ML101600452
| ML101600452 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 06/01/2010 |
| From: | Lynch T Constellation Energy Nuclear Group |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| TAC ME3736 | |
| Download: ML101600452 (68) | |
Text
Thomas A. Lynch P.O. Box 63 Plant General Manager Lycoming, New York 13093 315.349.5200 315.349.1321 Fax CENO a joint venture of Constellation neq-zvDF NINE MILE POINT NUCLEAR STATION June 1, 2010 U. S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTENTION:
Document Control Desk
SUBJECT:
Nine Mile Point Nuclear Station Unit No. 2; Docket No. 50-410 License Amendment Request Pursuant to 10 CFR 50.90: Extension of the Completion Time for an Inoperable Diesel Generator - Response to NRC Acceptance Review Comments (TAC No. ME3736)
REFERENCES:
(a) Letter from S. Belcher (NMPNS) to Document Control Desk (NRC), dated March 30, 2010, License Amendment Request Pursuant to 10 CFR 50.90:
Extension of the Completion Time for an Inoperable Diesel Generator -
Technical Specification 3.8.1, AC Sources - Operating (b) Letter from R. V. Guzman (NRC) to S. L. Belcher (NMPNS), dated May 11, 2010, Nine Mile Point Nuclear Station, Unit No. 2 - Acceptance Review of Requested Licensing Action Re: Extension of Completion Time for Inoperable Diesel Generator (TAC No. ME3736)
Nine Mile Point Nuclear Station, LLC (NMPNS) hereby transmits supplemental information in support of a previously submitted request for amendment to Nine Mile Point Unit 2 Renewed Operating License NPF-69. The request, dated March 30, 2010 (Reference a), proposed to modify Technical Specification Section 3.8.1, "AC Sources - Operating," to extend the Completion Time for an inoperable Division 1 or Division 2 diesel generator from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days. By letter dated May 11, 2010 (Reference b), the NRC forwarded comments required to be addressed prior to the staff's completion of the acceptance review for the amendment request. The supplemental information, provided in Attachment 1 to this letter A-bC(
Document Control Desk June 1, 2010 Page 2 and supported by the other attachments (Attachments 2 and 3) referenced therein, responds to each of the acceptance review comments documented in Reference (b).
The supplemental information contained in this submittal does not affect the No Significant Hazards Determination analysis provided by NMPNS in Reference (a). Pursuant to 10 CFR 50.91(b)(1), NMPNS has provided a copy of this supplemental information to the appropriate state representative. This letter contains no new regulatory commitments.
Should you have any questions regarding the information in this submittal, please contact T. F. Syrell, Licensing Director, at (315) 349-5219.
Very truly yours, STATE OF NEW YORK TO WIT:
COUNTY OF OSWEGO I, Thomas A. Lynch, being duly sworn, state that I am Plant General Manager, and that I am duly authorized to execute and file this supplemental information on behalf of Nine Mile Point Nuclear Station, LLC. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other Nine Mile Point employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it to be reliable.
Subscribed and sworn before me, a Notary Public in and for the State of New York and County of
______ W',
this J-"
day of JLtn_
,2010.
WITNESS my Hand and Notarial Seal:
N tN y Public AMY A. GREEN My Commission Expires:
Rotary Public State of New York Registration No. 01GR5038041 Oualified in Oswego County i
r I
Commission Expires January 11, 20.LI hate TAL/DEV
Document Control Desk June 1, 2010 Page 3 Attachments:
- 1. Nine Mile Point Unit 2 -
Response to NRC Acceptance Review Comments Regarding the Proposed Extension of the Completion Time for an Inoperable Diesel Generator
- 2.
Comparison of the NMP2 Fire PRA Model to the Technical Elements of Regulatory Guide 1.200, Revision 2, Section 1.2.4
- 3.
Comparison of the NMP2 Seismic PRA Model to the Technical Elements of Regulatory Guide 1.200, Revision 2, Section 1.2.6 cc:
S. J. Collins, NRC R. V. Guzman, NRC Resident Inspector, NRC A. L. Peterson, NYSERDA
2 ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR Nine Mile Point Nuclear Station, LLC June 1, 2010
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR By letter dated March 30, 2010, Nine Mile Point Nuclear Station, LLC (NMPNS) requested an amendment to Nine Mile Point Unit 2 (NMP2) Renewed Facility Operating License NPF-69.
The proposed amendment would modify Technical Specification (TS) Section 3.8.1, "AC Sources -
Operating," to extend the Completion Time for an inoperable Division 1 or Division 2 diesel generator (DG) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days. This attachment provides supplemental information in response to the acceptance review comments documented in the NRC's letter dated May 11, 2010. Each individual NRC comment is repeated (in italics), followed by the NMPNS response.
Probabilistic Risk Assessment (PRA) Licensing Review Comment 1 The submittal identifies that fire and seismic risk are included in the PRA model. A single paragraph referring to the individual plant examination for external events (IPEEE) submittal and to the NRC IPEEE evaluation is provided, along with a table of the NRC review comments and their disposition from the IPEEE. The purpose of the IPEEE and the NRC Research Office staff evaluation was to identify significant plant vulnerabilities, not to establish that the analyses were state-of-the art risk analyses to support licensing actions. This level of quality is not acceptable to support a risk-informed Technical Specification (TS) change. The licensee will need to submit PRA quality information on its fire and seismic risk models consistent with Regulatory Guide (RG) 1.200, Revision 2, Section 1.2.4 (fires) and 1.2.6 (seismic) to demonstrate that these quantitative models are adequate for this application. The licensee should also submit confirmation that the existing fire and seismic models, stated to be based on the IPEEE, still adequately reflect the current plant configuration with regards to mitigation of these events.
Response
As noted in Section 3.2.1 of the license amendment request (submittal), the NMP2 IPEEE evaluation is used as the basis for the internal fire and seismic models which are incorporated directly into the at-power internal events PRA model. This allows fire and seismic initiating events to be quantified using the latest internal events fault trees and accident sequences, with the external event initiators failing the appropriate systems, functions, and crew response actions. The current internal fire and seismic PRA models are in accordance with the guidance in Sections 1.2.4 and 1.2.5, respectively, of RG 1.200, Revision 1. NMPNS has confirmed that these models continue to adequately reflect the current plant configuration with regard to mitigation of these events by reviewing modifications to the plant that have occurred since the IPEEE was performed.
It is recognized that the internal fire and seismic PRA models do not meet all of the supporting requirements of Capability Category II of ASME/ANS PRA Standard RA-Sa-2009. Nevertheless, it is judged that these hazard analyses provide reasonable evaluations of the quantitative contribution to the risk metrics associated with the proposed extension of the Completion Time (CT) for an inoperable Division 1 or Division 2 DG. This conclusion is based on an assessment that compares the internal fire and seismic PRAs to the technical elements outlined in RG 1.200, Revision 2. Further discussion regarding the internal fire and seismic PRA models is provided below.
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ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR Internal Fire PRA The internal fire events analysis that is documented in the IPEEE is used as the basis for the NMP2 internal fire hazard quantification. In the IPEEE, internal fires were addressed by using a combination of the Fire Induced Vulnerability Evaluation (FIVE) methodology and fire PRA techniques described in NUREG/CR-4840. The NMP2 fire PRA study is a detailed analysis that uses quantification and model elements (e.g., system fault trees, event tree structures, random failure rates, common cause failures) consistent with those employed in the internal events portion of the NMP2 PRA.
The approach taken for the fire PRA was to perform a scenario-by-scenario analysis of unscreened compartments accounting for the relative location of ignition sources and targets, fire severity, damage thresholds, and fire suppression. The PRA was preceded by a fire compartment interaction analysis and a quantitative screening analysis, both performed in a manner consistent with the FIVE guidance.
Internal fire events are integrated with the internal events model and contribute approximately 30 percent to the baseline core damage frequency (CDF) and 19% to the baseline large early release frequency (LERF) for NMP2. However, because only a small fraction of the fire-induced core damage sequences lead to a loss of offsite power (when the DGs would be required), the results of the risk evaluation for the proposed amendment show that the contribution of fire event sequences to the delta risk estimates is relatively small.
NMPNS has performed an assessment that compares the current NMP2 internal fire PRA model to the technical elements outlined in Section 1.2.4 of RG 1.200, Revision 2. The results of this assessment are summarized in Attachment 2, which follows the format of Table 5 in RG 1.200, Revision 2. In those cases where the current internal fire PRA model is not entirely consistent with the technical elements of RG 1.200, Revision 2, assessments that include sensitivity studies have been performed to demonstrate that the model is still adequate for application to the proposed amendment.
Seismic PRA The seismic analysis that is documented in the IPEEE is used as the basis for the NMP2 seismic hazard quantification. A seismic PRA analysis approach was taken to identify potential seismic vulnerabilities at NMP2. The NMP2 seismic PRA method uses an acceptable methodology as identified in NUREG-1407.
This PRA technique includes consideration of the following elements:
Seismic hazard analysis Seismic fragility assessment Seismic systems analysis Quantification of the seismically induced core damage frequency The NMP2 seismic analysis also included the following elements:
Human interactions and recovery actions under seismic conditions Relay chatter during a seismic event
" Containment performance during a seismic event 2 of 12
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR In the NMP2 response to Generic Letter 88-20, Supplement 4, NMPNS committed to the EPRI seismic margins analysis (SMA) method. Understanding the importance of the PRA in support of decision making and that the IPEEE should add to the completeness of the PRA, the review level earthquake (RLE) used for screening was 0.5g, rather than 0.3g, as recommended by NUREG-1407. The seismic capacity of NMP2 was expected to be high; utilizing a 0.5g RLE provides more knowledge relative to the seismic capability of the plant. Relays that could impact the success path due to chatter were identified and evaluated rather than attempting to identify only those most susceptible to failure.
Seismic hazard analysis was performed to estimate the annual frequency of exceeding different levels of seismic ground motion at the plant site. The seismic hazard analysis focused on the identification of the sources of earthquakes that may impact the Nine Mile Point site, evaluation and assessment of the frequencies of occurrence of earthquakes of different magnitudes, estimation of the intensity of earthquake-induced ground motion (e.g., peak ground acceleration) at the site, and finally, the integration of this information to estimate the frequency of exceedance for selected levels of ground motion. For the Nine Mile Point site, there are two published site-specific hazard studies that were used in the IPEEE: (1)
EPRI NP-6395-D, "Probabilistic Seismic Hazard Evaluation at Nuclear Power Plant Sites in the Central and Eastern United States: Resolution of the Charleston Earthquake Issue," and (2) NUREG-1488, "Revised Livermore Seismic Hazard Estimates for 69 Nuclear Power Plant Sites East of the Rocky Mountains."
Seismic events contribute approximately 4% to the baseline CDF and 35% to the baseline LERF for NMP2.
Note that accident scenarios involving postulated seismic-induced DG failure have no contribution to the delta risk estimates of this analysis. This fact is due to the high correlation of seismic induced failures of similar equipment in like locations, i.e., all DGs would be failed (this is a standard seismic PRA modeling approach). Therefore, for accident scenarios involving seismic induced DG failure, there is no difference in the CDF whether one of the DGs is out of service for maintenance or not.
NMPNS has performed an assessment that compares the current NMP2 seismic PRA model to the technical elements outlined in Section 1.2.6 of RG 1.200, Revision 2. The results of this assessment are summarized in Attachment 3, which follows the format of Table 7 in RG 1.200, Revision 2. In those cases where the current seismic PRA model is not entirely consistent with the technical elements of RG 1.200, Revision 2, sufficient discussion is provided to demonstrate that the model is still adequate for application to the proposed amendment.
Comment 2 Other plant hazards are not identified as included in the quantitative risk analyses, nor are qualitative dispositions provided to determine that the risk from these hazard groups is insignificant. This is inconsistent with RG 1.174 which requires all hazards to be addressed. The licensee will need to address these external hazards unless they are included in the quantitative results; if so, then the technical adequacy of these PRA models will then need to be addressed per RG 1.200 Section 1.2.
Response
The NMP2 IPEEE performed an examination of high winds and tornados, external floods, and transportation and nearby facility accidents (referred to as "other hazards") to assess their potential for 3 of 12
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR impacting the NMP2 risk profile. Utilizing the progressive screening methodology described in NUREG-1407, the evaluation for each type of potential hazard included, as a minimum, a review of the plant relative to the hazard, a review of changes since the issuance of the plant's operating license, and a review of the plant against the 1975 Standard Review Plant (SRP). The IPEEE concluded that there was no significant quantitative risk contribution from these other hazards (i.e., they were screened), and none of the other hazards were required to be added to the PRA model. The underlying basis for this conclusion was NMP2 conformance with the SRP, which included consideration of hazard frequency and plant design.
Since the IPEEE was performed, the only significant change relating the other hazards has been the addition of a common hydrogen gas storage facility for Nine Mile Point Unit 1 (NMP1) and NMP2 to support implementation of reactor coolant system hydrogen water chemistry.
The addition of the hydrogen storage facility was evaluated and found to have a negligible impact on CDF and was screened from further consideration in the NMP2 PRA.
The proposed amendment to extend the CT for an inoperable Division 1 or Division 2 DG does not alter the conclusion of the IPEEE that the other hazards are negligible contributors to plant risk; therefore, explicit treatment of these other hazards is not necessary.
Comment 3 The evaluation of the internal events PRA model using RG 1.200 and the applicable PRA standard does not identify the relevant capability category(ies) associated with this application, nor is the capability category(ies) of the PRA model identified in the submittal. This is inconsistent with RG 1.200 Section 4.2.
The licensee will need to supplement their submittal to address the capability category(ies) of the standard applicable to this analysis.
Response
The NMP2 updated internal events PRA model used to perform the risk evaluation for the proposed license amendment meets American Society of Mechanical Engineers and American Nuclear Society (ASME/ANS) PRA Standard RA-Sa-2009, Capability Category II requirements.
Comment 4 There is no statement regarding any permanent plant changes implemented but not incorporated into the PRA model used to support this risk analysis. This is inconsistent with RG 1.200 Section 4.2.
The licensee will need to supplement their submittal to address this issue.
Response
The internal events PRA model used to support the proposed license amendment reflects the as-designed, as-operated plant at the time that the risk evaluation was performed. All permanent plant changes either have been incorporated into the PRA or have been evaluated as not relevant to the PRA. In addition, a review of currently planned permanent plant changes has been performed. Two planned plant changes 4 of 12
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR are already incorporated into the internal events PRA model, as discussed in Section 3.2.1 of the submittal (i.e., extended power uprate and the Division 3 DG backup cooling water supply). Other than those two changes, the review did not identify any other currently planned changes (such as design or operational practices) that would have a significant effect on the risk evaluation performed for the proposed license amendment. PRA model maintenance is further discussed in Section 3.2.2 of the submittal.
Please refer to the response to Comment 1 regarding the internal fire and seismic PRA models.
Comment 5 The submittal makes extensive commitments to Tier 2 equipment restrictions (Section 3.2.5) which are credited in the risk analyses. These restrictions are to be incorporated into plant procedures and the TS bases, but not into the TS action requirements. There is, no sensitivity analyses provided to allow the NRC staff to determine which, if any, of these restrictions are critical to the acceptance of this change.
The licensee will need to provide appropriate sensitivity analyses to permit NRC staff review of the acceptability of these restrictions and their control in procedures and TS bases, rather than in the TS actions.
Response
As described in Section 3.2.5 of the submittal, the following compensatory measures and configuration risk management controls have been credited in the PRA evaluation for the proposed amendment:
Case #
Tier 2 Equipment Restrictions Sensitivity Case N/A Div 3 Unavailability The other two DGs are operable and no planned maintenance or cid inasea3.
1 testing activities are scheduled on those two DGs.
D 2nailailt is no Div 2 Unavailability is not allowed by TS.
Switchyard Maintenance W/O Line 5 No planned maintenance or testing activities are scheduled in W/O Line 6 Scriba Substation, the NMP2 115kV switchyard, or the 115kV W/O Rsre T
power supply lines and transformers which could cause a line W/O Reserve Transformer B outage or challenge offsite power availability.
W/O Res A & Line 5 W/O Res B & Line 6 3
The High Pressure Core Spray (HPCS) system is available and no W/O Div 3 planned maintenance or testing activities are scheduled.
4 The Reactor Core Isolation Cooling (RCIC) system is available W/O RCIC and no planned maintenance or testing activities are scheduled.
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ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR Case #
Tier 2 Equipment Restrictions Sensitivity Case The NMP2 and NMPl diesel-driven fire pumps (DFP) and the cross-tie between the NMP2 and NMP1 fire protection water W/O Ul DFP 5
supply systems are available to provide a backup cooling water W/O U2 DFP supply to the Division 3 DG and no planned maintenance or testing activities are scheduled.
The Division 1 and Division 2 residual heat removal (RHR)
W/O RHR A 6
pumps and the low pressure core spray (LPCS) pump are W/O RHR B available and no planned maintenance or testing activities are W/O LPCS scheduled.
W/O RHR B & LPCS Both divisions of the redundant reactivity control system and the W/O ATWS Div 1 standby liquid control system (equipment required for mitigation W/O ATWS Div 2 of anticipated transients without scram (ATWS) events) are System (SLCS) Div 1 available and no planned maintenance or testing activities are S
SLCS Div 2 scheduled.
W/O SLCS Div 2 The stability of existing and projected grid conditions will be N/A 8
confirmed prior to planned entry into the extended DG CT by Bounded by case 2.
contacting the transmission system operator.
Operating crews will be briefed on the DG work plan. As a minimum, the briefing will include the following important procedural actions that could be required in the event a Loss of Offsite Power (LOOP), Station Blackout (SBO), or fire condition occurs:
Alignment of the fire protection water supply system to a provide cooling water to the Division 3 DG.
b Establishing the cross-connection to allow the Division 3 DG probability (HEP) was to power either Division 1 or Division 2 loads.
c Utilizing the portable generator as a backup source of AC
_ power to one of the Division 1 or Division 2 battery chargers.
9 d Utilizing the portable power supplies to maintain operability of ZOSVL1 d the safety relief valves (SRVs).
Closing containment isolation valves in the drywell floor drain and equipment drain lines. PRA operator actions ZIS03 (SBO) and ZIS05 (Fire).
ZIS03 - Operator fails to locally close equipment and floor ZIS03 e drain motor operated valves (MOVs) in the reactor building ZIS05 early in the SBO event.
ZIS05 - Operator fails to locally close equipment and floor drain MOVs in the reactor building early in the Fire event.
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ATTACHMENT 1 NINE MILE POINT UNIT 2' RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR Items 1 through 7 were credited by removing maintenance unavailability for the subject systems/equipment. Item 8 was credited qualitatively only by not increasing the HEP during the extended DG CT. For Items 9a, 9b, and 9c, no improved HEP was credited. Sensitivity analyses have been performed for Items 2 through 7, 9d, and 9e (Item 1 is excluded since TS 3.8.1 requires specific actions with two or more DGs inoperable). The results for Items 2 through 7 are presented in Tables 5-1a and 5-1 b below.
Table 5-1 a: Sensitivity Results, With and Without Protected Equipment Switchyard w/o W/o W/o W/o W/o W/o W/o With Value W/o W/o W/o W/o LINE 5 LINE 6 DIV 3 RCIC UI DFP U2 DFP Protected Accept.
& RES
& RES B Equipment Criteria A
2a 2b 2c 2d 2e 2f 3
4 5a 5b ACDF.*v 4.2E-07 4.1E-07 7.OE-07 7.2E-07 7.1E-07 7.2E-07 1.8E-06 3.2E-06 3.1E-07 4.6E-07 2.9E-07
<lE-6 ALERF.e 2.5E-08 3.8E-08 4.6E-08 3.8E-08 4.7E-08 3.9E-08 1.4E-07 2.8E-07 2.5E-08 3.7E-08 2.2E-08
<IE-7 ICCDP1 3.5E-07 3.3E-07 8.2E-07 3.4E-07 8.3E-07 3.5E-07 1.4E-06 3.1E-06 2.4E-07 3.5E-07 2.2E-07
<5E-7 ICCDP2 4.5E-07 4.6E-07 5.2E-07 1.0E-06 5.2E-07 L.OE-06 2.1E-06 3.2E-06 3.6E-07 5.3E-07 3.3E-07
<5E-7 ICLERP1 2.2E-08 2.4E-08 6.1E-08 2.4E-08 6.1E-08 2.4E-08 1.1E-07 2.7E-07 2.1E-08 3.OE-08 1.9E-08
<5E-8 ICLERP2 2.6E-08 5.OE-08 2.8E-08 4.9E-08 2.8E-08 5.OE-08 1.7E-07 2.7E-07 2.7E-08 4.1E-08 2.4E-08
<5E-8 Table 5-lb: Sensitivity Results, With and Without Protected Equipment W/o Wo Wo W/o W/o W/o W/o W/o RHS A RHS B LPCS RHS B &
ATWS ATWS SLCS SLCS With Acceptance Value LPCS DIV 1 DIV 2 A
B Protected Criteria 6a 6b 6c 6d 7a 7b 7c 7d Equipment ACDFave 4.OE-06 6.8E-07 3.9E-07 7.9E-07 2.9E-07 2.9E-07 2.9E-07 2.9E-07 2.9E-07
<IE-6 ALERFave 4.2E-08 3.1E-08 3.7E-08 4.3E-08 2.3E-08 2.3E-08 2.3E-08 2.2E-08 2.2E-08,
<IE-7 ICCDPi 1.3E-06 9.3E-07 2.5E-07 9.6E-07 2.2E-07 2.2E-07 2.2E-07 2.2E-07 2.2E-07
<5E-7 ICCDP2 6.4E-06 3.7E-07 5.OE-07 5.4E-07 3.4E-07 3.3E-07 3.4E-07 3.3E-07 3.3E-07
<5E-7 ICLERP1 3.5E-08 3.5E-08 3.2E-08 4.3E-08 1.9E-08 2.OE-08 1.9E-08 2.OE-08 1.9E-08
<5E-8 ICLERP2 4.6E-08 2.5E-08 3.8E-08 4.0E-08 2.5E-08 2.4E-08 2.5E-08 2.4E-08 2.4E-08
<5E-8 Table 5-2 provides risk metrics without any of the credited compensatory operator actions, 9d, 9e (SBO),
and 9e (Fire), and also with each action considered individually. Each of these cases assumes the Tier 2 equipment restrictions (protected equipment) are applied.
Table 5-2: Sensitivity Results, With and Without Compensatory Operator Actions Without With With With With Acceptance Comp ZOSVL1 ZIS03 ZIS05 All Criteria 9d 9e (SBO) 9e (Fire)
Comp ACDFave 3.7E-07 2.9E-07 3.7E-07 3.7E-07 2.9E-07
<lE-6 ALERFave1.OE-07 6.2E-08 8.8E-08 4.5E-08 2.2E-08
<lE-7 ICCDP_
3.3E-07 2.2E-07 3.3E-07 3.3E-07 2.2E-07
<5E-7 ICCDP2 3.8E-07 3.3E-07 3.8E-07 3.8E-07 3.3E-07
<5E-7 ICLERP1 1.2E-07 5.6E-08 L.lE-07 4.OE-08 1.9E-08
<5E-8 ICLERP 2 7.6E-08 6.3E-08 5.6E-08 4.7E-08 2.4E-08
<5E-8 7 of 12
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR Comment 6 The risk analyses are dependent upon the once-per-2-year use of the extended completion times (CTs),
but there is no justification as to why this assumption is valid. The licensee proposes to control voluntary use of the CT to once-per-2-years, but this is to be addressed in the TS bases, not in the TS action.
Emergent repairs may result in additional use of the extended CT. The licensee will need to provide a technical justification for this assumption, and will need to provide sensitivity studies to address emergent repair use of the extended CT considering the increased probability of common cause failures (consistent with RG 1.177, Appendix A).
Response
As discussed in Section 2.2 of the submittal, the proposed amendment is desired to permit required DG inspections, maintenance, and overhauls to be scheduled and performed online. Either a planned 2-year inspection or a planned 6-year overhaul is scheduled once every 2 years for each DG (see the table in the response to Comment 7 below). This schedule for planned maintenance activities forms the basis for the assumption utilized in the risk assessment for the proposed amendment. This assumption is consistent with other similar license amendment requests that have been previously reviewed and approved by the NRC (e.g., River Bend Station - NRC letter dated September 25, 2002, Accession No. ML022590314; Columbia Generating Station - NRC letter dated April 14, 2006, Accession No. ML061000672; and Prairie Island Nuclear Generating Plant -
NRC letter dated May 30, 2007, Accession No. ML071310023).
The common cause potential during the extended CT was considered. The common cause factors for the DGs are part of the results of determining the baseline risk metric values. However, TS 3.8.1 Required Action B.3.1 requires that within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, a determination be made that the operable DGs are not inoperable due to common cause failure.
This TS requirement is unchanged by the proposed TS amendment.
No additional common cause failure potential or HEP for incorrectly determining if a common cause was present has been added to the risk evaluation for the proposed amendment.
The DG extended CT risk evaluation assumes that a common cause failure does not exist due to the TS requirement to perform this common cause evaluation or, alternatively, to perform an operability test on the operable DGs. If the common cause determination method is by evaluation and is not sufficiently determinate as to whether a common cause failure exists, TS 3.8.1 Required Action B.3.2 allows testing to verify that the potential common cause is not impacting the operable DGs. If the common cause evaluation determines that the cause is likely to impact an operable DG, the TS actions allow a much shorter period to rectify the common cause inoperability or a plant shutdown would be required, regardless of the risk evaluation results that include an increased common cause potential. Specifically, TS 3.8.1 Required Action E. 1 would require restoration of one DG to operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for a Division 1 and Division 2 DG common cause and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the Division 3 DG is made inoperable by the common cause. Failure to restore a DG to operable status within these much shorter CTs would result in a required plant shutdown. Thus, for an actual common cause condition, the TS would preclude using the extended DG CT, unless the common cause condition is rectified. Based on these TS requirements, no PRA model adjustment is made to reflect an increased potential for common cause failure if one DG is out of service for corrective maintenance.
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ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR To conservatively bound uncertainty associated with common cause assumptions a sensitivity analysis with the following assumptions was performed:
All extended diesel maintenance events were assumed to be corrective. Note that the last time NMP2 DGs required corrective maintenance was for the Division 1 DG in 2006; the next previous failure was in 1995.
There is a 10% chance that common cause will not be correctly assessed in accordance with TS 3.8.1.
The current value for DG Division 1 and 2 common cause for start and run were summed and multiplied by 0.1, then added to the Division 1 and Division 2 failure to start.
The risk metrics for this sensitivity case remain within the acceptance guidelines of RG 1.174 and RG 1.177.
Table 6-1: Sensitivity Results, Div 1/2 Common Cause Without CCF DG Start Failure Acceptance Adjustment
+ CCF Criteria ACDFave 2.9E-07 3.09E-07
<1E-6 ALERFave 2.2E-08 2.47E-08
<lE-7 ICCDPm 2.2E-07 2.39E-07
<51-7 ICCDP2 3.3E-07 3.54E-07
<5E-7 ICLERP1 1.9E-08 2.11E-08
<5E-8 ICLERP2 2.4E-08 2.63E-08
<5E-8 Electrical Engineering Review Comment 7 In the LAR, the licensee did not provide adequate justification for amending TS Section 3.8.1 to extend the CT for an inoperable Division 1 or 2 diesel generator (DG) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days. Specifically, the licensee states, "the 2-year DG inspections (which typically require 5 days to complete) and the 6-year DG overhauls (which typically require 7 days to complete)." Provide the basis for the proposed extended CT of 14 days.
Response
The following table summarizes actual durations for 2-year DG inspections and 6-year DG overhauls performed for the NMP2 Division 1 and 2 DGs during the last three refueling outages.
Approximate Actual Maintenance Duration Refueling Outage /
Division 1 DG Division 2 DG 2-Yr. Inspection 6-Yr. Overhaul 2-Yr. Inspection 6-Yr. Overhaul RF010 /2006 7.3 days 7.6 days RF011 /2008 8 days 5.3 days RF012 /2010 8 days 8 days 9 of 12
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR The maintenance activities described in the above table were all performed during refueling outages; thus, the durations (ranging from approximately 5 to 8 days) were determined by outage schedules rather than TS CT requirements. As discussed in Section 3.2.6 of the submittal, the NMPNS practice is to schedule online maintenance activities (both preventive and corrective) so that they are completed within one-half of the TS CT limit. This practice is acknowledged in RG 1.177 (Section A.2.3.1). This allows sufficient time to resolve unexpected conditions discovered during performance of the maintenance or during subsequent post-maintenance testing so that subsequent actions required by the TS (e.g., plant shutdown) are avoided. Activities that require or result in exceeding 50 percent of the TS CT limit are classified as risk significant, requiring application of risk management actions in accordance with the NMPNS configuration risk management program.
Having an extended TS CT for an inoperable DG that is of sufficient duration also improves the effectiveness of the allowed maintenance period. A significant portion of on-line maintenance activities is associated with preparation and return-to-service activities, such as tagging, fluid system drain down, and fluid system fill and vent. The duration of these activities is relatively constant. A longer CT duration allows more maintenance to be accomplished during a given online maintenance period, thereby improving maintenance efficiency and avoiding multiple entry into and exiting from TS LCO Required Actions to complete desired activities.
The request to extend the TS CT for an inoperable Division 1 or Division 2 DG from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days is consistent with the above discussion, i.e., the 14-day CT is twice the expected duration for performing 2-year inspections or 6-year overhauls of the DGs while on line.
In addition, the risk evaluation performed in support of the proposed amendment concluded that the increase in risk is small and consistent with the guideline values in RG 1.177. The NRC has previously reviewed and approved similar license amendment requests to extend the TS CT for an inoperable DG to 14 days (e.g., River Bend Station - NRC Letter dated September 25, 2002, Accession No. ML022590314; Beaver Valley Power Station - NRC letter dated September 29, 2005, Accession No. ML052720259; Columbia Generating Station - NRC letter dated April 14, 2006, Accession No. ML061000672; and Prairie Island Nuclear Generating Plant - NRC letter dated May 30, 2007, Accession No. ML071310023).
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ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR Comment 8 It appears that the capacity of the proposed alternate alternating current (AC) power source (High Pressure Core Spray Emergency DG) to replace the inoperable Emergency DG (Division 1 or 2) is not adequate to support a loss-of-offsite power (LOOP) event with a unit trip. Considering the changes in electric grid performance post-deregulation, the duration of LOOP events has increased, and the probability of a LOOP as a consequence of a reactor trip has increased. As a deterministic measure to ensure adequate defense-in-depth, given the changes in the electric grid performance post-deregulation, the NRC staff requires the replacement power source has adequate capacity of handling station blackout (SBO) and LOOP loads, to supplement the existing EDGs during the extended 14-day allowed outage time. Provide justification to demonstrate that the proposed diesel is adequate to maintain the defense-in-depth philosophy of the emergency power system.
Response
The capacity of the Division 3 HPCS DG has been evaluated and is capable of supplying the electrical loads needed for LOOP and SBO events. The cross-connection alignment of the Division 3 DG to either the Division 1 or Division 2 emergency bus would only be utilized in the event that a LOOP occurs when the Division 1 or Division 2 DG is inoperable (e.g., for maintenance activities requiring entry into the proposed extended TS CT) and the redundant DG fails to operate.
This effectively creates an SBO condition.
The Division 3 DG has a continuous rating of 2600 kW and a 2000-hour rating of 2850 kW, as described in NMP2 Updated Safety Analysis Report (USAR) Section 8.3.1.1.2. The Division 3 emergency bus maximum load is 2540 kW (reference USAR Table 8.3-3). In the cross-connection alignment, the HPCS pump (2433 kW) will not be operating; thus, the remaining Division 3 emergency bus load is approximately 107 kW.
The loads powered by the Division 1 DG for a LOOP with unit trip condition are listed in USAR Table 8.3-1 (organized by power source) and are summarized in USAR Table 8.3-5 (as a function of time from inception of the event). The loads powered by the Division 2 DG for a LOOP with unit trip condition are listed in USAR Table 8.3-2 (organized by power source) and are summarized in USAR Table 8.3-6 (as a function of time from inception of the event). The loads powered by the Division 1 and Division 2 DGs consist of both automatically connected and manually connected loads, as discussed below.
Division 1 For the first two hours of the LOOP with unit trip condition, the maximum Division 1 running load is 2753 kW. This includes one automatically started Service Water (SW) pump, one manually started SW pump, and the manually started RHR pump A (assumed to occur one hour after event inception).
The LPCS pump, which is also powered from the Division 1 emergency bus, is not operating since a concurrent loss of coolant accident (LOCA) need not be assumed to occur. In accordance with existing NMP2 SBO special operating procedures, only a single Division 1 SW pump should be in operation when the Division 3 DG is cross-connected to the Division 1 emergency bus. Thus, the Division 1 loads to be powered by the Division 3 DG for the first two hours of the LOOP with unit trip condition would be:
2753 kW + 107 kW (Division 3 load) - 442 kW (one SW pump load) = 2418 kW 11 of 12
ATTACHMENT 1 NINE MILE POINT UNIT 2 RESPONSE TO NRC ACCEPTANCE REVIEW COMMENTS REGARDING THE PROPOSED EXTENSION OF THE COMPLETION TIME FOR AN INOPERABLE DIESEL GENERATOR After the first two hours of the LOOP with unit trip condition, the DG loading analyses assume that the Division 1 Spent Fuel Pool (SFP) cooling system pump (330 kW) is manually started to restore cooling flow to the spent fuel pool. This results in a total Division 1 load of 2748 kW, which is less than the 2000-hour rating of the Division 3 DG.
Based on actual spent fuel pool cooling requirements, this action is not actually needed until approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (or longer) after inception of the event (depending on the spent fuel pool initial water temperature and spent fuel heat load).
Division 2 For the first two hours of the LOOP with unit trip condition, the maximum Division 2 running load is 2679 kW. This includes one automatically started SW pump, one manually started SW pump, and the manually started RHR pump B (assumed to occur one hour after event inception). RHR pump C, which is also powered from the Division 2 emergency bus, functions only in the low pressure coolant injection (LPCI) mode and is not operating since a concurrent LOCA need not be assumed to occur.
In accordance with existing NMP2 SBO special operating procedures, only a single Division 2 SW pump should be in operation when the Division 3 DG is cross-connected to the Division 2 emergency bus. Thus, the Division 2 loads to be powered by the Division 3 DG for the first two hours of the LOOP with unit trip condition would be:
2679 kW + 107 kW (Division 3 load) - 442 kW (one SW pump load) = 2344 kW After the first two hours of the LOOP with unit trip condition, the DG loading analyses assume that the Division 2 SFP cooling system pump (330 kW) is manually started to restore cooling flow to the spent fuel pool. This results in a total Division 2 load of 2674 kW, which is less than the 2000-hour rating of the Division 3 DG. Based on actual spent fuel pool cooling requirements, this action is not actually needed until approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (or longer) after inception of the event (depending on the spent fuel pool initial temperature and heat load).
Based on the above evaluation, it is concluded that the Division 3 DG is capable of supplying either the Division 1 or Division 2 electrical loads needed for a LOOP or SBO event, including the powering of one RHR pump aligned in either the shutdown cooling or suppression pool cooling modes of operation to remove reactor decay heat.
As described in Section 3.1.1 of the submittal, the Shift Manager will determine the priority for energizing the safe shutdown loads based on plant needs while assuring that the Division 3 DG loading limits are not exceeded, as directed by the existing NMP2 SBO special operating procedures. Therefore, capability for cross-connecting the Division 3 DG to either the Division 1 or Division 2 emergency bus provides defense-in-depth in the event that a LOOP occurs while the Division 1 or Division 2 DG is in the proposed extended TS CT.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Nine Mile Point Nuclear Station, LLC June 1, 2010
ATTACHMENT 2 VS COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment Plant Boundary
- 1. Global analysis boundary captures all plant
- 1. All plant locations relevant to the fire probabilistic risk assessment (PRA) are included in the analysis.
Definition and locations relevant to the fire PRA.
Partitioning
- 2. Physical analysis units are identified by credited
- 2. The fire compartments are delineated in the same manner as used for the Appendix R analysis. Definitions are provided in Nine Mile partitioning elements that are capable of Point Unit 2 (NMP2) updated safety analysis report (USAR) Section 9A.2.4. The physical barriers included in the analysis confine substantially confining fire damage behaviors, damage from fires. These compartments include buildings in the protected area that can impact plant operation and are listed in Table A2-1A. These same compartments provide the basis for analyzing the effects of fires and documenting the analysis.
Equipment
- 1. Equipment is selected for inclusion in the plant
- 1. Electrical equipment in the internal events PRA and Appendix R safe shutdown analysis (SSA) provide the basis for equipment needed Selection response model that will lead to a fire-induced for the fire PRA model. Support system failures were considered with regard to initiating event potential for each compartment. If no plant initiator, or that is needed to respond to support system initiator was identified for a compartment, plant trip was generally assumed due to turbine trip or reactor trip unless these such an initiator (including equipment subject to causes could be excluded. The equipment selection includes the impact of single spurious operation. A multiple spurious operation fire-induced spurious actuation that affects the (MSO) review has been recently completed as well and discussed in 2 below.
plant response).
GAP: Since the individual plant examination for external events (IPEEE), new equipment has been added to the internal events PRA.
An MSO review (Attachment A2-C) was performed, as well as a review of modifications since the IPEEE. Neither of these reviews identified issues that would impact the submittal. As afurther review, the change tracking database was searched and identified six cable modifications that could have potentially impacted modeled components. These six modifications were evaluated as not having an impact.
- 2. The number of spurious actuations to be
- 2. Spurious actuations were considered in the IPEEE. Consequential events that were considered in the evaluation of spurious actuations addressed increases according to the include interfacing system loss of coolant accident (ISLOCA), reactor pressure vessel (RPV) overfill and vessel isolation. ISLOCA is.
significance of the consequence (e.g.,
unlikely since power is removed from residual heat removal (RHR) valves to ensure this event is extremely unlikely. RPV overfill and interfacing systems LOCA).
vessel isolation failures are unlikely and are not considered significant relative to the diesel generator (DG) allowed outage time (AOT) delta risk assessment. Most recently, the industry generic MSO list was reviewed and MSOs 5a, 5f, 5g, 5h and 5i were determined to be related to this application (DG events).
GAP: A detailed evaluation of all MSOs for inclusion in the PRA has not been completed. However, the generic list of MSOs was reviewed to select those that could affect alternating current (AC) power to show that the risk of applicable scenarios is expected to be low for this application. This evaluation is documented in Attachment A2-C. Also, a review of condition reports initiated since the IPEEE based on a search for multiple spurious operation identified no events that were relevant to NMP2.
Spurious indications that can cause undesirable operator actions were also reviewed. Procedures typically have operators look at another indication to verify the condition before taking a potentially undesirable action and/or the operators are instructed to not trip the equipment if the equipment is required. Reactor Core Isolation Cooling (RCIC) and High Pressure Core Spray (HPCS) are considered most important, as they provide immediate RPV level control. These systems were checked to ensure the potential for undesirable actions is low.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment
- 3. Instrumentation and support equipment are
- 3. Physical separation has been identified for instrumentation and support equipment needed for Appendix R; thus no additional
- included, instruments are explicitly modeled.
GAP: A Human Error Probability (HEP) review to determine if non-Appendix R instruments need modeling was performed. Ooperator actions with high risk achievement worth (RAW) values associated with the proposed DG AOT extension were evaluated to determine whether they have adequate instrumentation to support the HEP. Based on this review, it is unlikely that afire will significantly impact instrumentation and operator response for these important actions. The most important operator actions (e.g., emergency depressurization) depend on Appendix R spatially separated instruments and other actions have been reviewed (see Attachment A2-D).
Cable Cables that are required to support the operation of Cables that are required to support PRA equipment were identified and located. The equipment in the area impacted by fire was considered Selection fire PRA equipment (defined in the equipment lost.
selection element) are identified and located.
The identification of cables is based on a progressive analysis used in the fire analysis as summarized below:
A computerized spatial database was developed such that all plant cables and components in a fire compartment can be identified, including their raceways. A review of modifications (see Equipment Selection) determined that no significant changes have occurred.
GAP: Although there may have been some changes to cables and routing since the IPEEE was performed in 1994, in general, components, junction boxes and panels where cables are routed have not been relocated. Therefore, any new cables would be routed in the same manner through the same fire zones/fire areas as was documented in the cable original database and, as such, there is no impact on the fire PRA.
Cables that are required for PRA were identified for non-Appendix R equipment such as offsite power, feedwater, main condenser, and their support systems. These cables were queried against the spatial database to identify those compartments containing these impacts.
Initially, all possible Appendix R equipment impacts are assumed for each compartment. In other words, if the compartment is a Division 1 area, Division 1 equipment is assumed to fail, except in certain cases where it was relatively straightforward by use of the spatial database and Appendix R analysis to limit the impact. After the initial screening analysis, additional detailed cable evaluations and impacts, including their location, were included to better define realistic scenarios for inclusion in the PRA model.
Qualitative Screened out physical analysis units represent The screened out physical analysis units represent negligible contributions. Both qualitative and quantitative screening is conducted for Screening negligible contributions to risk and are considered each compartment with results summarized in Table A2-1A and A2-1B.
(Optional no further.
Element) 2 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment Fire PRA Plant
- 1. Based upon the internal events PRA, the logic
- 1. The internal events PRA model is used to represent the plant response for fire initiating events. The transient model is used as well, as Response Model model is adjusted to add new fire-induced its transfer to medium LOCA (MLOCA) (stuck open safety relief valve (SRV)), station blackout (SBO) and anticipated transient initiating events and modified or new accident without scram (ATWS) models. Tables A2-1A and A2-1B summarize the impacts for the initial screening analysis. Table A2-2 sequences, operator actions, and accident summarizes the initiating events determined to be risk important and included in the PRA after the more detailed compartment progressions (in particular those from spurious evaluations. The impacts of each initiating event are provided in Table A2-3.
actuations).
- 2. Inapplicable aspects of the internal events PRA
- 2. Aspects of the internal events model are bypassed in the fire portion of model; e.g. large and small LOCA, ISLOCA, and breaks outside model are bypassed.
containment (BOC) do not apply to fires, and therefore are not utilized.
Fire Scenario The screening scenarios are identified in Table A2-1 A and A2-1 B, which summarize the total ignition frequency determined for each Selection and compartment, the initiating event identified for each compartment, and model impacts assuming everything is affected by the fire in the Analysis compartment. For those compartments that did not screen, additional analyses were conducted including consideration of the location of ignition sources, targets, fire growth and propagation, and fire suppression (Attachment A2-B). As a result of these evaluations, risk important scenarios were identified for inclusion into the PRA model (Tables A2-2 and A2-3 summarize the results of these evaluations).
Four scenarios were identified for the main control room; each scenario includes consideration of operators remaining in the main control room and control room abandonment.
Walkdowns were conducted in support of the analysis and to consider multi-compartment fire propagation. Multi-compartment fire scenarios were judged to be low risk and no such scenarios are included in the PRA model.
- 1. Fire scenarios are defined in terms of ignition
- 1. Walkdowns were performed to identify ignition sources for all compartments. Fire growth, propagation, fire detection, fire suppression sources, fire growth and propagation, fire and equipment damaged by fire were evaluated for unscreened compartments.
detection, fire suppression, and cables and equipment ("targets") damaged by fire.
- 2. The effectiveness of various fire protection
- 2. The effectiveness of fire protection was assessed. Fire detection is provided in each compartment evaluated in the fire analysis. For features and systems is assessed (e.g., fixed those areas requiring more detailed analysis (i.e., did not screen out as part of the initial screening analysis), detection and suppression suppression systems).
capabilities were reviewed, as well as how these systems are credited in the analysis. Some areas also have automatic suppression systems or manual suppression capabilities. Fire growth for applicable fires is in accordance with the IPEEE.
GAP: The only major change since the IPEEE is that auto initiation of the C02 system for the switchgear rooms in now manual. This was considered in the fire growth evaluation and in the detailed evaluation (Attachment A2-B). The evaluation concluded that this change did not have a significant impact. Also, doubling the assumed failure probability of automatic actuation showed a very small increase in risk and did not change the conclusions of the analysis for the proposed amendment.
- 3. Appropriate fire modeling tools are applied.
- 3. The Electric Power Research Institute (EPRI) modeling tool, Fire Induced Vulnerability Evaluation (FIVE), was used.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment
- 4. The technical basis is established for statistical
- 4. Where explicit credit is taken for detection and suppression in the detailed analysis, an unreliability of 0.05 per demand is used for and empirical models in the context of the fire automatic detection and suppression. A plant specific systems analysis to estimate fire protection system reliability was not deemed scenarios (e.g., fire brigade response).
necessary. No significant reliability problems have been observed at NMP2. Very Early Smoke Detection Apparatus (VESDA) has been installed in several areas in the plant and is being installed in the normal switchgear rooms. This is incipient detection that provides more time for operator or fire brigade response. This system has not been credited in the PRA. Fire brigade response is considered in the evaluation of fire zones that did not screen. The IPEEE evaluated fire brigade staffing, equipment, drills and training.
There have been no significant changes to this IPEEE information.
- 5. Scenarios involving the fire-induced failure of
- 5. Based on NMP2 design (see USAR Section 9.5 and Appendix 9A), structural steel is qualified as a 3-hour barrier which includes fire structural steel are identified and assessed (at proofing. No scenarios that impact structures in a way that significant impacts can occur have been identified.
least qualitatively).
Fire Ignition
- 1. Frequencies are established for ignition
- 1. The frequency of a fire was developed for each compartment. Quantification of the ignition sources in the plant and the cumulative fire Frequencies sources and consequently for physical analysis ignition frequency is based on those hazards and the EPRI fire incident database is discussed in the FIVE methodology (Attachment units.
10.3 of EPRI TR100370). The total fire ignition frequency developed from this analysis for each compartment is provided in Table A2-1A. These frequencies were used in the initial screening analysis. The contributing ignition sources for each compartment developed from this analysis are considered in the detailed analysis of compartments when they could not be screened out using other methods.
- 2. Transient fires should be postulated for all
- 2. Transient fire frequency was considered as part of Item 1 above.
physical analysis units regardless of administrative controls.
- 3. Appropriate justification must be provided to
- 3. Nonnuclear experience was not used. EPRI TR 100370, Fire-Induced Vulnerability Evaluation (FIVE), is based on nuclear plant use nonnuclear experience to determine fire experience.
ignition frequency.
GAP: The latest ignition data was not used, but updating the data will not impact the result. Ignition frequencies are as derived from Table 1.2 of FIVE (Attachment 10.3 of EPRI TR 100370) and have not been updated to recent data. Attachment A2-A summarizes a comparison with recent updated data in EPRI 1016735 for some key ignition sources in the NMP2 PRA. Also, the presentfrequencies are judged to be reasonable (if not conservative) based on present methods of counting cabinets. The fire frequency will be comparable with no significant change once the frequency is adjusted for these compartments. A lowerfrequencyfor main control board fires would be calculated if more current data and methods were applied.
Quantitative
- 1. Physical analysis units that are screened out
- 1. Both qualitative and quantitative screening is conducted with results summarized in Tables 2A-1 A and 2A-lB. A containment Screening from more refined quantitative analysis are performance evaluation was conducted to provide confidence that LERF was at least an order of magnitude less than core damage retained to establish CDF and LERF/LRF.
frequency (CDF).
GAP: A CDF value less than IE-6 for a complete compartment was used as a screening value recognizing that a more detailed analysis would result in a CDF closer to 1E-7 or less. Table A2-1A was updated using the latest Computer Aided Fault Tree Analysis (CAFTA) 4 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment modelfor the same impacts and frequencies using a CDF screening value of lE-7. Several compartments screened out and 3 new events were added, refer to Table A2-2. These new events were determined to be non-consequential based on the detailed evaluation in Attachment A2-B. The fire CDF values are lower in ALL the cases.
Large early release frequency (LERF) screening was not performed for the IPEEE. However, a new screening assessment was performed using the current PRA and using the same fire zone impacts identified in Table A2-IA. This screening used a LERF cutoff of JE-8. No new zones were unscreened (see Table A2-IB).
GAP: Compartment screening was not retained and reported as a part of the total plant fire risk in the fire risk quantification. This is judged not to be significant based on the low screening value and other sensitivities considered for this application.
- 2. PRA contributors to CDF and LERF were conservatively characterized. Initial screening is very conservative as it assumes that all and LERF/LRF that are established in the cables in a compartment and equipment are impacted.
quantitative screening phase are conservatively characterized.
Circuit Failure The conditional probability of occurrence of Components were assumed to fail with a probability of 1.0 for cases were a cable existed in a compartment that could impact a component.
Analysis various circuit failure modes given cable damage As such, detailed circuit analyses were not required.
from a fire is based upon cable and circuit features.
GAP: Spurious operation was assessed using a probability of 0. 1 in the detailed evaluation without circuit failure analysis (see Attachment A2-B). However, this has no impact on the screening analysis conclusions.
Postifire Human
- 1. Operator actions and related post-initiator HFEs,
- 1. Human reliability was evaluated for response to control room fires for both the inside control room and the abandonment case.
Reliability conducted both within and outside of the main Analysis control room, are addressed.
GAP: The most important panelfor this application (852) has been evaluated and includes two scenarios involving offsite power and the DGs. Other panels were determined to be less consequential based on a cabinet Failure Modes and Effects Analysis (FMEA) evaluation in the IPEEE, Table 4.6-2, Control Room Panels Evaluation, and their exclusion does not impact this application.
- 2. The effects of fire-specific procedures are
- 2. Fire specific procedures are identified, reviewed and incorporated specifically for control room abandonment. No changes were identified and incorporated into the plant identified for other fire scenarios.
response model.
GAP: Procedure changes have been made since the IPEEE. These procedures were reviewed and confirmed that IPEEE assumptions are still valid. The IPEEE also discusses fire brigade staffing, equipment, drills and training. This information is still valid.
- 3. Plausible and feasible recovery actions, assessed
- 3. Plausible and feasible recovery actions, assessed for the effects of fire, are retained and used the same as HEP values as in the internal for the effects of fire, are identified and events model, or the associated action is failed (no recovery credited).
quantified.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment
- 4. Undesired operator actions resulting from
- 4. The IPEEE HEP analysis assumed that procedures typically have operators look at another indication to verify the condition before spurious indications are addressed, taking a potentially undesirable action and/or the operators are instructed to not trip the equipment if the equipment is required.
GAP: Evaluation of undesired operator actions resulting from spurious indications that are important to this application was performed.
See Equipment Selection review above.
- 5. Operator actions from the internal events PRA
- 5. Operator actions important for this application were assessed in Table A2-D. 1 for fires external to the control room. The probability for that are retained in the fire PRA are assessed for certain important actions was increased by 10. This sensitivity study showed a minimal increase in risk and did not change the fire effects, conclusions of the submittal (Table A2-D.2).
GAP: Human reliability for fires out in the plant external to the control room was not penalized for fires. A sensitivity analysis was performed on high importance operator actions that require a response of30 minutes or less. The HEP for these actions was increased by afactor of 1O and the results show a negligible increase in risk and when included in the assessment for the amendment, the results were well within the criteria.
Fire Risk
- 1. For each fire scenario, the fire risk results are
- 1. Table A2-3 summarizes CDF and LERF results for the fire initiating events modeled in the PRA. These are the result of combining the Quantification quantified by combining the fire ignition fire initiating event frequency and conditional core damage and large early release frequency through the plant response model.
frequency, the probability of fire damage and the conditional core damage probability (and CLRP/CLERP) from the fire PRA plant response model.
- 2. Total fire-induced CDF and LERF/LRF are
- 2. The submittal includes top cutsets and importance measures based on the integrated internal events-fire-seismic model.
calculated for the plant and significant contributors identified.
- 3. The contribution of quantitatively screened
- 3. Refer to Tables A2-1A and A2-1B. The screening is conservative and judged not to have an impact on the PRA.
scenarios (from the quantitative screening element) is added to yield the total risk values.
Seismic Fire
- 1. Potential interactions resulting from an
- 1. The IPEEE includes a qualitative review of potential seismic/fire interactions to ensure that there are no potentially important Interactions earthquake and a resulting fire that might contributors to plant risk and steps have been taken to ensure that potentially important risk contributors are mitigated.
contribute to plant risk are reviewed qualitatively.
- 2. Qualitative assessment verifies that such
- 2. See Item 1 above.
interactions have been considered and that steps are taken to ensure that the potential risk contributions are mitigated.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FIRE - RG 1.200 Rev 2 Technical Elements Element Technical Characteristics and Attributes NMP2 Assessment Uncertainty and
- 1. Uncertainty in quantitative fire PRA results
- 1. The submittal provides an assessment of uncertainty related to this specific application. Impact of parameter uncertainties is not Sensitivity because of parameter uncertainties are necessary for this application due to compensatory measures, etc. In the IPEEE, sensitivities were performed for control room fires.
evaluated.
GAP: A comprehensive uncertainty analysis has not been performed for fires; however, application-specific sensitivity analyses have been performed and show the conclusions for the proposed amendment do not change.
- 2. Model uncertainties as well as the potential
- 2. See Item 1 above. The assumptions are imbedded in the analysis (see Attachment A2-B) and have not been separated in the sensitivities of the results to associated documentation.
assumptions are identified and characterized.
GAP: This is a documentation issue for the future and does not impact the results for the proposed amendment.
7 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECH~NICAL ELEMENTS OF REGULATORY GUID)E 1.200, REVISION 2, SECTION 1.2.4 Table A2-1 A: Initial Fire Area Screening Analysis Summary, CDF - 5/2010 Post IPEEE Update Area Zone Description Fire Freq App R Initiator Screening Summary System Impacts OG A1/2 RW TW AS CN FW HS IC LA LB LC LS SV CV I
201SW Nort Aux Bay-LPCS pump 4.8E-03 I
es I CDF<IE-7 X
I 202SW North Aux Bay-RHR A pump 3.IE-03 I
es I CDF<IE-7 X
1 203SW North Aux Bay-RHR HE IA 2.4E-03 I
es I CDF<IE-7 X
1 211SW North Aux Bay-RHR & CCP HE 2.4E-03 I
yes (1)
CDF<IE-7 X
X I
221SW North Aux Bay-SWP to CCP 3.IE-04 I
RWX CDF <IE-7 X
X X
X X
I MI I
231SW North Aux Bay-MCC rea 9.9E-04 I
RWX CDF<IE-7 X
X X
X X
X I
Ml 2
204SW RCIC pump room 4.2E-03 I
no RCIC unavailabiity insignificant X
3 206SW South Aux Bay-RHR B HE 2.4E-03 II yes (1)
CDF <IE-7 X
3 207SW South Aux Bay-RHR B ur 4.2E-03 II yes (1)
CDF<IE-7 X
3 208SW South Ass Bay-LPCIC CuM 3.6E-03 II yes (1)
CDF <IE-7 X
3 214SW South Aux Bay-RHR HE lB 3.4E-04 II yes(l)
CDF<lE-7 X
X 3
224SW South Aux Bay-South access 2.4E-03 II RWX CDF <1E-7 X
X X
X X
3 239SW South A" Bay-MCC area 9.9E-04 II RWX CDF<1E-7 X
X X
X X
M2 4
205NZ HPCS pump room 4.7E-03 III no HPCS unavailability insisnificant X
5 234NZ Drywell 0.OE+00 (2)
(2)
(2) 8 301NW 140 degree tunnel I.5E-04 I
AIX CDF<IE-7 Al X
X Air 8
302NW 35 deree tunnel 1.4E-05 I
AIX CDF<IE-7 Al X
X X
Air 10 303NW 315 deg tunnel 1.2E-05 N
RWX CDF<IE-7 X
X X
16 306.INW Div1/2 cable area-general area 1.6E-04 I
RWX CDF<IE-7 X
X X
Air 16 306.2NW Document storage mrom 5.3E-04 N
no no initiator or impact 16 312NZ Div 1/2 cable area-generuI area 2.2E-04 I
MSIV CDF<IE-7 X
X 16 321NW Div l riser area 1.5E-04 I
AIX CDF<IE-7 KAR Al X
X X
X X
Air 16 332NW Div I cable chase West 1.5E-04 1
LOSP CDF=6.92E-7 0G Al X
X X
X X
X Air 16 352NW Div I cable chase West 1.6E-04 I
X X
X X
X Air 16 362.2NZ Pipe tunnel (FA55 362NZ) 2.3E-04 I
RWX
<IE-7 16 371NW Div I cable chase West 1.5E-04 I
X X
X X
X Air 17 305NW Div I riser area 1.3E-05 I
RWX CDF<IE-7 X
X X
X X
Air 17 322NW Div I cable routing area 1.5E-04 I
AIX CDF<IE-7 KAR Al X
X X
Air 17 325NW Div I cable routing area 1.3E-05 I
AIX CDF<IE-7 KAR Al X
17 333XL Div I standby switchgear room 9.9E-04 I
A1X CDF=1.22E-7 KAR Al X
DW 17 334NZ Div I battery room 5.IE-04 I
DIX CDF<IE-7 (DI -Div 1 DC)
X 17 343NZ Remote shutdown room A West 1.5E-04 I
AIX CDF<IE-7 Al X
17 NONEXX Fire Protection Valve Room 2.3E-04 I
AIX CDF<IE-7 Al 18 304NW 230 degree tunnel 1.5E-04 II A2X CDF = 1.58E-7 A2 X
X X
18 309NW Cable chase East 13E-05 II A2X CDF < IE-7 A2 X
X X
X 18 324NW Div 2 riser area I.5E-04 II A2X CDF 1.59E-7 KBR A2 X
X X
X X
18 337NW Div 2/3 cable chase East 1.5E-04 II A2X CDF = 1.58E-7 KBR A2 X
lB X
X X
X 18 359NW Div 2/3 cable chase East 1.5E-04 II A2X CDF = 1.58E-7 KBR A2 X
I B X
X X
X 18 377NW Div 2/3 cable chase East 1.5E-04 II A2X CDF = 1.58E-7 KBR A2 X
X X
X X
19 323NW Div 2 cable routing area 1.5E-04 II A2X CDF - 1.58E-7 KBR A2 X
X X
19 326NW Div 2 cable routing area 1.3E-05 II A2X CDF < IE-7 KBR A2 X
19 335NZ Div 2 battery room 5.IE-04 II D2X CDF < IE-7 (D2 - Div 2 DC) 19 336XL Div 2 standby switchCear room 9.7E-04 II A2X CDF = 5.03E-7 KBR A2 X
I B X
19 338NZ Remote shutdown room B East 1.5E-04 II A2X CDF<IE-7 A2 21 327NW HPCS ruble routing area 1.5E-04 III so HPCS unavuilubility isi niftcanX 21 342XL HPCS Switchgear 9.SE-04 III so HPCS un1vuilubility insignificant 22 340NZ Div I chiller 3S8E-O 1
no No initiator or impact on PRA 23 1
341NZ Div 2 chiller 3.8E-03 1I 1 no INo initiator or import on PRA 8 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-1A: Initial Fire Area Screening Analysis Summary, CDF - 5/2010 Post IPEEE Update Area Zone Description Fire Freq App R Initiator Screening Summary System Impacts OG AI/2 RW TW AS CN FW HS IC LA LB LC LS SV CV 25 360NZ Div I CR HVAC room 2.8E-03 I
no No initiator or impact on PRA 26 373.INZ Control Room (372-376) 9.9E-03 I & 1l yes CDF=9.9E-03 [detailed evaluation req 'd]
X 26 373.2NZ Shift supervisors office 2.3E-04 I & II yes CDF=2.3E-04 [detailed evaluation req d]
X 26 373.3NZ Training room 2.3E-04 I & II yes CDF=2.3E-04 [detailed evaluation req d]
X 27 378NZ Div 2 CR HVAC room 2.5E-03 11 MSIV CDF<]E-7 X
28 401.INZ Div I diesel generator-CR 2.7E-03 I
no DG unavailability insignificant DG 28 402.1SW Div I diesel generator 2.9E-02 I
no DG unavailability insignificant DG 29 401.2NZ Div 2 diesel generator-CR 2.7E-03 tI no DG unavailability insignificant DG 29 403.1SW Div 2 diesel generator 2.9E-02 II no DG unavailability insignificant DG 30 401.3NZ HPCS diesel control room 2.7E-03 III no DG unavailability insignificant DG 30 404.1SW HPCS diesel generator 2.9E-02 III no DG unavailability insignificant DG 34 0NA North reactor building 3.9E-02(4)
I See Zones below 34 212SW North reactor building El 175 1E-2(4)
I RWX CDF = I.58E-7 X
X X
X X
Air 34 222SW North reactor building El 215 IE-2(4)
I RWX CDF = 1.58E-7 X
X X
X X
X I
Air 34 232SW North reactor building El 240 1 E-2(4)
X X
X X
X I
Air 34 243SW North reactor building E1261 1E-2(4)
I RWX CDF = 1.58E-7 (El - ECCS Div 1) 2 of3 X
X X
X X
Air 34 252SW North reactor building E1289 IE-2(4)
I RWX CDF = 1.58E-7 x
X 2 of3 X
X X
Air 34 261SW North reactor building El 306 IE-2(4)
I no No initiator or impact on PRA Air 34 271SW North reactor building El 328 NW IE-2(4)
I RWX CDF<IE-7 X
MI 34 273SW North reactor building El 328 NE IE-2(4)
I no No initiator or impact on PRA 34/35 281NZ North reactor building El 353 and above IE-2(4) 1 no No initiator or impact on PRA 34 242NW Track bay (same as FA98) 5.3E-04(4)
N no No initiator or impact on PRA 35 ONA South reactor building 3.8E-02(4)
II See Zones below 35 213SW South reactor building El 175 IE-2(4)
II RWX CDF = 3.35E-6 X
X X
X 35 223SW South reactor building El 215 1E-2(4)
II RWX CDF = 8.43E-6 X
X X
X X
X II X
35 238SW South reactor building El240 1 E-2(4)
II RWX CDF = 3.35E-6 X
X X
X X
X II DW 35 245SW South reactor building El261 1 E-2(4)
II RWX CDF = 3.36E-6 (E2 - Div 2 ECCS)
X X
X X
X X
II M2 35 255SW South reactor building E1289 1 E-2(4)
II RWX CDF = 3.35E-6 X
X X
X DW 35 262SW South reactor building El 306 lE-2(4) 1I RWX CDF<IE-7 X
2of3 X
M2 35 272SW South reactor building El 328 SW lE-2(4)
N RWX CDF<IE-7 X
35 274SW South reactor buildian El 328 SE I E-2(4)
II no no initiator or impact on PRA 38 31INZ Computer battery room 5.1E-04 N
no no initiator or impact on PRA 39 307NZ Div I West battery room 5.0E-04 N
no no initiator or impact on PRA 40 308NZ Div 2 East battery room 5.OE-04 N
no 00 initiator or bepact on PRA 42 708NW Oil storage tank 3.8E-03 N
yes CDF <IE-7 I F 2of3 48 236NZ Div I HVAC room 2.4E-03 I
no no initiator or impact on PRA 49 70INW RR track bay 5.3E-04 N
no no initiator or impact on PRA 49 CHWTR Chilled water STR 6.0E-03 N
no no initiator or impact on PRA 50 256NZ Main steam tunnel 6.2E-04 I
X 50 702NZ Turbine building 3.6E-02 N
yes CDF <IE-7 50 703NZ Turbine building 8.3E-04 N
yes CDF <IE-7 II___IIII X
50 704NZ Turbine building 8.7E-04 I
N yes ICDFvIE-7 I of 3 I of3 50 50 709NZ 1I 5.0E-03 I
N yes ICDF<IE-7 x
x x
50 716SW
'I
('717 7tOR'ttJ\\
I N
lflnretu.7 '11.
Y 5(
Y
ý P17 718Sull I 3E-02 I
N es ICDF<]E-7 x
x x
x 50 721NZ Turbine building 5.9E-04 1
N yes ICDF<IE-7 x
I 7.9E-04 I
N I
yes ICDF<IE-7 50 1
725NZ ITurbine buildino 6.813-04 1
N I
yes ICDF~
-7o4 9 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THLE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-1 A: Initial Fire Area Screening Analysis Summary, CDF - 5/2010 Post IPEEE Update Zone Area Description Fire Freq AppR Initiator Screening Summary System Impacts OG AI/2 RW TW AS CN FW HS IC LA LB LC LS SV CV 50 727SW 50 728NZ (730, 731SW) 7.0E-03 N
yes CDF<IE-7 i
X I
5.3E-04 I
N yes CDF<IE-7 I
I I
I I
I I
X II 50 729NZ Turbine building 5.3E-04 N
yes ICDF <IE-7 50 751NZ Turbine building so 752.1NZ so 752.2NZ 50 753NZ 50 754NZ 50 755SNZ
- 2. 1E-03 N
- 1. 1E-03 N
1.5E-03 N
- 2. 1E-03 N
5.8E-04 T N
yes CDF <lE-7 yes CDF <lE-7 yes CDF <IE-7 yes CDF <IE-7 yes CDF <1 E-7 rurbine building rurbine building l5-2 N
yes
!CDF<IE-7 t
_t___I__1
-I__
50 756NZ Turbine building 5.8E-04 I
N yes ICDF<IE-7 50 50 50 51 52 762NZ Turbine building 763NZ 5.3E-04 N
- 2. 1E-03 N
5.3E-04 N
9.7E-04 N
1.1E-03 N
yes CDF <lE-7 yes CDF <lE-7 yes CDF <lE-7 LOSP CDF <lE-7 LOSP CDF <1E-7 X
X X
602XL OG X
X X
X X
52 604NZ 9.6E-04 I
N KBX ICDF-<cE-7 KBR X
X x
I of3 53 603NZ Battery rooms 4.9E-04 I
I1A,IB I X
X 55 55 55 55 237NZ Div 2 HVAC room 2.4E-03 II 2.3E-04 II 2.3E-04 II 2.313-04 1
II RWX ICDF<IE-7 X
X X
Pine tunnels El 244 TWX R1 1 M7
- r;ro *v*t* ;ntaL-*/rl;¢rh arPa t 210.00 I
M n*
55 81INZ Service water intakedisch area 2313-04 N
A x
55 902NW Condensate storage tanks 2.7E-03 N
LOC CDF <IE-7 57 58 58 58 58 961NW Asphalt tank and pumps 90INZ
.7.4E-04 N
7.5E-04 N
7.4E-04 N
7.7E-04 N
7.9E-04 N
no no initiator or impact on PRA 91 INW LWS - Radwaste no in initiator or impact on PRA 58 941NW LWS - Radwaste 7.6E-04 N
no no initiator or impact on PRA 59 908NZ WSS - Radwaste 7.4E-04 N
no no initiator or impact on PRA 59 921SW WSS - Radwaste 7.5E-04 N
no no initiator or impact on PRA 59 95INW WSS - Radwaste 7.5E-04 N
no no initiator or impact on PRA 60 807NZ Service water pump B 6.OE-03 II SAX CDF <IE-7 (SB) 3 of6 60 808NZ Auxiliary boiler room 3.0E-03 N
no no initiator or impact on PRA 61 806NZ Service water pump A 6-0E-03 I
SAX CDF<IE-7 (SA) 3 of 6 62 804NW Diesel fire pumo room 6.6E-03 N
no no imiiator or impact except fire pump 63 805NZ Electric fire pump room 6.7E-03 N
no no initiator or impact except fire pump 64 715NZ Foam pump room 5.8E-03 N
no no initiator or impact on PRA 65 714NW I&C shop 5.3E-04 N
no no initiator or impact on PRA 66 402.2SW Div I diesel day tank 2.3E-04 I
no DG unavailability insignificant DG 67 403.2SW Div 2 diesel day tank 2.3E-04 II no DG unavailability insignificant DG 68 404.2SW HPCS diesel day tank 2.3E-04 III no DG unavailability insignificant DG 69 80INZ Water treatment building 6.2E-03 N
no no initiator or impact on PRA 70 395XL Radwaste switchgear room 9.8E-04 N
X 70 903NZ Decon area & RW CR 70 905NW 7.8E-04 N
7.6E-04 N
7.5E-04 N
6,6E-03 II 5.w3 E-04 4 1 &III no no initiator c x
72 351.INZ Instrument s AIX ICDF=2.71E-7 based on 380.1 Al X
x 72 351.2NZ Corridor El 288 CB 5.3E-04 1I & It AIX ICDFP2.71E-7 based on 380.1 Al X
X 73 247NZ IStandby u2 treatmnt-A
] 2 40-03
__N__
I no ino imtiator rsgiiatipc 74 248NZ IStandby ga trametBE_.003 I
N I_
no Ino initiator or significat i act____
~EI~
10 of 46
ATTACEHMENT 2 COMPARISON OF TILE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-1 A: Initial Fire Area Screening Analysis Summary, CDF - 5/2010 Post IPEEE Update Area Zone Description Fire Freq App R Initiator Screening Summary System Impacts OG A1/2 RW TW AS CN FW HS IC LA LB LC LS SV CV 75 339NZ IHPCS battery room 5.OE-04 III no HPCS unavailability insignificant X
76 380.INZ Operators lunch room El 306 2.3E-03 I &III AIX CDF=l.18E-6 Al X
76 380.2NZ Corridor/toilet El 306 5.3E-04 I & III AIX CDF=2.7lE-7 based on 380.1 Al X
77 621NZ Penthouse 3.8E-03 N
LOC CDF <1E-7 78 612XL West normal switchgear 9.8E-04 N
X X
X 79 613XL East normal switc*gear 9.7E-04 N
X IAIB X
X 80 246NW South Aux service building 5.9E-04 N
RWX CDF <1 E-7 X
80 61INW Electrical bay 1.5E-04 N
RWX CDF<IE-7 X
X X
X X
80 761.2NZ Clen access area El 288 5.9E-04 N
RWX CDF<lE-7 2 of3 X
I of3 80 761.3NZ Clean access area El 306 5.9E-04 N
RWX CDF <1 E-7 2 of3 X
2 of3 81 253XL 600V switchgear room 9.6E-04 N
RWX CDF<IE-7 X
2 of3 82 732NW Lube oil storage room 4.0E-03 N
yes CDF<IE-7 I of 3 83 726XL Normal switchgear East 9.8E-04 N
X 84 740XL Normal switchgear West 9.8E-04 N
yes CDFvIE-7 IC 2 OF 6 X
85 251NW Standby gas treatment-HVAC 3.7E-03 N
no no initiator or impact on PRA 86 274SW Resin storage area 2.3E-03 N
no no initiator or impact on PRA 86 770NW Cafeteria and corridor 5.3 E-04 N
no no initiator or impact on PRA 87 255SW Div I SFC pump room (or 87SW) 3.5E-03 I
no no initiator or impact on PRA 88 331NW Corridor El 261 CB 7.7E-04 I&III LOSP 5.10E-6 OG Al X
X X
X 90 761.INZ Stairway enclosure 5.3E-04 N
RWX CDF <1E-7 2of3 Table 2A-1A Notes:
- 1.
N2-EOP-SC, Rev 10 requires the operator to immediately shut down the plant per OP-101C & D if more than 1 RB area temperature exceeds 135F. This is assumed to occur in the North and South Auxiliary Bays.
- 2.
The primary containment was qualitatively screened out. With the exception of instrumentation and containment venting valves, most equipment required to respond to an initiator in the drywell are located outside the primary containment. There is separation among the instrumentation and venting valves, and the primary containment is normally inerted during operation.
- 3.
The following summarizes the column headings (PRA systems) and the codes used to summarize impacts:
OG -
Offsite AC power in the PRA is represented by four event tree top events. OG represents the offsite grid (OG failure equates to a total loss of all offsite power), KA represents 115kV source A, KB represents 115kV source B, and KR represents crosstie capabilities between KA and KB to plant loads. The following explains the impact codes used in the table:
KAR - failure of both KA and KR capabilities KBR - failure of both KB and KR capabilities OG - failure of all offsite AC power (KA, KB & KR failed) 11 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Al/2 - Division 1 and 2 emergency AC power was modeled as top events Al and A2 in the PRA. For those systems where simplified cable block diagrams were developed or detailed evaluation of cables was performed, the evaluations of each component considered cables up to the emergency and normal switchgear rooms and control complex. However, in some cases where Appendix R indicated that emergency AC was in the fire zone or if the area was not evaluated in detail, it may have been assumed. The following explains the impact codes used in the table:
DG - only the emergency diesel for the applicable Division is affected.
Al - Div 1 emergency AC failure occurs or is assumed.
A2 - Div 2 emergency AC failure occurs or is assumed.
X - failure of both divisions can occur or is assumed.
RW -
Reactor building closed loop cooling (RBCLC) is modeled in the PRA as top event RW. The impacts are based on evaluation of the critical cables required for RBCLC components. The following explains the impact codes used in the table:
1 of 3 - one of three pump trains are impacted 2 of 3 - two of three pump trains are impacted X - system failure occurs TW -
Turbine building closed loop cooling (TBCLC) is modeled in the PRA as top event TW. The impacts are based on evaluation of the critical cables required for TBCLC components. The following explains the impact codes used in the table:
1 of 3 - one of three pump trains are impacted 2 of 3 - two of three pump trains are impacted X - system failure occurs AS -
Instrument air is modeled in the PRA as top event AS. The impacts are based on evaluation of the critical cables required for instrument air components. The following explains the impact codes used in the table:
IA - compressor 1A is impacted 1B - compressor 1B is impacted 1C - compressor 1C is impacted X - system failure occurs 12 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 CN -
The main condenser is modeled in the PRA as top event CN. The impacts are based on evaluation of the critical cables required for main condenser and support system components. The following explains the impact codes used in the table:
1 of 6 - one of six circ water pumps are impacted 2 of 6 - two of six circ water pumps are impacted 3 of 6 - three of six circ water pumps are impacted X - system failure due to more than 3 circ water pumps impacted and/or MSIVs close and/or main condenser or its support systems fail FW -
The main feedwater system is modeled in the PRA as top event FW. The impacts are based on evaluation of the critical cables required for feedwater and condensate components. The following explains the impact codes used in the table:
1 of 3 - one of three pump trains are impacted 2 of 3 - two of three pump trains are impacted X - system failure occurs HS, IC, LA, LB, LC, and LS model HPCS, RCIC, RHR "A", RHR "B", and LPCS, respectively in the PRA. The impact is either system failure, "X", or no impact. The impacts were developed from Appendix R evaluations and/or evaluations of cables in a specific fire zone.
SV -
Safety relief valves opening to allow low pressure injection is modeled in the PRA as top event SV. In general, the cables for this system were not evaluated in detail, because Appendix R assured that at least one Div of ADS is available. With one Div available, the unavailability of SV is low and in combination with the fire frequency is not significant. Still, if failure of Al or A2 is assumed in Appendix R Div 1 or Div 2 areas that were not evaluated in detail, this results in loss of 1/2 of SV in the PRA.
Thus, the impact is included where Al and A2 are failed. In cases where SV impact was found, "I" or "IH" is shown as an impact to represent Div 1 and 2, respectively.
CV -
Containment venting is modeled in the PRA as top event CV. The impacts are based on evaluation of the critical cables required for containment venting components. The following explains the impact codes used in the table:
MI - Div 1 MOVs in the standby gas treatment system (SGTS) are impacted. This has an insignificant impact on containment venting capability since Div 2 MOVs are available and the Div 1 MOVs can be locally opened or closed.
M2 - Div 2 MOVs in the SGTS system are impacted. This has an insignificant impact on containment venting capability since Div 1 MOVs are available and the Div 2 MOVs can be locally opened or closed.
13 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 DW - Drywell venting is impacted. This has an insignificant impact on containment venting since the preferred path from the suppression chamber is available.
Air - The outside air operated valves and/or the 20" AOV101 must be locally opened. There may be other impacts such as Ml or M2 and/or drywell venting may fail, however, suppression chamber venting is available if the outside AOV is opened locally as modeled in the PRA.
X - system failure Div 1 and 2 DC power (Dl and D2), vital AC (UA and UB), ECCS actuation (El and E2), and service water (SA and SB) were treated similarly to SV. Loss of service water or DC at the main source was modeled as an initiating event as shown in the table. Where cable evaluations were performed on main line systems or the BOP systems, cable evaluations and impacts were conducted to the electrical power source and controls.
(4)
Reactor building fire zones were evaluated with a screening frequency of 1 E-2/yr.
14 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-1B: Initial Fire Area Screening Analysis Summary, LERF Flags CLERP FREQ LERF LERF Screen?
CDF Screen?
26\\373.1NZ RPS 4.29E-03 9.90E-03 4.24E-05 No No 26\\373.XNZ AiX 4.29E-03 9.90E-03 4.24E-05 No No 26\\373.1NZ SCRAM 4.28E-03 9.90E-03 4.24E-05 No No 26\\373.2NZ RPS 4.29E-03 2.30E-04 9.86E-07 No No 24\\356NZ A2X 4.29E-03 2.30E-04 9.86E-07 No No 24\\356NZ AIX 4.29E-03 2.30E-04 9.86E-07 No No 24\\356NZ RPS 4.29E-03 2.30E-04 9.86E-07 No No 26\\373.3NZ RPS 4.29E-03 2.30E-04 9.86E-07 No No 26\\373.XNZ A2X 4.29E-03 2.30E-04 9.86E-07 No No 24\\356NZ SCRAM 4.28E-03 2.30E-04 9.85E-07 No No 26\\373.3NZ SCRAM 4.28E-03 2.30E-04 9.85E-07 No No 26\\373.2NZ SCRAM 4.28E-03
- 2.30E-04 9.85E-07 No_________No 24\\357XL AIX 4.29E-03 1.50E-04 6.43E-07 No No 24\\357XL RPS 4.29E-03 1.50E-04 6.43E-07 No No 24\\357XL A2X 4.29E-03 1.50E-04 6.43E-07 No No 24\\357XL SCRAM 4.28E-03 1.50E-04 6.42E-07 No No 88\\331NW LOSP 6.82E-04 7.70E-04 5.25E-07 No No 16\\352NW LOSP 4.27E-04 1.60E-04 6.84E-08 No No 16\\332NW LOSP 4.27E-04 1.50E-04 6.41E-08 No No 16\\371NW LOSP 4.27E-04 1.50E-04 6.41E-08 No No 35\\238SW RWX 6.29E-06 1.OOE-02 6.29E-08 No No 35\\245SW RWX 6.29E-06 1.00E-02 6.29E-08 No No 35\\223SW RWX 6.29E-06 1.00E-02 6.29E-08 No No 35\\255SW RWX 6.23E-06 1.OOE-02 6.23E-08 No No 35\\213SW RWX 6.23E-06 1.OOE-02 6.23E-08 No No 76\\380.INZ AIX 1.74E-05 2.30E-03 4.01E-08 No No 19\\336XL A2X 1.67E-05 9.70E-04 1.62E-08 No No 34\\232SW RWX 1.24E-06 1.00E-02 1.24E-08 No No 72\\351.iNZ AIX 1.74E-05 5.30E-04 9.23E-09 Yes No Screening Criteria: < IE-8 15 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-2: Detailed Evaluation Summary and Initiating Events Modeled -IPEEE and Updated Screening Summary Screening Summary Model Area Zone Description 2010 IPEEE Detailed Evaluation Initiating Criteria IE-7 Criteria >IE-6 Event 16 332NW Div 1 cable chase West CDF = 6.92E-7 CDF = IE-5 FA16A 16 352NW Div 1 cable chase West CDF = 7.38E-7 CDF= L.1E-5 Detailed evaluation FA16B 16 371NW Div 1 cable chase West CDF = 6.92E-7 CDF = IE-5 17 333XL Div I standby switchgear room CDF = 1.22E-7 CDF = 2E-6 Detailed evaluation F333XL 17 343NZ Remote shutdown room A West CDF < IE-7 CDF = 3E-7 Detailed evaluation [evaluated due to room B F343NZ not screened]
18 304NW 230 degree tunnel CDF = 1.58E-7 CDF = 3E-6 18 324NW Div 2 riser area CDF = 1.58E-7 CDF = 3E-6 18 337NW Div 2/3 cable chase East CDF = 1.58E-7 CDF = 3E-6 FA18A 18 359NW Div 2/3 cable chase East CDF 16Detailed evaluation FA18B 18 377NW Div 2/3 cable chase East CDF = 1.58E-7 CDF = 3E-6 19 323NW Div 2 cable routing area CDF = 1.58E-7 CDF = 3E-6 19 336XL Div 2 standby switchgear room CDF = 5.03E-7 CDF = 1.9E-5 Detailed evaluation F336XL 19 338NZ Remote shutdown room B East CDF < 1E-7 CDF = 3E-6 Detailed evaluation F338NZ 24 356NZ PGCC relay (353,354,362SG)
CDF = 2.63E-5 CDF = 2.3E-4 Screened based on evaluation at panel level of None 24 36N GCelay(353354,62SGCD
=2.63E-detail.
CDF = 1.71E-5 Screened after more careful assessment of 24 357XL PGCC computer room (358XG)
CDF = 1.5E-4 impacts None CDF = 1.13E-3 Fires in panels 852 (FCRl and FCR2) and 601 FCR0 26 373.1NZ Control Room (372-376)
CDF = 9.9E-3 (FCR3) determined important. FCR0 FCR2 conservatively added to represent other panels.
FCR3 CDF = 2.4 E-5 Screened after more careful assessment of 26 373.2NZ Shift supervisors office CDF = 2.3E4 impacts None 26 373.3NZ Training room E-5 Screened after more careful assessment of None CDF373.3N2Tr.4ninE-5oom CDF = 2.3E-4 impacts None 34 212SW North reactor building El 175 CDF = 1.58E-7 CDF = 8E-6 Screened based on detailed evaluation None 34 222SW North reactor building El 215 CDF = 1.58E-7 CDF = 8E-6 Screen*d based on detailed evaluation None 34 232SW North reactor building El 240 CDF = 2.48E-7 CDF = 8E-6 Screened based on detailed evaluation None 34 243SW North reactor building El 261 CDF = 1.58E-7 CDF = 8E-6 Screened based on detailed evaluation None 34 252SW North reactor building El 289 CDF = 1.58E-7 CDF = 8E-6 Screened based on detailed evaluation None 35 213SW South reactor building El 175 CDF = 3.35E-6 CDF = 8E-6 Screened based on detailed evaluation None 35 223SW South reactor building El 215 CDF = 8.43E-6 CDF = 8E-6 Screened based on detailed evaluation None 35 238SW South reactor building El 240 CDF = 3.35E-6 CDF = 8E-6 Screened based on detailed evaluation None 35 245SW South reactor building El 261 CDF = 3.36E-6 CDF = 8E-6 Screened based on detailed evaluation None 35 255SW South reactor building El 289 CDF = 3.35E-6 CDF = 8E-6 Screened based on detailed evaluation None 51 601XL West normal switchgear CDF < 1E-7 CDF = 1.1E-6 Total loss of offsite power modeled after FNSGR 52 602XL East normal switchgear CDF < 1 E-7 CDF = 1.3E-6 evaluation 16 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECIHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-2: Detailed Evaluation Summary and Initiating Events Modeled -IPEEE and Updated Screening Summary Screening Summary Model Area Zone Description 2010 IPEEE Detailed Evaluation Initiating Criteria > IE-7 Criteria _>
IE-6 Event 60 807NZ Service water pump B CDF < 1 E-7 CDF = 3.2E-6 Screened based on detailed evaluation None 61 806NZ Service water pump A CDF < 1 E-7 CDF = 3.2E-6 Screened based on detailed evaluation None 72 351.INZ Instrument shop El 288 CB CDF = 2.71 E-7 based on 380.1 CDF = 5.8E-7 based on Screened based on detailed evaluation None 380.1 72 351.2NZ Corridor El 288 CB CDF = 2.71E-7 based on 380.1 CDF = 5.8E-7 based on Screened based on detailed evaluation None 380.1 76 380.1NZ Operators lunch room El 306 CDF = 1.18E-6 CDF = 2.5E-6 Screened based on detailed evaluation None 76 380.2NZ Corridor/toilet El 306 CDF = 2.71E-7 based on 380.1 CDF = 5.8E-7 based on Screened based on detailed evaluation None 380.1 78 612XL West normal switchgear CDF < 1E-7 CDF = 1.2E-6 Total loss of offsite power modeled after FNSGR 79 613XL East normal switchgear CDF < 1 E-7 CDF = 1.1 E-6 evaluation 88 331NW Corridor El 261 CB 5.1OE-6 5.30E-05 Detailed evaluation FA88B 17 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-3: Fire Initiating Events and Their Contribution to CDF and LERF CDF and LERF Contribution, Percent Initiator Frequency Location Impacts CDF CDF1 CDF2 LERF LE F1 LERF2 Div.1 DG Div.2 DG e
]
OOS DG OOS FCRO 1.9E-4 Control Room Feedwater and main condenser 12.4%
4.6%
3.50%
1.3%
0.6%
0.5%
FCR1 1.E-5 Control Room Panel 852 Same as FCRO, LOSP, HPCS, potential 2.7%
3.8%
2.49%
2.3%
17.1%
9.7%
Div 2 DG FCR2 1.OE-5 Control Room Panel 852 Same as FCRO, LOSP A, potential Div 3.7%
2.0%
1.02%
0.4%
0.4%
0.2%
1 DG FCR3 1.E-5 Control Room Panel 601 Service Water 3.2%
1.2%
0.92%
0.3%
0.2%
0.1%
FNSGR 1.8E-4 Normal SWGR LOSP 0.6%
2.5%
2.64%
2.6%
1.2%
1.2%
FA88B 3.6E-6 Control Bldg Corridor EL 261 LOSP, HPCS 0.6%
1.5%
1.51%
3.2%
1.3%
1.3%
FA16B 2.1E-6 Div 1 Cable Chase West W/
LOSP, Division 1 AC, RCIC 0.27%
0.1%
4.35%
1.8%
0.1%
4.2%
Auto Suppression Failure FA18B
10.2%
0.09%
7.0%
9.3%
0.1%
Suppression Failure FA16A 4.1E-5 Div 1 Cable Chase West Division 1 AC and RCIC 0.08%
0.0%
0.18%
0.1%
0.0%
0.2%
FA18A 4.1E-5 Div 2 Cable Chases Division 2 AC and HPCS 2.11%
0.6%
0.41%
0.2%
0.2%
0.1%
F333XL 6.2E-5 Div 1 Switchgear Room Division 1 AC 0.08%
0.0%
0.03%
0.0%
0.0%
0.0%
F336XL 6.2E-5 Div 2 Switchgear Room Division 2 AC 1.03%
0.3%
0.18%
0.0%
0.0%
0.0%
F338NZ 1.4E-4 Remote Shutdown Room B RCIC and RHR B 0.00%
0.0%
0.01%
0.0%
0.0%
0.0%
F343NZ 1.4E-4 Remote Shutdown Room A RCIC and RHR A 0.02%
0.0%
0.20%
0.0%
0.0%
0.0%
TOTAL 30%
27%
18%
19%
30%
18%
18 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 ATTACHMENT A2-A IGNITION FREOUENCY COMPARISON Ignition frequencies are as derived from Table 1.2 of FIVE Attachment 10.3 (EPRI TR 100370) and have not been updated to recent data. The following summarizes a comparison with recent updated data in EPRI 1016735 for some key ignition sources in the NMP2 PRA:
Electrical Cabinets - Table 1.2 of FIVE Attachment 10.3 (EPRI TR 100370) has the following generic values:
Control Room = 9.5E-3 Switchgear Room = 1.5E-2 Cable Spreading = 3.2E-3 More recent data from EPRI 1016735 Bin 15.1 (non-HEAF) = 2.4E-2 and Bin 15.2 (HEAF) = L.1E-3.
Also, there is a separate Bin 4 = 8.2E-4 for the main front control board in the control room. Because of differences in methodology such as counting cabinets, etc., it is difficult to compare without essentially updating the ignition frequencies for, the NMP2 fire PRA. However, the present frequencies are judged to be reasonable based on the following comparisons:
The Unit 2 IPEEE frequency per cabinet in the emergency switchgear rooms is -5E-5/yr.
The value using the latest Bin 15.1 frequency and assuming 800 cabinets (unit 1 value, but Unit 2 is expected to have more cabinets) would be approximately 3E-5/yr.
Using NRC Inspection Manual 0609, Appendix F, Attachment 4, the frequency per cabinet is 5.5E-5/yr.
Transients - Table 1.2 of FIVE Attachment 10.3 (EPRI TR 100370) has a value of 1.3E-3 whereas more recent data from EPRI 1016735 Bin 7 = 4.8E-3. Thus, there could be an overall increase in transient frequency, but for the critical areas identified in the NMP2 fire PRA it is expected that the frequency will be comparable with no significant change once the frequency is adjusted for these compartments (e.g.,
influence factors and controls as described in Section 6 of NRREG/CR-6850).
Main Control Board - The frequency of a fire with major impacts was developed for the NMP2 PRA based on an evaluation of data for control room fires and the number of cabinets; a frequency of 1.1E-5/cabinet in the control room was used. This frequency would be closer to 1 E-6 based on more recent data and methods:
Total frequency for main control board = 8.2E-4 (EPRI 1016735 Bin 4)
There are 5 cabinets that make up the main control board The conditional probability from NUREG/CR-6850 Appendix L that the fire spreads beyond the initial starting point (e.g., a switch) and causes additional impacts can be considered. This is reasonable because the presence of operators essentially ensures incipient detection and suppression before the fire can develop and spread.
19 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 ATTACHMENT A2-B DETAILED EVALUATIONS Control Room Evaluation (FA26 373.lNZ) - As a result of detailed analysis, the following four fire initiators are included in the PRA model.
FCRO - Fire in control room with minor impact = 2.1 E-4/yr FCR1 - Fire in control room panel 852 - LOSP & HPCS failure = 1.1E-5/yr FCR2 - Fire in control room panel 852 - partial LOSP = 1.1 E-5/yr FCR3 - Fire in control room panel 601-loss of SW, but recoverable = 1.1 E-5/yr The most difficult area to screen was the control room because all safety and non-safety system control cables enter this area. In order to realistically estimate core damage frequency (CDF) for fires in this area, the routing of cables through the area was evaluated as well as the impact of fires in specific electrical cabinets. It was determined that 2 main control room cabinets dominate risk with regard to impact on the PRA. In addition, the fire events that have occurred in the database were evaluated to develop a more realistic estimate of a fire initiator that causes major damage.
GAP: Completeness of main control board fire scenario development is lacking, but scenarios are included for Panel 852, which is most important for the EDG AOT evaluation because this panel includes offsite power controls as well as controls for all 3 emergency diesels.
Shift Supervisors Office (FA26 373.2NZ), Training Room (FA26 373.3NZ), and PGCC Computer Room (FA24 357XL) - These compartments were not evaluated during the initial screening analysis (CDF was set equal to the total fire frequency for the area) because the spatial database developed for fire areas 24 and 26 did not distinguish between zones 373.lNZ (control room), 373.2NZ (shift supervisors office) and 373.3NZ (training room). Likewise the database did not distinguish between the relay and computer rooms. Thus, the actual cables being routed in these zones have to be evaluated. There is no safety related or important non-safety related equipment or cables in the supervisor's office or the training room based on a review of electrical drawings and a visual inspection. These rooms are screened out.
Regarding the computer room, the design review indicates that no safety related (divisional) cables are located in this zone. It is considered possible that a fire could cause a plant trip, but the low frequency of a fire in this zone in combination with the minor impact on plant systems indicates that this zone can be screened out.
Operators Lunch Room El 306 (FA76 380.1NZ) - This fire zone was not evaluated during the initial screening analysis. The initial screening analysis assumed loss of Division 1 AC power and HPCS based on Appendix R results and because the spatial database developed for fire area 76 did not distinguish between zones 380.1NZ (operators lunch room) and 380.2NZ (corridor). Thus, the actual cables being routed in these zones have to be evaluated. There are smoke detectors in the area with no automatic suppression. However, there are operators and other personnel either in the area or close by.
During a walkdown, the following conduits were observed on one wall in the room:
20 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 S
2CC502PF1 (purple), 2CC502PF2 (purple), 2CC502PF4 (purple), 2CC502PF5 (purple) 2CC520YP (yellow) containing cable 2HVKBYC503 The purple cables are associated with the HPCS (Div 3) system and the yellow cable is associated with Div 2 chilled water (control building cooling). Even if failure of these cables is assumed, the impact would be insignificant; this location can be screened out at <I E-7/yr.
There are smoke detectors in this area with no automatic suppression.
Corridor El 261 CB (FA88 331NW) - The initiating event frequency for FA88B contains the probability that automatic suppression fails (7.7E-4/yr for frequency of fire in FA88 times 0.05 probability of suppression failure = 3.9E-5/yr) which causes loss of normal AC power and HPCS.
Successful suppression is assumed to have no impact on these plant systems.
This corridor is very long as shown in the simplified diagram. This diagram shows several sections that were defined for the purposes of documenting walkdown notes. For initial analysis purposes, the corridor was broken into two separate zones with the shaded portion called FA88A and the remaining corridor FA88B.
These two zones were identified because Diesel Generator Rooms FA88A (Sections A and B, including B/C) in the diagram has no automatic suppression (does have A/B A
smoke detection) and the ceilings are much lower.
Whereas FA88B, the remaining non shaded sections, have automatic detection and suppression (smoke detection and cable tray water spray) and the ceiling is B
HPCS Chiller D
much higher. Thus, the following strategy was Swgr Rooms developed to more realistically assess the risk of fires in fire area 88:
B/C C
CID FA88A was evaluated to determine the impact of a fire in this zone. Initially, it will be assumed that a fire will cause this impact without a chance for suppression. All non-safety trays and conduits were 0
Div II Div I found to have no impact on offsite power and the
=
balance of plant (feedwater and main condenser). A single conduit (2CL511GD containing cable a
2BYSAGL609) can impact the Division I diesel generator. Another conduit, 2CL5 1 OYF, was found to be empty (no cable). Apparently the control cable to the Division 2 diesel generator was rerouted through Main Coruld 2CL510YH in another fire area as described in the FA88A evaluation below. Also, there is a HPCS (purple cable) in the B/C interface area.
I_8 0
D C0 0
-z DIE
)r FA88B has automatic suppression. If suppression is successful, no impacts are assumed to occur in cable trays and conduits. This is based on an evaluation of the time to cable critical temperature versus time to detect and suppress the fire. Also, all the impacts are associated with cables in cable trays and conduits up high in the vicinity of cable tray water sprays. There are no cables or cabinets of concern near the floor area. If automatic suppression fails, initially it will be assumed that all impacts identified in the 21 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 FA88B occur. This includes loss of offsite power, balance of plant systems, and HPCS. The location of the Division 1 diesel cable in FA88A which has no automatic suppression is at the opposite end of section A from where FA88B starts. Thus, a fire that impacts this cable and causes loss of offsite power in FA88B is considered unlikely and is neglected. FA88A can be easily screened out because the only impact of a fire is the Division 1 diesel and possibly HPCS. Even if we assume an initiating event and loss of the diesel and HPCS, the scenario will easily screen out below 1E-7/yr.
FA88B can be conservatively evaluated by running the FA88 fire initiator through the PRA with HPCS and offsite power failed. This is conservative because the total frequency of a fire in FA88 has been applied to the FA88B portion and additional detailed evaluations of HPCS cables and their vicinity to offsite power and other balance of plant cables has not been considered.
Fire area FA88A was inspected to determine if Div 1, 2 & 3 diesel generators are lost. The specific goal was to identify which wires were impacted by the fire and did they actually cause the loss of diesel generators. There are 2 conduits 2CL5 1 YF & 2CL5 11 GD in this zone. A query of the CRS2 database for conduit 2CL5 11 GD and a review of drawings EE-1 OA-9 indicates that cable 2BYSAGL609 provides power to 2BYS*PNL204A in the diesel generator room. Loss of this cable causes loss of the Div 1 DG control circuits for both the engine and the generator.
A query of the CRS2 database for conduit 2CL510YF indicated that this conduit is routed from 2BYS*PNL204B to the tray system located in a different fire area.
But, there is not any cable in the conduit. To verify that the power feed to 2BYS*PNL204B was not in this conduit, CRS2 was queried to identify the drawing for this panel.
Drawing EE-10A-9 indicates that the power feed to 2BYS*PNL204B is cable 2BYSBYL609. This cable is routed to 2BYS*PNL204B via the following raceways: 2CL507YQ, 2TL507Y, 2TL510Y &
2CL5 1 0YH.
Conduit 2CL510YH is located in the diesel generator control room. It runs from 2BYS*PNL204B out of the control room via the floor. Therefore, this conduit is not affected by a fire in FA88.
An evaluation of FA88B indicates this section of fire area 88 has automatic detection and suppression.
The fire area walkdown identified that the following divisional conduits exit one of the contiguous fire areas and enter FA88B.
The cables in the conduits were identified using the CRS2 database. The divisional cables are:
Div 1 2HVCAGK290, 2HVCCGK290, 2RPSAGK502, 2LACAGK200, 2LACAGK201, 2LACAGK202 Div 2 2LACBYK200, 2LACBYK201, 2LACBYK202, 2HVCBYK206 Failure of each cable was evaluated for the impact on shutdown and the failure of cables was evaluated for breaker coordination and potential loss of the busses that power the cables.
The Division 1 lighting system cables, 2LACAGK200, 2LACAGK201, 2LACAGK202 are powered from panel 2LAC*PNL100A. These cables supply power to the lighting system. Loss of the emergency lighting power feed is judged to have a minimal impact on the ability to respond to the fire since the required lights are battery backed. The supply breaker to 2LAC*PNL1OOA is sized to not trip in the event that all three cables have bolted faults.
Cables 2IHVCAGK290 and 2HfVCCGK290 are powered from 2EJS*PNL102A. Loss of each cable has an impact on the capability to isolate the control room when a high radiation condition exists. Damper 22 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 isolation or loss of this isolation feature has no impact on the capability to respond to this fire. The supply breaker to 2EJS*PNL102A is sized and coordinated so as to not open if both of these cables have bolted faults.
Cable 2RPSAGK502 is powered by panel 2RPM*PNLB100.
This panel provides power to the "B" scram solenoids. Failure of this panel generates a 1/2 reactor trip. Loss of the individual cable generates 1/2 for group 1 scram solenoids. This failure has no adverse impact on the capacity to respond to this fire.
The Division 2 lighting system cables 2LACBYK200, 2LACBYK201 and 2LACBYK202 are powered from 2LAC*PNL301B. The individual or combined failures of the cable have a minimal impact on the capacity to respond to this fire and are not modeled (see Div 1 evaluation above).
Cable 2HVCBYK206 powers a heater in the control building HVAC system. Failure of this cable has a minimal impact on the capacity to safely shutdown and is not modeled.
Division 2 Standby Switchgear Room (FA19 336XL) - This initiating event frequency for F336XL is 6.7E-5/yr. The dominant scenario was determined to be loss of Div 2 AC power due to switchgear fires that did not credit suppression.
The initial screening analysis assumed that Division 2 AC power failed, as well as RBCLC and HPCS, given a fire in this location. Walkdowns were performed in support of this more realistic evaluation. The ceiling and cables in this room are very high. Cables enter the cabinets from the top as well as from underneath. There are 7 smoke detectors in this fire zone and a manual carbon dioxide total flooding suppression system. A more realistic analysis of fires in this zone was performed by considering the impacts of fires within cabinets (electrical cabinet fires), on cables external to the cabinets (transient type of fires), and cabinet fire impacts on cables.
An evaluation of cables concluded that core damage frequency due to fires external to electrical cabinets is less than 1E-7/yr. This is based on the following:
" The frequency of a fire in this zone is dominated by electrical cabinet fires. The contribution from other causes (i.e., welding, transient, ventilation fans, junction box splices) external to the cabinets is much less frequent. This alone provides over an order of magnitude reduction in the screening analysis results.
" The proximity of cables that could have the impact assumed in the initial screening analysis was also evaluated. Based on this evaluation, it was determined that Div 2 cables associated with the 4kV switchgear, the diesel, and its supplies are not in close proximity with normal AC power feeds.
Most Div 2 cables come from underneath the switchgear (cable spreading below switchgear room) and normal AC power enters the top of the switchgear cabinets. Three yellow (Div 2) conduits (2CC534YN, G and M) enter the top of the switchgear. They come out of the floor behind the switchgear, go up the wall, and pass over to enter the top of the cabinet passing near 2CH514N.
These cables are associated with tie breaker 2NNS-SWGO15 103-8 which are control cables for an alternate offsite supply. Thus, fires external to electrical cabinets are unlikely to cause total failure of Div 2 AC power which was assumed in the screening analysis. Cabinet fires will dominate the frequency of a total loss of Div 2 AC power.
23 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4
- Four critical normal AC power cables to Div 2 switchgear were found in this room during the initial screening analysis. Two are in tray 2TC561N. The other two are in tray 2TH513N and enter this tray from conduits 2CH513NB and 2CH513NC which come from the top of the switchgear cabinet.
The frequency of core damage from a fire that causes loss of normal AC power to Div 2 switchgear, but does not lead to loss of the Div 2 diesel, is less than 1 E-7/yr (see initial screening analysis of fire area 52 604NZ).
RBCLC cables were also found in this room during the initial screening analysis. Two cables in tray 2TX564N can lead to a loss of RBCLC which would lead to loss of the main condenser and feedwater systems. However, these cables do not enter any cabinets in the room and the tray is not directly above or next to the Div 2 AC power cabinets. This tray is more than ten feet off the floor (second tray up) and it passes over 2BYS*SWG002B. A fire in this Div 2 DC power cabinet and potential impacts on the above cable trays (i.e., RBCLC) is assessed later in this section.
Another tray containing E
2BYS*SWG002B normal AC power (2TC561N) is in the Tray 2TX504N is second tray in stack of several about 10 ft vicinity but higher up near the ceiling. It above the floor. 2TC561 N is 3 is judged that fires that could impact 133 trsaboe rx5*4.
eJ 2CX5,I0PAI passes nearby these cable would not likely impact Division 2 AC power. Thus, fires that Div 11 Swftchgear Div I]I conduts run 15to2DIt impact Div 2 AC power and RBCLC as Room (336XL) above floor on this wall assumed in the initial screening analysis 2ENS*SWG103 2CX500PAI 9 2CX6PE are less than 1E-7/yr. Fires that impact Coneuts toCHofING &C come out ot top of SWG &
RBCLC and not impact Div 2 AC or DC go into 2T14513N near top a
bof ceiling and penetrates power can be neglected because core iFABS. 2CXDODPE also damage frequency would be less than passes near same penetraftc 1E-7/yr (RWX CCDP in the PRA times F8 the fire frequency).
FAS 3
'1
" Div 3 HPCS conduits pass along the wall behind the switchgear. The conduits are 2CX500PA1 and 2CX500PE. However, these conduits do not enter any cabinets in the room and it is judged that fires that could impact these conduits would not likely impact Division 2 AC or DC power. One conduit (PAl) passes near normal AC power (tray 2TC561N) and/or RBCLC (tray 2TX564N) at one end of the room. The other conduit (PE) passes near normal AC power (tray 2TH513N) at the opposite end of the room where cables exit through a penetration to FA88. Thus, fires that impact normal AC power to Div 2 switchgear or RBCLC and HPCS is possible in two localized areas. Core damage frequency from these events would be less than 1 E-7/yr even without taking credit for suppression.
" It is difficult to impact cables due to transient fires on the floor level because the cables are so high and all cables are IEEE 383 qualified. Even without automatic detection and manual suppression, it appears that the fire could bum out before impacting the cables.
Evaluation of Cabinets - the impact associated with an electrical cabinet fire depends on the cabinet and the location of the fire within the cabinet. Table 4.6-4 of the IPEEE identifies the 20 electrical cabinets in the room and describes the potential impact of a fire within each cabinet.
Based on this evaluation, emergency switchgear 2ENS*SWG1O3 was identified as the most critical cabinet as summarized below:
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4
" Loss of 2VBA*UPS2B results in the loss of Div 2 automatic ECCS actuation, Div 2 RRCS and the ability to open RCIC, LPCI "B" and "C" injection MOVs.
Although loss of the UPS was not identified as an automatic plant trip in the PRA, it is assumed for this fire that plant shutdown occurs.
The frequency of core damage was conservatively estimated with the PRA to be less than 1E-8/yr, assuming a plant trip and a fire frequency of 11E-3/yr. Thus, this scenario can be neglected.
- Loss of 2BYS*SWG002B (Div 2 DC) results in a plant trip and impacts the availability of several Div 2 components (i.e., pump start and actuation systems). The CCDP in the PRA from loss of Div 2 DC (initiating event D2X) combined with the fire frequency results in CDF less than 1E-7/yr and can be neglected.
" Loss of 2ENS*SWG1O3 (Div 2 AC) results in a plant trip and impacts the availability of Div 2 systems. The CCDP in the PRA from loss of Div 2 AC (initiating event A2X) combined with the fire frequency results in CDF less than 1E-7/yr and can be neglected.
From the above, loss of Div 2 AC power due to fire is expected to have the most important impact on core damage frequency, although apparently less than 1E-7/yr. For this reason, these scenarios were evaluated in more detail. With regard to a fire in a switchgear cabinet, it will usually start in a specific cubicle and therefore, the impacts suggested in Table 4.6-4 of the IPEEE are not expected for all fires. In order for the total impact to occur, either the fire must occur in a cubicle that could result in the total impact or the fire must occur in a cubicle that has limited impacts, but propagates to cause additional impacts before detection and suppression.
The 4kV switchgear was inspected to determine the fire locations that can cause loss of the bus. A fire in the cubicle where the protective relaying is located can cause the breakers to trip. A fire in a breaker cubicle that faults the upstream (supply side) cables can cause loss of the 4kV bus. A fire in a breaker cubicle that faults the load cables and also causes the breaker to fail as-is can cause loss of the 4kV bus.
Alternatively, if the fire causes spurious opening of the breaker or if it causes a fault that is cleared, the fire impact is localized to that load only.
A total loss of power can occur if the protective relaying for the bus is impacted by fire. Total loss of Division 2 4kV is assumed for any fire in the following cubicles:
C3226 Bkr 103-3, C3227 Bkr 103-4, C3236 Bkr 103-14 A total loss of 4kV can occur if a fire in an energized cubicle causes a power system fault within the cubicle and also depowers or fails the breaker control circuit before the C02 system is manually discharged and suppresses the fire. The fault will be cleared by the upstream breaker, not the branch breaker, resulting in loss of offsite power. After the supply breaker clears, the diesel generator breaker will close onto a faulted bus and quickly open thus preventing recovery of offsite power.
Alternatively, the fire can occur and the branch breaker operates to clear the fault. The C02 system. is manually discharged and suppresses the fire thus limiting any additional damage to the cubicle. A fire in the following cubicles can cause loss of the Division 2 bus or loss of the branch load:
C3228 Bkr 103-5, C3230 Bkr 103-7, no Id Bkr 103-8, C3231 Bkr 103-9, C3232 Bkr 103-10, C3233 Bkr 103-11, C3234 Bkr 103-12, C3239 Bkr 103-N2 25 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 A fire in an empty cubicle or racked down/out breaker is not postulated to occur since a fault on the supply side cables is actually a bus fault. The following cubicles have their breaker removed or it's control circuit depowered:
C3225 Bkr 103-2, C3229 no bkr, C3237 Bkr 103-15., C3238 Bkr 103-NI In summary, there are 3 of 17 cubicles in 2ENS*SWG103, associated with protective relaying, that can lead directly to loss of all Div 2 AC power. There are 8 of 17 cubicles that can lead to loss of all Div 2 AC power if a short (fault) also occurs from the fire. Later in this section, this information is used in developing the conditional frequency of fires that cause a total loss of Div 2 AC power given a fire occurs in 2ENS*SWG103. To develop these conditional frequencies, it was assumed that the total frequency of a fire in the cabinet is dominated by the 11 cubicles that can lead to a total loss of Div 2 AC power. The other six cubicles are usually not energized or empty and judged to contribute less to the total frequency.
Thus, conditional frequencies of 3/11 and 8/11 are used in the analysis.
The 600V AC distribution can be failed by a fire in 4kV bus breaker 103-1 switchgear and the feed for 2EJS*US3. Additionally, a fire at the "X3A" transformer will result in loss of 600V AC. Fires at the load center, 2EJS*US3, can cause loss of all 600V AC. 600V AC MCCs 2EHS*MCC303 bus B is separated from the D bus. A fire in the "B" bus can cause loss of the B & D busses while a fire at the D bus will only cause loss of that section.
A fire at the battery board breakers can result loss of 125V DC. It may cause only the loss of the branch load/supply or loss of the bus. Fire at a battery charger will result in loss of one of the two chargers but.
not the bus. There is another standby charger available that can be switched in after the fire is out and the room ventilated (local operator action).
A fire at the UPS can cause a non recoverable loss of 120V AC.
The fire frequency developed for this fire area using the FIVE methodology included all cabinets. Some cabinets are empty and some switchgear breakers are completely depowered while a few are in standby.
Also, fires in several cabinets will have an insignificant impact.
To better model this
- area, a
more detailed evaluation was performed to identify cabinets/cubicles/enclosures that are energized or have been previously shown to be important to risk.
The approach taken realized that only powered equipment was likely to fail and only those cubicles that were previously shown to have some affect on risk need be evaluated.
This fire area contains very few exposed cables and they are locates more than 20 feet above the floor.
All of the important cables are in cubicles or cabinets. There is no Div 2 4kV cables (and only control wires to the alternate power offsite source) that are routed outside of switchgear in conduit.
The fire frequency was calculated using a combination of fixed and transient combustibles. For this switchgear room, the major source of damage is the cubicles themselves. Transient combustibles are of lesser concern because of procedural controls to limit transient combustibles and there is a cross zone detection system and a 100% coverage manual C02 system.
The total fire frequency is partitioned according to the normal operating status of the cabinet and other features that determine the potential for fire. All loads were subjectively categorized into four groups 26 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 according to their potential for fire. The first category is the equipment that is normally operating, requires internal cooling and has a high density of internal components; 2VBA*UPS2B and 2BYS*CHGR2B 1. T he second group of components are normally operating but far from design capacity and have lower density of internal components; 2ENS*SWGlO3, 2EJS*US3, 2EJS*X3A and 2BYS*SWG002B. The third group of components are panels that are intermittently operating or not operating and are not near their design capacity; 2EHS*MCC303, 2EJS*PNL300B, 2EJA*XD301B and 2EJA*PNL301B. The last group consists of panels that are not normally operating or are at a minimal loading such as emergency lighting panels and transformers, the breaker test station, and the standby charger.
Later in this section, this information is used in developing the conditional frequency of a fire in electrical cabinet 2ENS*SWG1O3, given a fire in this room. It was decided that using a 1/20 conditional frequency (a total of 20 cabinets in Table 4.6-4 of the IPEEE) could be optimistic since the frequency of cabinet fires is probably dependent on the cabinet as discussed in the previous paragraph. If we assumed that the total fire frequency is dominated by the six cabinets identified in the first two groups, a 1/6 conditional frequency would be used. A 1/5 conditional frequency is used in the analysis described below.
The frequency of a fire within electrical cabinet 2ENS*SWG103 that causes loss of Div 2 AC power is estimated with the following equation:
FSWG103/A2 = F336XL
- FSWG103 * [(3/11) + (8/11)*PF] = 9.7E-4 * (1/5) [(3/11 + (8/11)*0.1] =
6.7E-5/yr Where:
FSWG103/A2 is the annual frequency of a fire in 2ENS*SWG103 that results in loss of Division 2 AC power (A2X initiator in the PRA)
F336XL is the sum total annual frequency of a fire in this room from all causes.
FSWG103 is the fraction of fires in the room associated with 2ENS*SWG1O3. Rather than utilize 1 in 20 cabinets as shown in Table 4.6-4, 1/5 is used based on the evaluation above.
PF is the probability of a fault causing loss of the switchgear. A value of 0.1 is used.
(3/11) and (8/11) are fractions of fires in 2ENS*SWG103 (cubicles) that lead to loss of bus from protective relay cubicles and other cubicles requiring an additional short, respectively. The development of these conditional frequencies is discussed above.
Core damage frequency can be estimated by taking the CCDP in the PRA for initiating event A2X times the above frequency for fires. The result is as follows:
6.7E-5/yr
- 6.3E-5 = 4.2E-9/yr If the probability of a fault is set equal to 1.0, core damage frequency would increase to 4E-8/yr.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Another bounding calculation was performed to check the possible upper bound frequency of fires that have minor impact initially, but manual suppression does not work and the fire propagates to have the impact assumed in the initial screening analysis. The result is as follows:
5E-7/yr*0.05 = 3E-8/yr where 5E-7/yr is the core damage frequency in the initial screening analysis utilizing the total fire frequency for the room, assuming loss of Div 2 AC power, HPCS, and RBCLC, and taking no credit for suppression preventing propagation. The 0.05 value is the unreliability of suppression. Thus, the fire is assumed to keep burning to have this level of impact. This conservative bounding estimate indicates that core damage frequency will be less than 1 E-7/yr even if spurious failure was increased to 1.0.
Evaluation of Cabinet Fire Impacts on Cables - during walkdowns, the potential for cabinet or panel fires to impact cables or conduits overhead was evaluated. This was done because cabinets dominate the frequency of fires in this room and a combination of impacts from the cabinet failure and cables nearby could be important. The following summarizes the conclusions of this evaluation:
Some fires in the 4kV switchgear already result in a total loss of Div 2 AC power. The normal AC power cables are routed straight up toward the ceiling, above a cubicle that does lead to loss of Div 2 AC power, before being routed in trays. It is unlikely that any fire in this switchgear, which does not result in a total loss Div 2 AC power, would impact these cables.
As described earlier, both RBCLC and normal AC power cables pass over 2BYS*SWG002B. Since RBCLC is much closer to the top of this cabinet, core damage frequency was estimated for the case where Div 2 DC power and RBCLC are both lost. Using a conditional frequency of 1/5, as used in the previous evaluation of cabinets above, core damage frequency is less than 1 E-7/yr.
Another less likely scenario would also include failure of normal AC power to Div 2. These cables are much higher, three trays above RBCLC. Again, core damage frequency was estimated for the case where Div 2 DC power, RBCLC and normal AC power to Div 2 are lost.
Other cabinet fires would have much less impact than the cases identified above.
Division 1 Standby Switchgear Room (FA17 333XL) - This initiating event frequency for F333XL is 6.7E-5/yr and is based on assumed symmetry with Div 2 based on review comparison. The dominant scenario was determined to be loss of Divisional AC power due to switchgear fires that did not credit suppression.
The initial screening analysis assumed that Division 1 AC power and RCIC failed, given a fire in this location. The functional design of the electrical distribution system for Division 1 is essentially identical to the Division 2 functional design. Walkdowns and design reviews were performed to compare this area with the Division 2 room. The ceiling and cables in this room are very high. Cables enter the cabinets from the top as well as from underneath. There are 7 smoke detectors in this fire zone and a manual carbon dioxide total flooding suppression system. The Division 1 and 2 standby switchgear rooms each have the same number of cabinets with the same ratio of empty to deenergized cubicles. The relative locations of protective relay cabinets are essentially the same. There are some differences in the physical routing of conduits and raceways. The degree of separation or independence of cables associated with the 28 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 offsite power sources and those associated with the diesel was evaluated to determine the number of locations where a fire can cause the loss of both offsite power and the failure of the diesel. There are no cable trays over the Division 1 125 VDC switchgear as there is in the Division 2 standby switchgear room and no RBCLC system cables.
Core damage frequency from the initial screening analysis is less than 1E-6/yr. This value is also less than the Division 2 switchgear screening analysis which was subsequently screened in the above Division 2 evaluation. Because these switchgear rooms are very similar with regard to design, cabinets, routing of normal AC and diesel cables, and fire impacts, this section does not provide the same level of detail as above for Division 2. Instead, the important attributes identified above for Division 2 that reduce the probability of core damage were checked by design review and walkdown. These important attributes include the fact that fire frequency is dominated by electrical cabinets, that normal AC power and diesel supply cables are separated such that failure of both is dominated by cabinet fires in specific cubicles, that the switchgear is similar to the Division 1 switchgear, and the room arrangements and configurations are very similar. Based on this review, the area easily screens below 1 E-7/yr.
Division 1 Cable Chase West (FA16 332NW, 352NW & 371NW) - Two initiating events (FA16A and FA1 6B) are postulated for these rooms. FA16A is a fire near vertical cable trays that contain Division 1 and RCIC cables. The frequency (4.5E-5/yr) is based on the total for these rooms (4.5E-4/yr) times a spatial factor (10%) for a fire near vertical trays. FA16B is a fire near vertical cable trays that contain Division 1 and RCIC cables times the probability of automatic suppression failure (0.05) which allows normal AC power and the balance of plant to be affected. The frequency (2.3E-6/yr) is based on FAl 6A (4.5E-5/yr) times suppression failure (0.05).
The initial screening analysis assumed failure of Division 1 AC power and RCIC, given a fire in this location. T his was based on the Appendix R analysis which indicated that Division 1 and RCIC are impacted. The actual impact on Division 1 was not assessed. In addition, the BOP cable evaluation identified loss of offsite power and other balance of plant systems being lost.
A walkdown was performed to investigate a more realistic evaluation of impacts. T he ceiling and horizontal cable trays in this room are high. Taking credit for automatic suppression (0.05 unavailability assumed) in these rooms would result in a core damage frequency less than 1 E-7/yr still assuming the worst impact as in the initial screening analysis. Note that only IEEE 383 cables are used and for most fires it is not expected that impacts would occur away from the fire (i.e., hot gas layers, etc) even without suppression (i.e. fire burns out). For these reasons, the focus of the evaluation in these rooms is on identifying impacts that could occur before detection and suppression. This includes electrical cabinet fires and noncabinet fires near the floor as described below.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 The following summarizes detection and suppression in each zone:
Fire Zone Number of Type of Automatic Fire Suppression Detectors Temp Smoke Area Water Sprinkler Cable Tray Water I
I Spray 332N'W 0
5 No Yes 352NW 0
4 Yes Yes 371NW 0
4 Yes Yes Electrical Cabinet Fires - The frequency of a fire in each zone is dominated by electrical cabinet fires.
Therefore, the impact of a fire in each cabinet was assessed and is summarized in Table 4.6-5 of the IPEEE. Only impacts judged to potentially influence the PRA are noted and in many cases the impacts are based on conservative assumptions (i.e., a cabinet supplies main steam circuits and it was assumed that MSIVs close and condenser is unavailable even though the circuit impacts were not evaluated). In addition, the proximity of cables to cabinets was evaluated during walkdowns and included in Table 4.6-5 of the IPEEE. If the cabinet is closed (not vented) no additional impacts were considered. In the case of vented electrical cabinets, conduits and cable trays within about 5 feet of the cabinet were considered for the plume and 1.5 feet from the cabinet for radiation heat transfer.
One important finding from this evaluation is that normal AC power is not affected by cabinet fires. This finding alone would reduce the frequency of core damage from cabinet fires below 1 E-7/yr. Also, the loss of all Division 1 equipment was not found to occur due to a single cabinet fire. Thus, the modeling of impacts by cabinet and considering the frequency of a fire/cabinet would further reduce core damage frequency.
Noncabinet Fires - The frequency of fire due to other causes such as transients, welding, and junction box/splices are about an order of magnitude less than cabinets. In fact, if this non cabinet frequency was used in the initial screening, these rooms would screen out at 1E-7/yr. Because of this, it was decided to judgmentally consider a spatial reduction factor to completely screen these rooms. When considering the floor area where fires could potentially impact Div 1 cables (i.e., vertical trays or conduits near the floor) before suppression would occur, it was judged that 10% of the floor area could potentially cause some damage. Assuming that these fires are as likely to occur any place on the floor area, this would reduce core damage frequency less than 1E-7/yr. Note that this is conservative because it still assumes that for all these fires the worst case impacts also occur as in the initial screening analysis. A more realistic assessment could consider those areas where both offsite power (loss of offsite power reduces the reliability of Div 2) and Div 1 cables are located which would reduce the spatial reduction factor even further. Thus, identifying those areas where normal AC power and Div 1 can be impacted would produce a smaller spatial reduction factor. For those areas where a fire does not affect both offsite power and Div 1, core damage frequency estimates for these scenarios would be much less. Finally, assuming that loss of Div 1 cables lead to a total loss of Div 1 equipment is still conservative.
Division 2 Cable Chases (FA18 304NW, 324NW, 337NW, 359NW, 377NW & FA19 323NW) - Two initiating events (FA1 8A and FA1 8B) are postulated for these rooms. FA1 8A is a fire near vertical cable trays that contain Division 2 and HPCS cables. The frequency (4.5E-5/yr) is based on the total for these 30 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 rooms (4.5E-4/yr) times a spatial factor (10%) for a fire near vertical trays. FA18B is a fire near vertical cable trays that contain Division 2 and HPCS cables times the probability of automatic suppression failure (0.05) which allows normal AC power and the balance of plant to be affected. The frequency (2.3E-6/yr) is based on FA18A (4.5E-5/yr) times suppression failure (0.05).
The initial screening analysis assumed failure of Division 2 AC power and HPCS, given a fire in one of these locations. This was based on the Appendix R analysis which indicated that Division 2 and HPCS are impacted. The actual impact on Division 2 was not assessed. In addition, the BOP cable evaluation identified a partial loss of offsite power and other balance of plant systems being lost. The following summarizes detection and suppression in each zone:
Fire Zone Number of Type of Automatic Fire Suppression Detectors Tempt Smoke Area Water Sprinkler Cable Tray Water Spray 304NW 0
4 Yes Yes 324NW 0
4 Yes Yes 337NW 0
5 No Yes 359N3,V 0
5 Yes Yes 37T7MV 0
3 Yes Yes 323NW 0
15 No Yes These compartments are similar to the Division 1 Cable Chase West compartments described above.
However, the frequency of core damage is less for these Division 2 areas which means that smaller reduction factors are needed to screen these areas. Rather than document impacts of cabinets in detail, as done in Table 4.6-5 of the IPEEE for the Division 1 areas, a walkdown and review was performed to assure that cabinet impacts are similar to those in the Division 1 areas (i.e., symmetry) and to investigate the proximity of vented cabinets to cable trays and conduits. Note that 337NW, 359NW and 337NW are symmetrical to those Division 1 zones described above. There were very few cabinets in the other zones.
Based on this review, it was concluded that the approach taken for the Division 1 areas also applied in these areas as summarized below:
Taking credit for automatic suppression (0.05 unavailability assumed) in these rooms would result in a core damage frequency less than 1E-6/yr still assuming the worst impact as in the initial screening analysis. Note that only IEEE 383 cables are used and for most fires it is not expected that impacts would occur away from the fire (e.g., hot gas layers, etc.) even without suppression (i.e., fire burns out).
The configuration of zones 337NW, 359NW and 337NW is similar to the Division 1 zones evaluated above and the impact of cabinet fires is similarly symmetrical.
No significant new scenario was identified from the walkdown and review of cabinets. Thus, these zones can be screened out for the same reasons developed above.
Thus, fire zones 304NW, 323NW and 324NW can also be screened for the same reasons developed above.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Normal Switchgear Rooms (FA51 601XL, FA52 602XL, FA78 612XL & FA79 613XL) - According to the analysis, suppression would have to fail in order to impact sufficient cables to cause a total loss of offsite power. Such a scenario is postulated for initiating event FNSGR where the frequency is the sum of the 4 rooms (FA$1 601XL, FA52 602XL, FA78 612XL & FA79 613XL), 4E-3/yr, times the probability of suppression failure (0.05) which equals 2E-4/yr. Normal AC is set to guaranteed failure without recovery.
The initial screening analysis assumed that normal offsite power and balance of plant systems failed, given a fire in this location. Although the most recent screening indicates these compartments can be screened, they are retained due to potential importance to the proposed amendment. The frequency of fires is dominated by electrical cabinet fires similar to other areas evaluated previously.
With the exception of FA52 which has MG sets that contribute, electrical cabinets dominate by an order of magnitude. Thus, the screening of these areas concentrated on electrical cabinets and the MG sets similar to other analyses.
Each fire zone has smoke detectors and a manual actuated total flooding carbon dioxide suppression system. The fraction of fires that cause a total loss of offsite power versus partial loss of offsite power or even less impacts is the key to this analysis. Fires that cause a partial loss of offsite power would screen out at less than 1 E-7/yr.
Based on the above and previous analysis, walkdowns and design reviews were performed to develop confidence that a reduction factor of at least 1/10 could be developed for cabinet fires that cause total loss of offsite power. No single cabinet was identified that could cause a total loss of offsite power. Cable trays were identified that could lead to total loss of offsite power, however, the manual suppression system provides confidence that propagation and damage to cable trays is unlikely. The following summarizes walkdown and design review conclusions:
FA51 - This fire area contains the chargers and switchgear that is associated with the 125 VDC systems 2BYS-SWG001A and 2BYS-SWG001B. The power cables for 2NNSSWG016 are routed through this area. There are numerous cables associated with the 115kV motorized disconnects. A fire in this area results in the loss of offsite power to 2ENS*SWG1O1 due to cables - cabinet fires do not fail offsite power supplies. Loss of balance of plant systems should be assumed since this was not evaluated.
FA52 - A fire in this area can result in a total loss of offsite power due to control cables - cabinet fires do not fail offsite power supplies. Power cables to both 2NNS-SWG016 and 017 are routed in this area; there is approximately 50 feet separation between the cables (cables to SWG016 are routed on the opposite end of the room from SWG017 cables). Loss of balance of plant systems should be assumed since this was not evaluated.
This area contains the grounding transformers for the main supply transformers from offsite power, the feeder cables for buses 2NNS-SWGO 16, 017, the motor generator sets for the RPS power, two non-safety UPSs, UJPS3A & B, the grounding transformers for the 4.16kV busses 2NNS-SWGO 16, 2NNS-SWG017, 2NNS-SWG018 and the four non-safety UPSs, UPS 1A,B,C,D.
Loss of a grounding transformer, by itself, will not result in loss of offsite power to the associated bus. The AC power system for this bus is delta connected and is not grounded. For a fire to cause the loss of the associated offsite power bus, another concurrent failure in a power feed must occur in addition to a fault in the grounding transformer power cable.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Loss of the RPS UPSs 2VBB-UPS3A & 3B will result in reactor trip and vessel isolation. There are a few cables 15 ft directly above the UPSs. At higher elevations there are more cables.
Loss of the BOP UPSs is conservatively assumed to result in loss of the BOP systems.
The offsite power cables supplying power to both Division 1 & 2 4kV busses pass through this room. There is approximately 50 feet separation between these power cables at the point of closest approach.
The intervening space between the tray routes has a small combustible loading, consisting of horizontal cable trays.
The control cables for the motorized disconnects in the 115kV switchyard are impacted by a fire that affects either trays 2TC850N or 2TC855N. If the fire causes wire to wire short circuits then the motorized disconnects will open and not be able to be reclosed: A minimum of two disconnects opening (2YUC-MDS3 or 2YUL-MDS1 and 2YUC-MDS4 or 2YUL-MDS2) isolate the plant from offsite power. In this case, offsite power is not recoverable.
FA78 - A fire in this area can result in a total loss of offsite power due to control cables - cabinet fires can cause a partial loss of offsite power (loss of 2NNS-SWG016 supply). Loss of balance of plant systems should be assumed since this was not evaluated.
FA79 - A fire in this area can result in a total loss of offsite power due to control cables - cabinet fires can cause a partial loss of offsite power (loss of 2NNS-SWG017 supply). Loss of balance of plant systems should be assumed since this was not evaluated.
Remote Shutdown Room B East (FA19 338NZ) - This initiating event (F338NZ) frequency is 1.5E-4/yr. Loss of Div 2 service water pumps, RCIC due to SRV actuation, and RHR B are modeled for this initiator.
The initial screening analysis conservatively assumed that Division 2 AC power was impacted by a fire in this zone. Since the actual impact was not evaluated, this was performed first.
The remote shutdown panel 2CES*PNL405 contains both remote shutdown divisions that are separated by a three hour fire wall. This panel contains transfer switches and controls. Panels 2CES*PNL415 &
2CES*PNL416 are not located within the remote shutdown room. They contain isolation switches that prevents spurious operation where needed and it provides isolation for circuits that need manual actuation for remote safe shutdown. The design bases for these switches assume that the switches are transferred before their circuits are impacted by the control room fire. A fire at either panel causes loss of all circuits connected to the panel. For the control room fire, two switches at 2CES*PNL415 or 416 and at the remote shutdown panel must be thrown to recover a service water pump.
The 2CES*PNL415/416 switches isolates unwanted control room contacts and the transfer switch isolates the operation features.
A fire at the remote shutdown panel could cause loss of Divisional service water (the three Divisional pumps trip and/or lose control power).
These pumps cannot be operated from the control room.
Additionally, the fire can cause actuation of an SRV (1 or more of 4 SRVs). Loss of control power to one solenoid is not a concern because the SRVs have three solenoids (two from Division 1 and one from Division 2 that can actuate the valve). There is a possibility that these valves cannot be closed if they spuriously open. A RHR pump can be lost due failure of control cables.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Diesel generator backed AC power is not directly impacted by a fire in 2CES*PNL405.
AC power components are isolated by either 2CES*PNL415 or 2CES*PNL416, both located in different fire areas from the remote shutdown panel.
Two smoke detectors are provided with no automatic suppression. This is a small room with the impacts concentrated at one panel. For this reason no credit for suppression before impact was considered. A fire initiator (FA338 = 1.5E-4/yr) was run through the PRA model as follows:
Loss of Division 2 service water pumps Loss of RCIC due to ADS actuation ADS success Loss of RHR B The resulting core damage frequency from FA338 is less than 1E-7/yr.
The above calculation is conservative. ADS actuation requires hot shorts with a probability which was not applied (i.e., 0.1). Allowing RCIC to succeed and requiring the operators to actuate ADS would lead to a core damage frequency estimate comparable to or less than calculated for the above case.
Remote Shutdown Room A West (FA17 343NZ) - This initiating event (F338NZ) frequency is 1.5E-4/yr. Loss of Div 1 service water pumps, RCIC due to SRV actuation, and RHR A are modeled for this initiator. Although this compartment screened during initial screening, this initiator was added to include symmetry with the Div 2 remote shutdown panel.
Reactor Building (FA34 212SW, 222SW, 232SW, 243SW & 252SW) - Similar to other locations, the total impacts associated with each zone were assumed to occur in the initial screening. The impacts include loss of Division 1 ECCS (RHR, LPCS, ADS), RCIC and balance of plant systems (RBCLC, main condenser, and feedwater). Each fire zone represents one half of a reactor building floor elevation which is a large area. The total frequency of a fire in FA34 is about 3.9E-2/yr. The initial screening analysis used a fire frequency of 1E-2/yr for each fire zone (assumed to be a reasonably conservative estimate) which led to a core damage frequency of less than 1E-6 for some zones. The reactor building was screened out by inspecting dominate (highest frequency) fire sources and the proximity of potential important targets during a walkdown. The strategy and walkdown notes are provided below.
Automatic cable tray water spray suppression is provided in each zone. The following summarizes the detectors in each fire zone:
IFire Zone Number of Detectors
________ Temperature JSmoke 212SW 13 34 222SW 0
39 232SW 5
32 243SW 5
38 i252SW 0
39 34 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 The frequency of a fire in FA34 is based on the following fire source frequencies (events/yr):
H2 Recombiner 2.9E-2 Pumps 6.4E-3 Elec Cabinet 2.1E-3 Compressors 5.9E-4 Ventilation/Fans 4.1 E-4 Transformers 2.8E-4 JB/Splice 2.5E-4 Weld/ORD 2.OE-4 Weld/CAB 6.OE-5 Transients 4.1E-5 The initial screening analysis did not demonstrate that the fire zones meet the definition of a fire compartment in FIVE. However, core damage frequency results for the upper elevations screened out of the initial screening analysis and are not sensitive to the total fire frequency for area FA34. Also, given the size of these areas, height of the ceilings, and the floor openings, the accumulation of hot gases is difficult.
During the walkdown, the proximity of cables to the ceiling and the potential for gas accumulation were considered and no important configurations or impacts were identified. This fire area was evaluated utilizing the following strategy:
Those fire sources with frequencies less than 1E-3 can be screened out. The total frequency of these other causes is on the order of 1E-3/yr; assuming the total impact as in the initial screening analysis, core damage frequency would be less than 1E-7/yr. However, during the walkdown, the proximity of compressors, ventilation/fans, and transformers to cables and other important systems were inspected to obtain confidence that fires from these sources cannot have the impact assumed in the initial screening analysis.
Also, junction boxes and splices (JB/Splice) are typically contained in enclosures without vents which mean that these firesare expected to have only limited local impacts. This evaluation provides confidence that core damage frequency from these lower frequency sources is less than 1E-7/yr.
Starting at elevation 175 (lowest elevation), each fire zone was inspected for the high frequency sources and their proximity to other important equipment and cables (i.e., radiant and plume impacts).
Also, ceilings/overheads were visually inspected for the potential of hot gas accumulation and flow.
During the walkdown, automatic cable tray water spray suppression capabilities were confirmed where important.
When conduits or cable trays were found in close proximity to a source (<5 feet from electrical equipment), they were not considered important unless there is a mixture of safety (green and/or yellow) with non-safety (black). If the fire does not impact safety and non-safety (balance of plant), the fire can be easily screened.
Each elevation was walked down with no distinction made between fire areas 34 and 35. The impacts identified during the walkdown were evaluated (i.e., cable raceway database, CRS2, was used to identify cables within a raceway and the elementary and/or wiring diagrams used to identify impact). Based on impacts, fire frequency, and the PRA, FA34 was screened out.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Reactor Building (FA35 213SW, 223SW, 238SW, 245SW & 255SW) - This fire area is similar to FA34 described in the previous section. Similarly, the total impacts associated with each zone were assumed to occur in the initial screening. The impacts include loss of Division 2 ECCS (RHR, ADS),
HPCS, and balance of plant systems (RBCLC, main condenser, and feedwater). Each fire zone represents one half of a reactor building floor elevation which is a large area. The total frequency of a fire in FA35 is about 3.8E-2/yr. The initial screening analysis used a fire frequency of 1E-2/yr for each fire zone (assumed to be a reasonably conservative estimate) which led to a core damage frequency of 8E-6/yr for some zones.
Automatic cable tray water spray suppression is provided in each zone. The following summarizes the detectors in each fire zone:
IFire Zone
_Nmber of Detectors Temperatre Smoke 213SW 20 35 223SW 0
39 238SW 1
32 245SW 2
37 255SW 4
33 The frequency of fires in FA35 is based on the following sources and frequencies (events/yr):
H2 Recombiner 2.9E-2 Pumps 4.1E-3 Elec Cabinet 2.1E-3 Elevator Motors 1.6E-3 Ventilation/Fans 5.3E-4 Transformers 5.7E-4 Compressors 3.9E-4 JB/Splice 2.2E-4 Weld/ORD 2.OE-4 Weld/CAB 6.OE-5 Transients 4.1E-5 The strategy for evaluating this fire area is the same as described in the previous section for FA34.
Service Water Pumps (FA60 807NZ & FA61 806NZ) - For each of these zones, the initial screening analysis assumed failure of the Division 1 service water header and pumps similar to the PRA initiator SAX. A fire initiating event frequency in each zone is equal to 6E-3/yr and leads to a CDF value of <1E-7 in each zone (symmetry between Div 1 and 2 is assumed). There are six smoke detectors provided for each fire zone with no automatic suppression.
A walkdown was performed to assess the location of fire sources that dominate the fire initiating event frequency to determine more realistic impacts of fires. It was noted prior to the walkdown that the fire 36 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 frequency was dominated by electrical cabinets and pumps. The total frequency of other fire causes is about an order of magnitude less likely and a more detailed evaluation of these causes and impacts would likely result in additional reduction factors.
With regard to pump and electrical cabinet fires, the following summarizes the walkdown observations:
The pumps are in a deep pit about forty feet below the deck (El 261) where most of the remaining service water equipment (strainers, MOVs, MCC, cable trays) is located. There is another elevation above the deck where hot gases would tend to collect given a fire in the area. There is no important equipment or cables at this higher elevation.
There is sufficient distance between the three pumps, their associated cables, and other critical equipment on the upper deck such that a fire initiated at one pump is very unlikely to impact a second pump let alone all three as assumed in the screening analysis.
The only conceivable scenario that could impact more than one pump might be a pump fire and oil spill onto the floor.
However, there is limited oil associated with a pump motor and the surface area associated with oil spread on the floor to impact all three pumps is large. This may not even be credible, but if it is, the frequency of such an event is less than assumed in the screening analysis.
In addition, the safety related header supplies are not impacted. Our judgment is that pump fires that impact all three pumps are unlikely and can be screened out (core damage frequency <1 E-7/yr).
There are two large unit coolers (e.g., 2HVY*UC2A & C in FA61) below the deck at El 261, but above one of the pumps. The initiating frequency for a unit cooler fire is less than the frequency for the pumps and the impact would likely be only one pump. Therefore, this source can be screened as stated above.
The major electrical cabinet in each area is the MCC (e.g., 2EHS*MCC101 in FA61) on the deck at El 261. The MCC is actually contained within another cabinet, thus the impact of fires within the MCC are very unlikely to impact cable trays above the MCC. No vented cabinets that could impact cables or conduits were identified during the walkdown.
Each MCC supplies Divisional strainers, strainer MOVs, pump discharge MOVs, unit coolers, a crosstie MOV, header MOVs and tunnel heaters. There are no cables that would depower the pumps and since service water is normally operating (MOVs are in their correct position for normal operation), a fire would have to cause a short circuit to have an impact on system operation (i.e.,
shorts cause pump discharge MOV or header MOV to close). The probability of a short is less than 1.0. In addition, the frequency of a fire that impacts more than one MCC cubicle causing loss of two or more pumps, or loss of pumps and header supplies is much less than the frequency used in the screening analysis. All these factors are judged to lead to core damage frequencies less than 1 E-7/yr.
Based on the above analysis and walkdown observations, it is judged that core damage frequency in each area due to fires is easily <lE-7/yr.
Corridors and Instrument Shop El 288 and 306 of CB - As a result of performing the screening analysis using the latest CAFTA model and using a 1E-7 screening value, the following new 37 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 compartments required evaluation; they assumed the same conservative impacts as other zones in the area:
Area Zone Description Screening Value 72 351.LNZ Instrument shop El 288 CB 2.7E-7 72 351.2NZ Corridor El 288 CB 2.7E-7 76 380.2NZ Corridor/toilet El 306 2.7E-7 These areas were reviewed, including walkdowns to inspect cabinets in the corridors. There are no cable trays in these corridors and no PRA impacts were identified.
Appendix R (UFSAR Appendix 9A) confirms that there are no safety related impacts in these areas. As a result, CDF is clearly less than 1E-7/yr.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 ATTACHMENT A2-C REVIEW OF INDUSTRY-GENERIC MSOs APPLICABLE TO DG-RELATED EVENTS MPL #
Generic Scenario Generic Notes Evaluation E12 5a Additional components Scenario causes diesel This MSO concern is not applicable to NMP2.
load onto credited generator overloading and diesel generator inoperability. Note: Scenario Simultaneous loading of attached loads to the diesel. NMP2 does not have a very site specific. Interlocks sequencer. It does have sequencing logic that consists of several relays.
may prevent this from NMP2 has no load sequencer for operation under the loss of off-site power.
occurring. In addition, Therefore, there may be concern for spurious operation of some of the large overloading may also occur if loads that may be loaded spuriously which could cause a DG stall condition.
proper load sequencing is bypassed via hot shorts, NMP2 does not load DGs for either LOCA or LOOP scenarios through any causing simultaneous loading load sequencer pre programmed devices. Logic circuits for these sequencing of multiple components onto circuits are routed from PNL 415, 852 (Relay RM) and 609 (at MCR) to the the DG.
respective switchgear.
2ENS*SWG101 and 102 loadings include RHR pumps, SWP, SFP pumps, and LPCS. Each DG is rated for 4750 KW for 2000 hrs of operation. A LOOP will pickup UVR27 which will trip all loads feeder breakers at the switchgear (except 600V SST feeder breakers). A loop sets a time delayed relay, then closes each load feeder breaker after bus is powered by the DG.
All the control cables to these switchgear are separated and isolated from one another according to the NMP2 Electrical separation criteria. Each division of control circuits from CRfRR to switchgear maybe routed within the same cable or raceway since separation is not required within the same division; therefore, when one division of power source was selected for safe shutdown, all associated circuits such as these control circuits were considered. Therefore, as such, this MSO concern was included in the evaluation concept of original safe shutdown analyses. At most, it was anticipated that a failure in one division of power source cannot impact other division. The same argument applies to the control room/relay room fire and control room evacuation.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 MPL #
Generic Scenario Generic Notes Evaluation R43 5f Non-synchronous Scenario causes damage to Spurious start of the DG and spurious closure of the feeder breaker.
paralleling of DG with diesel generator by closing 2EGS*EG1 2ENS*SWG101-13, -10, -1 on-site and off-site into a live bus out-of-phase.
2EGS*EG3 sources through Note: Scenarios are very site 2EGS*EG2 2ENS*SWG103-2 -4, -14 spurious breaker specific. Interlocks may operations prevent this from occurring.
Based on modifications made to the plant and physical separation of control cables associated with emergency switchgear, the likelihood of this scenario is very low.
At NMP2, modifications were implemented as part of the plant original compliance and safe shutdown analysis to prevent connecting offsite power to the DGs when they are not synchronized. This was accomplished by an additional permissive (contact in the control circuit) in the DG breaker control circuit that would prevent fire induced spurious closure of the breaker if offsite power is available at the emergency busses. This modification precludes this scenario from occurring during and following a control room fire event.
For a postulated fire outside the control room, the likelihood of this scenario is very low due to physical separation of control cables associated with the emergency switchgears. The divisional switchgears and associated breakers are located in separate fire areas.
For an auto-start of a DG, the diesel breaker cannot close unless the bus (normal feed) breakers are both open. There is a contact on the diesel breaker circuit that prevents it. Operations can close the diesel breaker manually, but there is another contact that forces them to turn on the Sync scope in order to close the breaker. This is procedurally controlled.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 MPL #
Generic Scenario Generic Notes Evaluation R43 5g Non-Synchronous Scenario causes damage to This scenario is not credible at NMP2.
Paralleling - inadvertent diesel generator by closing cross-tie breaker into a live bus out-of-phase.
EE-MO01A, B operation between Note: Scenario very site opposite divisions (e.g., specific. Interlocks may On a given emergency bus there is only one breaker for the two feeds. There 4160V, 480V) of Div prevent this from occurring, are no maintenance tie breakers.
1(2) DGs through Spurious Operation of 480 V Breakers or the Divisional Cross-Tie through 4160 V Maintenance Tie Breakers R43 5h Cross-tying the offsite Spurious breaker closings This scenario is not credible at NMP2.
power sources through between separate divisions of the on-site busses &
off-site power.
EE-MO01A, B breakers In order to cross tie, an extra breaker has to be inserted into the second cubicle. That is an abnormal line up.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUJIDE 1.200, REVISION 2, SECTION 1.2.4 MPLI # [ Generic Scenario I
Generic Notes Evaluation R43 I 5i Spurious diesel generator operation without cooling water The fire causes the startup of the Diesel Generator.
Spurious closure of the ESW Pump Discharge Valve or trip of the ESW Pump would stop the cooling water supply to the Diesel Generator. Running the Diesel Generator with a loss of cooling water could trip the diesel on high temperature. If the fire has resulted in the actuation of a LOOP or LOCA bypass of the high temperature trip, the diesel could continue to run until damage from over-temperature conditions stop it.
PID IlL Only 5 minutes are available if the DG is loaded, 15 minutes if half loaded, or 30 minutes if not loaded. The spurious start of the DG can occur for a fire in panel 852 in the MCR and in DG control panel in DG control room.
MOV 95A AND MOV 95B have to fail for EG2 MOV 94A AND B have to fail for EG2 MOV 66A for EG1, MOV 66B for EG3, MOV 94A, B, MOV 95A, B for EG2 Operators can manually open MOV 66A and MOV 66B. As previously noted, this would take less than 5 minutes based on alarms in MCR. Div 1 and 2 DGs can also run longer than 5 minutes fully loaded based on previous operating experience.
" If the diesel was started due to a short and not an actual LOP/LOCA condition, Operations could simply shut it down manually.
" If it was due to a LOCA circuit short, there is the LOCA over-ride that can be used to shut it down.
" If the diesel was manually shut down, it would still be able to be started manually, if required.
" If there is a start with no LOP, the normal feed breaker to the switchgear would still be closed, blocking closure of the diesel breaker. The diesel would be totally unloaded.
" Operations can open the MOV94AIB or MOV95A/B as required - they are local in the diesel rooms.
" An operator would have to be stationed at the diesel panels to ensure proper start or stop of the diesel(s).
- The override of the high temperature shut off does not mask the alarm.
Operators would still see the alarm and could shut the diesel down -
assuming there is not a LOP.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 MPL #
Generic Scenario Generic Notes Evaluation
- If there is a false start with no LOCA, the loading on the diesel would be minimal -just 2 service water pumps. The 15 to 30 minute duration would be appropriate for operation with no cooling.
The current NMP2 safe shutdown analysis demonstrates the availability of one train of safe shutdown capability including support system such as electrical distribution and service water systems. In order for a fire event to cause the postulated scenario (i.e., spurious DG start without SW), it has to cross divisional boundaries. The current divisional separation at NMP2 is such that a postulated fire can potentially cause this scenario in only one division of safe shutdown system/train. There are 2 divisions of electrical distribution and service water systems. Each division's components, associated controls, and cabling are separated from the redundant division in accordance with 10CFR50, Appendix R III.G.2 requirements.
For a control/relay room fire, the existing control room evacuation procedure (N2-SOP-78) includes steps for plant operators to verify at the diesel control panel the proper start and control of DGs, including verification of service water supply.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 ATTACHMENT A2-D IMPORTANT OPERATOR ACTIONS A detailed evaluation of HEPs in the internal events PRA for fires has not been completed for the NMP2 Fire PRA. Thus, the most important operator actions were identified and evaluated to determine whether there is an important operator action that could be effected when considering response during a fire. The following table provides a list of operator actions with a RAW greater than 2 with Division 1 DG out of service and with Division 2 DG out of service (this was done 1St with CDF with Division 1 DG out of service; blanks indicate RAW is less than 2). It is assumed that a fire could cause some confusion and delay with the operating crew at least early during the event. Thus, those operator actions required less than an hour after a plant trip were considered potentially important for further evaluation.
Based on this review, operator actions ZOD01, ZSAO1, and ZHS04 were identified for further evaluation
- refer to Table A2-D. 1. A sensitivity analysis was performed where fires risk was quantified with these operator actions increased by a factor of 10 for the amendment analysis. The results show that there is very little change between the base case results and the factor of 10 increase, as shown in Table A2-D.2.
Table A2-D. 1: Important Operator Actions Event Name RAW [RAW IE1 RW RA2 Description Evaluation ZOD01_ODOPERATOR 24.09 18.22 101.12 87.85 Operator Fails to Manually 30 mi Z 1 O A40 1 7
Depressurize (Transient)
ZHRA1 HROPERATOR 23.11 17.66 4.03 3.64 Operators Fail to Successfully
- ~_RPRTO 31 766 40
.4 Respond to Control Room Fire Fire specific HEP Required within 15 min per Operator Fails to Bypass RCIC SOP-1, but RCIC success for ZIC02OICSBYPTEMP 8.69 6.62 8.11 6.94 Trip on High RHR Area even 15 minutes and then trip Z0_C4 Te urep on Hh Rwould provide additional time Temperature - SBO and a cue to re-start and trip high area temp trips.
ZIC04 OPEN DOOR 7.96 6.07 6.97 5.96 Operator Fails to Open RCIC Required within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per
-_Room Doors Given SBO SOP-1 ZHRA2 HROPERATOR 6.36 5.04 2.02
<2 Operators Fail to Successfully I-IR2RPEA R
6.6 5.4
.2 2
Respond to Control Room Fire Fire specific HEP ZSA01 SWOPERATOR 5.99 5.05
<2
<2 Operators Fail to start a SW 30 mi
_____-__________ 5.99 5.05
<2
_<2 _Pump About 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> based on room ZHS05 HSROOMCOL 3.6 4.47 3.26 4.63 Operator Fails to open HPCS heat up and this ZHS04 must be Room Doors and HVAC Duct successful and will be a further cue to perform this action ZISO4_EDGCOOLING 3.38 4.29 2.61 4.08 Operator fails to protect DG 15 to 30 min assuming that Z _ O G 8 9 1 From High Temp During SBO ZHS03 is not already aligned ZOH03 OHOPERATOR 3.34 7.31
<2
<2 Operator Fails to Align RHR Several hours available 0_ OHOPERATOR_________3.34____7.31__
<2_____
<2_____
Early (To Avoid HCTL) 6 Operator Fails to Align Fire Assuming ZHS06 is successful; Z14O3pSDGaeraor Fs CooAlingn F operators have close to an hour 6 Water for DG Cooling to perform this alignment.
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ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-D. 1: Important Operator Actions
. i o 11 oF21L.F11LERF2 Event Name RAF A
RAW [ RAW Description Evaluation This should start within an hour 6 Operator Fails to Conduct DC after SBO, but this could be ZOLS1LLOADSHEDDC 3.14 2.49 3.09 2.6 oad Shedding Procedure delayed at least an hour based on conservatisms in the model regarding battery life.
Operator Fails to Allow HPCS Operators would have to ZHS06 HPCSLV8SBO 2.95 4.5 2.7 4.75 to Run for Init Level Restoration consciously prevent HPCS in SBO operation, which is judged unlikely Operators Fail to Open ECCS ZMAO IOPENRMDOOR 2.48 2.12
<2
<2 Room Doors Given High Temp Several hours available Annunciator Operators fail to align ZCV02_CVOPERATOR 2.4 2.52
<2
<2 containment venting when air or Several hours available Div 1 AC unavailable Operators fail to align ZCVO0_CVOPERATOR 2.36 2.49
<2
<2 containment venting when all Several hours available support systems are available 15 min is conservatively used Operator Fails to Manually for HEP. An operator is ZA301DCRDOOR 2.3 2.22 3.01 2.13 Open DG Room Door or Supply dispatched to DG when it starts; MOV Compensatory measure used for AOT Operator Fails to Vent PC ZCV06_PPSWPCVENT 2.15
<2
<2 (Local Actions including use of Several hours available Port. power-pack)
ZOD04 ODOPERATOR
<2
<2 3.74 3.38 Operator Fails to Manually Fire induced small LOCA is ZD04-_D_
PERATOR
<2_<2_3.74 3.38 Depressurize (SLOCA) very unlikely Initiated at RPV level at TAF ZIS03 SBOE-FAIL-
<2
<2 2.94 4.23 Operator Fails to Locally Close (30 min) per SOP-1; MOVs (SBOE)
Compensatory measure used for AOT ZAIOI AIOPERATOR
<2
<2 2.31 2.14 Operator Fails to Inhibit ADS Fire induced ATWS is very
_(ATWS) unlikely 45 of 46
ATTACHMENT 2 COMPARISON OF THE NMP2 FIRE PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.4 Table A2-D.2: Operator Actions ZOD01, ZSAO1 & ZHS04 HEP Increased by a Factor of 10 Vle AOT HEP x Base Case 10 Acceptance Criteria ACDFave 2.85E-07 2.88E-07
<lE-6 ALERFave 2.23E-08 2.26E-08
<1E-7 ICCDPI 2.16E-07 2.18E-07
<5E-7 ICCDP2 3.31E-07 3.34E-07
<5E-7 ICLERP1 1.88E-08 1.90E-08
<5E-8 ICLERP2 2.40E-08 2.43E-08
<5E-8 46 of 46
'I ATTACHMENT 3 COMPARISON OF THE NMP2 SEISMIC PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.6 Nine Mile Point Nuclear Station, LLC June 1, 2010
ATTACHMENT 3 COMPARISON OF THE NMP2 SEISMIC PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.6 Regulatory Guide 1.200, Rev. 2 (Table 7)
NMP2 Assessment Element Technical Characteristics and Attributes Probabilistic Seismic Analysis
- 1. Seismic hazard analysis
- a. establishes the frequency of earthquakes at the site
- b. site-specific
- c. examines all credible sources of damaging earthquakes
- d. includes current information
- e. based on comprehensive data, including geological, seismological, and geophysical data, local site topography, historical information
- f. reflects the composite distribution of the informed technical community
- g. level of analysis depends on application and site complexity
- 2. Aleatory and epistemic uncertainties in the hazard analysis (in characterizing the seismic sources and the ground motion propagation) properly accounted for fully propagated allow estimates of fractile hazard curves, median and mean hazard curves, uniform hazard response spectra
- 3. Spectral shape used in the seismic PRA based on a site-specific evaluation broad-band, smooth spectral shapes for lower-seismicity sites acceptable if shown to be appropriate for the site uniform hazard response spectra acceptable if it reflects the site-specific shape
- 4. Need to assess whether for the specific application, other seismic hazards need to be included in the seismic PRA, such as fault displacement landslide, soil liquefaction soil settlement Seismic hazards developed by EPRI and NRC (see references below) were used to develop seismic initiating events. The hazard estimate depends on uncertain estimates of attenuation, upperbound magnitudes, and the geometry of the postulated sources. Such uncertainties are included in the hazard analysis by assigning probabilities to alternative hypotheses about these parameters. A probability distribution for the frequency of occurrence is thereby developed. The hazards are discretized and used as initiating events in the PRA accident sequence analysis. The following summarizes the point estimate initiating events as developed in the PRA:
EPRI HAZARD Acceleration Mean Annual Range (g)
Frequency SEIS1 0.01-0.05 1.46E-2 SEIS2 0.05-0.10 2.87E-4 SEIS3 0.10-0.25 6.61E-5 SEIS4 0.25-0.51 6.21E-6 SEIS5 0.51-0.71 5.10E-7 SEIS6 0.71-1.02 1.44E-7 The following provide the hazard analysis details and results:
EPRI NP-6395-D, April 1989, "Probabilistic Seismic Hazard Evaluations at Nuclear Plant Sites in the Central and Eastern United States: Resolution of the Charleston Earthquake Issue," Prepared by Risk Engineering, Inc., Yankee Atomic Electric Company, and Woodward-Clyde Consultants.
NUREG-1488, "Revised Livermore Seismic Hazard Estimates for 69 Nuclear Power Plant Sites East of the Rocky Mountains"' Final Report, April 1994.
GAP: These are generic issues associated with hazard development and its impact on plan fragility that should be considered in future updates. However, these issues do not impact this application.
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ATTACHMENT 3 A
COMPARISON OF THE NMP2 SEISMIC PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.6 Regulatory Guide 1.200, Rev. 2 (Table 7)
NMP2 Assessment Element I
Technical Characteristics and Attributes Seismic Fragility Analysis
- 1. Seismic fragility estimate
- a. plant-specific
- b. realistic
- c. includes all systems that participate in accident sequences included in the seismic-PRA systems model
- d. basis for screening of high capacity components is fully described
- 2. Seismic fragility evaluation performed for critical SSCs based on
- a. review of plant design documents
- b. earthquake experience data
- c. fragility test data
- d. generic qualification test data (use is justified)
- e. walkdowns
- 3. walkdowns focus on
- a. anchorage
- b. lateral seismic support
- c. potential systems interactions Systems and equipment modeled in the PRA as well as the structures that house this equipment were identified and considered in developing the equipment list for the seismic margins assessment. Also, a relay chatter evaluation was performed to identify those relays that could potentially affect mitigating equipment.
Structures, systems, and components identified were evaluated for seismic capabilities including seismic qualification, analysis, and test information that would support screening. Calculations were performed as necessary to support screening. The strategy developed for the seismic margin assessment and PRA development included the following:
- 1. The seismic margins assessment used a 0.5g HCLPF as the screening level instead of 0.3 required by Generic Letter 88-20. This was to ensure that the screening fragility used in the PRA as a direct contributor to CDF (COMP 1) would not be too conservative.
- 2. Consistent with other seismic PRAs, loss of feedwater, main condenser and their support systems is incorporated within the loss of offsite power fragility (COMP3). This is a reasonable assumption since offsite power has been assessed to be the weak link and this is based on actual earthquake experience.
The seismic margins evaluation methodology is based on the following including detailed walkdowns:
" EPRI NP-6041, "A Methodology for Assessment of Nuclear Power Plant Seismic Margin," Revision 1, August 1991.
" SQUG, "Generic Implementation Procedure (GIP) For Seismic Verification of Nuclear Plant Equipment," Revision 2 Corrected, February 14, 1992.
- EPRI NP-5223, "Generic Seismic Ruggedness of Power Plant Equipment," Rev 1, February 1991.
" EPRI NP-7147, "Seismic Ruggedness of Relays," February 1991.
" EPRI NP-7146, "Development of In-Cabinet Amplified Response Spectrum for Electrical Cabinets,"
December 1990.
" EPRI NP-7148, "Procedure for Evaluating Nuclear Power Plant Relay Seismic Functionality," December 1990.
As a result of the seismic margins evaluation of structures and equipment, the only component that did not meet the 0.5g HCLPF screening was the nitrogen makeup supply (COMP2). Also, it was noted during the evaluation that some components, including certain relays, had small margins above the 0.5g HCLPF screening value. Thus, the conservatism in the model with regard to assigning the screening HCLPF (COMP1) to core damage may not be significant. Additional more detailed fragility analysis would be required to make this determination.
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ATTACHMENT 3 COMPARISON OF THE NMP2 SEISMIC PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.6 Regulatory Guide 1.200, Rev. 2 (Table 7)
NMP2 Assessment Element Technical Characteristics and Attributes NMP2 specific references include the following:
- "Identification of Structures, Systems & Components," Nine Mile Point Unit 2 IPEEE - Seismic Analysis, NMPC Report SAS-13U2-1, December 1993.
" "Relay Chatter Evaluation," Nine Mile Point Unit 2 IPEEE - Seismic Analysis, NMPC Report SAS-13U2-2, January 1994.
" NMP2 Screening Evaluation Work Sheets (SEWS) signed by the Seismic Review Team, 6/94.
" NMPC Document Number STRS 08.000-5000, Rev 0, "NMP2 IPEEE Floor response Spectra," Prepared by Stevenson & Associates.
" NMPC Calculation 2-SQ-061, Rev 0, "HCLPF Calculations for IPEEE."
" NMPC Document Number STRS 08.000-5001, Rev 0, "NMP2 IPEEE Relay HCLPF Evaluation Report,"
Prepared by Stevenson & Associates.
GAP: Overall, the analysis is judged to be conservative. The contribution to CDF is still small (4%). The impact to LERF is 35% and as such, it is an important contributor that is dominated by screening fragility.
However, this does not impact the proposed amendment.
I I
Seismic Plant
Response
Analysis
- 1. The seismic PRA models include a.
b.
C.
d.
seismic-caused initiating events seismically induced SSC failures nonseismically induced unavailabilities, other significant failures (including human errors) that can lead to CDF or LERF The internal events PRA model is used to represent the plant response for seismic initiating events. The transient model is used as well as its transfer to medium LOCA (stuck open SRV) and station blackout models. The model is based on the following:
" The seismic initiating basic events (SEISI through SEIS6) are included as initiating events in the transient event tree model top logic.
" The screening fragility (COMP1) is incorporated into the AC and DC power models, including recovery models to ensure that this fragility goes directly to core damage.
" The nitrogen fragility (COMP2) is incorporated into the nitrogen system model as a failure mode.
" The offsite power fragility (COMP3) is incorporated into the normal offsite AC power model, including recovery.
- 2. The seismic PRA models
- a.
adapted to incorporate seismic-analysis aspects that are different from corresponding aspects found in the at-power, internal events PRA model
- b.
reflects the as-built and as-operated plant being 3 of 4
ATTACHMENT 3 COMPARISON OF THE NMP2 SEISMIC PRA MODEL TO THE TECHNICAL ELEMENTS OF REGULATORY GUIDE 1.200, REVISION 2, SECTION 1.2.6 Regulatory Guide 1.200, Rev. 2 (Table 7)
NMP2 Assessment Element Technical Characteristics and Attributes analyzed Key human actions were evaluated, including recovery of seismic induced failures.
- a.
the seismic hazard Operator action to depressurize the reactor, given loss of RCIC and HPCS is an important event
- b.
the seismic fragilities (ZOD05). It was assumed for transients that the operators inhibited ADS (automatic depressurization)
- c.
the systems analysis and then, had to manually open the safety relief valves when level reached top of active fuel. The reliability of ADS and injection systems is sufficiently high such that if the operators failed to disable ADS, core damage frequency would not change significantly. In fact, it is assumed that this treatment is as conservative for seismic events as it is for transients. The operator failure probability used for emergency depressurization was increased in the seismic model relative to a general transient.
Long term alignment of RHR to suppression pool cooling is explicitly modeled (ZOH 01). This was considered to be a very reliable operator action for non seismic events due to the significant time available, limited actions required, and redundant cues available to the operators in the EOPs. The total unavailability of RHR Trains A and B with all support systems available has a higher failure probability than ZOHO0, which has the equivalent impact as the operator failure. This value is assumed to reasonably envelop operator errors even for seismic events.
e The containment isolation (IS) model includes an operator action to isolate outside motor operated valves, given a station blackout. The operator failure probability is set to 1.0 for the case where COMP 1 fails.
- Operator action to initiate ECCS given that signals fail (ZMEOI) is conservatively set to failure for seismic initiating events.
GAP: A more detailed HRA evaluation should be completed for future updates. This is unlikely to impact the proposed amendment as demonstrated by the fire sensitivity analysis of operator actions related to events outside the control room.
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