ML20199B738

Provides Response to 971105 RAI Re TS Change Request Notice 210,proposing Amends to License DPR-72.List of Commitments Made in Submittal Encl

ML20199B738
Person / Time
Site:	Crystal River
Issue date:	11/15/1997
From:	Holden J FLORIDA POWER CORP.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
TAC-M98991, NUDOCS 9711190075
Download: ML20199B738 (32)

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,4 Florida Power Ct4tPORAtoN WNs'oE' November 15,1997 3F1197-40 U.S. Nuclear ReguLlery Commission Attn: Docun ent Comtol Desk Washingon, DC 20555-0001 c ubject: Technical Specification Change Request Notice 210 Request for Additional Information (TAC No, M98991)

References:

1. FPC letter dated June 14,1997 (3F0697-10), " Technical Specification Change Request Notice 210"

2. NRC letter dated November 5,1997 (3 Nil 97-08), " Request for Additional Information - License Amendment Related to Technical Specification Change Request No. 210, Small Dreak Loss of Coolant Accident (SIlLOCA) Submittal"

Dear Sir:

In Reference 1, Florida Power Corporation (FPC) submitted Technical Specification Change Request Notice (TSCRN) 210, which proposed amendments to Operating License No. DPR-72 for Crystal River Unit 3 (CR-3). The TSCRN is necessary to support operatian with certain hardware, design, and licensing basis changes primarily invohing the Emergency Feedwater (EFW), Emergency Core Cooling System (ECCS), and Emergency Diesel Generators (EDG). In Reference 2, the NRC provided FPC with a request for additiona! information regarding Control Complex Cooling and Iligh Pressure injection. Attachments A and Il provide FPC's response to each of these requests.

Attachment C prosides a list of commitments made in this submittal. These commitments include submitting a revision to the Technical Specification requirements requested in TSCRN 210 based {\Cd upon the NRC review. FPC concludes that the revision, based on this RAI response, does not affect the presious conclusions or the basis for the conclusions in the No Significant Hazards

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9711190075 971115 PDR P

ADOCK 05000302 PDR I{\t CRYSTAL RIVER ENEROY CoMPLEK: 15780 W. Power Line Street . Crystal River, Florkla 34429 470s (362)795 4488 A norida Progress Company

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. Consideration provided in Reference-1 in accordance with 10CFR50.92(c), and FPC does not consider that an additional public notice in accordance with 10CFR50.9)(a)(2) is necessary.

If you have any questions concerning this submittal, please contact Mr. David Kunsemiller, Manager, Nuclear Licensing at (352) 563-4566.

Sincerely, 4

dd e JbMn J. Iloid n-  !

Director Site Nuclear Operations l

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cc: Regional Administrator, Region 11 Senior Resident inspector NRR Project Manager Attachments:

A. Response to Request for Additional Information - Control Complex Cooling it Response to Request for Additional Information -liigh Pressure injection C. List ofCommitments t

D. List of Acronyms l

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FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/ LICENSE NUMBER DPR-72 ATTACIIMENT A to 3F1197-40 RESPONSE TO NRC RAI CONTROL COMPLEX COOLING

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ATTACllMENT A RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION TECIINICAL SPECIFICATION CHANGE REQUEST NOTICE 210

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CONTROL COMPLEX COOLING )

l NRC REQUEST NUAIMER I, CONTROL ContPLEX COOLING 1he proposed 3Wday allourd outage time (A0T)for the chillers and associated pumps appears to be unacceptable and inconsistent uith uhat the Nuclear Regulatory Commission (NRC) staff has accepted in the past. The chillers and chillei unter pumps ser r a number of diferent sqfety-relatedfunctions in addition to cooling the control room. A 30-day ACTfor the loss of singlefailure protection is only allourd in the Standard Technical Specyications (TS) uhen it 1

only affects control room cooling. Plants that have TSfor safety related chilled unter systems (see CEOG-STS, NUREG-1432) that cool more than the control room, the accepted A0T has l been 7 days Therefore, it appears that the risk intvived uith one chiller or pump inoperable l does not support a 30-day ACT. Hourver, for the control complex heat exchanger, 30 days is acceptable because the system remains protectedfrom single activefailures.

Also, for Fuel Cycle 11, uhile in Afodes 1, 2, and 3, the NRC staff believes that the required A0Y is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for a Train B chiller or chilled unter pump. With CHHE-1B or CHP-1B inoperable, the emergencyfeedunter/ emergency core cooling system (EFW/ECCS) response to certain SBLOCAs is vulnerable to certain single failures because of the load management problems associated uith emergency diesel generator (EDG) -1A uhile a Train B chiller or pump is inoperable. As ur understand your SBLC TA scenarios, the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> verification of the emergencyfeedunter pump (EFP) -2 (CHHE-lu or CHP-1B) only assures adequate SBLOCA mitigation capability (load management / decay heat removal) if no other single failures are assumed. The generally accepted 3& day ACTfo. control room chillers is based on the assumption that control room cooling is the only afectedfunction that is vulnerable to a single failure uhile in the 3& day limiting condition of operation (LCO) (this acceptance basis is consistent uith NUREG-1430 and your proposed Basis). Because of your present EDG capacity limitations, scfety r functions (EFW/ECCS), other than control complex cooling, are potentially affecred by the inoperability of the Train B chiller or chilled unterpump.

As proposed, if a SBLOCA utre to occur uhile in LCO 3.7.18, the associated risk may be sigmficantly greater if a Train B chiller or pump is inoperable (Condition A) compared to an inoperable Train A chiller or pump (Condition B). The reasoning behind this is tv2s uhile in Condition B (f a SBLOCA/EFP-2 failure urre to occur, load management and the control complex cooling system (CCCS) are still available. While in Condition A, if a SBLOCA/EFP-2 failure urre to occur, adequme load management uill not be available uithout purposely disabling the entire CCCS (to manage loads) function, or prematurely securing EFP-1A to

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• O U. S. Nuclear Regulatory Con t%n Attachment A 3F1197-40 Page 2 restore the CCCSfunction further complicat:ng the event. Jims, there appear to be more vndnerabilities (SBLOCA/EFP-2 failure is s 1, there may be more) while in Condition A than while in Condition B. 7herefore,for Cycle 11, the AOTfor the Train B chiller and chilled water pump should be 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (while in Modes I, 2, and 3), the same as other SBLOCA mitigating equipment. Also, the AOTfor the Train A chiller andpump should, es a minimum, be 7 days to minimize the riskfrom totalloss of cooling that would affect a numbe, of different safety-related areas in addition to control room cooling. You should revise your proposed 75 changes to address the above, or provide additional information andjustification as to why such changes are not necessary.

FPC HESPONM Florida Power Corporation (FPC) has reviewed the NRC's request regarding changes in the allowable outage time (AOT) for the Control Complex chillers and pumps. Based on this review, FPC accepts the NRC's request. A revised request will be submitted by Novembcr 21,1997 to address the following:

e the AOT for the "A" train chiller and pump, CllllE-1A and CllP 1A, will be reduced from 30 days to 7 days since these components serve to cool more than the control room, e the AOT for the 'B" train chiller and pump, CllllE-1B and CllP-1B, will be reduced from 30 days to 72-hour AOT for the remainder of Cycle 11.

In addition, FPC provides clarification regarding the following statement above:

" the AOT for the Train B chiller and chided water pump should be 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (while in Mcdes 1,2, and 3), the same as other SDLOCA mitigating equipment."

This statement appears to be due to a potential misunderstanding that the AOT for two EFW valves, ASV 204 and ASV-5, were revised from 7 days to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. TSCRN 210 did not change the AOT for any equipment and did not establish an AOT for all SBLOCA mitigation equipment as 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In a phone conversation with the NRC staff on October 30,1997, FPC representatives stated that ASV-204 and ASV-5 are not considered to be steam supply valves with a 7-day AOT, but are considered as part of the turbine driven emergency feedwater pump, which has a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AOT. Consequently, the AOT for these valves has not been revised.

TSCRN 210 proposes a revision to the Bases of Technical Specification 3.7.5 whiv,i indicates those valves ac' dressed as steam supply valves and those necessary to support operation of the tuitine driven feedwater pump.

U. S. Nuclear Regulatory Commission Attachment A 3F1197-40 Page 3 NRC Rii()UEST NUS1IIER 2. CONTR01, COAfPl.!!X C001.ING LCO 3.7.18 requires tun heat exchangers for the CCCS to be Operable. The proposed Background section of the Bases states there are "tuo pairs of heat exchangers." It isfurther stated in the Background that "A single chiller and associated chilled unter pump will provide the required temperature controlfor either heat exchangers." 1he use of the singular "cither" and the plural " heat exchangers"further corfuses what is neededfor adequate temperature contrct. Please provide additional itformation and modify the proposed Bases and LCO as necessary to clarify exactly how many and which heat exchangers are necessary to maintain adequate control complex cooling and, therefore, required to be Operable. Also,for consistency and clarity LCO 3. 7.18.h should specify tuo " Operable" heat exchangers in lieu ofJust two heat exchangers, the same asyou have proposed in LCO 3.7.18.afor the two " Operable" chillers and associatedpumps.

FPC HESPONSE The "two pairs of heat exchangers" referred to in the Bases are the control complex heat exchangers, CIIIIE-5A anc CilllE-5B, and the penetration cooling heat exchangers, CllllE-13A and CllllE-13D (see Final Safety Analysis Repon (FSAR) Figure 9-16). Upon further review, FPC concurs that the proposed Bases change requires revision to delete any reference to the penetration cooling heat exchangers since they are outside the scope of the Specification. The Background of the Bases will also be clarified to refer to a singular heat exchanger and the term

' Operable"will be added to 1.CO 3.7.18.b.

The revised request will be submitted by November 21,1997.

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U. S. Nuclear Regulatory Commission Attachment A 3F1197-40 Page 4 .

NRCREQUESTSIIMBER 3. CONTROL COMPLEX COOLING r The proposed ppplicabilityfor LCO 3.7.18 is Modes 1, 2, 3, and 4. To be consistent with NUREG 1430 and your corresponding IS 3.7.12 for the control room emergency ventilation  :

system, the qpplicability should be exparuled to include "During movement ofirradiatedfuel l assemblies." However the 72-hom Train B AOTdiscussed above, would not be requiredduring  ;

this mode (as it would not be required in Mcxle 4) and the AOTfor this mode would be 30 days, '

- the same as Train A components. Picase make any necessary revisions to include this additional mode in)vur LCO orprovide additional information tajustify why such changes should not be '

required.

FPC RESPONSE FPC accepts the NRC's request to expand the applicability of proposed Technical l Specification 3.7,18, Control Complex Cooling, to include, 'During movement ofirradiated fuel assemblics." The revised request will be submitted by November 21,1997.

Regarding the 'B" train AOT in Mode 4, FPC wishes to keep the completion time for Required Actions for an inoperable chiller or pump consistent for all applicable hiodes, including Mode 4. l This is done ta minimize the complexity of the proposed Technical Specifications. The time spent in Mode 4 w minimal so there would be limited impact on plant operation due to the shortened required action time.

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FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/ LICENSE NUMBER DPR-72 ATTACHMENT B to 3F1197-40 RESPONSE TO NRC RAI HIGH PRESSURE INJECTION

ATTACIIMENT B RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION TECIINICAL SPECIFICATION CIIANGE REQUEST NOTICE 210 IIIGli PRESSURE INJECTION NRC REQUEST NUMBER 1, IllGil PRESSURE INJECTION 1he submittal (pg.1) also indicates that certain aspects of the loss of EFP-2 were not analyzed. Please describe the potentialfor EFP-1 to be lost due to an automatic trip or as part of the load management strategy, given EFP-2 is lost.

FPC RESPON5E The Background section of the Safety Assessment for TSCRN 210 (Attachment B) states:

"The consequences of a SBLOCA with a concurrent LOOP and loss of EFP-2 as the single failure (probability of occurrence is approximately 4E-9/ year) were not analyzed with respect to the subsequent loss of EFP-1 due to the auto-trip function, or the need to shut down EFP-1 to support ECCS piggyback operation."

The above statement was included in the Background section of the submittal to state that, prior to TSCRN 210, no single failure analysis involving the loss of EFP-2 and the subsequent loss of EFP-1 existed. Ilowever, the analysis competed for TSCRN 210 does consider the loss of EFP-1 given EFP-2 as the single failiire. The current analysis addressing the potential loss of EFP-1 is described in pages 5 through 7 of the Safety Assessment. in summary, the analysis demonstrates that the Technical Specification changes, modifications and operator actions addressed by TSCRN 210 ensure that sufficient emergency feedwater is available to mitigate the consequences of a SBLOCA, coincident with the loss of EFP-2 as the single failure.

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U. S. Nuclear Regulatory Commission Attachment B 3FI197-40 Page 2

- NRC Request 2 was divided into multiple parts.

NRC REQUEST NUMBER 2A, HIGH PRESSURE INJECTION  ;

Please verify that the isolation of the wrong high pressure irtfection (HPI) line, glwn a HPl j line break,- is not a more limiting single failure for your electrical system or from the l standpoint ofLOCA consequences. )

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FPC RESPONSE

. - Isolating an intact 11PI line following an 11PI line break is not a more limiting single failure  :

than either core cooling or EDO loading. Isolation of an intact ilPI line is similar to, but less-  !

limiting than, the single failure of an 11PI isolation valve in the closed position following an 11PI line break. The only difference between the operator isolating an intact ilPI line and a  !

failed closed 11P1 isolation valve is the time period over which the 11PI isolation valve is l closed. -The single failure of an llPI isolation valve in the closed position at the onset of the event is more limiting relative to core cooling than isolation of an intact ilPI line because there i would be less integrated ECCS flow delivered to the core. The single failure of an llPI isolation valyc in the closed position during an llPI line break has been analyzed. The analysis concluded that sufficient ECCS flow would be delivered to maintain the core covered ,

with reactor coolant.

Isolating an intact 11P1 line following an IIPI line break is also not a more limiting single '

failure relative to EDG loading. In this situation, both trains of emergency AC power would be available to mitigate the accident. .;

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U. S. Nuclear Regulatory Commission Attachment B 3Fil97-40 Page 3 l

NRC REQUEST NUMBER 28, filGil PRESSURE INJECTION Additionally, please evaluate the llPIline isolation criteria of 50 gpmfrom an instrumentation standpoint and the expectedflow splits in thejour !ryection paths.

FPC RESPONSE The new IIPI line isolatien criterion ersures that those llPI line breaks requiring isolation can be identined, while also ensuring that an irtact ilP1 line is not identified as requiring isolation.

-In determining the new IIPi line isolation c lterion (50 gpm difference between the highest and next highest flowing IIPI lines), various break locations and sing!c failures were considered.

The revised ilPI line isolation criterion was determined using the expected flow splits in the four llPI line: and applying instrument uncertainties to minimize the indicated flow difference between highest and next highest flowing IIPI lines.

The worst case scenario was pinch break on the llPI side of line "B2" with one llPI pump operation and a reactor coolant pressure of 1100 psig. The flow from the broken llPI line, "B2", was calculated to be 175 gpm. The next highest flow was calculated to be 101 gpm through IIPI line "Bl". Applying instrument errors, the lowest flow indication on the broken "B2" IIPI line would be 162 gpm and the highest flow indication on the intact "Bl" llPI line would be 112 gpm. The difference between the two highest flows, adjusted for instrument errors would be 50 gpm.

If the pinch on the broken llPI discharge line allowed more flow than 175 gpm, then the difference between the two highest ilPI flow indications, including instrument error, would be greater than 50 gpm and the operator would isolate the broken llPi discharge line. If the pinch on the broken llPI discharge line limited the flow to less than 175 gpm, then the total flow into the reactor would increase and be sufficient to maintain the core covered with reactor coolant without operator action to isolate the broken llPI discharge line.

U. S. Nuclear Regulatory Commission Attachment B -  !

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NRC REQUEST NUMBER 2C, filGil PRESSURE INJECTION l With uhatfrequency do you e.tpect the operators nillisolate an intact injection path?

FPC RESPONSE ,

The calculated probability of the operator mistakenly isolating one of the intact injection lines ,

4 during a rupture of r.n llPI discharge line was calculated to be 3.6x10 . The dominant failure mode was the operator, having correctly determined the broken injection line, selecting the wrong control, and inadvertently closing the injection valve on an intact line. ,

Although a calculated probability of inadvertent isolation of an intact liPI discharge line by the operator exists, actual experience through simulator validations have demonstrated that operators have consistently isolated the simulated broken line.

Inadvertent isolation of an intact ilPI line by the operators due to human error could occur due to two situations' e the operator could misreu the llPI flow indications of the broken injection line and one of the intact injection lines, resulting in the operator calculating the 50 gpm delta flow for the wrong injection line, or i

. . the operator could inadvertently close the incorrec'. isolation valve after correctly determining which IIPI line should be isolated.

Fault tree modeling of these failure paths was created. iluman error probabilities were quantified using NUREG/CR-1278, "llandbook of Iluman Reliability Analysis with Emphasis on Nuclear Power Application," Sandia National Laboratories,1983.

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4- 4, U. S. Nuclear Regulatory Commission Attachment B ,

3F1197-40 Page5 I

NRC REQUEST NUMBER 2D, HIGil PRESSURE INJECTION What are operators instructed to do (( one of the four litfection line isolation valves falls to 7 open on an er;gineered sqfeguards signal? l l

FPC RESPONSE Emergency Operating Proced. ire E0P-03, Step 3.3, detail 3, instructs the operators to

" ensure" all llPI valves are open. This includes actions to align the valves to the alternate power supplies using switches on the main control board and to open any injection valve that

- does not open automatically on an ES signal. " Ensure" is defined- in Administrative Instruction (AI) 505 as " verify proper alignment or position of equipment and if not correct, manipulate controls to achieve correct alignment or position." -t l

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U. S. Nuclear Regulatory Commission Attachment B J 3F1197-40 Page 6 l NRC REQUEST NUMBER 2E, filGil PRR'sSURE INJECTION A review of the emergency operanng procedures indicate that the operators are instructed to isolate a .second ilPIflowpath, is this event bounded by the accident analysis?

FPC RESPONSE The EOPs do not call for isolation of the second IIPI flow path. Before applying the isolation criterion that would result in the isolation of a broken llPI line, all four llPI valves must be open (EOP-03, Step 3.6, detail 3).

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U. S. Nuclear Regulatory Commission Attachment B  ;

3F1197-40 Page 7 f

NRC REQUEST NUMBER 3, filGil PRESSURE INJECTION 1he submittal (pg. 3) indicates that the loss-of-ofsite poner is assumed to occur coincident i uith the react,r trip. Please explain uhy this is assumed and discuss ifit is consistent uith the  ;

design basis (for LOCA and other systems).

FPC RESPONSE i

The CR 3 ECCS performance to comply with 10 CFR 50.46 and Appendix K is based upon the assumption that a loss of offsite power (LOOP) occurs with the reactor trip. Assuming a LOOP at reactor trip rather than concurrent with the LOCA is conservative in that the start of the EDGs and ECCS is delayed. The analysis performed for TSCRN 210 was performed using this assumption and is, therefore, coaaistent with the asisting CR-3 licensing and design basis.

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U, S. Nuclear Regulatory Commission Attachment B 3F1197-40 Page 8

_NRC REQUEST NUMBER 4, filGli PRESSURE INJECTION 1he submittal (pg. 4) describes the methodsfor once-throagh steam generator (OTSG) cooling amt then describes ' defense-in-depth' contingencies. The discussion includes the efect of depressurizing the steam generators using the turbine bypass valves or the atmospheric dump ,

valves. Please verify that the cooling associated nith the depressurization of OTSG cooling is '

considered a defense-in-depth mechanism rather than being credited in the accident analysis because these are notfully qua!!fied components.

l FPC RESPONSE The accident analysis for SBLOCA does not credit an RCS cooldown using TBVs or ADVs, l but does rely upon OTSG cooling using the MSSVs until decay heat can be removed by ECCS injection alone. There are four MSSVs on each main steam line, for a total of 16 valves, i Each MSSV is safety related. EFW is relied upon to provide the source of feedwater to the OTSO. All of the components credited in the accident analysis are fully qualified. In certain .

SBLOCA scenarios. emergency feedwater would be supplied by the steam driven emergency feedwater pump, EFP-2, The operators are directed by. the EOPs to cycle ASV-5 and ASV 204 on low OTSG steam pressure in order to manage the operation of EFP 2. These components are also fully qualified.

RCS cooldown using the ADVs or TBVs is specified by the EOPs in accordance with the generic technical guidelines, liowever, this cooldcwn is associated with post LOCA plant recovery and is not required to satisfy 10CFR50.46 requirements.

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U. S. Nuclear Regulatory Commission Attachment B 3F1197-40 Page 9 NRC REQUEST NUMBER S, iblGil PRESSURE INJECTION Please emluate the increased risk associated uith the proposed plant and procedure changes including the new load management urategy that is being proposed. For comparison, assume the onsite electrical, the ERY, and HPl systems and their interconnections were adequatelj sized and no load management or reliance on ERY is necessary.

FPC RESPONSE The Technical Specification changes preposed by TSCRN 210, specifically those associated with restrictions for EFW and ECCS, result in a slight dccrease in core damage frequency of approximately 2x108 per year. This reduction in risk is associated with limitations on p' ant operation for a greater number of combinations of inoperable components.

The risk was evaluated based on the expected frequency of the initiating event, in this case, a SDLOCA concurrent with a LOOP, and the failure probabilities of the equipment and operators to respond. The occurrence of a SDLOCA concurrent with a LOOP and a single failure is already extremely low. Changes in procedures and new load management strategies addressing these remote combinations of events do not have an appreciable effect on such a substantially low risk.

The most dramatic impact on core damage risk is the addition of a dedicated diesel generator 4

to the auxiliary feedwater pump, FWP-7, which resulted in a decrease of 7.8 x 10 per year in the core damage frequency. Ilowever, FWP-7 is considered to be "defensa-in depth" and the design basis does not rely upon its use for mitigation of SBLOCAs.

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U. S. Nuclear Regulatory Commission Attachment B 3Fil97-40 Page 10 NRC REQUEST NUnfRER 6, filGil PRESSURE INJECTION Please describe the current LOCA analysis of record that uns submitted in Afay of 1996.

Verify that the changes in the plant and procedures are correctly modeled in that analysis and that the modeling (CRAl72) is consistent uith the code limitations and restrictions.

FPC RESPONSE The most limiting break sizes that were analyzed to support restart of CR 3 in 1996 were perforn:ed using an NRC-approved small break LOCA evaluation model (BAW-10154A).

These calculations were in compliance with the limitations and restrictions for CRAFT 2 filAW-10092A, Rev. 3) and TilETAl-ll (BAW-10094A, Rev. 3).

A brief description of the analyses that were performed to support plant startup in 1996 is provided h the following paragraphs. The results of all of the analyses and evaluations that were performed are summarized in Pfl Document 51-1245866-00, " Reevaluation of 11PI Requirements During SBLOCAs" (FPC calculation M96-0032).

During the evaluation of the llPI line pinch break transient for CR-3, it was concluded that additional evaluation of certain CLPD breaks assuming a loss of offsite power and a single failure resulting in the loss of one of the two emergency dit.sel generators (EDG) was nCCCssary.

By comparing the RCS behavior and time of the minimum core inventory for spectrum of CLPD break sizes, it was determined that the 0.07 to 0.20 ft2breaks would be most affected by the llPI How deficiency, with the 0.125 ft' case determined as the most limiting. RELAP5 analyses were used to confirm these engineering judgments, and the CRAFT 2-based EM was used to analyre the 0.10, 0.125, and 0.15 ft2 breaks. The 0.125 ft: break calculated the highest peak clad temperature (PCT) at 1859'F. By [[letter::3F0596-22, Informs NRC That FPC Completed New SBLOCA Analyses in Support of Efforts Re Improved HPI Instrumentation & Change as Stated in PCT in Accordance w/10CFR50.46 Requirements|letter dated May 22,1996]] (3F0596-22),

FPC reported the PCT in accordance with 10 CFR 50.46 requirements.

The LOCA analyses of record are performed with loss of offsite power and a most limiting single failure that tesults in the loss of one train of pumped ECCS injection flow, leaving both core Good tanks, one llPI pump and one LPI pump for mitigation of the transient. The analyses also make the assump:lon that EFW Dow to the OTSGs would be available throaghout the transient. The changes that are being made to the plant and to the operating procedures are to ensure that the plant viill operate within the bounds of the LOCA analyses.

Evaluations and analyses of the llPI now delivery to the RCS have been performed. These calculations, coupled with the procedure changes and plant modifications, verify that the peak fuel clad temperatures that were reported for the 1996 analyses remain bounding.

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I U. S. Nuclear Regulatory Co'nmission Attachment B i 3F1197-40 Page11 NRC REQUEST NUMRER 7, filGil PRESSURE INJECTION ,

Please clar(fy Action A of TS LCO 3.5.2 uhich requires that if one or more ECCS trains are Inoperable and *at least 100% of the ECCSflow equivalent to a single operable ECCS train available. " Because you run nith the discharge of the llPI cmss connected and it appears that i four offour injection paths are ainays needed. A definition of a " train" of flPI uvuld be  ;

helpful, is a " train" one llPI pump and tuo, three, or four Irtfection lines or is it the e equipment associated uith a particular safety bus?  :

FPC RESPONSE ,

in the normal system configuration, a " train" of 11PI is a single llPI pump and its associated ,

flow path from the BWST to the pump discharge header. With the discharge header cross-connect valves open, the injection lines cannot be associated with either train. Two of the

injection line valves are normally powered from Engineered Safeguards Bus A and two from ,

! Bus B. Ilowever, any of the four valves can be powered from either bus by operator action from the Control Room.

With the llP! system fully operable, the system can tolerate any single active failure for any design basis sccident, including a rupture of an llPI Injection line resulting in one pump injecting through three injection lines (for failure of a pump or associated flow path), or two i pumps injecting through two injection lines (for failure of an injection line valve).

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3F1197-40 I

NRC REOUEST NUMHER 8. filGli PRESNURE INJECTION is the Inoperability of an injection line (i.e., an inoperable in)cction line isolation mlve) considered thefailure of one .' rain or both trains? The 1S bases (pg. H 3.5-13) state that " flow is required through a minimum of three injection legs in the event of a postulated break in the HP1 injection piping." If this is the case, how is thefailure of one of the injection line isolation mlves bounded by accident analysis (for a llP1line break, uhen one of thefow injection lines is broken; are three of the remaining three required to meet the accident analysis)?

FPC HESPONSE Failure of an injection line isolation valve would be considered a failure of one ' train"ofIIPI only since at least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train would still be available. In the event of an llPI line break with r. failure of one of the injection valves on another line to open, two intact lines with two llPI pumps would remain to mitigate the accident.

This has been shown analytically to be acceptab!c.

The clarification of the Bases to address the possiWity of two llPI line operation with a failed close IIPI discharge valve as the single failure will be included in the revised submittal scheduled to be issued on November 21,1997.

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t U. S. Nuclear Regulatory Commission Attachment B l 3Fil97 40 Page 1.'2 NRC REQUEST NUMBER 9, filGil PRESS!!RE INJECTION Are there any single failures that could cause tuo of the four injection lines (or isolation

)

sulves) to be inoperable?

FPC RESPONSE ,

There are no single failures that would cause the loss of 2 of the 4 IIPl line injection valves.

Ilowever, two llPI valves would be closed initially with a failure of either the "A" or "B" r

. train power supply. Ilowever, the control room operators would manually align the affected ,

. valves to the alternate power supply and open them in accordance with EOP-03, Step 3.3.

This operator action is identified in TSCRN 210. Attachment F. Table 3A, OA # 3. In a letter dated May 29,1979 (3N0579-08), the NRC concluded that the operator action is acceptable.

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O U. S. Nuclear Regulatory Commission Attachment B 3F1197-40 Page 14 NRC REQUEST NUMBER 10, filGil PRESSURE INJECTION Operator Action #4 [lsolate reactor coolant pump (RCP) seal injection], in Table 3A of Attachment D to the September 25,1997, submittal has not been approved by the NRC. There is not sufficient information in the submittal to make a safety determination. A description of how RCP seal cooling uill be maintained after injection is isolated and under uhat circumstances it uvuld be lost should be provided. Additionally, the pump vendor recommendations should also support isolation of the seal injection and this should be described in detail.

FPC RESPONSE Following a LOCA that results in a loss of adequate subcooling margin, the RCPs are manually tripped. RCP seal injection is also manually isolated. In addition, operators manually initiate reactor building isolation and cooling (RBIC) which isolates RCP controlled bleed-off (Scal return). Seal area cooling is maintained provided the service water system expansion tank level remains above the interlock setpoint.

The RCP pump vendor states that the pump and seal cartridge are designed to operate continuously without seal injection flow. If a loss of seal injection and seal area cooling occurs, then the manufacturer requires that the RCPs be tripped and the controlled bleed-off isolated.

Procedures provide the necessary guidance [OP-302) to trip the RCP(s) if a sustained loss of seal injection and seal area cooling occurs. EOPs provide the required guidance to manage RCP services and operation.

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U. S. Nuclear Regulatory Commission Attachment B 3Fil97-40 Page 15 NRC REQUEST N_ UMBER 11, filGil PRESSURE INJECTION It is not clearfrom reading the submittal that a post-SULOCA situation is precluded ta uhich the containment conditions cause an initiation of containment spray, uhich, combined uith ECCS injection, could drain the borated unter storage tank to the snisch over point in about 45 minutes even uith the loss of one diest!. With the needfor chillers (at one hour?), the need for low pressure itdection to provide HPI suction from the sump, the needfor the motor-driven EFP (EFP 1) (for certain scenarios), and other loads (such as valve position changes), it uvuld appear that the operadng diesel could be overloaded. Please address the norst case postulated scenario in terms of the time-dependent diesel loading, identifying uhich loading actions are automatic and uhich are operator actions. It seems that the timing may be important; reflect timing uncertainties in the assessment.

FPC RESPONSE The time to drain down the BWST for those break sizes requiring OTSG cooling is discussed in Attachment D of TSCRN 210 (see pages 23 through 26). In summary, for those SBLOCA scenarios addressed by TSCRif 210, the BWST inventory would be available for more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This inventory is sufficient to ensure the required OTSG cooling prior to securing the motor driven EFW pump to load the control complex chillers or LPI pumps for ECCS recirculation from the reactor building sump.

The minimum borated water storage tank (BWST) inventory available for pump injection is 263,536 gallons. An average flow rate of 5836 gpm is required to deplete this volume within 45 minutes. This is ,sentially equal to the run out now rates from one train of ECCS equipment including high pressure injection, low pressuie injection, and reactor building spray The reactor coolant system pressure must be less than approximately 100 psia or less for ilPI and LPI to inject at these Dow rates. To achieve an RCS pressure of 100 psia or less, the break sizes would be large encogh that ECCS injection alone, without OTSG cooling, is sufficient to remove the stored energy and core decay heat.

FPC has determiaed that the operating EDG(s) would not be overloaded during the SBLOCA scenarios addressed by TSCRN 210. Two of these accident scenarios represented a challenge to EDG loading: Loss of Battery B (LOBB) and Loss of EFP-2.

During the SBLOCA scenario involving a LOBB, the "A" train EDG would provide onsite power, and EFP-1 and EFP-2 would start and snare Dow. The worst case steady state automatically connected loading for these conditions is 3054 kW. Approximately 10 to 30 minutes into the accident, the operators would manually load the Control Complex Emergency Duty Supply fan and the Control Complex return air and EFIC room fans. These fr.ns would raise the worst case loading to 3134 kW. Within at least 80 minutes, the operators would align EFP-2 to the "A" train EFW Gow path and secure EFP-1. The operator would then

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i i U. S. Nuclear Regulatory Commission Attachment B  :

3Fil97-40 Page 16 manually apply the load of the Control Complex chiller and pump, the spent fuel pump and its j air handling fan, and LPI to establish ECCS recirculation injection from the reactor building sump. These subsequent loads would increase the total load to 3173 kW after securing EFP-1.

There is sufficient margin to 3400 kW at the upper limit of the 200-hour rating to apply short -

duration loads of any MOVs.  ;

During the SBLOCA scenario involving a loss of EFP-2, EFP-1 would start and provide OTSG cooling, and both "A" and "B" EDGs would provide onsite power to both ES equipment trains. The shared flow between both trains of Nuclear Services Closed Cycle Cooling Water (SW) and Nuclear Services Seawater (RW) systems causes a reduction in loading on the "A" train EDG which more than offsets the loading increase from the increase ,

in EFP-1 flow due to loss of EFP-2. The worst case steady case loading in these conditions is 3040 kW. Similar to the LOBB scenario, the operators would load the Control Complex cooling fans, and "B" train chiller and pump. After more than two hours but prior to draining the BWST, the operator would load the LPI pumps to establish ECCS recirculation injection from the reactor building sump. At this time, EFW flow would be reduced to approximately 840 gpm, SW and RW flow would be shared between both trains, and both trains of HPl providing injection at 600 gpm (pump run-out). The total loading on the "A" train EDG would be 3221 kW. If the operator would secure the "A train SW and RW pumps, the loading would be reduced to 2339 kW. Additionally, there is sufficient margin to 3400 kW at the upper limit of the 200-hour rating to apply short duration loads of any MOVs.

Table 1 provides a load profile for the "A" train EDG The profile demonstrates that the EDCs would not experience a steady state loading exceeding the EDG service ratings as <

revised by TSCRN 210. The profile shows various load spikes due to the starting of moters.

These loads are less than the manufacturer limits of 3910 kW as described in the Bases of Technical Specification 3.8.1 as proposed by TSCRN 210.

Table 2 provides a listing of the automatically and manually connected loads to the "A" train EDG. The equipment loads are based on a steam line break, which is calculated to be the result in the worst case loads, in summary, the modifications, Technical Specifications changes, and operator actions proposed by TSCRN 210 will ensure that the EDGs are not overloaded for a SBLOCA scenario.

1 J

. , . . _ , . . .,y ._ y- -- , _ _ , - , - - - , , , . , ,, ., ,y w. , , ,, ,-w,-.. ,. , %,s.,-

EGDG-1 A composite auto connected loading profile resulting from various accident scenarios for first 4.5 minutes.

4500 4000 337; 3743 33_1 12id 3233

$ 3# 279 ,

\-

=,

.a 25 m ,,gn I

T o

)

-134

@2000

= ,

.e}I 1500 -

I 1000  ;

500 300 100 150 200 250 >

0 50 Time in seconds from start of accident Figure 1, Sheet I of 3 e i

EGDG-1 A composite auto plus manual loading profile resulting from various accident scenarios.4.5 minutes to I hr.

3350 3300 -33 3250

4

.5 y 3200

=5 5

I 3u4(10NMinutesjC5HroTC6fnplex andEFIC Room tans HIRTed d 3150 O

O .

c2 3100 3054 l

3050 3000 70 20 30 40 50 60 0 10 Time in minutes from start of accident Figure 1, Sheet 2 of 3 t

EGDG-1 A composite loading profile resulting from various accident scenarios.1 nr to 8 hr.

3300 3173(SFPI A,AHF8A,Ht. Trace added) 3200 -

3134 (Prior to securing EFP-1) 30S9(DHP-1A added) 3I00 - -

3 3000

4

.5 en

.E 2900 -

'E 22 : Chiller & Pomp added) f y 2S00 -

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O uJ 2700 -

i 2588(EFP -1 tripped) 2500 -

2400 8 9 3 4 5 6 7 0 1 2 Time in hours from start of accident Figure 1, Sheet 3 of 3 6

I

,'s TABl.E 1

+ CALC E-91-0026, REV.3, ATT.1; FILENAME:EGASS.WK3 PAGE 2 OF 9 EMERGENCY DIESEL GENERATOR "A" AUTO & MANUALLY CONNECTED LOADS guto Connected loads on Emeric l J cyyletel Generator 'A'mSjam Line llreak inside_Cgnji m_e_&

i Equipment 1 Flow opml BHP KW l Test KW twmeses EGAT@tP10A!iFi BSP-1A 1600 193.4 199.1 1,2 SWP-1A 9400 496.4 493.8 1,2 MUP-1B 600 693.2 663.8 1,2 RWP-2A 17700 550.9 550.9 1,3 RWP-3A 11000 186.5 197 1,2 EFP-1 525 546.3 532.5 1,2 DCP-1A 3800I 72.1 77.8 1,2 AHF-1A_ --- 60.4 60.4 1 INVERTERS _

--- 57.2 57.2 1 BATTERY CHARGERS --- 19.6 19.6 1 ES MCC 3A1 MISCEll.ANEOUS LOADS --- 72.9 72.8 1 ES MCC 3A2 MISCEll.ANEOUS LOADS --- 54.7 54.7 1 ES._M_CC 3A3 MISCELLANEOUS LOADS

--- 2.4 2.4 1 ES MCC 3AB MISCELLANEOUS LOADS --- 37.3 37.2 1 480V SWGR CT/PT BURDEN & XFMR FANS --- 2.6 2.6 1 4.16 KV SWGR CT/PT BURDEN --- 1.6 1.6 1 TRANSFORMER & EDG "A" CABLE LOSSES --- 6.3 6.5 lEDG "A"_ STEADY STATE AUTO CONNECTED LOADS l 3053.8 l 3029.9 l liSSIINTIAL.hMN_UAhlJAITL]IiD LOADS APPLLcARLI;_Lo_tip_G 'A' PRIGILTO TRIPPING EFP-1 kmne EGAMANIIGAMN1BH EFIC CONTROL COMPLEX FAN (AHF-54A) 12.5 12.5 1 CONT COMP EMER DUTY SUPPLY FAN (AHF-18A) 49.7 49.7 1 CONTROL COMPLEX RETURN AIR FAN (AHF-19A) 17.5 17.5 1 hMN_U.A1.LY At[1HiDJ OADS APPLICA14E TOjiDG 'A' AITER TRIPfjNG EFP-1 Sune T GAMAMIGAMN MtH CONTR_OL COMPLEX WATER CHILLER (CHHE-1 A) 195.5 195f1 CHILLED WATER SUPPLY PUMP (CHP-1 A) 18.1 18.1 1 DE. CAY HEAT PUMP DHP-1 A Cc0 3300 GPM 283.9 272.6 1,2 SPENT FUEL PUMP (SFP-1 A) 41.3 41.3 1 S_FP-1 A AIR HANDLING FAN AHF-8A 6.8 6.8 1

, HEAT TRACING 36.4 36.4 1

1. CABLE LOSSES FOR THESE LOADS ARE INCLUDED IN THEIR LOADING VALUES

2. TEST KW VALUES ARE BASED ON IN-PLANT KW TESTING OF THE PUMPS. BHP KW VALUES ARE BASED ON BHP VALUES TAKEN FROM CALC M-96-0069,REV.0 3.KW TESTING DATA FOR RWP-2A IS NOT AVAll.ABLE. THEREFORE KW BASED ON BHP IS BEING USED IN PLACE OF KW BASED ON FIELD TESTING.

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FLORIDA POWER CORPORATION h CRYSTAL RIVER UNIT 3 3 DOCKET NUMBER 50-302/ LICENSE NUMBER DPR-72 I

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$ ATTACHMENT C to 3F1197-40

<g LIST OF COMMITMENTS t

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e 0

. .? ,

s.

ATTACIIMENT C LIST OF COMMITMENTS ,

The fo: lowing table identifies those actions committed to by Florida Power Corporation in this document. Any other actions discussed in the submittal represent intended or planned actions by Florida Power Corporation. They are described 13 :he NRC for the NRC's information and are not regulatory commitments. Please notify the Manager, Nuclear 'lcensing of any questions regarding this document or any associated regulatory commitments.

ID Number Committaent Due Date 3F1197-40-1 A revised request will be submitted by November 21, November 21,1997 1997 to address the following: .

. the AOT for the "A" train chiller and pump, CHHE-1 A and CHP-1 A, will be reduced from 30

?.. days to 7 days since these components serve to

f. cool more than the control room.

• the AOT for the 'B"trein chiller and pump, CHHB-1B and CHP-1B, will be reduced from 30 days to 72-hour AOT for the remainder of Cycle 11.

3F1197-40-2 The Basis will be revised to delete any reference to November 21,1997 the penetration cooling heat exchangers. The I Background of the Bases will also be clarified to refer to a singular heat exchanger. The term

' Operable"will also be added to LCO 3.7.18.b.

3F1197-40-3 FPC will expand the applicability of proposed November 21,1997 Technical Specification 3.7.18, Control Complex Cooling, to incluoe 'During movement ofirradiated fuel assemblies."

3F1197-40-4 The clarification of the Bases to address the November 21,1997 possibility of two HPI line operation with a failed close HPI discharge valve as the single failure will included in the resised submittal scheduled to be issued on November 21,1997.

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FLORIDA POWER CORPORATION CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302/ LICENSE NUMBER DPR-72 ATTACHMENT D to 3F1197-40 RESPONSE TO NRC RAI LIST OF ACRONYMS

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'cf ATTACHMENT D RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION TECIINICAL SPECf FICATION CII ANGE REQUEST NOTICE 210 LIST OF ACRONYMS ADV Atmospheric Dump Valve AOT Allowed Outage Time ASV Auxiliary Steam Valve BWST Borated Water Storage Tank CCCS Control Complex Cooling System CilllE Chilled Water lleat Exchanger CilP Chilled Water Pump CLPD- Cold Leg Pump Discharge CR-3 Crystal River Unit 3 ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EFIC Emergency Feedwater Initiation and Control EFP Emergency Feedwater Pump EFW Emergency Feedwater EOP Emergency Operating Procedure FPC Florida Power Corporation FSAR Final Safety Analysis Report FTl Framatome Technologies incorporated FWP Feedwater Pump GPM gallons per minute llP1 liigh Pressure injection LCO Limiting Condition for Operation LOBA Loss of Battery "A" LOBB Loss of Battery "B" LOCA Loss of Coolant Accident LPI Low Pressure Injection MOV Motor Operated Valve MSSV 1 fain Steam Safety Valve NRR Nuclear Reactor Regulation OTSG Once Through Steam Generator PSIA Pounds per Square Inch Absolute PSIG Pounds per Square Inch Gauge RAI Request for Additional Information RBIC Reactor Building Isolation and Cooling RCP Reactor Coolant Pump RCS Acactor Coo! ant System ,

RW Raw Water (Nuclear Services and Decay Heat Seawater Systems)

SELOCA Small Break Loss of Coolant Accident TBV Turbine Bypass Valve TSCRN Technical Specification Change Request Notice

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