In Attachment 1 to the letter dated May 30, 2017 (ADAMS Accession No. ML17150A449), the licensee provided tables on pages 4 through 6 for delta (A) Core Damage Frequency (CDF) and A Large Early Release Frequency (LERF).
I. Table page 4, "Change in Risk from LaSalle County Station Pre-RI [risk informed]-ISI Section XI Program to Fourth Interval RI-ISI Program," explain why both A CDF and A LERF are roughly equivalent for each unit, since LERF is typically at least an order of magnitude lower than CDF.
II. Table on page 5, "LaSalle County Station Unit 1 Delta-CDF and Delta-LERF by System," explain why the values appear to have roughly equal A CDFs and A LERFs for the feed water, main steam, reactor core isolation cooling and reactor water cleanup systems.
Ill. Table on page 5,"LaSalle County Station Unit 1 Break Exclusion Region (BER)
Weld Delta-CDF and Delta-LERF by System," explain why the A CDF and A LERF values for the emergency core cooling system (ECCS) are negative (implying a decrease)?
IV. Table on page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System"", explain why the value for A LERF for the ECCS system is negative.
V. Table on page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System" for both the ECCS and high pressure core spray (HPCS) systems, explain why there is an increase (or decrease) for A CDF and the opposite trend for A LERF.
VI. With respect to the ECCS:
- a. Explain why the A CDF is positive as shown in the table on page 6 "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System" while the A CDF is negative as shown in the table on page 6 "LaSalle County Station Unit 2 BER Weld Delta-CDF and Delta-LERF by System."
- b. Explain why the A LERF is greater in magnitude as shown in the table on page 6 "LaSalle County Station Unit 2 BER Weld Delta-CDF and Delta-LERF by System" than the A LERF shown in the table on page 6 "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System."
VII. With respect to the HPCS, explain why the A CDF is negative in the table on page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System"' while the A CDF for the BER welds is positive as shown in the table on page 6, "LaSalle County Station Unit 2 BER Weld Delta-CDF and Delta-LERF by System ".
LS-LAR-09 Rev. 1
LaSaft RU-0 RAC Response In the letter dated July 20, 2017, (ADAMS Accession No. ML17201Q396), both SR DA-C6 and DA-C10 state similar conclusions including:
"The plant data sources and developed demand estimates, however, are judged to be reasonable to support the PRA. Pursuing plant demand data per the explicit direction in the SR is not expected to result in significant impacts upon the PRA results. Therefore, DA-C6 is being self-assess as "Not Met" is not judged to impact this application."
Provide the justification for SRs that are not expected to result in significant impacts to the PRA. Explain whether the data sources align with the four listed as acceptable in SR DA-C6.
PRA RAD 4 - Safety Significance of Piping Segments Based on the information provided, the NRC staff could not determine whether the licensee reviewed the safety significance of the piping segments subject to inspection to ascertain whether there should be any changes in inspection locations for this fourth interval. Discuss whether there were any changes and, if so, explain the basis for those changes.
RAI 4 will be addressed outside of this support application.
For ease of review the responses to RAI 1, 2 and 3 below will be prefaced with the applicable NRC request for additional information.
6 LS-L.AR-09 Rev. 1
LaSalle RI-ISI RAI Response RAI 1 - Logic Model Enhancement identified as PRA Maintenance In the letter dated July 20, 2017, (ADAMS No. ML17201Q396), the licensee identified four changes to the PRA model as shown below. The licensee classified each change as PRA maintenance rather than a PRA upgrade with respect to the definitions provided in American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) RA-Sa-2009, "Addenda to ASME RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications" (the PRA Standard). In order for the NRC staff to confirm that the changes qualified as maintenance as opposed to upgrades, provide the following:
RAC Question RAI 1 Part I. 2011 PRA Model Change, "Deleted loss of bus 241Y and 242Y as initiating events and added loss of bus 241X, 242X and 251 as initiating events."
According to Section 1-A.3.5 of the PRA Standard, replacement of point estimates with system fault trees for support system initiators constitutes an upgrade, although this may be permitted as maintenance rather than upgrade if the contribution is not risk significant:
- a. Discuss whether the added initiating events were incorporated as point estimates or fault trees. If any were fault trees-
- i. Discuss whether the initiator frequencies rose or fell after the incorporation of the fault trees and, if they did rise, describe whether they were risk-significant and provide an explanation of this fluctuation.
ii. Discuss whether any potential interactions with other systems were included in the PRA model (e.g., interactions to ensure that any Common Cause Failures (CCFs) have been addressed) and provide details of these interactions.
Response to RAI 1 Part I a.
Bus 241X, 242X and 251 initiating events were added as point estimates. As noted in RAI question I.a, additional discussion is only required if the added initiation events were fault trees.
As these events are not fault trees, further discussion in response to Parts I.a.i and I.a.ii is not required.
[CAI Question RAI 1 Part II
- 11. 2011 PRA Model Change, "Created a new event tree for isolated Turbine Building and Auxiliary Building floods."
Provide the justification for citing the impact of this new event as "small".
- Response to RAI 1 Part II The internal flood damage state scenarios are transferred into one of the following three internal flood accident sequence event tree structures:
LS LAR-09 Rev. 1
f' 0 - 1 ., ..
~: 1 ~,,~
Isolated RB Flood Unisolated TB/RB Flood Isolated TB Flood The third event tree structure listed above (Isolated TB Flood) is used for Turbine Building and Auxiliary Building (AB) internal flood scenarios that are terminated prior to propagation into the Reactor Building (i.e., the effects of these floods are confined to TB or AB equipment). There are two TB flood event tree sequences that appear in the 2014 PRA Model of Record base CDF results. The sequence basic event tags shown in the table below are used to show the Fussell-Vesely (FV) contribution. The total FV is less than 0.0047. As noted in Regulatory Guide 1.174, Revision 2, "The PSA Applications Guide suggested values of Fussell-Vesely importance of 0.05 at the system level and 0.005 at the component level." The event tree logic represents failures (leaks) from multiple components. The system level guidance threshold is therefore, more appropriate for event tree importance. The total result is an order of magnitude less than the system level FV importance of 0.05. Therefore, this contribution is considered "small".
It should also be noted, that flood initiating event contributions are not included in RI-ISI calculations. Therefore, this model change does not impact RI-ISI results.
FUSSELL-BASIC EVENT VESELY RAW DESCRIPTION ACCIDENT SEQUENCE TBFLD-005 RCVSEQ-TBFLD-005 5.7E-04 1.0 MARKER ACCIDENT SEQUENCE TBFLD-017 RCVSEQ-TBFLD-017 4.1 E-03 1.0 MARKER TOTAL FUSSELL-VESELY 4.7E-03 RAI Question RAI 1 Part III III. 2011 PRA Model Change, "Converted the Human Reliability Analysis (HRA) calculations to the EPRI HRA Calculator software platform. The HRA Calculator was also used to facilitate the Human Error Probability (HEP) dependence analysis."
- a. In adopting the HRA Calculator, describe whether, the exact same methods, steps and sequence that were used in the pre-existing, manual HRA calculations were exactly mirrored when adopting the HRA Calculator (e.g., Human Cognitive Reliability (HCR)/Operator Reliability Experiments (ORE) Method (HCR/ORE) for the diagnostic phase, Technique for Human Error Rate Prediction (THERP) for the execution phase).
- b. Describe whether the independent review of the HRA was performed by an experienced HRA analyst who is not a licensee employee nor a contractor involved in the incorporation of the HRA Calculator, and provide a description of the analyst's professional profile.
LS-LAR-09 Rev. 1
LaSalle RMS1 RAL, ~ Response Response to RAI 1 Part III Response to Part a:
The following provides an overview of the process used by the independent reviewer to determine if conversion to the HRA Calculator was maintenance or an upgrade, and addresses specifically whether a change in methods, steps and sequence were made.
As a first step in the review, the independent reviewer compared the 2011 HRA documentation with the previous (2006) documentation, focusing on the HRA methods described as used when developing human error probabilities (HEPs) for the human failure events (HFEs). The 2006 and 2011 HRA documents described the same methods, in 2006, those methods were performed manually, while in 2011 they were implemented using the HRA Calculator (HRAC) tool. This was confirmed by a review of individual calculations for pre-initiator and post-initiator HEPs. This was confirmed by a review of individual calculations for pre-initiator and post-initiator HEPs.
The summary screen of the HRAC tool highlights the method selected to perform the HRA for each HFE included in the HRAC database. Thus, the next step performed by the independent reviewer was to review the HRAC summary screen to verify that the methods described as being used to complete the 2011 HRAs for the individual HFEs were as included in the HRA documentation. This review verified the methods documented for 2011 match the methods selected in the HRAC.
Additionally, the methods used, and HEPs generated, for risk-significant pre- and post-initiator human failure events for 2011 were compared to the pre- and post-initiator HFEs in the 2006 analysis. Here, a risk-significant event is defined as any event that has a Fussell-Vesely (F-V) importance measure greater than or equal to 0.005 (i.e., 0.5%),
and/or a risk achievement worth (RA\N) importance measure greater than or equal to 2.0. The results of the comparisons are included in Table 1 for Post-initiators and Table 2 for Pre-initiators.
As a result of these comparisons and reviews, it was concluded that the use of the HRA Calculator in the 2011 PRA update was not a change in methodologies, but rather the use of a tool that provides efficiencies in the application of and documentation of methods employed in the 2006 PRA, and whose use was continued in the 2011 PRA update. Calculations of HEPs, and the determination of dependency levels and dependent HEPs, utilize the same methods and techniques in the 2006 and 2011 PRA updates. Differences in HEPs can be attributed to refinements and updates to the information used to generate the values; the differences are not due to changes in methodologies, i.e., the methods are the same.
9 LS-LAR-09 Rev. 1
LaSalle RI-ISI RAI Response TABLE I COrifiPARISON OF POST-INITIATOR H CAS, 2011 VS. 2006 ASME/ANS 2011 2011 2006 RA-SA-2009 HFE BASIC EVENT ID DESCRIPTION 2011 F-V RAW 2011 HEP 2006 HEP METHOD METHOD COMMENT ON HEPS EXAMPLE 2P.1SOPl`.1SIVINLKH-- HEP: 5.16E-02 1.02 7.00E-01 9.95E-01 ASEP and ASEP and In 2006, the time available 23 PRA OPERATOR Cause- Cause- and time required were Maintenance FAILS TO based; based; essentially the same, with (simulator BYPASS LOW THERP THERP only a small windo.v for observations)
LEVEL LISIV success. This resulted in the INTERLOCK high ASEP HEP. In 2011, additional analyses and simulator observation provided justification for a slightly larger margin bet :,een time available and time required, such that the ASEP
_ contribution reduced slightly.
2CVOPVEN f----H-- HEP: 4.66E-02 8.01 6.60E-03 9.10E-03 ASEP and ASEP and Time available increased in 23 PRA OPERATOR Cause- Cause- 2011 due to refined P1AAP Maintenance FAILS TO based, based; analyses. This reduced (refined supporting INITIATE THERP THERP dependency/stress analysis)
PRIPJARY (1) multipliers, reducing Cognitive CONTAINP.iEN and Execution HEPs. ASEP T VENTING contribution not considered for long time frame actions (refinement as a result of HEP consistency check).
2CVOP-VNTCNT-H-- HEP 3.52E-02 1.45 7.20E-02 7.98E-02 ASEP and ASEP and Slight adjustments to timing 23 PRA OPERATOR Cause- Cause- and credit in caused based Maintenance FAILS TO based; based; analysis. (refined supporting CONTROL THERP THERP analysis)
VENT WITHIN PROCEDURAL IZED PRESSURE BAND _
BWTOPWTHXSTBYH-- HEP: OP FAILS 2.64E-02 1 1.00E+00 1.00E+00 ASEP and ASEP and Insufficient time to complete N/A no change TO ALIGN Cause- Cause- action.
STANDBY based; based; TBCCW HX THERP THERP TRAIN L 10 LS-LAR-09 Rev. 1
11111113 11111 11
>. ASME/ANS 2011 2011 2006 RA-SA-2009 HFE BASIC EVENT ID _DESCRI17TION 2011 F-V RAW 2011 HEP 2006 HEP METHOD METHOD COMMENT ON HEPS EXAMPLE 2SLOP-LVLC I RLH-- HEP: 2.44E-02 1.07 2.70E-01 1.15E-01 ASEP and ASEP and In 2006, the time required to 23 PRA OPERATOR Cause- Cause- complete the action was lover Maintenance FAILS TO based; based; than the time required in the (simulator LOWER LEVEL THERP THERP 2011 calculation (time observations)
EARLY (ATWS) changed in 2011 analysis based on simulator observations). As a result, the ASEP contribution to the HEP increased in 2011.
2ADOP-FW--AT-Hr- HEP: 1.87E-02 1.67 2.70E-02 2.00E-02 ASEP and ASEP and Slightly more conservative 23 PRA OPERATOR Cause- Cause- assumptions regarding r.laintenance FAILS TO based; based; cognitive and execution (refined supporting riANUALLY THERP THERP recovery were used in 2011. analysis)
DEPRESSURIZ E THE RPV -
ATWS (FW AVAILABLE 2HDOP-HD-ERLYH-- HEP: 1.57E-02 1 1.00E+00 1.00E+00 ASEP and ASEP and Insufficient time to complete N/A no change OPERATOR Cause- Cause- action.
FAILS TO based; based; ALIGN THERP THERP HEATER DRAIN FOR INJECTION (EARLY TIME FRAMIE 2FPOPr.1ANTRIP1 H-- HEP: 1.51 E-02 1.02 4.10E-01 1.00E+00 ASEP and ASEP and Different (less conservative) 23 PRA OPERATOR Cause- Cause- estimate of delay time in 2011 Maintenance FAILS TO TRIP based; based; results in more time available (refined supporting FPS FOR FPS THERP THERP to complete action. analysis)
BREAK (SHORT TIPJE FRAr.1E) 11 LS-LAR-09 Rev. 1
LaSalle RI-ISI RAI Response TABLE 1 COMIPARISON OF POST-INITIATOR HFES, 2011 VS. 2006 ASME/ANS 2011 2011 2006 RA-SA-2009 HFE BASIC EVENT ID DESCRIPTION 2011 F-V RAW 2011 HEP 2006 HEP METHOD METHOD COMMENT ON HEPS EXAMPLE 2ADOPRPVLEVELH-- HEP: 1.32E-02 1.72 1.80E-02 1.70E-02 ASEP and ASEP and Slight differences in 23 PRA OPERATOR Cause- Cause- assumptions regarding Maintenance CONTROLS based; based; cognitive and execution (refined supporting RPV LEVEL THERP THERP recovery were used in 2011. analysis)
TOO LOW (LOW PRESSURE-ATWS 2DCOPRCIC-LS-H-- HEP: 9.29E-03 1.17 5.20E-02 4.00E-02 ASEP and ASEP and Slight change in calculation of 23 PRA OPERATOR Cause- Cause- ASEP value in 2011. Maintenance FAILS TO based; based; (refined supporting SHED 125 VDC THERP THERP analysis)
NON ESSENTIAL LOADS 2ADOP-ADS-AT-H-- HEP: 8.95E-03 1.04 1.80E-01 1.20E-01 ASEP and ASEP and Slight differences in 23 PRA OPERATOR Cause- Cause- assumptions regarding Maintenance FAILS TO based; based; cognitive and execution (refined supporting MANUALLY THERP THERP recovery were used in 2011. analysis)
DEPRESSURIZ E THE RPV-ATWS (NO FW AVAIL) 2FPOPALGNFPSAH-- HEP: 8.43E-03 1.16 5.20E-02 6.07E-02 ASEP and ASEP and Treatment of errors of 23 PRA OPERATOR Cause- Cause- commission explicitly included Maintenance FAILS TO based; based; in Execution HEP in 2011, (refined supporting ALIGN FPS THERP THERP replacing estimate made in analysis)
FOLLOWING (1) 2006. Results in some CONTAINMEN reduction in that contribution T VENT OR to overall HEP. ASEP FAILURE contribution not considered for long time frame actions (refinement as a result of HEP consistency check).
12 LS-LAR-09 Rev. 1
LaSalle RI-ISI RAI Response TABLE COMPARGZ-DON OF POST-INITIATOR HFES, 2011 VS. 2006 ASN1E/ANS 2011 2011 2006 RA-SA-2009 HFE BASIC EVENT ID DESCRIPTION 2011 F-V RAW 2011 HEP 2006 HEP METHOD METHOD COMMENT ON HEPS EXAMPLE 2FWOPP. OV10AB-H-- HEP: 7.63E-03 1.17 4.20E-02 6.10E-02 ASEP and ASEP and More precise calculation of 23 PRA OPERATOR Cause- Cause- ASEP HEP in 2011, results in Maintenance FAILS TO based; based; some reduction in that (refined supporting CLOSE THE THERP THERP contribution to overall HEP. analysis)
TDRFP DISCHARGE M.OVS 2FW010A & B 2SLOP-IN-ERLYH-- HEP: 7.36E-03 1.08 8.50E-02 8.85E-02 ASEP and ASEP and Essentially the same HEPs; 23 PRA OPERATOR Cause- Cause- minor differences in Maintenance FAILS TO based; based; assumptions used. (refined supporting INITIATE SBLC THERP THERP analysis)
EARLY 2SLOPLATLVL'I i H-- HEP: 6.32E-03 1.19 3.30E-02 7.90E-03 ASEP and ASEP and Different (increased) 23 PRA OPERATOR Cause- Cause- manipulation time in 2011 Maintenance FAILS TO based; based; based on simulator (simulator CONTROL THERP THERP observation and nevi hard observations)
LEVEL LATE IN card.
TURBINE TRIP ATWS 2HDOP-H'1 R-DRNH-- HEP: 6.04E-03 1.02 4.10E-01 1.50E-01 ASEP and ASEP and More precise calculation of 23 PRA OPERATOR Cause- Cause- execution steps in 2011, Maintenance FAILS TO based; based; results in some increase in (refined supporting ALIGN THERP THERP that contribution to overall analysis)
HEATER I (1) HEP. ASEP contribution not DRAIN considered for long time DURING DBA frame actions (refinement as LOCA a result of HEP consistency
_ check).
2RHOPSPCINIT-H-- HEP: 4.38E-03 20.05 2.3E-04 1.6E-04 ASEP and ASEP and Cause-based HEP more 23 PRA OPERATOR Cause- Cause- conservative in 2011. ASEP Maintenance FAILS TO based; based; contribution not considered (refined supporting INITIATE THERP THERP for long time frame actions analysis)
SUPPRESSIO (1) (refinement as a result of HEP N POOL consistency check).
COOLING I ANON-ATWS -- f 1 -
13 LS-LAR-09 Rev. 1
LaSalle Ill-ISI RAI Response r
MihPARISON OF POST-INITIATOR HFES, 2011 VS. 2006 ASPJIE/ANS 2011 2011 2006 RA-SA-2009 HFE E3d^%SIC EVEi- 4T iD DESCRIPTION 2011 F -V RAW 2011 HEP 2006 HEP METHOD METHOD COMMENT ON REPS EXAMPLE 2SYOPDGB-VLV3H-- HEP: 2.04E-03 3.95 6.90E-04 1.9E-03 ASEP and ASEP and Longer time allo ved in 2011 23 PRA OPERATOR Cause- Cause- based on walkdo:*:n and Maintenance FAILS TO based; based; calculation information; ASEP (refined supporting CLOSE LOCAL THERP THERP contribution not considered analysis)
ISOLATION (1) for long time frame actions VALVE IN (refinement as a result of HEP CSCS ROO1 1 consistency check). Cause-(LONG based contribution is lo,..er in TIMEFRAME) 2011 calculation.
2SYOPALLCSCS2H-- HEP: 4.54E-04 2.97 2.30E-04 1.8E-03 ASEP and ASEP and More credit for recovery (STA, 23 PRA OPERATOR Cause- Cause- etc.) in cause-based HEP in Maintenance FAILS TO TRIP based; based; 2011. ASEP contribution not (refined supporting ALL SITE CSC THERP THERP considered for long time analysis)
GIVEN CSCS (1) frame actions (refinement as BREAK (LONG a result of HEP consistency TIME FRAME) check).
2SYOPTRPCSCS2H-- HEP: 1.46E-04 2.04 1.40E-04 9.4E-04 ASEP and ASEP and More credit for recovery (STA, 23 PRA OPERATOR Cause- Cause- etc.) in cause-based HEP in f.laintenance FAILS TO TRIP based; based; 2011. ASEP contribution not (refined supporting AFFECTED THERP THERP considered for long time analysis)
CSCS PUMP (1) frame actions (refinement as FOR BREAK IN a result of HEP consistency RB (LONG check).
_ TERrJ 2FPOPMANTRIP3H-- HEP: 3.67E-04 2.02 3.60E-04 1.3E-04 ASEP and ASEP and 2006 calculation applies a 23 PRA OPERATOR Cause- Cause- recovery factor "Given the Maintenance FAILS TO TRIP based; based; very long time frame (refined supporting FPS FOR FPS THERP THERP involved..."; this recovery analysis)
BREAK (1) factor is not applied in the (EXTENDED 2011 calculation.
TIME FRAI'.1E Mote to Table 1:
In 2011, to respond to peer revie.i comments, a consistency check of HEPs v.,as performed. As a result, the use of ASEP remained in the HRA methodology, but its contribution
- as minimized for long time frarne actions. Therefore, although considered as part of the overall calculation, the method selected for 2011 is listed in 2011 documentation as
°CBDUNTHERP", v:;th no ASEP contribution to the final HEP. The overall approach is the same bet.%een 2011 and 2006, i.e., ASEP, CBDTf.1, and THERP are all considered, but their conbibutions to individual HEPs may vary.
14 LS-LAR-09 Rev. 1
TABLE 2 R E-MMATORS e MiiPARISON OF HFES, 2011 VS. 2006 ASME/ANS RA-2011 2011 2011 2006 SA-2009 DESCRIPTION 2011 F-V RAW HEP 2006 HEP METHOD METHOD COMMENT ON REPS EXAMPLE
_ HFE BASIC EVENT ID BDGHUCDGO --- H-- PRE-HEP: 1.25E-02 2.55 8.00E-03 N/A ASEP N/A Nevi HFE, added for 20 additional OPERATOR 2011 HFEs added for P.;ISALIGNS 0 DG improved modeling
_ SPEED DROOP _
2HCHUF038 ---- H-- PRE-HEP: 1.22E-02 2.51 8.00E-03 N/A ASEP N/A Nei HFE, added for 20 additional OPERATOR 2011 HFEs added for MISALIGNS improved modeling HPCS AND LEAVES 2E22-F038 CLOSED AFTER MAINT 2DGHUCSDG2AFLH-- PRE-HEP: 6.37E-03 8.96 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance FAILS TO calculation (refined supporting RESTORE analysis)
RESTORE 2A DG STRAINER 2DG01 F BDGHUCSTRN2A-11-- PRE-HEP: 6.37E-03 8.96 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance LIISALIGNS 2A calculation (refined supporting DC COOLING analysis)
WATER TRAIN tJANUAL VALVES 2VYHUSER00%1 . H-- PRE-HEP: 6.34E-03 8.92 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR I conservative in 2011 Maintenance MISALIGNS i calculation (refined supporting CSCS COOLING analysis)
WATER MANUAL VALVES TO SE CORNER ROO,.1 2DGI IUCDG2B --- H-- PRE-HEP: 5.20E-03 1.64 8.00E-03 N/A ASEP N/A N& HFE, added for 20 additional OPERATOR 2011 HFEs added for r1ISALIGNS 213 improved modeling DG SPEED DROOP 15 LS-LAR-09 Rev. 1
LaSalle RHSI RAI Response ASME/ANS RA-2011 2011 2011 2006 SA-2009 HFE BASIC EVENT ID DESCRIPTION 2011 F-V RAW HEP 2006 HEP METHOD METHOD COMMENT ON REPS EXAMPLE 2RHHURHRF98B-H-- PRE-HEP: 4.64E-03 6.79 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance r111SALIGNS RHR calculation (refined supporting SYSTEM AND analysis)
LEAVES 2E12-F098B CLOSED AFTER PJAINT.
2RS1 iUCSCD300BH-- PRE-HEP: 4.64E-03 6.79 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance FAILS TO calculation (refined supporting RESTORE analysis)
STRAINER (2E12-D30013) AFTER MAINTENANCE 2RSHU-RHRSWCDH-- PRE-HEP: 4.64E-03 6.79 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 r1aintenance t-411SALIGNS calculation (refined supporting TRAIN B RHR analysis)
SERVICE WATER BDGHUCSODG01 FH- - PRE-HEP: 4.11 E-03 6.14 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance FAILS TO calculation (refined supporting RESTORE analysis)
RESTORE 0 DG STRAINER (ODG01 F) AFTER MAINT.
BDGHUCSTRNOA-H-- PRE-HEP: 4.11 E-03 6.14 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 PJaintenance MISALIGNS 0 DG calculation (refined supporting COOLING analysis)
WATER TRAIN P41ANUAL VALVES 16 LS-LAR-09 Rev. 1
U it E-N 1f A OkS COu DAMSON OF HFES, 2011 VS. 2006 e
ASME/ANS RA-2011 2011 2011 2006 SA-2009 Hk=E BASi% LVENT ID DESCRIPTION 2011 F-V RAW HEP 2006 HEP METHOD METHOD COI'0MENT ON HEPS EXAMPLE 2RHHURHRF98A-H-- PRE-HEP: 3.38E-03 5.22 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance PiISALIGNS RHR calculation (refined supporting SYSTEM AND analysis)
LEAVES 2E12-F098A CLOSED AFTER MAINT.
2RSHUCSRSTRE-H-- PRE-HEP: 3.38E--03 5.22 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance FAILS TO calculation (refined supporting RESTORE analysis)
STRAINER (2E12-D300A) AFTER MAINTENANCE 2RSHU-RHRSWABH-- PRE-HEP: 3.38E-03 5.22 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance UIISALIGNS calculation (refined supporting TRAIN A RHR analysis)
SERVICE WATER 2VYHUNWR00%1 1--H-- PRE-HEP: 3.38E-03 5.22 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance MISALIGNS calculation (refined supporting CSCS COOLING analysis)
WATER P41ANUAL VALVES TO NW CORNER ROOM BDGHUCLDGO--H-- PRE-HEP: 2.12E-03 2.25 1.70E-03 #N/A ASEP N/A Nevj HFE, added for 20 additional OPERATOR 2011 HFEs added for I'AISCALIBRATION improved modeling OF0DGDAY TANK LEVEL SENSOR 17 LS-LAR-09 Rev. 1
11,111 _ 5 ASPUIE/ANS RA-2011 2011 2011 2006 SA-2009 FIFE BASIC EVENT ID DESCRIPTION 2011 F-V RAW HEP 2006 HEP METHOD METHOD COMMENT ON HEPS EXAMPLE 2DGHUCS22D300H-- PRE-HEP: 8.98E-04 2.12 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance FAILS TO calculation (refined supporting RESTORE analysis)
RESTORE 2B DG STRAINER (2E22-D300 2VYHUSWROO%1--H-- PRE-HEP: 8.98E-04 2.12 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance L11SALIGNS calculation (refined supporting CSCS COOLING analysis)
WATER MANUAL VALVES TO SW CORNER ROOI`.1 BDGHUCS T RN2B-H-- PRE-HEP: 8.98E-04 2.12 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance MISALIGNS 2B calculation (refined supporting DG COOLING analysis)
WATER TRAIN MANUAL VALVES BDGHUCSDGO --- H PRE-HEP: 8.24E-04 2.03 8.00E-04 9.00E-05 ASEP ASEP ASEP recovery more 23 PRA OPERATOR conservative in 2011 Maintenance LIISALIGNS 0 DG calculation (refined supporting COOLING analysis)
WATER SUPPLY TO DG 18 LS-LAR-09 Rev. 1
W P The independent reviewer was neither an employee nor contractor of the licensee when the LaSalle HRA was incorporated into the HRA Calculator in 2011. The analyst's professional profile is summarized below.
Over 35 years of nuclear power PRA experience Managed, participated in, or served as an independent reviewer for several PRA projects (including all aspects of HRA), focusing on the use of risk assessment techniques to address utility operations, safety, plant design, and regulatory issues Member of EPRI HRA Users Group Reviewer/tester of HRA Calculator software Co-author, EPRI report on HRA Dependency Analysis (in preparation)
Mission expert/lecturer (including on the subject of HRA), for International Atomic Energy Agency-sponsored missions for PSA applications, in multiple countries Exelon Qualified for Risk Management Concepts, FPIE PRA Model Interpretation, PRA Update, Risk Management Applications, and Fire External Events IV. 2011 PRA Model Change, "The fault trees related to recovery of alternating current (AC) power in the intermediate timeframe were enhanced by modifying the gate names and descriptors to clarify that the intermediate timeframe is 2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />.
Also, the conditional probability that the battery fails was changed and was or'ed [OR Gated] with the operator action to load shed."
- a. Explain why clarification was needed regarding the "intermediate timeframe is 2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />." Describe whether the intermediate timeframe in the PRA model was changed to "2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />" from some other values, and provide justification as necessary to support a change in timeframe.
- b. Describe whether this change is comparable to example I-A.3.13 (Revised Modeling of Station Blackout) in the PRA standard and if so explain why this change is considered maintenance as opposed to an upgrade.
WaTkWITA
[Response to Part a:
The clarification "intermediate timeframe is 2 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />" was made to facilitate the use of the PRA model only and was not required to correct logic errors or change methodology. The fault trees related to recovery of AC power in the intermediate timeframe were enhanced by modifying the gate names and descriptors to facilitate future use of the PRA model. A review of event tree logic found no structural changes between the peer reviewed PRA model and the 2011 PRA model updates related to this clarification change. The logic structure remained unchanged. The time frames for AC power recovery were related to 125 VDC battery life and load shed in support of RCIC operation. Both the peer reviewed PRA model and 2011 PRA models reflect 125 VDC 19 LS-LAR-09 Rev. 1
battery life of 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> with load shed and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> without load shed. The battery life assumptions did not change from the 2006C peer reviewed PRA model and the 2011 update. AC power recovery continued to be incorporated in fault tree logic in the 2011 update.
As noted in the previous supplemental information request response (letter RS-17-102 from David M. Gullott, EGC LLC to US NRC dated May 30, 2017, ADAMS No.
ML17201Q396), a change was made related to an operator action to load shed. This operator action was from below the RCIC "SBO" logic gate where it was located in the 2006C PRA model, to below a battery gate in the 2011 PRA model. However, the impact to the affected event tree sequences was the same.
In summary, the 2011 PRA model changes made in the fault trees related to recovery of alternating current (AC) power did not effectively change the logic as confirmed in the quantification results. Cutsets and cutset frequencies were not impacted by these changes. Therefore, it is appropriate to classify this change as a model enhancement, and no new methodology was employed compared to the prior model.
PRA Standard Example 1-A.3.13 (Example 13) involves Loss of Offsite Power event tree changes and changes being handled by fault tree logic rather than post quantification techniques. In discussing this example, the PRA Standard includes a rationale of "this change represents a fairly extensive model structure / logic change." In comparison, the LaSalle changes were not extensive but were primarily descriptive. The event tree structure remained the same. AC power recovery was handled with fault tree PRA modeling for both the peer reviewed PRA model and subsequent PRA model updates (2011 and 2014). Therefore, the LaSalle change is not comparable to Example 13 of the standard, and a classification of PRA Maintenance is justified.
20 LS-LAR-09 Rev. 1
LaSalle RI-ISI RAI Response PRA RAI 2 - Evaluation of the Change in Risk In Attachment 1 to the letter dated May 30, 2017 (ADAMS Accession No. ML17150A449), the licensee provided tables on pages 4 through 6 for delta (0) Core Damage Frequency (CDF) and 4 Large Early Release Frequency (LERF).
I. Table - page 4, "Change in Risk from LaSalle County Station Pre-RI [risk informed]-ISI Section XI Program to Fourth Interval RI-ISI Program", explain why both 0 CDF and 0 LERF are roughly equivalent for each unit, since LERF is typically at least an order of magnitude lower than CDF.
Response to RAI 2 Part I The delta-CDF and delta-LERF results are roughly the same because the dominant, contributing consequence of a pipe break for delta-CDF is containment bypass events such as breaks in the break exclusion region (BER) piping at LaSalle. Since the accident sequences bypass containment the delta-LERF contribution is identical to the delta-CDF contribution. Numerically for Unit 1, the top 32 highest delta-CDF welds contribute 5.1E-9 to the Unit 1 total while also contributing the same amount, 5.1 E-9 to the delta-LERF total.
The same reasons apply for Unit 2. Of the top 36 highest contributing welds to delta-CDF, 28 welds have the same delta-LERF because of the associated containment bypass scenario. These top 36 welds contribute 6.2E-9 to delta-CDF and 5.7E-9 to delta-LERF.
Note that there was a typo in table on page 4 of the Attachment to the relief request for Unit 2 delta-CDF. The value should be 6.31 E-09 which is consistent with the data table on page 6.
DELTA-UNIT DELTA-CDF LERF Unit 1 5.26E-09 4.34E-09 Unit 2 6.31 E-09 4.94E-09 RAI (question RAI 2 Part II II. Table - page 5, "LaSalle County Station Unit 1 Delta-CDF and Delta-LERF by System," explain why the values appear to have roughly equal 0 CDFs and A LERFs for the feed water, main steam, reactor core isolation cooling and reactor water cleanup systems.
Response to RAI 2 Part II Each system will be addressed separately.
Feedwater: Like the response to RAI 2.1, the reason delta-CDF and delta-LERF results are roughly the same is because the dominant consequences are bypass scenarios, i.e. break in BER piping or large LOCA - steam. For feedwater, the three 21 LS-LAR-09 Rev. 1
highest delta-CDF consequences have the same identical contribution to delta-LERF and their sum is 1.6E-09. The next welds begin to contribute much less to both delta-CDF and delta-LERF.
Main Steam: Like the response to RAI 2.1, the reason delta-CDF and delta-LERF results are roughly the same is because the dominant consequence is a bypass scenario, i.e. main steam line break and failure to isolate. For Main Steam, the six highest delta-CDF consequences have the same identical contribution to delta-LERF and their sum is 1.0E-09. The next welds begin to contribute much less to both delta-CDF and delta-LERF.
Reactor Core Isolation Cooling: Like the response to RAI 2.1, the reason delta-CDF and delta-LERF results are roughly the same is because the dominant consequences are bypass scenarios, i.e. injection line breaks with failure to isolate.
For RCIC, the 19 of the 20 highest delta-CDF consequences have the same identical contribution to delta-LERF and their sum is 5.2E-10.
Reactor Water Cleanup: Like the response to RAI 2.1, the reason delta-CDF and delta-LERF results are roughly the same is because the dominant consequence is a bypass scenario, i.e. piping rupture with failure to isolate. For RWCU, the three highest delta-CDF consequences have the same identical contribution to delta-LERF and their sum is 1.5E-09. The next welds begin to contribute much less to both delta-CDF and delta-LERF.
RAI Question RAI 2 Part III Ill. Table - page 5,"LaSalle County Station Unit 1 Break Exclusion Region (BER)
Weld Delta-CDF and Delta-LERF by System," explain why the 0 CDF and 0 LERF values for the Emergency Core Cooling System (ECCS) are negative (implying a decrease)?
Response to RAI 2 Dart III A weld can have a negative delta-risk, or risk improvement for two reasons. First, if the weld is selected for inspection and was not previously inspected under the previous ASME Section XI program. Secondly a risk improvement can also occur if the RI-ISI inspection has a greater probability of weld flaw detection (POD) than the traditional ASME Section XI inspection, see equation 3-9 in EPRI TR-112657. For ECCS there are 77 BER welds, two of which have damage mechanisms (Erosion-Corrosion) that have improved probability of detection in the RI-ISI weld inspection.
The welds also have high PRA consequence risk as well as constituting a containment bypass. Selecting these two welds for inspection yields a risk improvement of -4.7E-10 for delta-CDF and delta-LERF. The remainder of the ECCS BER welds contribute 1.9E-10 making the sum -2.8E-10 for delta-CDF and delta-LERF CAI Question RAI 2 Dart IV IV. Table - page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System," explain why the value for 0 LERF for the ECCS system is negative.
22 LS-LAR-09 Rev. 1
11-011 I ,1 ]~ L* G Response to RAI 2 Part IV The answer is similar to question III above and involves the large risk-benefit from selecting welds with high PRA consequence that have improved POD under an RI-ISI weld examination. There are ten ECCS welds selected for inspection that are either were not previously selected for inspection under the previous ASME Section XI program, or have damage mechanisms with improved POD under RI-ISI exams, or both. These welds contribute -5.8E-10 to delta-LERF while the remaining welds contribute 4.4E-10. Therefore the delta-LERF contribution is -1.4E-10.
U1[AZTMM, 0 1fi:7=1IPAI 1!I V. Table - page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System" for both the ECCS and high pressure core spray systems (HPCS), explain why there is an increase (or decrease) for A CDF and the opposite trend for A LERF.
Response to RAI 2 Part V Each system will be addressed separately.
ECCS: This answer builds upon the discussion from RAI 2.IV. The reason the ECCS delta-LERF is negative is because the risk benefit is larger the higher the LERF. The RI-ISI selected welds are modeled with containment bypass consequences so the LERF is the same as the CDF. That makes the delta-LERF much higher than the delta-LERF for any other ECCS weld. The delta-CDF and delta-LERF risk improvements are nearly the same for the 10 selected welds, but the delta-CDF contribution of the remaining welds is higher than the delta-LERF contribution.
Therefore the delta-LERF is negative and the delta-CDF is positive.
HPCS: The answer for this system is the opposite of the ECCS system. If a high consequence containment bypass weld is not selected for RI-ISI inspection it will carry a larger percentage of the delta-LERF contribution for that system. Even though there are welds selected that contribute a risk benefit, the unselected high consequence welds turn the total positive for delta-LERF. These welds do not carry the same relative weight for the delta-CDF total so the delta-CDF remains negative.
RAI Question RAI 2 Part VI VI. With respect to the ECCS:
- a. Explain why the A CDF is positive as shown in the table on page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System," while the A CDF is negative as shown in the table on page 6, "LaSalle County Station Unit 2 BER Weld Delta-CDF and Delta-LERF by System."
- b. Explain why the A LERF is greater in magnitude as shown in the table on page 6 "LaSalle County Station Unit 2 BER Weld Delta-CDF and Delta-LERF by 23 LS-LAR-09 Rev. 1
System" than the n LERF shown in the table on page 6 "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System."
Response to Part a:
The ECCS BER welds are a subset of the entire system. The RI-ISI selected welds that cause the risk benefit are two BER welds. Since there are only 81 BER welds, the 2 risk beneficial welds have a greater impact on the total causing it to turn negative. The total number of ECCS welds is 869 so there are many more with no risk benefit that dilute the few with the risk benefit to turn the system total positive.
Response to Part b:
The answer is a similar reason to RAI 2 VI a. above. There are less BER welds and the presence of these 2 BER welds with a large risk benefit cause the ECCS BER delta-LERF to be more negative than the ECCS delta-LERF where there are more welds to dilute the quantitative impact.
VII. With respect to the HPCS, explain why the 0 CDF is negative in the table on page 6, "LaSalle County Station Unit 2 Delta-CDF and Delta-LERF by System," while the 0 CDF for the BER welds is positive as shown in the table on page 6, "LaSalle County Station Unit 2 BER Weld Delta-CDF and Delta-LERF by System".
Response to RAI 2 Part VII There are 5 welds that provide a risk benefit to the HPCS system that cause the system total delta-CDF to be negative. None of these welds are BER. In addition there are no other welds selected that provide a risk benefit to the HPCS BER delta-CDF. Therefore, the system total is negative and the BER total is positive.
24 LS-LAR-09 Rev. 1
LaSalle Rl-lSl RAI Response r =
In the letter dated July 20, 2017, (ADAMS Accession No. ML17201IQ396), both SR DA-C6 and DA-C10 state similar conclusions including:
"The plant data sources and developed demand estimates, however, are judged to be reasonable to support the PRA. Pursuing plant demand data per the explicit direction in the SR is not expected to result in significant impacts upon the PRA results. Therefore, DA-C6 is being self-assess as "Not Met" is not judged to impact this application."
Provide the justification for SRs that are not expected to result in significant impacts to the PRA. Explain whether the data sources align with the four listed as acceptable in SR DA-C6.
Response to RAB 3 As indicated in the previous RAI response, the current estimates of demands for standby components are based on a mixture of data sources such as plant process computer data, test frequency and associated procedure review (e.g., # cycles / test times the number of tests per year), MSPI basis document data, operator logs, work clearance order database, and system manager estimates. These sources align with the four items listed in DA-C6 (i.e., surveillance tests, maintenance acts, surveillance tests or maintenance on other components, and operational demands).
The self-assessment following the 2014 PRA model update of the two SRs (i.e., DA-C6 and DA-C10) as being not met was potentially conservative since there was not sufficient documentation to show the full intent of this SR was met. Note that the 2008 peer review did indicate these SRs were met with a suggestion to improve documentation. The data collection and analysis in 2006, 2011 and 2014 updates were performed essentially in the same or very similar manner. In any event, a hypothetical example is provided below to demonstrate that the actual demand estimates for standby components will only have a second order impact on the individual component reliability data and as such will not have a significant impact on the overall PRA model results.
This is followed by a sensitivity case using the LaSalle model.
The following example using a motor driven pump failure to start demonstrates the potential impact of data changes. Consistent with the 2011 PRA update, this example uses data from NUREG/CR-6928 (2010 data).
Motor Driven Pump (Standby) Fails to Start Generic Mean: 9.47E-4 per demand, Beta distribution, ao = 1.948, P. = 2054 Mean = a / (a+ P) a = ao+ Failures R = Po + Successes Assume no failures in 100 demands over data collection period a= 1.948+0= 1.948 R = 2054 + 100 = 2154 Mean,00 = 1.948 / (1.948 + 2154) = 9.04E-4 25 LS-LAR-09 Rev. 1
If the actual number of demands were off by 20% (i.e., 80 demands), then the calculated mean would be different by about 1.0% as follows:
a = 1.948 + 0 = 1.948 R=2054+80=2134 Mean$o = 1.948 / (1.948 + 2134) = 9.12E-4
% Diff = (9.12E-4 9.04E-4) / 9.04E-4 = 8.85E-3
- 100% = 0.885%
Similarly, if there were two failures over the data collection period, the results would still only be different by about 1.0% as shown below.
For 100 demands, a= 1.948+2=3.948 (3=2054+98=2152 Mean,00 = 3.948 / (3.948 + 2152) = 1.83E-3 For 80 demands, a = 1.948 + 2 = 3.948 P=2054+78=2132 Meanso = 3.948 / (3.948 + 2132) = 1.85E-3
% Diff = (1.85E-3 1.83E-3) / 1.83E-3 = 1.09E-2
- 100% = 1.09%
Furthermore, a LaSalle model sensitivity case was performed assuming that all of the plant-specific demand estimates were over-estimated by 20%. Even if the strict intent of the SR was not met for every estimate provided, it is judged that a 20% reduction in the demand estimates would provide a bounding assessment of any potential impact if some of the estimated demands were excluded. This involved 42 unique type codes in the PRA model. The sensitivity case for this bounding assumption resulted in a 0.87%
increase in CDF and a 0.04% increase in LERF. This demonstrates that performing additional refinements to the plant-specific data will not have a significant impact on the PRA model.
Note:
Response to RAI 4 is outside the scope of support application LS-LAR-09.
ME LS-LAR-09 Rev. 1
ATTACHMENT 2 Response to Request for Additional Information NRC PRA RAI 4 NRC PRA RAI 4 Safety Sianificance of Piaina Seaments Based on the information provided, the NRC staff could not determine whether the licensee reviewed the safety significance of the piping segments subject to inspection to ascertain whether there should be any changes in inspection locations for this fourth interval. Discuss whether there were any changes and, if so, explain the basis for those changes.
EGC Response LSCS maintains the plant safety-related systems and components in accordance with applicable design and licensing bases. This includes assigning appropriate ISI Classifications, which in turn feed into the Risk Informed Inservice Inspection (RI-ISI) program scoping.
Systems, piping, and components are continually evaluated and maintained through the station engineering change procedures. When modifications are made that impact the station safety functions and ISI Classifications, the RI-ISI Program scoping and evaluations are updated accordingly.
As noted at the end of Relief Request 14R-01, Section 4, LSCS implements an "evaluation and ranking" process that includes the Consequence Evaluation and Degradation Mechanism Assessment portions of the approved RI-ISI Program to maintain the Risk Categorization and Element Selection methods of EPRI TR-112657, "Revised Risk-Informed Inservice Inspection Evaluation Procedure," Revision B-A. These portions of the RI-ISI Program are continually maintained and are reevaluated as major revisions of the site Probabilistic Risk Assessment (PRA) occur and as modifications to plant configuration and/or design are made. The Consequence Evaluation, Degradation Mechanism Assessment, Risk Ranking, Element Selection, and Risk Impact Assessment steps encompass the complete living program process applied under the LSCS Rl-ISI Program.
This living program evaluation was conducted at the end of each ASME Section XI inspection period, including at the end of the Third Ten-Year Inspection Interval in support of the transition to the new Fourth Interval. Changes resulting from plant modifications such as the Flexible Coping Strategy (FLEX) system connections and from the latest PRA Model were incorporated into the new Fourth Interval RI-ISI Program Risk Ranking and Element Selections. Finally, the EPRI TR-112657 prescribed Risk Impact Assessment was completed to confirm the Fourth Interval element selections met the governing risk metrics. The results of this evaluation are provided in the tables included in Relief Request 1419-01, Section 4, and the criteria were met for all individual systems as well as for the overall plant rollup.
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