3F1209-04, Response to Follow-up to Progress Energy RAI Responses on CR-3 SAMA Evaluation

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Response to Follow-up to Progress Energy RAI Responses on CR-3 SAMA Evaluation
ML093580090
Person / Time
Site: Crystal River Duke Energy icon.png
Issue date: 12/18/2009
From: Franke J
Progress Energy Florida
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
3F1209-04, TAC ME0278
Download: ML093580090 (19)
v • d • e


Text

Progress Energy Crystal River Nuclear Plant Docket No. 50-302 Operating License No. DPR-72 Ref: 10CFR54 December 18, 2009 3F1209-04 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

Crystal River Unit 3 - Response to Follow-up to Progress Energy RAI Responses on CR-3 SAMA Evaluation (TAC NO. ME0278)

References:

(1) CR-3 to NRC letter dated December 16, 2008, "Crystal River Unit 3 - Application for Renewal of Operating License" (2) NRC to CR-3 letter dated August 10, 2009, "Request for Additional Information Regarding Severe Accident Mitigation Alternatives for Crystal River Unit 3 Nuclear Generating Plant License Renewal Application (TAC NO. ME0278)"

(3) CR-3 to NRC letter dated October 9, 2009, "Crystal River Unit 3 - Response to Request for Additional Information Regarding Severe Accident Mitigation Alternatives for Crystal River Unit 3 Nuclear Generating Plant License Renewal Application (TAC NO. ME0278)"

(4) NRC to CR-3 Electronic Mail dated November 2, 2009, "Follow-up to Progress Energy RAI Responses on CR-3 SAMA Evaluation"

Dear Sir:

On December 16, 2008, Florida Power Corporation (FPC), doing business as Progress Energy Florida, Inc. (PEF), requested renewal of the operating license for Crystal River Unit 3 (CR-3) to extend theterm of its operating license an additional 20 years beyond the current expiration date (Reference 1).

Subsequently, the Nuclear Regulatory Commission (NRC), by letter dated August 10, 2009, provided a request for additional information (RAI) concerning the CR-3 License Renewal Application (Reference 2).

CR-3 responded to the RAI by letter dated October 9, 2009 (Reference 3). By electronic mail received on November 2, 2009 (Reference 4), the NRC requested a follow-up response to information provided in Reference 3. The Enclosure to this letter provides the response to Reference 4.

No new regulatory commitments are contained in this submittal.

If you have any questions regarding this submittal, please contact Mr. Mike Heath, Supervisor, License al, at (910) 457-3487, e-mail at mike.heath@pgnmail.com.

Jon A. Franke Vice President Crystal River Unit 3 JAF/dwh

Enclosure:

Response to Request for Additional Information xc: NRC CR-3 Project Manager NRC License Renewal Project Manager NRC Regional Administrator, Region II Senior Resident Inspector Progress Energy Florida, Inc.

Crystal River Nuclear Plant 15760 W. Power Line Street a.Z Crystal River, FL 34428

U. S. Nuclear Regulatory Commission Page 2 of 2 3F1209-04 STATE OF FLORIDA COUNTY OF CITRUS Jon A. Franke states that he is the Vice President, Crystal River Nuclear Plant for Florida Power Corporation, doing business as Progress Energy Florida, Inc.; that he is authorized on the part of said company to sign and file with the Nuclear Regulatory Commission the information attached hereto; and that all such statements made and matters set forth therein are true and correct to the best of his knowledge, information and belief.

  • on A Franke Vice President Crystal River Nuclear Plant The foregoing document was acknowledged before me this day of S~J~..~(~2 IXAJ , 2009, by Jon A. Franke.

Signature of Notary Public State of Florida Q'_..* co mminon Expres Mar 1,20101

.-1.W Cominin DI5238 BoddB Ja aia sn (Print, type, or stamp Commissioned Name of Notary Public)

Personally / Produced Known -OR- Identification

PROGRESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50 - 302 / LICENSE NUMBER DPR - 72 ENCLOSURE RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 1 of 16 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION RAI 1.c Progress Energy did not characterize the significant review comments from the full-scope PRA self-assessment or the limited-scope peer review cited in the RAI response. Without providing any details, Progress Energy concluded that the findings from these two review "should not have a significant impact on the results of the SAMA analysis." Provide the information requested in the last sentence of this RAI relative to these two reviews (i.e., "Describe any significant review comments, their resolution, and the potential impact of any unresolved comments on the results of the SAMA analysis").

Response

The following section lists the significant comments from self-assessments and peer reviews on the Crystal River Unit 3 (CR-3) ProbabilisticRisk Assessment (PRA) model since the Model of Record (MOR) 2006 was issued. The term "significant"for this response is defined as having any change to the PRA model or results. The non-significant comments were limited to documentation improvements. The review comments that affect the model do not have a significant impact to the issued PRA model. The following discussion gives each comment and its impact to the MOR 2006 PRA model which was the one used for the SAMA analysis. For the three findings described below, there was little impact on the SAMA analysis such that a potential plant enhancement could have been masked by impropermodeling. That is, the MOR 2006 adequately captured an appropriateimportance listing for the modeled basic events, and also was able to satisfactorilycalculate an averted cost-risk so that a reasonableestimate could be made as to whether a particularSAMA enhancement was cost beneficial. Additionally, in Section E.7.2.3 of the Environmental Report .(ER), each of the quantified SAMAs was reevaluated at the 9 5 th percentile for averted cost, which was meant to account for general uncertainty in the overall PRA model so as to bound the cost benefit for each of the identified SAMAs.

2007 Significant Self Assessment Items:

Factand Observation(FnO)-AS-B6 Significant Comment The recent addition of the non-safety Emergency Diesel Generator (EDG) has not been included in the Offsite Power (OSP) recovery evaluation.

Resolution The OSP recovery evaluation was included in the 2008 draft model which includes credit for the non-safety EDG.

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 2 of 16 Impact The impact to the MOR 2006 model was not significant because the effect of the addition of the non-safety EDG to the OSP recovery reduced the overall EDG system contribution to Core Damage Frequency (CDF).

FnO-HR-G4-2 Significant Comment The accident sequence timing for Human Error Probability(HEP) in Appendix B of calculation, P-02-0006 is not referenced to the latest ModularAccident Analysis Program (MAAP) analysis.

The timing is also not related to a specific sequence. The result is some suspect timing and HEPs. Examples:

QHUEFP1Y: Fail to start Emergency Feedwater Pump EFP-1. The available time is 60 minutes, based on Core Damage (CD) at 90 minutes. Success criteria in RCS-01-61 show the need to go to feed and bleed at 30 minutes. If no action occurs at 30 minutes, then CD results at 45 minutes, assuming that the Reactor Coolant Pump (RCP)is on. If the RCP is off, action must occur by 60 minutes.

QHUEFW9Y: Human Failure Event for raising the water level in the Once-Through Steam Generator (OTSG). Timeline suggests this is used for a Small Break Loss of Coolant Accident (SLOCA). Thermal-hydraulicreference is for a Station Blackout (SBO) sequence. Not clear if the reference applies to a SLOCA.

QHUMSIVY: Isolate Main Steam Isolation Valve. The timing reference is for SBO and states that 60 minutes is allowed for recovery. Sixty minutes is for RCP's not operating.

If RCPs operate, the time to CD is 30 minutes. There is not enough documentation in the worksheet to know if this event is only used in sequences with the RCPs tripped.

QHUFWPTY: Uses 60 minutes for time to recover. Reference for 60 minutes is from the SBO analysis. Not clearif this event only applies to SBO analysis.

RHUHPRRY: Initiate High Pressure Recirculation following a Steam Generator Tube Rupture (SGTR). The event does not make sense. After Refueling Water Storage Tank drains for SGTR, there is no inventory in sump to switch to.

Resolution The MAAP timing analysis for the human events has been used to calculate the Human Reliability Analysis (HRA) timelines and included in the draft model 2009.

Impact The impact to the MOR 2006 is not considered significantbecause in both the MOR 2006 model and draft model 2009, the operatoractions account for a large portion of the overall CDF.

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 3 of 16 FnO-DA-C1 Significant Comment The frequency of Loss of Offsite Power (LOSP, LOOP) is developed through Bayesian update of generic data with plant specific historical events. This is developed through screening of historicaldata, ratherthan using generic data verbatim. The Offsite Power (OSP),historicaldata is screened to remove events that "arenot typical" to the CR-3 site. The screening process and rules are not substantiated. Grid and weather events at plants with less robust OSP connections than CR-3 were discarded as applicable failures, but the operating time for these plants was included in the plant population. The resulting generic initiating event frequency of 6.6E-3 conflicts with several NUREG's on LOSP. The result of these two practices is that the plant-specific data for LOSP is reduced by a factor of 10, with no justification as to why the methods and data are allowable for CR-3.

Resolution The 2008 model revision no longer incorporates a screening approach for LOOP data. The generic LOOP event frequencies are directly taken from NUREG/CR-6890, "Reevaluation of Station Blackout Risk at Nuclear Power Plants." These values are Bayesian updated against plant experience (or grid region experience). As part of this update, the four categories of LOOP events were also adopted.

Impact The LOSP analysis was revised to include the four categories of LOOP events. The LOSP contribution slightly decreased from 6% of CDF to 4% of CDF which was a small impact to the model and, therefore, not considered a significant impact to the MOR 2006 model.

2009 Significant Items from FocusedPEER Review:

The Focused PEER review was conducted againstthe 2008 PRA model. There were no FnO's from the 2009 focused PEER review that required changes to the model or changes to the results.

RAI 2.e.i Progress Energy did not identify or describe the Plant Damage States (PDS) from the Level 1 PSA or provide their frequency. As recommended by NEI 05-01, "provide a table or matrix describing the mapping of Level 1 accident sequences into Level 2 release categories."

Response

The Level I accident sequences are grouped into core damage bins (CDB) based upon conditions presented in the following table.

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 4 of 16 Table 1 - Mapping of Accident Sequences to Core Damage Bins Accident CDB(s) RCS leakage rate Timing of SSHR* RCS pressure Cavity status at Sequence RPV failure status at RPV failure RPV failure 1

TBQU I Small LOCA Early Failed High Dry TKBQU I Small LOCA Early Failed High Dry' TKBU 1 Small LOCA Early Failed High Dry' TBL1U 2 Cycling Relief Early Failed High Dry' SU 3 Small LOCA Late Available High DryI TKU 3 Small LOCA Late Available High Dry' TQU 3 Small LOCA Late Available High Dry' SBP 4 Small LOCA Early Failed High Wet SX 5 Small LOCA Late Available High Wet TBLIWX 5 Small LOCA Late Available High Wet TBQX 5 Small LOCA Late Available High Wet TKBQX 5 Small LOCA Late Available High. Wet TQX 5 Small LOCA Late Available High Wet SBX 6 Small LOCA Late Failed High Wet TBL1L2X 6 Small LOCA Late Failed High Wet AU 7 Large LOCA Early N/A Low Dry1 RV 7 Large LOCA Early N/A Low Dry1 TBP 7 Large LOCA Early Failed Low Dry' TKBIB2/(TKBL) 7 Large LOCA Early Failed Low Dry' TKBM 7 Large LOCA Early Failed Low Dry' TKBP 7 Large LOCA Early Failed Low Dry' 1

MU 9 Medium LOCA Early N/A Medium Dry AX 11 Large LOCA Early N/A Low Wet MX 12 Medium LOCA Late N/A Medium Wet RCQGY 18 Small LOCA (Bypass) Late Available Medium Dry RQGY 18 Small LOCA (Bypass) Late Available Medium Dry RUG 18 Small LOCA (Bypass) Late Available Medium Dry RUQ 18 Small LOCA (Bypass) Late Available Medium Dry RBQY 19 Small LOCA (Bypass) Late Failed High Dry RUC2 20 Small LOCA (Bypass) Late Available High Dry RBQX 21 Small LOCA (Bypass) Late Failed High Wet RBX 21 Small LOCA (Bypass) Late Failed High Wet RBP 22 Small LOCA (Bypass) Early Failed High Dry RCP 22 Small LOCA (Bypass) Early Failed2 High Dry RUB 22 Small LOCA (Bypass) Early Failed High Dry ISLOCA 23 Large LOCA (Bypass) Early N/A Low Dry

  • SSHR - Secondary-Side Heat Removal
1. Assumes no reactorbuilding spray.
2. SSHR available to intact OTSG, but unavailablefor cooldown.

The Level 2 fault tree determines the Containment Safeguards Event Tree (CSET) End State.

The list of CSET End States is listed in Table 2 below. The CDBs are combined with the CSET to produce the PDS. The output of the quantification of the Level 2 fault tree provides the frequencies for each PDS.

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 5 of 16 Table 2 - ContainmentSafeguards Event Tree CSET End State Description A Successful isolation, sprays and fans functioning B Small isolation failure, sprays and fans functioning C Large.isolation failure, sprays and fans functioning D Successful isolation, sprays fail in recirculationand fans functioning E Small isolation failure, sprays fail in recirculationand fans functioning F Large isolation failure, sprays fail in recirculationand fans functioning G Successful isolation, sprays functioning and fans fail H Small isolation failure, sprays functioning and fans failed I Large isolation failure, sprays functioning and fans failed J Successful isolation, sprays fail in recirculationand fans failed K Small isolation failure, sprays fail in recirculationand fans fail L Large isolation failure, sprays fail in recirculationand fans fail M Successful isolation, sprays fail in injection and fans succeed N Small isolation failure, sprays fail in injection and fans succeed 0 Large isolation failure, sprays fail in injection and fans succeed P Successful isolation, sprays fail in injection and fans failed Q Small isolation failure, sprays fail in injection and fans fail R Large isolation failure, sprays fail in injection and fans fail S Containment bypass

U. S. Nuclear Regulatory Commission Enclosure 3FY1209-04 Page 6 of 16 Table 3 - CSET Definition Identifier Description Definition IC-1 Containment This release category represents an accident sequence in which the containment is intact. The source term for this Intact type of sequence is very small and limited to the containment design leakage rate.

RC-1 Release This release category is a late containmentfailure caused by gradualoverpressurization. The core debris is assumed Category I to be coolable. This type of gradualpressure increase is assumed to result in a benign containment failure and the duration of the release could be over a long period of time. Either the containment sprays or a pool of water over the core debris scrubs the release from the containment.

RC-1A Release This release category is similarto RC-1 except that re-vaporization occurs. Re-vaporization is caused by the self-Category 1A heating of radionuclidesplated out on the Reactor Coolant System (RCS), becoming re-suspended in the containment atmosphere. This re-vaporization is postulated to occur late in the accident sequence after the containment has failed.

This allows the radionuclidesto be released from the containment after only a limited holdup time. The impact of re-vaporization on the source terms is to increase the contribution of volatile radionuclidesto the source term.

RC-IB Release This release category is similarto RC-l except that no scrubbing by containmentsprays and/orwater pools is Category 1B available. If containment sprays function, or the Borated Water Storage Tank (BWST) inventory is otherwise dumped into containment, then both debris cooling and scrubbing will be attained(unless debris uncoolability is assumed).

This can be assumed because for the CR-3 containment, when the BWST is discharged,the water level reaches several feet over the basemat (lower compartment), completely covering the debris bed for the duration of all applicable sequences studied. This category implies a debris bed that eventually dries up resulting in considerable core-concrete interaction(CCI).

RC-1BA Release This release category is similarto RC-1 except that both re-vaporizationand no containment scrubbing are assumed Category 1BA to occur.

RC-2 Release This release category represents a large early containment failure. The core debris is assumed to be coolable. The Category 2 large failure significantly reduces radionuclideholdup time in the containment. The CR-3 specific liner failure releases are assumed to belong to this category. The release from the containment is scrubbedby containmentspray operationat the time following fission product releases from the primary side. In this case, the releases will be driven by the prompt release of fission products at containment failure and the effect of re-vaporization,if any, should be small. Thus, release categories with re-vaporization will not be postulatedfor the large early containment failures.

However, care will be taken when assigning source terms to pick a representativesequence for RC-2 (and RC-2B) that exhibits re-vaporization.

RC-2B Release This release category is similarto RC-2 except that no scrubbing by containmentsprays and/or water pools is Category 2B assumed to happen.

RC-3 Release This release categoryrepresents an early containment isolation failure with a small leakage rate (4 in. diameter). The Category 3 core debris is assumed to be coolable. Either the containmentsprays or a pool of water over the core debris scrubs the release from the containment. Forthe largerof the small leakage failures (i.e., close to 4 in. in diameter), the releases will be driven by the prompt release of fission products at containmentfailure and the effect of re-vaporization, if any, should be small. Smaller diameter isolation failures will result in reduced source terms due to the longer time available for naturalremoval mechanisms, such as gravity settling, to take place. Thus, release categories with re-vaporizationwill not be postulated for the small early containment failures. However, care will be taken when

_assigning source terms to pick a representativesequence for RC-3 (and RC-3B) that exhibits re-vaporization.

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 7 of 16 Identifier Description Definition RC-3B Release This release category is similar to RC-3 except that no scrubbingby containmentsprays and/or water pools is Category 3B assumed to happen.

RC-4 Release This release category represents a containment bypass accident sequence with a small leakage rate. The leakage Category 4 rate that would correspond to a SGTR sequence with cycling Safety-Relief Valves (SRVs), or an Interfacing System Loss of CoolantAccident (ISLOCA) in which operatorsreact in time to mitigate effects by closing the valves on the Residual Heat Removal (RHR) suction line. The core debris is assumed to be coolable and releases from the containmentscrubbed. Scrubbing by water in the faulted Steam Generator(SG) above the break is assumed to occur.

Note that the operatingproceduresdirect the operatorto isolate the faulted SG. -Thus, the faulted SG will be dry in the majority of the cases and no fission product scrubbing would occur. This category will be kept for future use (in case the procedures change), but for the purposes of this study, the unscrubbed source term (RC-4C) will be conservatively assigned to these low probabilitybranches.

RC-4C Release This release category is similar to RC-4 except that no scrubbing by water in the faulted SG above the break occurs.

Category 4C The core debris is assumed to be coolable and releases from the containmentscrubbed. Note that a release category for no scrubbing by containmentsprays and/or water pools is not postulated in this case. This is so because, for the bypass sequences, most of the release would be directly from the primary to the environment or the auxiliary building.

Re-vaporization is also assumed to be negligible as compared to the direct releases.

RC-5 Release The sequence representsa containment bypass accident with a large leakage rate. Such rate is representativeof a Category 5 SGTR accident with a stuck open SRV in the faulted SG, or an unmitigated ISLOCA accident. The core debris is assumed to be coolable and releases from the containment scrubbed. The releases from the faulted SG are assumed to be scrubbed by water above the break line. However the probabilityof scrubbed releasesis very low due to the presentprocedures. Thus, similarly to RC-4, the unscrubbedsource.term (RC-5C) will be conservatively assigned to these low probabilitybranches.

RC-5C Release This release category is similarto RC-5 except that scrubbing by water in the faulted SG above the break occurs. The Category 5C releases from the faulted SG are not scrubbed by water above the break line. The core debris is assumed to be coolable and releases from the containment scrubbed.

The Containment Release Category Fractionsare obtainedfrom containment failure event trees. Each PDS from the Level 2 quantificationis multiplied by the Containment Release Category fractions in that row to obtain the frequency of containment release category. Forexample, the frequency of IC-I release category from the Plant Damage State 1M (first row of Table 4) would be calculated as 5.67E-12

  • 9.89E-1 = 5.61E-12.

Table 4 provides the mapping of Level 2 quantificationcutset file results and does not include PDSs that did not appearin the cutset.

U. S. Nuclear Regulatory Commission Enclosure 3FY1209-04 Page 8 of 16 Table 4 - Mapping of Quantificationresults to Containment Release Category Level 2 Level I accident Containment Release Category Fraction Quantification results - Level sequences maccid mapped Frequency of to plant damage PDS IC-i RC-1 RC-IA RC-1B RC-IBA RC-2 RC-2B RC-3 RC-3B RC-4 RC-4C PDSquency PDS of states RC-5 RC-5C 5.67E-12 TBQU, TKBQU, IM 9.89E-01 0 0 9.12E-03 I.O1E-03 1.00E-03 1.83E-04 0 0 0 0 0 0 TKBU 1.06E-10 TBLIU 2M 9.94E-01 0 0 4.55E-03 5.06E-04 3.29E-04 2.84E-04 0 0 0 0 0 0 9.29E-13 TBLIU 20 0 0 0 0 0 0 1.OOE+00 0 0 0 0 0 0 1.36E-11 TBL1U 2P 7.46E-01 0 0 2.28E-01 2.53E-02 7.40E-04 1.43E-04 0 0 0 0 0 0 2.85E-12 TBL1U 2R 0 0 0 0 0 0 1. OOE+00 0 0 0 0 0 0 5.74E-12 SU, TKU, TQU 3M 9.89E-01 0 0 1.01E-02 1.O1E-05 1.15E-03 7.93E-05 0 0 0 0 0 0 2.67E-11 SBP 4M 9.89E-01 8.15E-03 9.06E-04 9.93E-04 1.1OE-04 0 1.23E-03 0 0 0 0 0 0 2.51E-10 SX, TBL1WX, TBQX, 5M 9.89E-01 9.21E-03 9.22E-06 9.27E-04 9.28E-07 0 1.19E-03 0 0 0 0 0 0 TKBQX, TQX 7.76E-13 SX, TKBQX, TBLIVX,TQX TBQX, 5P 7.86E-01 1.93E-01 1.93E-04 1.94E-02 1.94E-05 0 1.81E-03 0 0 0 0 0 0 1.09E-10 SBX, TBLIL2X 6M 9.89E-01 8.15E-03 9.06E-04 9.93E-04 1.1OE-04 0 1.23E-03 0 0 0 0 0 0 9.29E-13 SBX, TBLIL2X 60 0 0 0 0 0 8.91E-01 1.09E-01 0 0 0 0 0 0 1.36E-11 SBX, TBLIL2X 6P 7.85E-01 1.71E-01 1.89E-02 2.08E-02 2.31E-03 0 2.26E-03 0 0 0 0 0 0 2.85E-12 SBX, TBL1L2X 6R 0 0 0 0 0 8.91E-01 1.09E-01 0 0 0 0 0 0 AU, RV, TBP, 2.39E-10 TKBIB2/(TKBL), 7A 9.89E-01 9.67E-03 9.76E-105 7.26E-04 7.34E-06 0 7.50E-04 0 0 0 0 0 0 TKBM, TKBP AU, RV, TBP, 5.79E-12 TKBIB2I(TKBL), 7D 9.89E-01 0 0 1.04E-02 1.05E-04 6.91E-04 5.89E-05 0 0 0 0 0 0 TKBM, TKBP AU, RV, TBP, 6.39E-11 TKBIB2/(TKBL), 7M 9.89E-01 0 0 1.04E-02 1.05E-04 6.91E-04 5.89E-05 0 0 0 0 0 0 TKBM, TKBP 2.86E-12 MU 9M 9.88E-01 0 0 9.43E-03 1.05E-03 5.36E-04 5.95E-04 0 0 0 0 0 0 1.05E-11 AX 11A 9.89E-01 9.67E-03 9.76E-05 7.26E-04 7.34E-06 0 7.50E-04 0 0 0 0 0 0 5.64E- 11 AX 1ID 9.89E-01 9.67E-03 9.76E-05 7.26E-04 7.34E-06 0 7.50E-04 0 0 0 0 0 0 2.23E-12 AX 11M 9.89E-01 9.67E-03 9.76E-05 7.26E-04 7.34E-06 0 7.50E-04 0 0 0 0 0 0 4.49E-11 MX 12M 9.88E-01 4.71E-03 5.24E-04 4.71E-03 5.24E-04 0 1.19E-03 0 0 0 0 0 0 8.19E-09 RCQGY, RQGY, 18S 0 0 0 0 0 0 0 0 .0 0 I.00E+00 0 0 RUG, RUQ 6.08E-I1 RUC2 20S 0 0 0 0 0 0 0 0 0 0 1.OOE+O0 0 0 3.26E-13 RBQX, RBX 21S 0 0 0 0 0 0 0 0 0 0 1.OOE+00 0 0 3.09E-07 RBP, RCP, RUB 22S 0 0 0 ,0 0 0 0 0 0 0 1.00E+00 0 0 5.14E-08 ISLOCA 23S 0 0 0 0 0 0 0 0 0 0 0 0 1.OOE+O0

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 9 of 16 RAI 3.b Progress Energy identified several fire protection related modifications made at CR-3 since the IPEEE, but did not identify the specific fire compartments where the modifications were made.

Provide a separate accounting of the fire protection related enhancements for each of the dominant fire areas.

Resgponse The following table correlates the risk significant zones per the original Individual Plant Examination - External Events (IPEEE)identified in the response to RAI 3.a from CR-3 to NRC letter dated October 9, 2009, "Crystal River Unit 3 - Response to Request for Additional Information Regarding Severe Accident Mitigation Alternatives for Crystal River Unit 3 Nuclear Generating Plant License Renewal Application (TAC NO. ME0278)," with fire protection (FP) related hardware modifications.

Zone Description FP-RelatedModification(s)

CC-108-106 EnhancedEmergency Lighting, Upgraded BATTERY CHARGER ROOM 3A Fire Detectors EnhancedEmergency Lighting, Upgraded Fire Detectors, Electrical Cable Re-CC-108-108 4160V ES SWITCHGEAR BUS ROOM 3A Routing for DHV-42 (ReactorBuilding Sump to Decay Heat Pump 1A Suction Isolation Valve)

CC-108-107 4160V ES SWITCHGEAR BUS ROOM 3B UpgradedFire Detectors UpgradedFire Detectors, ElectricalCable CC-124-117 480V ES SWITCHGEAR BUS ROOM 3A Re-Routing for DHV-42 (ReactorBuilding Sump to Decay Heat Pump 1A Suction Isolation Valve)

CC-108-105 BATTERY CHARGER ROOM 35 Enhanced Fr eetrEmergency Lighting, Upgraded Fire Detectors CC-108-102 HALLWAY AND REMOTE SHUTDOWN Upgraded Fire Detectors ROOM UpgradedFireDetectors ROM Enhanced Emergency Lighting, Upgraded CC-124-111 CRD & COMMUNICATION EQUIPROOM Fire Eters Fire Detectors CC-108-109 INVERTER ROOM 38 Enhanced Fr eetrEmergency Lighting, Upgraded Fire Detectors CC-145-118B CONTROL ROOM UpgradedFire Detectors UpgradedFire Detectors, Electrical Cable CC-134-118BA CABLE SPREADING ROOM Re-Routing for BSV-3, -4 (Reactor Building Spray HeaderInlet Isolation Valves)

RAI 4.a Progress Energy failed to provide the requested analysis of the impacts of the planned 20%

extended power uprate on the SAMA analysis, despite the fact that this request is within the scope of NEI 05-01 (Section 8.1). Provide the requested analysis.

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 10 of 16

Response

As the response to this follow-up RAI, a description of the changes to the PRA model, from the issued Model of Record 2006 to the current draft model, is presented below to gain insight to the effects that the Extended Power Uprate (EPU)will have on the PRA.

Model of Record MOR2006 - CDF = 4.99E-6 / LERF = 3. 69E-7 Since the Model of Record 2006 was issued, the CR-3 model.has undergone draft updates that have not yet been issued as a new model of record. These updates include closing gaps from the American Society of Mechanical Engineers (ASME) gap self-assessment and focused peer review. Also the PRA model was modified to include multiple spurious actuations as required for a fire PRA that meets the requirements of Regulatory Guide 1.200, Rev. 2. The following sections describe the changes that have been made and the affects to CDF and Large Early Release Frequency (LERF).

PSA Model 2008 Update - CDF = 3.78E-6/LERF = 4.30E-7 The CR-3 Probabilistic Safety Assessment (PSA) model update 2008 was completed in' February 2009. This revision was performed to incorporate the ASME gap self-assessment findings, update plant specific data, and incorporate fault tree logic to support the fire PRA model. The change in the model results are dominated primarily by the data update. The generic and plant specific data were both updated and the values generally trended downward (lower failure probabilities) due to improved industry and plant experience. For systems, the most significant change is that Decay Heat Removal (DH) System importance has decreased significantly due to the data update improving both the availability and the reliability of the DH system. A PRA model comment was resolved by including the Emergency Diesel Generator (EG) system where more credit was provided for the recently added non-safety diesel in LOSP recovery thereby reducing system contribution to CDF. Reactor Coolant (RC) system, importance reduction was also primarily related to data improvement in valve reliability. The increase to LERF is due to the inclusion of the ISLOCA fault tree into the model, which was previously a point estimate; and SGTR contribution increasedwhich translatesdirectly to LERF.

PSA Model 2009 Update - CDF = 3.63E-6 / LERF = 1.82E-7 The CR-3 PSA model update 2009 was completed in July 2009. This revision was performed to incorporate the ASME gap self-assessment findings associated with the HRA and incorporate fault tree logic to support the fire PRA.

The noticeable effect on the PRA model results was in the decrease in LERF. The SGTR initiator decrease is related to HRA analysis improvements; this change has had a significant impact on reducing the Level 2 results. The safety Alternating Current (AC) bus initiatorshave been removed based on stable plant operation with the loss of a safety AC bus. The makeup contributionalso decreasedbased upon HRA analysis.

PSA Model 2009a Update/Pre-EPUmodel - CDF = 3.4E-6 / LERF = 1.6 E-7 Prior to including the EPU modifications into the PRA model, a couple of deficiencies were noted in the 2009 base model. These items were not related to EPU, therefore were added to the pre-and post-EPU model to be consistent in modeling the plant. These changes included

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 11 of 16 Emergency Feedwater Initiation and Control (EFIC) OTSG pressure control channel fails high mission time of 2 years which is actually I month; and the second item was modeling the recovery of Heating, Ventilation & Air Conditioning (HVAC) from a pair of two HRA events to one HRA event.

In the 2009 model, the failure of the HVAC was divided into failure to start the fans and failure of starting the chilled water pumps which caused over conservative dependencies in the cutsets; therefore, one HRA was used as the failure to restore HVAC. JHUCHPARRR_M (OPERATORS FAIL TO START VENTILLATION SYSTEMS) replaced the following HRA events in the fault tree:

JHUAHFSY OPERATORS FAIL TO ALIGN AND START STANDBYAH FANS JHUCHPSY OPERATORS FAIL TO ALIGN AND START STANDBY CH TRAIN JHUCHP2Y OPERATORS FAIL TO START CHP-2 APP R CHILLED WATER SYSTEM Post-EPUModel 2009a Update - CDF = 3.6E-6 LERF = 1.7 E-7 The changes that are considered for the PRA EPU update include proposed hardware modifications and updated thermal hydraulic analysis that affect operatoractions. The notable changes to the PRA model include the following.

1) The installation of a low pressure injection cross-tie increased the ISLOCA initiating event which feeds into the LERF contribution.
2) Loss of offsite power non-recovery probability was reevaluated to account for new shorter time available.
3) The HRA and dependency analysis was affected by the new shortertime available.
4) The success criteriafor medium LOCA would be changed to include one core flood tank being required as a result of the EPU.

U. S. Nuclear Regulatory Commission Enclosure 3F17209-04 Page 12 of 16 CDF 5.50E-06 5.OOE-06 4.50E-06 4.OOE-06 3.50E-06 3.OOE-06 2.50E-06 2.00E-06 1.50E-06 1.00E-06 5.00E-07 0.00E+00 MOR 2006 MODEL2008 MODEL2009 MODEL2009A EPU MODEL LERF 5.OOE-07 4.50E-07 4.OOE-07 3.50E-07 3.OOE-07 2.50E-07 2.OOE-07

1. 50E-07 1.OOE-07 5.O0E-08 0.OOE+00 MOR2006 MODEL2008 MODEL2009 MODEL2009A EPU MODEL Conservative Scalinq of Offsite Dose and Consequences Using MOR2006 To attempt characterizing the impact that an increase in the fission product inventory, from an EPU, might have on offsite dose and consequences, the person-rem and cost values were scaled by a factor of 1.2 (i.e., 903 MWe scaled to 1083.6 MWe). The base release category frequencies were assumed to be constant. The following table shows the original table from the ER (Table E.3-7) with columns showing the new conservative "post-EPU"values for Dose Risk and Offsite Economic Cost Risk (OECR):

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 13 of 16 Revised Table E.3-7 MACCS2 Base Case Mean Results with EPU Estimates Obtainedby Scaling Pre-EPUValues by a Factorof 1.2 Source Release Pre-EPU Pre-EPU Post-EPU Post-EPU Frequency Pre-EPU Pre-EPU Post-EPU Post-Term Category Dose Offsite Dose Offsite (lyr) Dose-Risk OECR Dose-Risk EPU (p-rem) Economic (p-rem) Economic (p-rem/yr) ($/yr) (p-rem/yr) OECR Cost ($) Cost ($) ($lyr) 1 /C-1 9.81E+03 1.02E+04 1.18E+04 1.22E+04 4.15E-06 4.07E-02 4.23E-02 4.89E-02 5.08E-02 2 RC-1 2.06E+05 2.17E+07 2.47E+05 2.60E+07 2.48E-08 5.12E-03 5.39E-01 6.14E-03 6.47E-01 3 RC-1A 1.51E+05 1.56E+06 1.81E+05 1.87E+06 3.94E-10 5.94E-05 6.14E-04 7.13E-05 7.37E-04 4 RC-1B 2.17E+06 1.85E+09 2.60E+06 2.22E+09 1.55E-08 3.36E-02 2.87E+01 4.04E-02 3.44E+01 5 RC-IBA 2.17E+06 1.85E+09 2.60E+06 2.22E+09 1. 18E-09 2.57E-03 2.19E+00 3.08E-03 2.62E+00 6 RC-2 3.96E+06 8.55E+09 4.75E+06 1.03E+10 8.53E-10 3.38E-03 7.29E+00 4.05E-03 8. 75E+00 7 RC-2B 3. 76E+06 7.70E+09 4.51E+06 9.24E+09 3.43E-09 1.29E-02 2.64E+01 1.55E-02 3.17E+01 8 RC-3 3.00E+05 6. 10E+07 3.60E+05 7.32E+07 2.16E-07 6.48E-02 1.32E+01 7.78E-02 1.58E+01 9 RC-3B 1.93E+06 4.32E+09 2.32E+06 5.18E+09 1.58E-07 3.05E-01 6.83E+02 3.66E-01 8.20E+02 10 RC-4C 7.47E+06 1.41E+10 8.96E+06 1.69E+10 3.59E-07 2.68E+00 5.06E+03 3.22E+00 6.08E+03 11 RC-5C 1.44E+07 1.96E+10 1.73E+07 2.35E+10 5.74E-08 8.26E-01 1.12E+03 9.92E-01 1.35E+03 FREQUENCY WEIGHTED TOTALS 4.99E-06 3.98E+00 6.95E+03 4.77E+00 8.34E+03 The next step involved calculating a new value for the Modified Maximum Averted Cost Risk (MMACR), which also accounted for an increase in the replacement power cost by using a factor of 1.2 and an external events multiplier of 12, which was adopted in RAI response 3.c.

Based on this new input, the new post-EPU MMACR value was found to be $4,668,000.

The last step involved comparing the new post-EPU averted costs to the originalimplementation costs. The table shown below lists the status of the cost effectiveness for each of the evaluated SAMAs for both pre- and post-EPU conditions at the 9 5 th percentile. In conservatively scaling the offsite dose and consequence values by a factor of 1.2, it was shown that there would be no change in the cost-beneficial status of any of the evaluated SAMAs, which implies that the SAMA results and decision for deciding which SAMAs are cost beneficial remains unchanged as a result of consideringthe pending EPU implementation at CR-3.

It should be noted that the pre-EPU numbers for SAMA 49 were multiplied by a factor of 1.2 directly to obtain the post-EPU values. This is due to the fact that in response to RAI 3.d, the averted cost-risk for SAMA 49 was determined using the ratio of the fire CDF for Battery ChargerRoom 3A to the internal events CDF, and that ratio multiplied by the original MACR of

$341,000. This approach provides a conservative assessment for the cost benefit associated with SAMA 49 for post-EPU conditions.

Summary of the Impact of Using the 95 Percentile PRA Results Pre-EPL Averted Pre-EPUNet Post-EPU Averted Post-EPUNet Change in Cost SAMA ID Cost of Cost Risk (95th Value (95th Cost Risk (95th Value (95th Effectiveness?

Implementation Percentile with Percentile) Percentile with Percentile) (Yes or No) x12 EE multiplier) Percentile) x12 EE multiplier) Percentile) (YesorNo) 34 $50,000 $1,238,754 $1,188,754 $1,358,227 $1,308,227 No 33 $50,000 $201,223 $151,223 $211,556 $161,556 No

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 14 of 16 Summary of the Impact of Using the 95 Percentile PRA Results Pre-EPU Averted Pre-EPUNet Post-EPU Averted Post-EPUNet Change in Cost SAMA ID Cost of Cost Risk (95th Value (95th Cost Risk (95th Value (95th Effectiveness?

Implementation Percentilewith Percentile with x12 EE multiplier) Percentile) x12 EE multiplier) Percentile) (Yes or No) 9 $50,000 $210,954 $160,954 $222,569 $172,569 No 10 $50,000 $385,886 $335,886 $450,632 $400,632 No 38 $50,000 $156,934 $106,934 $171,950 $121,950 No 3 $350,000 $307,249 ($42,751) $321,637 ($28,363) No 6 $400,000 $258,749 ($141,251) $271,541 ($128,459) No 5 $500,000 $510,643 $10,643 $558,333 $58,333 No 17 $500,000 $357,503 ($142,497) $405,846 ($94,154) No

.11 $250,000 $116,334 ($133,666) $127,190 ($122,810) No 15 $300,000 $322,867 $22,867 $372,754 $72,754 No 4 $250,000 $393,159 $143,159 $423,033 $173,033 No 35 $700,000 $3,388,897 $2,688,897 $4,023,617 $3,323,617 No 51 $100,000 $1,004,230 $904,230 $1,099,976 $999,976 No 49 $150,000 $2,237,648 $2,087,648 $2,685,178 $2,535,178 No RAI 5.a Progress Energy does not adequately support why SAMAs were not developed for the 4.16 kV Switchgear Bus Rooms 3A and 3B. On the one hand Progress Energy uses the IPEEE to justify SAMA 49 to upgrade fire barriers in Battery Charger Room 3A, but on the other hand argues that the IPEEE is not an appropriate basis for considering a SAMA to upgrade fire barriers in the switchgear bus rooms. Provide an assessment of a SAMA to reduce fire risk in Switchgear Bus Rooms 3A and 3B.

Response

As discussed in the response to RAI 5.a, it was recognized that changes to 4.16kV Switchgear Bus Rooms 3A and 3B, similar to those proposed for SAMA 49, would be cost beneficial when using the IPEEE results and the external events multiplier of 12. The averted cost-risk and net values for these plant enhancements can be estimated in the same manner as described for SAMA 49 in the response to RAI 3.d.

4.16kV Switch-gear Bus Room 3A For 4.16kV Switchgear Bus Room 3A, the averted cost-risk can be estimated by multiplying the internal events Maximum Averted Cost Risk'(MACR) by the ratio of the 4.16kV SwitchgearBus Room 3A fire CDF to the internalevents CDF:

$341,000

  • 7.31E-06/4.95E-06 = $503,578 It is assumed that the cost of implementation (C01) for improving the fire barriers in 4.16kV Switchgear Bus Room 3A is the same as what was estimated for Battery ChargerRoom 3A in

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 15 of 16 SAMA 49 ($150,000). This estimate can be used with the $503,578 averted cost-risk calculated above to quantify the net value:

Net Value for Improving the Fire Barriersin 4.16kV SwitchgearBus Room 3A A verted AetdCOl Net Value Cost-Risk

$503,578 $150,000 $353,578 The net value for this SAMA is the averted cost-risk minus the COI, or $353,578 ($503,578 -

$150,000 = $353,578).

As documented in Section E.7.2 of the ER, the point estimate based cost-risk values can be multiplied by 2.18 to account for the impact of the use of the 9 5 th percentile PRA results. For 4.16kV Switchgear Bus Room 3A, this results in an averted cost-risk of $1,097,800 (2.18

  • 503,578 = $1,097,800) and a net value of $947,800 ($1,097,800 - $150,000 = $947,800).

4.16kV Switch-gear Bus Room 3B For 4.16kV Switchgear Bus Room 3B, the averted cost-risk can be estimated by multiplying the internal events MACR by the ratio of the 4.16kV Switchgear Bus Room 3B fire CDF to the internalevents CDF:

$341,000

  • 6.79E-06 / 4.95E-06 = $467,756 It is assumed that the cost of implementation (COI) for improving the fire barriers in 4.16kV Switchgear Bus Room 3B is the same as what was estimated for Battery ChargerRoom 3A in SAMA 49 ($150,000). This estimate can be used with the $467,756 averted cost-risk calculated above to quantify the net value:

Net Value for Improving the Fire Barriersin 4.16kV Switchgear Bus Room 3B A verted AetdCO/ Net Value Cost-Risk

$467,756 $150,000 $317,756 The net value for this SAMA is the averted cost-risk minus the CO/, or $317,756 ($467,756 -

$150,000 = $317,756).

As documented in Section E. 7.2 of the ER, the point estimate based cost-risk values can be multiplied by 2.18 to account for the impact of the use of the 9 5 th percentile PRA results, For.

4.1,6kV Switchgear Bus Room 3B, this results in an averted cost-risk of $1,019,708 (2.18

  • 467,756 = $1,019,708) and a net value of $869,708 ($1,019,708- $150,000 = $869,708).

U. S. Nuclear Regulatory Commission Enclosure 3F1209-04 Page 16 of 16 RAI 5.d.i Progress Energy did not adequately support why procedures and training could not be identified as an effective means of reducing the risk of basic event APWNR01R. Describe how it is that "no such weaknesses" were identified in the power restoration procedures at CR-3 despite the fact that this event has a failure probability of 0.6?

Response

APWNROIR is not a Human Performance Error, but is a non recovery factor for loss of offsite power. It is a discrete integration of the time-dependent failures and the non-recovery distributions using raw data from Technical Update, Losses of Off-Site Power at U.S. Nuclear Power Plants- 2002, Electric Power Research Institute, TR-1008052, April 2003.

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