Text

Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specifications to Adopt Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completi
	ML20316A007
Person / Time
Site:	Harris
Issue date:	11/11/2020
From:	Maza K; Duke Energy Progress
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA-20-0321
	Download: ML20316A007 (44)
	v • d • e

1. DUKE Kim Maza Site Vice President

~ ENERGY" Harris Nuclear Plant 5413 Shearon Harris Road New Hill, NC 27562 10 CFR 50.90 November 11, 2020 RA-20-0321 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Shearon Harris Nuclear Power Plant, Unit 1 Docket No. 50-400/Renewed License No. NPF-63

Subject:

Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specifications to Adopt Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b Ladies and Gentlemen:

By letter dated October 7, 2019 (Agencywide Document Access and Management System (ADAMS) Accession No. ML19280C844), Duke Energy Progress, LLC (Duke Energy),

submitted a license amendment request (LAR) for Shearon Harris Nuclear Power Plant, Unit 1 (HNP). The proposed amendment would modify Technical Specifications (TS) requirements to permit the use of Risk-Informed Completion Times in accordance with Technical Specifications Task Force (TSTF) traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b (ADAMS Accession No. ML18183A493).

The U.S. Nuclear Regulatory Commission (NRC) staff reviewed the LAR and determined that additional information is needed to complete their review. Duke Energy received the request for additional information (RAI) from the NRC through electronic mail on September 29, 2020 (ADAMS Accession No. ML20274A046). provides Duke Energys response to the RAI questions. The information contained within this response does not change the No Significant Hazards Consideration provided in the original LAR submittal. Attachment 2 provides a revised mark-up of the Engineered Safety Features Actuation System (ESFAS) instrumentation TS.

No regulatory commitments are contained in this submittal.

If there are any questions or if additional information is needed, please contact Mr. Art Zaremba, Manager - Nuclear Fleet Licensing, at 980-373-2062 or Arthur.Zaremba@duke-energy.com.

U.S. Nuclear Regulatory Commission RA-20-0321 Page2 I declare under penalty of perjury that the foregoing is true and correct. Executed on November 11, 2020.

Sincerely, Kim E. Maza Site Vice President Harris Nuclear Plant Attachments:

1. Response to Request for Additional Information

2. Revised Technical Specifications Mark-Up for ESFAS Instrumentation cc (with Attachments):

L. Dudes, NRC Regional Administrator, Region II J. Zeiler, NRC Senior Resident Inspector, HNP M. Mahoney, NRC Project Manager, HNP W. L. Cox, 111, Section Chief N.C. DHSR

U.S. Nuclear Regulatory Commission RA-20-0321 Page 4 Attachment 1 Response to Request for Additional Information

U.S. Nuclear Regulatory Commission RA-20-0321 Page 5 Request for Additional Information By letter dated October 7, 2019 (Agencywide Document Access and Management System (ADAMS) Accession No. ML19280C844), Duke Energy Progress, LLC (Duke Energy),

submitted a license amendment request (LAR) to amend the Technical Specifications (TS) for the Shearon Harris Nuclear Power Plant, Unit 1 (HNP). The proposed amendment would modify TS requirements to permit the use of risk-informed completion times (RICT) in accordance with the Technical Specifications Task Force (TSTF) traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b (ADAMS Accession No. ML18183A493).

Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Domestic Licensing of Production and Utilization Facilities, Section 50.36, Technical specifications, establishes the regulatory requirements related to the content of TS. Section 50.36(c)(2) to 10 CFR Part 50 states, in part, that the limiting conditions for operation (LCO) are the lowest functional capability or performance level of equipment required for safe operation of the facility, and when LCOs are not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TS until the LCO can be met. The U.S. Nuclear Regulatory Commission (NRC) staff reviewed the LAR and determined that additional information is required to complete their review. The specific request for additional information (RAI) is addressed below.

RAI 1

Table E2-1 of Enclosure 2 of the LAR provides a summary of the open internal flooding and internal fire probabilistic risk assessment (PRA) facts and observations (F&Os) and how they are dispositioned for TSTF-505. Address the following:

a) Disposition for Finding Number 1-16 states, [s]ince maintenance-induced flooding is not a significant contributor to CDF/LERF [core damage frequency/large early release frequency], and since Harris is a single unit site with no shared systems, it is expected that additional validation of the results will not impact CDF/LERF or the calculation of RICTs. Provide information supporting the statement that maintenance-induced flooding is not a significant contributor to CDF and LERF.

b) F&O 1-19 states that flood alarms credited as cues in the human reliability analysis may not be applicable to the different flood scenarios evaluated in the internal flooding PRA.

The F&Os closure team did not close F&O 1-19 stating that the evaluation of alarms and alarm timing is not sufficient. The licensee performed a sensitivity study increasing this time by a factor of 3 and stated that there was minimal impact on the flooding results.

The disposition of this finding states, [t]his supporting requirement is MET, and no impact on calculation of RICTs is expected due to this recommendation. Clarify if this assumption has been shown to not impact the RICT calculations and provide any supporting information (e.g., results of the sensitivity study).

c) Supporting requirement QU-C2 of the American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) PRA Standard provides that dependency between human error probabilities in a cutset or sequence must be assessed. F&O 2-12 states that the flooding PRA assumes no dependency between the flood mitigation actions and the subsequent operator actions carried over from the internal events PRA

U.S. Nuclear Regulatory Commission RA-20-0321 Page 6 since the time between these actions are sufficiently long (essentially hours). F&O 2-12 further states that, a specific combination-by-combination evaluation of the dependency should be provided to demonstrate that indeed there is insufficient dependency between these two groups of operator actions.

Disposition for F&O 2-12 states, F&O Closure panel recommended that a specific, combination-by-combination evaluation of the dependency should be provided to demonstrate that indeed there is insufficient dependency between these two groups of operator actions. This is a documentation issue only, and there is no impact on calculation of RICTs. Provide detailed justification that there are no dependencies between the flood mitigation actions and the subsequent operator actions carried over from the internal events PRA (e.g., summarize the results of a combination-by-combination evaluation as recommended by the F&O closure panel).

Duke Energy Response to RAI 1, Part a Supporting Requirement (SR) ISFO-A4 part b of the ASME/ANS RA-Sa-2009 Standard (Reference 9) requires human-induced mechanisms for flooding be identified. In the HNP Internal Flooding PRA (IFPRA) human-induced flooding events were identified and added to the model. Inclusion of generic data is not required per this SR (it is a later requirement of SR IFEV-A7). The deficiency in the F&O in relation to plant-specific maintenance-induced flooding events was that the process used for the identification of the included maintenance events was not evident. As part of the TSTF-505 disposition, an additional operating experience search was performed to determine if any maintenance-induced events were missed along with discussions with HNP Operations. Only two Mode 1 maintenance events were identified in these discussions and included in the model. As HNP is a single unit site, shared system maintenance events do not need to be considered. As this process was exhaustive and included modeled maintenance events, additional analysis would not be warranted and would not lead to identification of any new plant-specific maintenance-induced events for inclusion into the IFPRA.

An accurate accounting of maintenance-induced internal flood events was verified based on discussions with Operations personnel and a review of plant-specific operating history (e.g.,

review of condition reports). As a result, only two specific areas were identified where online maintenance of systems involved isolation of a pressure boundary, which if lost, could result in a maintenance-induced internal flood event. The methodology for determining the frequency of such maintenance-induced internal flood events was found in Section 7 of Electric Power Research Institute (EPRI) 3002000079 (Reference 16). This methodology was followed to derive potential maintenance-induced internal flood events for all areas of the plant, but only those two scenarios determined by Operations personnel were retained in the PRA model. The EPRI methodology allows for exclusion of any postulated scenarios for those areas where maintenance activities are not expected (e.g., straight run of pipe where maintenance on a pressure boundary is not performed). That is, maintenance-induced flood events can be excluded in areas where no maintenance is expected. Given these considerations, F&O 1-16 has been adequately addressed and does not affect the RICT calculation.

Duke Energy Response to RAI 1, Part b The HNP IFPRA credits flooding mitigation actions for Fire Protection (FP) and Normal Service Water/Emergency Service Water (NSW/ESW) breaks. An operator interview was conducted to

U.S. Nuclear Regulatory Commission RA-20-0321 Page 7 confirm the cues, timing, and proceduralized Operations response to Fire Protection and NSW/ESW flooding events. Additionally, timing data obtained in the simulator for the purposes of validating the Time Critical Action (TCA) to initiate protective measures for a NSW/ESW flood were applied.

The operator interview combined with the simulator data indicated that the original diagnosis time for the FP flooding action was upheld but the diagnosis time for the NSW/ESW flooding action was underestimated. For both FP and NSW/ESW floods, the original operator cue time was underestimated while the execution times were conservatively overestimated. The overall result is an increase in the time available for recovery for all flooding mitigation actions.

Therefore, the human error probabilities either remain unchanged or decrease and the RICT calculations are not adversely impacted.

Duke Energy Response to RAI 1, Part c The HNP Internal Events Dependency Analysis was reperformed to include the Internal Flooding mitigation actions. Like the full power internal events (FPIE) actions, all internal flooding (IF) actions had their probabilities set to 1.0 in producing the CDF and LERF cutsets that were imported into the dependency analysis to ensure their inclusion.

The IF actions were manually placed first in the operator action combinations in which they were included as appropriate for cutsets with flooding initiators. In all but one case, the IF and FPIE action pairs were determined to be independent. The actions do not have common cognitive elements as they have different cues and procedures and they serve different functions. Also, the timelines for each IF and FPIE action pair were manually evaluated to ensure that they could be addressed in series. The single human failure event (HFE) pair that was not feasible in series was manually evaluated and had a result of low dependence. Finally, if the calculated joint human error probability (HEP) was greater than the minimum joint HEP floor value (even if the IF and FPIE action pair had zero dependence), it was replaced as defined in the HNP FPIE dependency analysis process.

This combination by combination dependency analysis is incorporated into the PRA model.

RAI 2

The response to Audit Question 08 Part (c) explains that the surrogate for TS 3.3.2 Functional Unit 4.c Action 19 Main Steam Isolation (Containment Pressure - High 2), which is not modeled in the PRA, is to use the same basic events for failure of pressure instruments as is used for containment spray actuation (Containment Pressure - High 3). However, it is unclear to the NRC staff that failure of containment spray is bounding for failure of main steam isolation because 1) the main steam isolation function is to prevent containment bypass, which is an immediate pathway out of containment (a likely LERF event), while the containment spray function is to reduce containment pressure and prevent eventual containment over-pressurization, which is a longer-term pathway for release (a possible non-LERF event), and 2) the containment pressure failure criteria for containment spray (High-3 or 10 psig) is higher than the corresponding failure criteria for main steam isolation (High-2 or 3 psig). Address the following:

a) Provide justification that the surrogate is bounding for failure of main steam isolation. In the response, specifically address 1) the potential difference in timing of the release due

U.S. Nuclear Regulatory Commission RA-20-0321 Page 8 to the failure of the pressure instruments and 2) how the failure criteria for main steam isolation (High-2 or 3 psig) is accounted for in the RICT calculation.

b) Alternatively, if the surrogate cannot be justified as bounding, either remove TS 3.3.2 Function Unit 4.c Action 19 from the RICT Program or provide justification for a different surrogate that is bounding.

Duke Energy Response to RAI 2 HNP TS 3.3.2 Functional Unit 4.c, Main Steam Isolation (Containment Pressure - High 2) is being removed from the scope of the RICT Program. Additionally, for almost all instances of inoperability where Functional Unit 1.c, Safety Injection (Containment Pressure - High 1) applies, Functional Unit 4.c simultaneously applies. For that reason, Functional Unit 1.c is also being removed from the scope of the HNP RICT Program. No other functional units in TS 3.3.2 are being removed from the scope of the RICT Program.

A revised TS mark-up that reflects removal of HNP TS 3.3.2 Functional Unit 4.c and TS 3.3.2 Functional Unit 1.c from the proposed RICT Program is included as Attachment 2 to this submittal.

RAI 3

The NRC staff safety evaluation to Nuclear Energy Institute (NEI) Topical Report NEI 06-09, NEI 06 09 A, Revision 0, Risk Managed Technical Specifications (RMTS) Guidelines, (ADAMS Accession No. ML12286A322) specifies that the LAR is to identify key assumptions and sources of uncertainty and to assess/disposition each as to their impact on the RMTS application. of the LAR describes the process for identifying key assumptions and sources of uncertainties, and provides an assessment of each identified key assumption and uncertainty.

The LAR indicates that plant-specific key assumptions and modeling uncertainties from the internal events PRA documentation were considered, as well as generic sources of uncertainty from EPRI Topical Report 1016737, Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments. However, it is unclear from the LAR whether the sources of modeling uncertainty (both plant-specific and generic) were identified for the LERF PRA model.

The NRC staff is also unclear of whether there are any key assumptions that may be contributing to the relatively high conditional large early release estimate for internal events.

The NRC staff notes that generic modelling uncertainties for Level 2 PRAs are identified in EPRI Report 1026511, Practical Guidance on the use of Probabilistic Risk Assessment in Risk-Informed Applications with a Focus on the Treatment of Uncertainty, however, Section 4.1 of of the LAR does not indicate the generic uncertainties that were considered for the Level 2 PRA. Considering the observations above, address the following:

a) Describe, separately for the internal events, interal flooding, and fire PRAs, the process used to identify and evaluate key assumptions and sources of model uncertainty for the Level 2 PRA models. Describe how this process aligns with guidance in NUREG-1855, Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making, Revision 1 (ADAMS Accession No. ML17062A466), or other NRC-accepted methods.

b) Identify and describe any additional key sources of model uncertainty and related assumptions associated with the Level 2 PRA models.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 9 c) For those key sources of model uncertainty and related assumptions that could impact the application identified under part (b):

i. Provide qualitative or quantitative justification that these key uncertainties and assumptions do not cause the baseline PRA results to challenge the Regulatory Guidance (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 3 (ADAMS Accession No. ML17317A256), risk acceptance guidelines, collectively or individually.

ii. Provide qualitative or quantitative justification that these key uncertainties and assumptions have no impact on the RICT calculations, or, if determined to have a significant impact, consistent with the guidance in NEI 06-09, discuss the Risk Management Actions for each key uncertainty and assumption that will be implemented to minimize their potential adverse impact.

Duke Energy Response to RAI 3, Part a Plant specific sources of uncertainty and assumptions for the Level 2 PRA models for internal events, internal flood and fire PRAs were assessed for the application and presented in the original LAR (Reference 12). Additionally, generic sources of uncertainty and assumptions for internal events (EPRI 1026511), internal flood (EPRI 1026511), and fire (EPRI 1026511) were assessed from the noted EPRI reports. Note: EPRI 1026511 does contain some LERF generic sources of uncertainty.

Specifically, the HNP internal events model documents and evaluates Level 2 uncertainty and assumptions used in creation of the Level 2 analysis. As described in Enclosure 9 of Reference 12 (henceforth referred to simply as Enclosure 9), the process used to evaluate sources of model uncertainty and assumptions is consistent with NUREG-1855, Revision 1. This process is outlined below, with some additional information beyond that which was provided in Reference 12:

- Model specific and generic uncertainties and assumptions were gathered.

- Each uncertainty/assumption was assessed to determine if it is considered key for the application.

o Considerations were applied to each source of uncertainty/assumption to determine if an item is key. These considerations are highlighted in Enclosure 9.

From a practical standpoint, some additional considerations were included that mirror the considerations in Enclosure 9 and allow the analyst to remove statements of fact and items that do not pertain to the application (e.g., Level 2 PRA issues that do not impact LERF).

o The analyst performing this assessment is a skilled, experienced PRA practitioner with many years of experience working on the HNP PRA models.

o The analyst assessing uncertainties and assumptions must make judgements to determine if some items are key. This judgement considers the overall model, the application, and how the model is utilized for the application.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 10 o In practice, all the model specific and generic uncertainties and assumptions were loaded into a spreadsheet and the analyst reviewed them one-by-one.

o Each item was assessed against the criteria presented in Enclosure 9 and the additional considerations noted above.

- Items that were not screened on the considerations noted in Enclosure 9 were considered key for this application. These items are reported and dispositioned for the application in Enclosure 9.

- Specifically related to LERF, the generic uncertainties for Level 2 PRAs identified in EPRI Report 1026511 have been assessed in response to this RAI. No generic uncertainties from this EPRI report are key to this application.

This process aligns with NRC guidance in NUREG-1855 by identifying the uncertainty related to the analysis, by identification of the assumptions used in the model, by evaluating whether the assumption is reasonable or widely accepted, and by dispositioning the assumption or uncertainty with sensitivities, if required.

The internal flood and fire models did not modify the Level 2 analysis or introduce any additional modeling changes; therefore, these modeling assumptions and uncertainties remain unchanged from the ones identified for the internal events model.

Generic Level 2 sources of uncertainty and assumptions from EPRI 1026511 were evaluated in response to this RAI question. As such, plant-specific and generic Level 2 assumptions have been evaluated for the application.

Key sources of model uncertainty were examined when developing input to the Reference 12 LAR and the subject RAI response. Those key sources of model uncertainty that were deemed to have a significant impact on the application were carried forward for further analysis, as documented in Enclosure 9. No additional key sources of model uncertainty were identified from the review of Level 2 generic uncertainties in response to this RAI.

Additionally, since the Reference 12 LAR was submitted, a model update was completed that implemented a number of items, including the addition of an operator action (OPER-SAMGAFW) to mitigate large early releases from steam generator (SG) tube ruptures with a stuck open main steam isolation valve, safety relief valve or power-operated relief valve. This improvement does reduce SG tube rupture contribution to LERF and reduces the overall LERF value. Changes to the model were reviewed for any that would be key to the application, and none were identified.

Development of the new operator action was reviewed in detail to determine if it would be key to the application. This added operator action is not a PRA upgrade because the operator action was developed in accordance with industry practice using consensus methods and the same process and software as all other HNP human failure events (HFEs). To reduce uncertainty associated with this operator action, Modular Accident Analysis Program (MAAP) runs and detailed discussion with an experienced senior reactor operator licensed individual were used to develop timing. As such, development of this operator action (OPER-SAMGAFW) is not considered key for the application.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 11 Additionally, defense-in-depth and risk mitigation is implemented through Risk Management Actions (RMAs). For this example, OPER-SAMGAFW significantly affects steam isolation RICTs and implementing a RICT on a steam line isolation technical specification (e.g., TS 3.3.2 Functional Unit 4.b Action 14) would require operators to establish RMAs that may include several considerations:

1. Brief operating shifts and increase operator awareness of configuration specific risks.

2. Implementers and other involved personnel should understand and be briefed how their actions can influence the risk to the plant.

3. Increase control of activities that could result in an initiating event as identified using the Electronic Risk Analysis Tool (ERAT) Initiator Importance report.

4. Protect functional components that are most important for event mitigation as identified using the ERAT In Service Component Importance report.

5. Require a knowledgeable observer or subject matter expert to be present for the maintenance activity, or for applicable portions of the activity.

6. The equipment or safety functions should be returned to a functional status within a reasonable amount of time.

Duke Energy Response to RAI 3, Part b No additional key sources of model uncertainty and related assumptions associated with the Level 2 PRA models were identified.

Duke Energy Response to RAI 3, Part c Not Applicable.

RAI 4

The response to Audit Question 15 Part (c.iii) provides the results of a sensitivity study from crediting FLEX. Sensitivity study results were provided for TS 3.8.1.1 Action c.1 (alternating current (AC) Sources - Operating) in which one off-site circuit and one emergency diesel generator are inoperable, and TS 3.8.2.1 Action (direct current (DC) Sources - Operating) for two cases: 1) one battery not available and 2) one DC bus not available. In each case the RICT was shown to be insignificantly impacted by crediting FLEX. The results showed minor impact on the resultant RICTs for these TS actions. Address the following with regards to this sensitivity study:

a) The response to part b of Audit Question 15 states that the credit for FLEX includes credit for a portably FLEX auxiliary feedwater (AFW) pump as another source of injection into the steam generators for decay heat removal. Elsewhere in the response it is implied that FLEX is only credited for extended loss of AC power scenarios.

Address the following:

i. Clarify how FLEX is being credited in the PRA.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 12 ii. If FLEX is being credited for non-extended loss of AC power scenarios, provide the results of a sensitivity study that does not credit FLEX for TS 3.7.1.2 Action a (AFW System) and any other applicable TS actions.

b) Provide clarification on what the values are that are provided for the line items in Tables 15.c.iii-1 through 15.c.iii-9 titled Degraded FLEX SSCs (TRUE), Degraded FLEX HRAs (TRUE), and Degraded All FLEX (TRUE). They do not appear to be CDF/LERF for the Base (No Maintenance) case with no credit for FLEX because subtracting this value from the 3.8.1.1.c.1 value does not yield the resultant Delta. In the response, explain how the RICTs for the degraded cases were calculated using these values and justify that the calculated RICT results are correct.

Duke Energy Response to RAI 4, Part a) i.

FLEX equipment is only credited for extended loss of AC power (ELAP) scenarios. The FLEX AFW pump is another source of feed water injection requiring the operation of the FLEX diesel generators (DGs) for power and the FLEX AFW pump requires operator alignment and operation. The FLEX AFW pump is not expected to be functional or available until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the event (i.e., initiation of loss of power), as documented in the FLEX Timeline Calculation.

FLEX is only credited for backup power to FLEX related systems, 125 V DC, 480 V AC systems and as another source of injection into the SGs for decay heat removal. The FLEX AFW Pump is modeled as a source of feedwater to SGs in late station blackout (SBO) events.

This credit includes portable FLEX DGs that can supply power to up to four motor control centers (MCCs), as well as a portable motor driven pump to supply AFW to each SG. The portable FLEX AFW pump requires power from the FLEX DGs. FLEX is applied to the HNP models for extended periods of loss of AC power and can provide power to a FLEX powered AFW pump (for SBO events).

The FLEX equipment currently credited in the PRA model includes the permanently installed DGs and non-permanently installed portable pumps. Permanently installed piping, hoses or connection points are not modeled. Post initiator actions are modeled and include failure to load shed, failure to align and start FLEX DG, failure to refuel FLEX DG, and failure to align and start FLEX AFW pump. The FLEX DG, while permanently in place, requires operator actions to hookup to its respective connections for powering the associated loads. This action, along with the corresponding HFE, is modeled in the PRA.

Duke Energy Response to RAI 4, Part a) ii.

FLEX is only being credited for ELAP scenarios. The FLEX AFW Pump is modeled as a source of feedwater to SGs in late SBO events. The timing study for the FLEX AFW pump explains that it is expected to be 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the event (i.e., initiation of loss of power) that the FLEX AFW pump would be aligned. The FLEX timeline calculation lists 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months as the time required for alignment of the FLEX AFW pump. The FLEX timeline calculation documents the validation studies and states that the FLEX components are for ELAP scenarios.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 13 Duke Energy Response to RAI 4, Part b)

Tables 15.c.iii-1 through 15.c.iii-9 are included below. The values in the tables were verified to be correct. An additional column was added to the far right of the tables in order to provide clarification for how the values are derived. In summary, the internal events model was re-quantified for each case with a recovery rule file that fails the FLEX equipment and/or the FLEX operator actions, and this new value is recorded. The newly quantified value was then added to the Fire and Flooding values and listed as the Total new value in the next row. Note: there was no change to the Fire and Flooding values, as discussed during the audit. Therefore, only the internal events were required to be modified for this sensitivity. This new total was then compared to the Base value for a new delta. This new delta value is used to provide the new RICT (in days) for the given scenario.

As shown in the tables below, the number of RICT days for each TS Action are not highly sensitive to the reliabilities of the FLEX equipment or those operator actions associated with the FLEX equipment. Neither the FLEX HRAs nor the FLEX equipment failure rates are significant to the RICT application. The CDF column represents the limiting RICT based on CDF numbers only. The LERF column represents the limiting RICT based on LERF numbers only.

Table 15.c.iii-1 FLEX Sensitivity to Equipment (One off-site circuit and one EDG inoperable)

CDF (/yr) LERF (/yr) Description Base (No Maintenance) 3.48E-05 4.04E-06 Base values 3.8.1.1 c.1 8.37E-04 1.89E-04 Metric value with respective SSC failed Delta 8.03E-04 1.85E-04 Delta from the base value RICT (days) 4.55 2.0 Respective RICT value Degraded FLEX SSCs (TRUE) 3.46E-4 1.34E-4 Initiating Event (IE) Only Value quantified with FLEX SSCs set to TRUE 3.8.1.1 c.1 8.38E-04 1.89E-04 Total Value with FLEX SSCs set to TRUE Delta 8.04E-04 1.85E-04 New Delta between the above value and the Base Value (i.e.,

8.38E-4 minus 3.48E-5 = 8.04E-4 for CDF.

RICT (days) 4.54 2.0 Respective RICT value using the new Delta from directly above.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 14 Table 15.c.iii-2 FLEX Sensitivity to Human Failures (One off-site circuit and one EDG inoperable)

CDF (/yr) LERF (/yr) Description Base (No Maintenance) 3.48E-05 4.04E-06 Base values 3.8.1.1 c.1 8.37E-04 1.89E-04 Metric value with respective SSC failed Delta 8.03E-04 1.85E-04 Delta from the base value RICT (days) 4.55 2.0 Respective RICT value Degraded FLEX HRAs (TRUE) 3.46E-4 1.34E-4 IE Only Value quantified with FLEX HRAs set to TRUE 3.8.1.1 c.1 8.38E-04 1.89E-04 Total Value with FLEX HRAs set to TRUE Delta 8.03E-04 1.85E-04 New Delta between the above value and the Base Value (i.e.,

8.38E-4 minus 3.48E-5 = 8.03E-4 for CDF).

RICT (days) 4.54 2.0 Respective RICT value using the new Delta from directly above.

Table 15.c.iii-3 FLEX Sensitivity to Equipment and Human Failures (One off-site circuit and one EDG inoperable)

CDF (/yr) LERF (/yr) Description Base (No Maintenance) 3.48E-05 4.04E-06 Base Value 3.8.1.1 c.1 8.37E-04 1.89E-04 Metric value with respective SSC failed Delta 8.03E-04 1.85E-04 Delta from the base value RICT (days) 4.55 2.0 Respective RICT value Degraded All FLEX (TRUE) 3.47E-4 1.34E-4 IE value quantified with FLEX SSCs and HRAs set to TRUE 3.8.1.1 c.1 8.39E-04 1.89E-04 Total Value with All FLEX items set to TRUE (added to IF and Fire)

Delta 8.04E-04 1.85E-04 New Delta between the above value and the original Base Value (i.e., 8.39E-4 minus 3.48E-5 = 8.04E-4 for CDF)

RICT (days) 4.54 2.0 Respective RICT value using the new Delta from directly above.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 15 Table 15.c.iii-4 FLEX Sensitivity to Equipment DC Sources - Operating 3.8.2.1 Action (DC Sources - Operating One battery not available)

CDF (/yr) LERF (/yr)

Base (No Maintenance) 3.48E-05 4.04E-06 Base values 3.8.2.1 1.56E-4 1.76E-5 Metric value with respective SSC failed Delta 1.21E-4 1.36E-5 Delta from the base value RICT (days) 30.1 27 Respective RICT value Degraded FLEX SSCs (TRUE) 5.42E-6 1.55E-6 IE Only Value quantified with FLEX SSCs set to TRUE 3.8.2.1 1.57E-4 1.78E-5 Total Value with FLEX SSCs set to TRUE Delta 1.23E-4 1.37E-5 New Delta between the above value and the Base Value (i.e., 1.57E-4 minus 3.48E-5 = 1.23E-4 for CDF.

RICT (days) 29.8 26.6 Respective RICT value using the new Delta from directly above.

Table 15.c.iii-5 FLEX Sensitivity to Human Failures DC Sources - Operating 3.8.2.1 Action (DC Sources - Operating One battery not available)

CDF (/yr) LERF (/yr)

Base (No Maintenance) 3.48E-05 4.04E-06 Base values 3.8.2.1 1.56E-4 1.76E-5 Metric value with respective SSC failed Delta 1.21E-4 1.36E-5 Delta from the base value RICT (days) 30.1 27 Respective RICT value Degraded FLEX HRAs (TRUE) 5.56E-6 1.52E-6 IE Only Value quantified with FLEX HRAs set to TRUE 3.8.2.1 1.57E-4 1.78E-5 Total Value with FLEX HRAs set to TRUE Delta 1.23E-4 1.37E-5 New Delta between the above value and the Base Value (i.e., 1.57E-4 minus 3.48E-5 = 1.23E-4 for CDF).

RICT (days) 29.8 26.6 Respective RICT value using the new Delta from directly above.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 16 Table 15.c.iii-6 FLEX Sensitivity to Equipment and Human Failures DC Sources - Operating 3.8.2.1 Action (DC Sources - Operating One battery not available)

CDF (/yr) LERF (/yr)

Base (No Maintenance) 3.48E-05 4.04E-06 Base Value 3.8.2.1 1.56E-4 1.76E-5 Metric value quantified with respective SSC failed Delta 1.21E-4 1.36E-5 Delta from the base value RICT (days) 30.1 27 Respective RICT value Degraded FLEX All (TRUE) 6.83E-6 1.71E-6 IE value quantified with FLEX SSCs and HRAs set to TRUE 3.8.2.1 1.59E-4 1.79E-5 Total Value with All FLEX items set to TRUE Delta 1.24E-4 1.39E-5 New Delta between the above value and the original Base Value (i.e., 1.59E-4 minus 3.48E-5 = 1.24E-4 for CDF)

RICT (days) 29.5 26.3 Respective RICT value using the new Delta from directly above.

Table 15.c.iii-7 FLEX Sensitivity to Equipment DC Sources - Operating 3.8.2.1 Action (DC Sources - Operating; One DC Bus is not available)

CDF (/yr) LERF (/yr)

Base (No Maintenance) 3.48E-05 4.04E-06 Base values 3.8.2.1 2.08E-3 2.76E-4 Metric value with respective SSC failed Delta 2.05E-3 2.72E-4 Delta from the base value RICT (days) 1.8 1.34 Respective RICT value Degraded FLEX SSCs (TRUE) 1.44E-3 2.08E-4 IE Only Value quantified with FLEX SSCs set to TRUE in IE 3.8.2.1 2.11E-3 2.80E-4 Total Value with FLEX SSCs set to TRUE Delta 2.08E-3 2.76E-4 New Delta between the above value and the Base Value (i.e., 2.11E-3 minus 3.48E-5 = 2.08E-3 for CDF.

RICT (days) 1.8 1.32 Respective RICT value using the new Delta from directly above.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 17 Table 15.c.iii-8 FLEX Sensitivity to Human Failures DC Sources - Operating 3.8.2.1 Action (One DC Bus is not available)

CDF (/yr) LERF (/yr)

Base (No Maintenance) 3.48E-05 4.04E-06 Base values 3.8.2.1 2.08E-3 2.76E-4 Metric value with respective SSC failed Delta 2.05E-3 2.72E-4 Delta from the base value RICT (days) 1.8 1.34 Respective RICT value Degraded FLEX HRAs (TRUE) 1.44E-3 2.08E-4 IE Only Value quantified with FLEX HRAs set to TRUE i IE with FLEX Total Value 3.8.2.1 2.11E-3 2.80E-4 HRAs set to TRUE Delta 2.08E-3 2.76E-4 New Delta between the above value and the Base Value (i.e., 2.11E-3 minus 3.48E-5 = 2.08E-3 for CDF).

RICT (days) 1.8 1.32 Respective RICT value using the new Delta from directly above.

Table 15.c.iii-9 FLEX Sensitivity to Equipment and Human Failures DC Sources - Operating 3.8.2.1 Action (One DC Bus is not available)

CDF (/yr) LERF (/yr)

Base (No Maintenance) 3.48E-05 4.04E-06 Base Value 3.8.2.1 2.08E-3 2.76E-4 Metric value with respective SSC failed Delta 2.05E-3 2.72E-4 Delta from the base value RICT (days) 1.8 1.34 Respective RICT value Degraded FLEX All (TRUE) 1.47E-3 2.12E-4 IE value quantified with FLEX SSCs and HRAs set to TRUE 3.8.2.1 2.14E-3 2.84E-4 Total Value with All FLEX items set to TRUE Delta 2.11E-3 2.80E-4 New Delta between the above value and the original Base Value (i.e., 2.14E-3 minus 3.48E-5 = 2.11E-3 for CDF)

RICT (days) 1.7 1.30 Respective RICT value using the new Delta from directly above.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 18

RAI 5

Revision 3 of RG 1.174, states that the acceptability of the engineering analyses is determined by assessing the scope, level of detail, supporting technical analyses, and plant representation.

The NRCs safety evaluation for Topical Report NEI 06-09, Revision 0-A, states that the

[o]ther sources of risk (i.e., seismic, other external events) must be quantitatively assessed if they contribute significantly to configuration-specific risk.

In Section 6.1.2 of Enclosure 4 to the LAR, the licensee discussed the plant-level high confidence of low probability of failure (HCLPF) capacity, the median plant-level acceleration capacity (am), and the composite variability in the plant-level acceleration capacity (c).

However, the licensee did not provide the actual values of these parameters used to calculate the seismic CDF of 2.14E-06/year in Section 6.1.4 of the Enclosure 4 to the LAR.

Provide the values of input parameters, HCLPF or am, and c, used to calculate the seismic CDF with justification.

Duke Energy Response to RAI 5 The values of the input parameters used to calculate the HNP revised seismic CDF (SCDF) of 4.98E-07/yr are provided in Table 5-1. The original calculation of SCDF provided in the Reference 12 LAR has been judged to be overly conservative because it did not apply the spectral ratios to adjust the peak ground acceleration (PGA)-based plant level fragility curve, and it conservatively biased the SCDF calculation to the high hazard frequencies by not including the HNP 2.5 Hz hazard curve. Discussion of the revised calculation and justification are provided herein.

Table 5 HNP Plant Level Fragility Data for SCDF Calculations CDF (PGA) Fragility RLE Spectral Ratios C50 [am]

c HCLPF 10Hz 5Hz 2.5Hz 1Hz (g) 0.74 0.4 0.29 1.87 2.12 2.12 0.96 The original seismic design for HNP was conducted to a safe shutdown earthquake (SSE) with a NUREG/CR-0098 (Reference 1) spectral shape anchored to 0.15g PGA. Since the HNP SSE significantly exceeds the updated Ground Motion Response Spectrum (GMRS) in the 1 Hz to 10 Hz range (shown in Figure 5-1), HNP screens from further seismic evaluation, and a full seismic PRA is not required. The screening out from further seismic evaluation is consistent with the HNP response to a NRC staff request for information pursuant to 10 CFR 50.54(f) regarding the Fukushima Dai-ichi accident (References 2 and 3) and the NRC staffs screening results of the information provided (Reference 4).

The seismic margin assessment (SMA) performed for the individual plant examination of external events (IPEEE) (Reference 5) used a Regulatory Guide (RG) 1.60 review level earthquake (RLE) spectrum anchored to a 0.3g PGA as the seismic demand response curve. The IPEEE results concluded that this RLE demand curve is the lower bound HCLPF capacity of the plant level fragility curve. As such, the spectral ratios from the IPEEE assessment can be used to translate the PGA-based HCLPF capacity to the HCLPF capacities of different frequencies of interest (e.g.,

1 Hz, 2.5 Hz, 5 Hz and 10 Hz). However, the spectral ratios of the GMRS curve only provide the

U.S. Nuclear Regulatory Commission RA-20-0321 Page 19 ratios of seismic demand, not the ratio of seismic HCLPF capacity relative to other spectral frequencies. Since the GMRS anchored to 0.3g PGA is bounded by the RLE response curve (also shown in Figure 5-1) for key frequencies of interest, the spectral ratios from the IPEEE assessment are used to obtain the spectral acceleration HCLPF capacity of the plant level fragility curve (i.e., the plant is shown to have the spectral capacity from the IPEEE assessment).

SSE-GMRS comparison, Harris 0.70 0.60 I ~

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0.00 0.1 10 100 Spectral frequency, Hz Figure 5 The HNP GMRS anchored to 0.3g PGA is bounded by the RLE for key frequencies.

Past seismic PRAs (SPRAs) have demonstrated that plant seismic risk is a function of the seismic response at a variety of spectral frequencies (e.g., PGA, 1 Hz, 2.5 Hz, 5 Hz and 10 Hz), and that there are risk contributions from all these frequencies due to the variations in equipment, systems and structures that contribute to risk (Reference 6). Inclusion of a set of hazard curves at the various spectral frequencies, therefore, provides a more reasonable conservative representation of plant risk than a point estimate that considers PGA alone.

The plant level fragility is the conditional probability of plant damage at a given seismic hazard input level and was developed by the NRC as part of the Generic Issue (GI)-199 Safety / Risk Assessment (Reference 7) based on information provided in the IPEEE submittal. Appendix C of the NRC GI-199 report defines the methods used to estimate a plant-level fragility and establishes the RLE as a conservative minimum seismic capacity of the plant. The NRC estimated the plant-level fragility based on the reported plant-level HCLPF values of assessed components, and an estimate of the composite variability, c, from the SMA components. The HCLPF is related to the median seismic capacity by:

C50 = HCLPF x exp (2.3264 x c)

U.S. Nuclear Regulatory Commission RA-20-0321 Page 20 where:

HCLPF is the limiting seismic capacity of a component (from the SMA) whose seismic failure would lead directly to core damage,

C50 (or am) is the median (50th percentile) plant-level acceleration capacity (g), and

c is the composite variability in the plant-level acceleration capacity.

The median plant-level PGA fragility data from Table C-2 of Reference 7 is provided in Table 5-2:

Table 5 Plant-Level Fragility Data PGA Fragility Spectral Ratios HCLPF C50 c 10Hz 5Hz 1Hz 0.29 0.74 0.4 1.87 2.12 0.96 The spectral ratios for the median capacity at each frequency provided in Table 5-1 were replicated for this analysis using methods defined in NUREG/CR-0098 in order to include the 2.5 Hz hazard curve in this assessment. The calculated spectral ratios align with NRC GI-199 calculations. The plant level seismic fragility is modeled as a cumulative log-normal distribution function for each acceleration:

Pf (a) = ( ln(a/am) / )

c where:

Pf (a) is the conditional probability of failure for a given acceleration, a,

is the cumulative normal distribution function in Excel (NORMSDIST or NORM.S.DIST),

a is the given seismic acceleration demand of interest (g),

am (or C50) is the median (50th percentile) plant-level acceleration capacity (g) at each spectral frequency, and

c is the composite variability in the mean fragility curve.

The HNP plant level fragilities for the RLE are plotted in Figure 5-2. For all spectral frequencies, the cumulative probability of failure is 1.0 for ground accelerations greater than 7.5g. These values are inherently conservative as they represent the lower bound HCLPF capacity based on the most limiting component in the plant, and they are used as the conditional core damage probabilities (CCDPs) for the SCDF calculation.

In order to validate that the components included in the SMA are still representative of the as-built, as-operated plant, the components deemed significant in the IPEEE were assessed to validate that the equipment credited in the SMA success path still perform the credited function, and to determine if any new equipment in the success path has been added to the list. This list of components is referred to as the Seismic Safe Shutdown Equipment List (SSEL). Engineering changes (ECs) generated since 1990 were identified and reviewed to validate the equipment credited in the success path described in the SMA. The results of the review demonstrated that

U.S. Nuclear Regulatory Commission RA-20-0321 Page 21 there is no impact of equipment changes on the function of any equipment on the SSEL, and no new equipment has been added to the list. This provides high confidence that the components from the SMA used to determine the plant level fragility are still representative of the as-built, as-operated plant and establishes the RLE as a conservative minimum seismic capacity of the plant.

Plant Level Fragility - RLE 1.0

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Figure 5 Plant Level Fragilities for the HNP Review Level Earthquake (0.3g)

The NRC used approximate methods to estimate the SCDF for each operating nuclear plant as part of their 2010 study. These SCDF estimates were developed using a method that involved integrating the mean seismic hazard curve and the mean plant-level fragility curve for each plant.

This method was first developed by Kennedy (Reference 8) and is discussed in Non-Mandatory Appendix 10-B.9 of Reference 9, as well as Appendix D of the screening, prioritization and implementation details (SPID) for the resolution of Fukushima Near-Term Task Force Recommendation 2.1 (Reference 10). This method has previously been used by the Staff in the resolution of GI-199 and during reviews of various risk-informed license amendments (Reference 7). This same approach was judged by EPRI (Reference 6) to be the most appropriate method to assess this latest set of new site-specific seismic hazard estimates developed in response to the NRCs 10 CFR 50.54(f) letter.

The frequency ranges that drive the plant seismic risk are typically very broad, including contributions from 1 Hz to PGA. One of the methods to account for the spectral frequency contribution to the SCDF used in the GI-199 Safety / Risk Assessment considered each of the frequencies to contribute equally to the overall SCDF. The methodology accounts for the contribution to seismic risk across the frequency range and is a more reasonable conservative representation of seismic risk than using PGA alone. The resulting SCDF estimate associated with this spectral weighting is shown mathematically by the following equation:

SCDFavg = SCDFpga + SCDF10 + SCDF5 + SCDF2.5 + SCDF1

U.S. Nuclear Regulatory Commission RA-20-0321 Page 22 This averaging was judged by EPRI to be appropriate as past SPRAs have demonstrated that there are risk contributions from all these frequencies due to the variety of equipment, systems and structures that end up contributing to the risk. In addition, EPRI conducted limited sensitivity studies related to this frequency weighting by evaluating the number of frequencies considered between 4 and 6, and by assessing an alternate approach in the GI-199 Safety / Risk Assessment.

The overall results and conclusions are relatively insensitive to the approach taken. EPRI does not recommend using very conservative approaches to estimate the SCDF such as use of the maximum SCDFs calculated at any one frequency. This type of bounding approach is overly conservative and judged to not provide realistic risk estimates consistent with SCDFs and seismic LERFs (SLERFs) calculated in SPRAs.

In the initial HNP LAR submittal for TSTF-505 (Reference 12), the SCDF penalty of 2.14E-06 (per year) was calculated by integrating the hazard curves for PGA, 1 Hz, 5 Hz, and 10 Hz with the PGA-based plant level fragility curve. That original calculation has been judged to be overly conservative because it did not apply the spectral ratios to adjust the PGA-based plant level fragility curve, and it biased the calculation to the high frequencies by not including the 2.5 Hz curve in the calculation. Since the cumulative probability of failure is 1.0 for accelerations greater than 7.5g for all frequencies, inclusion of the 2.5 Hz hazard curve provides a more reasonable conservative representation of risk.

The updated SCDFavg is 4.98E-07(per year), and if applied as a potential seismic penalty to a RICT with a 30-day backstop, the seismic incremental core damage probability (SICDP) would be 4.10E-08 (per 30-days). This risk estimate does not contribute significantly to configuration-specific risk and would not impact any maintenance decisions. Quantitative seismic modeling, therefore, can be omitted from the RICT calculations per NEI 06-09 (Reference 11).

RAI 6

Section 2.3.1, Item 7, of NEI 06-09, Revision 0-A, states, in part, that the impact of other external events risk shall be addressed in the RMTS program, and explains that one acceptable method for accomplishing this is performing a reasonable bounding analysis and applying it along with the internal events risk contribution in calculating the configuration risk and the associated RICT. The NRC staffs SE for NEI 06-09 states that [w]here PRA models are not available, conservative or bounding analyses may be performed to quantify the risk impact and support the calculation of the RICT.

The LAR indicates that seismic PRA models are not available for Harris. Section 6.1 of to the LAR, describes the approach taken to estimate the seismic CDF and LERF for Harris using non-PRA information. The approach involves the use of a plant level HCLPF fragility curve for estimating the seismic CDF and then uses the estimated seismic CDF value to estimate a bounding seismic LERF value. Section 6.1.5 of Enclosure 4 to the LAR explains that the seismic LERF was calculated using the ratio between the internal events CDF and LERF with the following adjustment. The CDF and LERF associated with Steam Generator Tube Rupture scenarios and Interfacing System loss of coolant accidents were first subtracted from the internal events CDF and LERF values before the ratio was calculated because these scenarios are generally not important contributors to seismic risk. Using this approach, the LAR presents an internal events LERF-to-CDF ratio of 3.5% and a bounding seismic LERF value of 7.51E-08 per year. The LAR then indicates that because the estimated seismic LERF falls below the 1.0E-07 (per year) RG 1.174 screening criteria, a seismic LERF penalty will not be

U.S. Nuclear Regulatory Commission RA-20-0321 Page 23 added to change-in-LERF used to calculate RICTs. The NRC staff is not aware of guidance in RG 1.174 that may be viewed as LERF screening criteria.

As noted above, NEI 06-09, Revision 0-A as well as the corresponding NRC staff safety evaluation calls for a bounding analysis when addressing the impact of external hazards that cannot be screened. NRC staff has generally observed that the LERF-to-CDF ratio for seismic events can be significantly higher than the LERF-to-CDF ratio for internal events and is typically much higher than 3.5% due to the unique nature of seismically-induced failures. It is unclear that the estimated seismic LERF based on a LERF-to-CDF ratios of 3.5% can be considered a bounding value. Therefore, address the following:

a) Justify that the seismic LERF provided in the LAR to support RICT calculations for the Harris is bounding. Include the rationale that the use of the seismic CDF to LERF ratio derived from the internal events LERF to CDF ratio is bounding for seismically induced events, given that random events in an internal events PRA do not necessarily capture seismically-induced failures that may uniquely contribute to seismic LERF.

b) If the approach to estimating seismic LERF cannot be justified as bounding for this application in response to part (a) above, then provide, with justification, the bounding seismic LERF penalties for use in RICT calculations Duke Energy Response to RAI 6 The SLERF estimate for HNP has been updated to include a site-specific assessment of fragilities for critical components in the HNP containment boundary, and to include the updated SCDF estimate described in the response to RAI 5 above. The SCDF estimate previously submitted in the HNP TSTF-505 LAR (Reference 12) has been determined to be overly conservative because it did not apply the spectral ratios to adjust the PGA-based plant level fragility curve, and it biased the calculation to the high frequencies by not including the 2.5 Hz hazard curve. The convolution of the updated SCDF with the site-specific assessment of SLERF fragilities results in a reasonably conservative estimate of the plant seismic risk. The updated SCDF for HNP is 4.98E-07/yr, and the updated SLERF is 9.97E-08/yr. This risk estimate does not contribute significantly to configuration-specific risk and would not impact any maintenance decisions. Quantitative modeling, therefore, can be omitted from the RICT calculations per NEI 06-09 (Reference 11).

Discussion of the revised SCDF calculation is provided in the response to RAI 5, and discussion and justification of the revised SLERF calculation are provided herein.

The SLERF calculation described in the original HNP LAR submittal (Reference 12) has been updated to provide an appropriate bounding estimate and has been revised as follows.

A site-specific assessment of fragilities for critical components in the containment boundary has been developed for use in this SLERF assessment. Analyses of the HNP seismic category I structures were originally performed as part of the SMA for the HNP IPEEE (Reference 5) to identify vulnerabilities that involve early failure of containment functions. The analyses included consideration of containment integrity, containment isolation, and other containment functions.

Concerns such as falling and differential building displacements were considered. Displacement concerns between the containment shell and internal structure were reviewed. Containment isolation valves and penetrations were reviewed to identify anomalies that might affect containment performance. A containment walkdown was conducted by a seismic review team to

U.S. Nuclear Regulatory Commission RA-20-0321 Page 24 identify/evaluate any potential unusual conditions or configurations (e.g., spatial interactions, unique penetrations, piping hard spots, bridging of the seismic gap between the containment liner and interior structure, etc.). Seismic capacities for containment were determined to be greater than the 0.3g review level earthquake (RLE), and no vulnerabilities or unusual conditions that would be detrimental to the containment integrity were identified. All HNP civil structures, therefore, were screened from further review based on the EPRI NP-6041, Table 2-3 (Reference 13), screening criteria and Section 3.8 of the HNP Updated Final Safety Analysis Report (Reference 14).

Due to the change in shape and magnitude of the GMRS from the updated site-specific seismic hazard information from HNPs 50.54(f) submittal to the NRC (Reference 3), the in-structure response spectra (ISRS) for the SLERF critical components has been updated for use in this analysis. The IPEEE analyses were used as a starting point for scaling evaluations, and the scaling method documented in the EPRI fragility guide (Reference 15) was used. In order to assess the fragilities for those components critical to SLERF, the SSCs were evaluated to the higher level 0.55g PGA and the new spectral shape of the GMRS earthquake (shown if Figure 6-1).

The scope of the containment assessment included three main tasks:

Estimation of seismic response in the containment structure for the new seismic hazard:

Developed and implemented a method to scale the spectra from the IPEEE or design basis ISRS to estimate the response to the latest seismic hazard shape based on the EPRI fragility guide (Reference 15).

Fragility assessment of the following components critical to SLERF:

The containment structure, Containment penetration failures that could lead to SLERF, Piping failures at containment penetrations that could lead to SLERF, and Containment bypass valve failures that could lead to SLERF.

The developed fragilities considered multiple failure modes, but the final fragility is based on the controlling failure mode:

Acceleration related failures (structural/anchorage)

Falling/deflection seismic interaction failures, Differential displacement failure modes

Virtual walkdown review of the HNP containment to support the fragilities assessment.

The seismic fragilities were developed based on dividing an estimate of the seismic capacity by the appropriate seismic demand. The seismic demands are generated from the scaled responses from the 0.55g PGA current seismic hazard. The seismic capacities for the SLERF SSCs were determined using tabulated seismic capacities based on experience data outlined in Section 4.2, Seismic Capacities based on Experience, of Reference 15. The experience data covers both structures in Section 4.2.2, for the fragility of the containment building, and equipment in Section 4.2.1, for the fragilities of piping, penetrations and valves that could lead to LERF.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 25 1.4 12

§ 10 C

0

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~ 08 u

~

06

~

u

<IJ

~04 0.2 0,0 0.1 10 100 1requency (I lz)

- - RG l.60 - GMRS - -GMRS-0.SSPGA Figure 6 5% Damped SSE and GMRS (anchored to 0.55g PGA) at HNP A virtual walkdown of the key areas of interest to the SLERF fragility assessment was performed to verify the assumptions in the analysis. After the plant drawings were analyzed, photos of penetrations, valves, and piping were reviewed, and video walkdowns in the areas of interest, including GoPro 3D videos inside containment, were performed. The areas where the SLERF piping, penetrations, and valves exist in both the Containment Building and the Auxiliary Building were reviewed, and interactions that could affect any of the penetrations were assessed. The overall conclusion from the virtual walkdowns is that nothing was observed (e.g., seismic interactions, differential displacements, equipment or support degradations, etc.)

that would degrade the seismic capacities for the valves, piping and penetrations. As such, the seismic capacities from Tables 4-2 and 4-4 from Reference 15 can be used directly to develop fragilities.

All the bounding fragilities were assessed to have HCLPF capacities greater than 0.55g as shown in Table 6.1. The limiting capacity for the mechanical penetrations is used as part of the seismic conditional large early release probability (CLERP) in the SLERF calculations. This capacity is controlling over any functional relay failure as the IPEEE relay assessment concluded that there is a margin of 2.4 above the RLE (i.e., 0.72g). The calculated spectral ratios for the mechanical penetrations are provided in Table 6-2.

As with the SCDF calculation described in the response to RAI 5 above, the frequency ranges that drive the plant SLERF are typically very broad, including contributions from 1 Hz to PGA.

The methodology used in the SCDF calculation was applied to the estimate of SLERF to account for contribution of the various spectral frequencies to the overall SCDF. The methodology accounts for the contribution to seismic risk across the frequency range and is a more realistic conservative representation of seismic risk than using PGA alone.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 26 Table 6 SLERF Critical Component Fragilities Demand Capacity HCLPF Component Am (g) c R U (g) (g) (g)

Containment 1.15 2.0 0.96 2.17 0.35 0.24 0.26 Structure Mechanical 1.15 1.2 0.57 1.29 0.35 0.24 0.26 Penetrations Piping 1.55 1.8 0.64 1.45 0.35 0.24 0.26 Valves 1.55 1.8 0.64 1.45 0.35 0.24 0.26 Table 6 HNP Plant Level Fragility Data for SLERF Calculations (limiting fragilities for mechanical penetrations)

LERF (PGA) Fragility GMRS Spectral Ratios C50 (g) c HCLPF 10Hz 5Hz 2.5 Hz 1Hz 1.29 0.35 0.57 2.05 1.67 0.97 0.71 The SLERF estimate associated with this spectral weighting is shown mathematically by the following equation:

SLERFavg = SLERFpga + SLERF10 + SLERF5 + SLERF2.5 + SLERF1 where the plant level fragilities determined from the IPEEE assessment (per RAI 5) are assumed to represent seismic CCDPs at various seismic hazard bins. The seismic conditional large early release probabilities CLERPs are represented by convolution of the plant level fragilities and the updated containment LERF fragilities provided in Table 6-2.

The calculated results of the seismic core damage frequency (SCDF) (from the response to RAI

5) and seismic large early release frequency (SLERF) are:

SCDFavg = 4.98E-07 (per year),

SLERFavg = 9.97E-08 (per year), and

SLERF/SCDF Ratio: 0.20 The estimate of the SCDF is less than 1.0E-06 (per year), and the SLERF is less than 1.0E-07 (per year). These results are inherently conservative because the seismic initiating frequencies are convolved with the plant level fragility whose HCLPF capacity is based on the most limiting component in the SMA. As such, the plant level fragility represents a seismic CCDP that is more conservative than a CCDP estimate calculated from a plant support model. No credit is taken for systems modeling, including mitigation systems such as alternate seal injection (ASI) and the dedicated shutdown diesel generator (DSDG); accident mitigation strategies, including FLEX; or for operator actions. Similarly, the conservative SCDF is an input to the SLERF computations, and the screening or lower bound capacity for the mechanical penetrations is used

U.S. Nuclear Regulatory Commission RA-20-0321 Page 27 as the controlling containment fragility for the SLERF calculations. This results in a conservatively biased seismic CLERP and a conservative SLERF calculation.

For any RICT with a 30-day backstop, the seismic incremental core damage probability (ICDP) and seismic incremental large early release probability (ILERP) would be:

ICDP = 4.10E-08 (per 30 days), and

ILERP = 8.20E-09 (per 30 days).

These results demonstrate that the seismic hazard is not significant at HNP and that seismic events will have a negligible impact on configuration-specific risk under TSTF-505. Since it does not impact any maintenance decisions, quantitative modeling of the seismic hazard may be omitted from the RICT calculations per NEI 06-09 (Reference 11).

RAI 7

The NRC staff notes that entries to some TS Actions may imply the loss of one division of battery supply (i.e., TS 3.8.2.1 and TS 3.8.3.1). When in these action statements, one DC bus is not energized by its associated battery bank. Under these conditions, for the purpose of defense-in-depth evaluation, three types of initiators are postulated; 1) plant transients not involving loss of offsite power (LOOP) or loss of cooling accident (LOCA), 2) transients involving LOOP, and 3) transients involving LOCA.

For the Type-1 initiators, transients not involving LOOP or LOCA, the defense-in-depth for the DC power sources is satisfied by the battery charger in the affected DC bus, and the batteries and chargers on the unaffected DC bus (i.e., three sources of power for defense-in-depth considerations). For Type-2 initiators, transients involving LOOP, the defense-in-depth can be satisfied by the unaffected DC bus. However, the affected DC bus associated with the TS action cannot be credited due to loss of AC power to the chargers preventing the start of the associated emergency diesel generator. For Type-3 initiators, transients involving LOCA, generating a safety injection signal without LOOP, the battery chargers when energized could provide power to the associated DC buses if they have sufficient capacity. However, the battery charger capacity appears not to be sufficient per information provided in Updated Final Safety Analysis Report (UFSAR) Table 8.3.2-1. In UFSAR Table 8.3.2-1, it appears that without the battery, the load profile for 125 Volts DC during the LOOP and simultaneous LOOP/LOCA, the battery charger may not have sufficient capacity to meet the load requirements.

It is not clear that, without the batteries, whether the battery chargers alone can support either LOOP, LOCA, or LOOP-and-LOCA initiators. The NRC staff requests the following information to support the electrical evaluation:

1. Capacity of the battery chargers.

2. Information demonstrating that, when the batteries are not available, the battery chargers can provide the required safety injection loads to support the mitigation from design basis accidents with Type-2 and Type-3 initiators.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 28 Duke Energy Response to RAI 7, Part 1 From the Electrical distribution system load factor study:

Component 125 vdc Class 1E Battery Chargers1 Bus 480v MCCs 1A21-SA & 1A31-SA, 480v MCCs 1B21-SB & 1B31-SB Or 1D23 (alternate)

KVA (at 150 amp rating) 34.1 KVA (Normal) 16 KVA (LOCA) 40 (LB 1 - 2) / 20 (LB 3 - 9)

KVA (LOCA/LOOP) 40 (LB 1 - 2) / 20 (LB 3 - 9)

KVA (LOOP) 40 (LB 1 - 2) / 20 (LB 3 - 9)

KVA (Shutdown) 6 KVA (Startup) 16 Efficiency 2 1.00 PF 0.968 Note 1: Only model one of these two redundant chargers as operating.

Note 2: Loading shown is input loading and thus already considers efficiency.

For LOCA, LOCA/LOOP and LOOP conditions, it is conservatively assumed that the chargers are in current limit (115% of rated) during LB 1 & 2 (Load Block 1 & 2 is the first 0 -10 seconds of the Sequencer actuation) due to EDG field flashing and switchgear breaker trip coils all operating at once (LOCA/LOOP and LOOP), followed by 20 KVA in subsequent load blocks.

Capacity of the battery chargers: 34.1 KVA at 150 amp rating Required: 40 KVA during LOCA conditions for LB 1-2 / 20 KVA during LB 3-9 Duke Energy Response to RAI 7, Part 2 For Type-2 initiators, transients involving LOOP, the power supply to the battery charger would be lost due to the LOOP. The safety DC bus would be lost with the battery not available, the EDG field flash would not occur and the EDG would not restore safety AC power.

For Type-3 initiators, transients involving LOCA, it is conservatively assumed that the battery charger would be in current limit (115% of rated) during LB 1 & 2 due to the EDG field flashing and switchgear breaker trip coils operating at once. With the battery charger current limit and the battery not available, the battery charger would not have sufficient capacity to support LOCA load requirements.

RAI 8

The NRC staff verifies that each proposed TS condition design success criteria reflect the redundant or absolute minimum electrical power source/subsystem required to be operable by the LCOs to support the safety functions necessary to mitigate postulated design basis accidents, safely shutdown the reactor, and maintain the reactor in a safe shutdown condition.

The dedicated shutdown diesel generator is credited in several TS actions in the LAR.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 29 To support the electrical evaluation of the proposed electrical power systems TS conditions in the application and verify that the capability of the affected electrical power systems to perform their safety functions (assuming no additional failures) is maintained, the NRC staff requests the following information:

1. Seismic qualification of the dedicated shutdown diesel generator capturing this information can strengthen the defense-in-depth discussion as it relates to the dedicated shutdown diesel generator.

2. Capability of the dedicated shutdown diesel generator to meet the 24-hour mission time (e.g., capacity of fuel source or ability to refuel.)

Duke Energy Response to RAI 8, Part 1 The dedicated shutdown diesel generator (DSDG) is not seismically qualified. However, the DSDG provides an additional layer of protection (i.e., defense-in-depth) beyond the mitigation capability of the TS required emergency DGs, for events (e.g., seismic) resulting in a loss of offsite power. Therefore, although the safety benefit of the DSDG at HNP for postulated seismic events is not quantitatively credited, a reduction in overall seismic CDF and LERF would result if the DSDG were to be credited.

Duke Energy Response to RAI 8, Part 2 The DSDG has the capability to meet the 24-hour mission time. The DSDG fuel tank has sufficient capacity at 75% level (i.e., minimum fuel tank level provided by procedure) to meet the 24-hour mission time.

References

1. NUREG/CR-0098, 1978, Development of Criteria for Seismic Review of Selected Nuclear Power Plants, U.S. Nuclear Regulatory Commission, Washington, D.C., May 1978.

2. NRC Letter, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3 and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident, March 12, 2012 (ADAMS Accession No. ML12053A340).

3. Duke Energy Letter, Seismic Hazard Evaluation and Screening Report, Shearon Harris Nuclear Power Plant, Unit 1, March 27, 2014 (ADAMS Accession No. ML14090A441).

4. Duke Energy Letter, Screening and Prioritization Results Regarding Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Seismic Hazard Re-Evaluations for Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident, May 9, 2014 (ADAMS Accession No. ML14111A147).

U.S. Nuclear Regulatory Commission RA-20-0321 Page 30

5. Duke Energy Letter, Shearon Harris Nuclear Power Plant, Docket No. 50-44/License No. NPF-63, Response to Generic Letter 88-20 Supplement 4 - Individual Plant Examination for External Events (IPEEE), June 30, 1995 (ADAMS Accession No. ML9507060075).

6. Electric Power Research Institute (EPRI) Letter RSM-031114-077 to Nuclear Energy Institute, Fleet Seismic Core Damage Frequency Estimates for Central and Eastern U.S. Nuclear Power Plants Using New Site-Specific Hazard Estimates, March 11, 2014 (ADAMS Accession No. ML14083A586).

7. Generic Issue 199 (GI-199), Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants Safety Risk Assessment, U.S. Nuclear Regulatory Commission, Washington, DC, August 2010 (ADAMS Accession No. ML11356A034).

8. Kennedy, R.P. Overview of Methods for Seismic PRA and Margins Including Recent Innovations, Proceedings of the Organization for the Economic Cooperation and Development/Nuclear Energy Agency Workshop on Seismic Risk, Tokyo, Japan, 10 - 12 August 1999.

9. ASME Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications. American Society of Mechanical Engineers and American Nuclear Society Standard ASME/ANS RA-Sb-2009 (Addenda to ASME/ANS RA-S-2008).

10. Seismic Evaluation Guidance: Screening, Prioritization and Implementation Details (SPID) for the Resolution of Fukushima Near-Term Task Force Recommendation 2.1:

Seismic, Electric Power Research Institute (EPRI) Final Report 1025287, Palo Alto, CA, February 2013.

11. NEI 06-09, Rev. 0, Risk-Informed Technical Specifications Initiative 4b - Risk Managed Technical Specifications (RMTS) Guidelines, November 2006.

12. Duke Energy Letter, License Amendment Request to Revise Technical Specifications to Adopt Risk-Informed Completion Times TSTF-505, Revision 2, Provide Risk Informed Extended Completion Times - RITSTF Initiative 4b, October 7, 2019 (ADAMS Accession No. ML19280C844).

13. Electric Power Research Institute, A Methodology for Assessment of Nuclear Power Plant Seismic Margin, Revision 1, EPRI NP-6041-SLR1, Palo Alto, CA, August 1, 1991.

14. Shearon Harris Nuclear Power Plant - Updated Final Safety Analysis Report, Chapter 3, Amendment 63.

U.S. Nuclear Regulatory Commission RA-20-0321 Page 31

15. Electric Power Research Institute, Seismic Fragility and Seismic Margin Guidance for Seismic Probabilistic Risk Assessments, EPRI 3002012994, Palo Alto, CA, September 27, 2018.

16. Electric Power Research Institute, Pipe Rupture Frequencies for Internal Flooding Probabilistic Risk Assessments, EPRI 3002000079, Palo Alto, CA, April 2013.

U.S. Nuclear Regulatory Commission RA-20-0321 Attachment 2 Revised Technical Specifications Mark-Up for ESFAS Instrumentation

Harris Technical Specifications Inserts INSERT 1 or in accordance with the Risk-Informed Completion Time Program INSERT 2 Action 13a - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels per Specification 4.3.1.1.

INSERT 3 ACTION 26 - With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels per Specification 4.3.2.1.

ACTION 27 - With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or in accordance with the Risk-Informed Completion Time Program or be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

INSERT4

r. Risk-Informed Completion Time Program This program provides controls to calculate a Risk-Informed Completion Time (RICT) and must be implemented in accordance with NEI 06-09-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines." The program shall include the following:

a. The RICT may not exceed 30 days;

b. A RICT may only be utilized in MODE 1 and 2;

c. When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.

1. For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.

2. For emergent conditions, the revised RICT must be determined within the time limits of the Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

3. Revising the RICT is not required if the plant configuration change would lower plant risk and would result in a longer RICT.

d. For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:

1. Numerically accounting for the increased possibility of CCF in the RICT calculation; or

2. Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.

e. The risk assessment approaches and methods shall be acceptable to the NRC.

The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods used to support this license amendment, or other methods approved by the NRC for generic use; and any

change in the PRA methods to assess risk that are outside these approval boundaries require prior NRG approval.

(

TABLE 3.3-3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO . CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

1. Safety Injection (Reactor Trip.

Feedwater Isolation. Control Room Isolation. Start Diesel Generators. Containment Ventilation Isolation. Phase A Containment Isolation. Start Auxiliary Feedwater System Motor-Driven Pumps. Start Containment Fan Coolers. Start Emergency Service Water Pumps.

Start Emergency Service Water Booster Pumps)

a. Manual Initiation 2 1 2 1. 2. 3. 4 18

b. Automatic Actuation Logic and 2 1 2 1. 2. 3. 4 14 Actuation Relays C. Containment Pressure--High-1 3 2 2 1. 2. 3. 4

d. Pressurizer Pressure--Low 3 2 2 1. 2. 3# 19

e. Steam Line Pressure--Low 3/steam 2/steam 2/steam line 1. 2. 3# 19 line 1i ne in any steam line SHEARON HARRIS - UNIT 1 3/4 3-18 Amendment No. <<H

( ( (

No proposed changes on this page. Provided for information TABLE l. l-3 (Continued} only.

ENlilNEEREO SAFETY FEATURES ACTUAl ION SYSTEM INSTRUMENTATION MINIMUM TOTAL HO. CHANNELS CIIAHNELS APPLICABLE FUNCTIONAL UNIT Of CHANNELS TO TRIP Ol'ERABL~ HODES ACTION

2. Contalnaent Spray

a. Manual lnitt1tton ** 2 1 with 2 1. 2. 3, 4 18 2 coincident

,witches

b. Auto*allc Aclualton 2 1 2 14 Logic and Aclualton Relays

c. .Contatnaent. Pressure-- 4 2 l 1. 2, 3 16 ffigh-3

~ 3. Conlafnaent Isolation

a. Phase "A* l1olatton l) Manual lntttatton 2 1 2 18

2) Auloaaltc Actuation 2 1 2 1, 2, 3, 4 14 Logic and Actuation Relay,

3) Safely Injection See Ile* 1. above for all Safely Injection Initiating functions and requl/eaents. .~..

b. Phase *e* Isolation

1) Manual Containaent See Ile* 2.a. above for Manual Contalnaenl Spray initialing functions Spray lntttatlon and requtreaents.

I

I J'

l

( (

No proposed changes on this page. Provided for information only.

TABLE 3.3-3 (Continued)

I IA ENGIN£EAEO SAFETY FEATURES ACTUATION SYSTEM INSTRUHENTATION z MINIHUfi TOTAL NO.

I

a FUNCTIONAL UNIT Of CHANHELS CHANNELS TO TRIP CHANNELS OPEHAOLE APPLICABLE HODES ACTION M

'f' *

3. Contalflllttnt lsol1tton (Continued) i i 2) Aut01Nttc Actuation 2 l 2 1, 2, l, 4 14 t1

... logic and Actuation I i I

I Relay*

I l) Contatnaent See *ltea 2.c. abovf for Contatnaent Pres~ure lltgh-3 tntttating

\. Pressure--Hlgh-l functions and requlreaents.

Ii c. Contatnaent Ventilation l t!

holatton l

.... 1) Manual tonlalnaanl See ltea 2.a. above for Manual Contatnaent Spray tnttlattng

~ Spray lntttatton functions and requtre* ents.

,1....2, 3, 4,

~

I

2) Autoaattc Actuation 2 1 2 17, 25 Logic and Actuation Mel1y1 I

3) Safety lnjeclton See lte* 1. above for all Safety Injection Initiating functions and requt re* ents.

l

4) Contatn* ent ladloactlvtty

- Area Monitor, 4 See Ta~l* 3.l-6, lte*, la, for tntttattng tuncttons (both preentry and requlreaenl~. .. ..

I afld noraal purges)

~

b. Airborne Ga,eous A1dtoacllvtty

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

~

H

~

~ 3. Containment Isolation (Continued)

(1) RCS Leak 1 See Table 3.3-6, Item lbl, for initiating functions Detection and requirements.

(normal purge)

(2) Preentry Purge 1 See Table 3.3-6, Item lb2, for initiating functions Detector and requirements.

c. ,Airborne Particulate Radioactivity (1) RCS Leak 1 See Table 3.3-6, Item lCl, for initiating functions Detection and requirements.

(normal purge)

(2) Preentry Purge 1 See Table 3.3-6, Item 1C2, for initiating functions Detector and requirements.

5) Manual Phase "A" See Item 3.a.1) above for Manual Phase "A" Isolation initiating Isolation functions and requirements.

4. Main Steaµi Line Isolation

a. Manual Initiation

1) Individual MSIV 1/steam line 1/steam line 1/operating 1, 2, 3, 4 23 Closure steam line

2) System 2 1 2 1, 2, 3

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UN IT OF CHANNELS TO TRIP OPERABLE MODES ACTION

4. Main Steam Line Isolation (Continued) b . Automatic Actuation Logic and 2 1 2 1. 2. 3. 4 14 Actuation Relays

c. Containment Pressure- -High-2 3 2 2 1. 2. 3 w~ I

d. Steam Line Pressure--Low See Item 1.e . above for Steam Line Pressure--Low initiating functions and requirements.

e. Negative Steam Line Pressure 3/steam 2 in any 2/steam line 3***. 4... 19 Rate--High line steam line

5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation Logic and 2 1 2 1. 2 24 Actuation Relays

b. Steam Generator Water 4/stm. gen. 2/stm. gen. 3/stm. gen. 1. 2 19 Level--High-High (P-14) in any stm. in each gen. stm. gen.

c. Safety Injection See Item 1. above for all Safety Injection initiating functions and requirements.

SHEARON HARRIS - UNIT 1 3/4 3-22 Amendment No . .:i..o.:t

No proposed changes on this page. Provided for information only.

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO . CHANNELS CHANNELS APPLICABLE FUNCTIONAL UN IT OF CHANNELS TO TRIP OPERABLE MODES ACTION

6. Auxiliary Feedwater

a. Manual Initiation

1) Motor -Driven Pumps 1/pump 1/pump 1/pump 1. 2. 3 23

2) Turbine-Driven Pumps 2/pump 1/pump 2/pump 1. 2. 3 23

b. Automatic Actuation Logic and 2 1 2 1. 2. 3 21 Actuation Relays C. Steam Generator Water Level--Low-Low

1) Start Motor - 3/stm. gen. 2/stm. gen. 2/stm. 1. 2. 3 19 Driven Pumps in any stm. gen. in gen. each stm .

gen.

2) Start Turbine- 3/stm. gen. 2/stm. gen. 2/stm. 1. 2. 3 19 Driven Pump in any 2 gen. in stm. gen. each stm.

gen.

d. Safety Injection Start See Item 1. above for all Safety Injection initiating Motor-Driven Pumps functions and requirements.

e. Loss-of-Offsite Power Start See Item 9. below for Loss of Offsite Power initiating Motor-Driven Pumps and functions and requirements.

Turbine-Driven Pump

f. Trip of All Main Feedwater Pumps 1/pump 1/pump 1/pump 1. 2 15 Start Motor-Driven Pumps SHEARON HARRIS - UNIT 1 3/4 3-23 Amendment No. 1 01

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

6. Auxiliary Feedwater (Continued)

g. Steam Line Differential 3/steam line 2/steam line 2/steam 1. 2. 3 Pressure--High twice with any line steamline low Coincident With Main Steam Line See Item 4. above for all Steam Line Isolation initiating Isolation (Causes AFW Isolation) functions and requirements

7. Safety Injection Switchover to Containment Sump

a. Automatic Actuation Logic and 2 1 2 1. 2, 3, 4 14 Actuation Relays

b. RWST Level--Low-Low 4 2 3 1. 2. 3, 4 16 Coincident With Safety Injection See Item 1. above for all Safety Injection initiating functions and requirements.

8. Containment Spray Switch-over to Containment Sump

a. Automatic Actuation Logic and 2 1 2 1. 2. 3, 4 14 Actuation Relays SHEARON HARRIS - UNIT 1 3/4 3- 24 Amendment No ...io.:l

No proposed changes on this page.

Provided for information only.

TABLE 3.3-3 (Continued)

ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. OF CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT CHANNELS TO TRIP OPERABLE MODES ACTION

8. Containment Spray Switch-over to Containment Sump (Continued)

b. RWST--Low Low See Item 7.b. above for all RWST--Low Low initiating functions and requirements.

Coincident With Containment Spray See Item 2 above for all Containment Spray initiating functions and requirements.

9. Loss-of-Offsite Power

a. 6.9 kV Emergency Bus--Undervoltage 3/bus 2/bus 2/bus 1, 2, 3, 4 15a Primary

b. 6.9 kV Emergency Bus--Undervoltage 3/bus 2/bus 2/bus 1, 2, 3, 4 15a Secondary

10. Engineered Safety Features Actuation System Interlocks

a. Pressurizer Pressure, P-11 3 2 2 1, 2, 3 20 Not P-11 3 2 2 1, 2, 3 20

b. Low-Low Tavg, P-12 3 2 2 1, 2, 3 20

c. Reactor Trip, P-4 2 2 2 1, 2, 3 22

d. Steam Generator Water Level, P-14 See Item 5.b. above for all P-14 initiating functions and requirements.

SHEARON HARRIS - UNIT 1 3/4 3-25 Amendment No. 179

TABLE 3.3-3 (Continued)

TABLE NOTATIONS

Trip function may be blocked in this MODE below the P-11 (Pressurizer Pressure Interlock)

Setpoint.

- During CORE ALTERATIONS or movement of irradiated fuel in containment, refer to Specification 3.9.9.

- - Trip function automatically blocked above P-11 and may be blocked below P-11 when Safety Injection on low steam line pressure is not blocked.

r lNSERT1 ACTION STATEMENTS ACTION 14 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1, provided the other channel is OPERABLE.

ACTION 15 - With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed until performance of the next required CHANNEL OPERATIONAL TEST provided the inoperable channel is placed in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ACTION 15a - With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . With less than the minimum channels OPERABLE, operation may proceed provided the minimum number of channels is restored within one hour, otherwise declare the affected diesel generator inoperable. When performing surveillance testing of either primary or secondary undervoltage relays, the redundant emergency bus and associated primary and secondary relays shall be OPERABLE.

ACTION 16 - With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and the Minimum Channels OPERABLE requirement is met. One additional channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1.

ACTION 17 - With less than the Minimum Channels OPERABLE requirement, operation may continue provided the Containment Purge Makeup and Exhaust Isolation valves are maintained closed while in MODES 1, 2, 3 and 4 (refer to Specification 3.6.1.7). For MODE 6, refer to Specification 3.9.4.

ACTION 18 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

INSERT 1 SHEARON HARRIS - UNIT 1 3/4 3-26 Amendment No. 179

TABLE 3.3-3 (Cont inued )

ACTION STATEMENTS (Continued)

ACTION 19 - With the number of OPERABLE channels one less than the Total Number of Channels. operation may proceed provided the following conditions are satisfied: INSERT 1

a. The inoperable annel is placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . and

b. The Minimum Channels OPERABLE requirement is met: however.

the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels per Specification 4.3.2 .1.

ACTION 20 - With less than the Minimum Number of Channels OPERABLE. within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months determine by observation of the associated permissive annunciator window(s) that the interlock is in its required state for the existing plant condition . or apply Specification 3.0 .3. INSERT 1 ACTION 21 - With the number of OPERABLE cha nels one less than the Minimum Channels OPERABLE requirement . estore the inoperable channel to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months s: however. one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1 provided the other channel is OPERABLE .

ACTION 22 - With the number of OPERABLE channels one less than the Total Number of Channels. restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY withi n 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 23 - With the number of OPERABLE channels less than the Total Number of Channels. declare the associated equipment inoperable and take the appropriate ACTION required in accordance with the specific equipment specification . INSERT 1 ACTION 24 - With the number of OPERABLE cha els one less than the Minimum Channels OPERABLE requirement . estore t he inoperable channel to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months : however. one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.2.1 provided the other channel is OPERABLE .

ACTION 25 - During CORE ALTERATIONS or movement of irradiated fuel within containment. comply with the ACTION statement of Specification 3.9.9.

!INSERT 3 I L

SHEARON HARRIS - UNIT 1 3/4 3- 27 Amemdment No . ~

v t e Letter Sequence Response to RAI
EPID:L-2019-LLA-0218, TSTF-505 (Approved, Closed)
Initiation Request Acceptance Supplement Administration Questions 29 September 2020 Answers 11 November 2020 Results Approval Other: ML20141L623, ML20175A575, ML20329A381, ML21116A207
MONTHYEAR2020-05-20 [Table View]

RA-20-0321, Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specifications to Adopt Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Comple

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RA-20-0321, Response to Request for Additional Information Regarding License Amendment Request to Revise Technical Specifications to Adopt Technical Specifications Task Force (TSTF) Traveler TSTF-505, Revision 2, Provide Risk-Informed Extended Comple

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