JPN-96-038, Responds to 960614 RAI Re Proposed Tech Spec Change Revision to Allow out-of-service Times for Single Inoperable EDGs to Accommodate on-line Maint of EDGs

Responds to 960614 RAI Re Proposed Tech Spec Change Revision to Allow out-of-service Times for Single Inoperable EDGs to Accommodate on-line Maint of EDGs

ML20117M951
Person / Time
Site:	FitzPatrick
Issue date:	09/12/1996
From:	William Cahill POWER AUTHORITY OF THE STATE OF NEW YORK (NEW YORK
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
JPN-96-038, JPN-96-38, NUDOCS 9609180254
Download: ML20117M951 (24)

Text

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1 I 123 Main Street White Piams, New York 10601 l 914-681 6840

. 914-207 3309 (FAX)

William J. Cahill, Jr.

& Authority ch.er"vciee<oracer September 12,1996 JPN-96-038 United States Nuclear Regulatory Commission ATTN: Document Control Desk Mail Station P1-137 Washington, DC 20555

Subject:

James A. FitzPatrick Nuclear Power Plant Docket No. 50-333 ,

Response to NRC Request For Additional Information Regarding Proposed Technical Specification Chanae (JPTS-95-OO7)

References:

1. NYPA letter, W. J. Cahill, Jr. to USNRC Document Contro! Desk, (JPN-96-004) dated January 25,1996 l 2. NYPA letter, W. J. Cahill, Jr. to USNRC Document Control Desk, (JPN-96-018) dated April 26,1996

Dear Sir:

In Reference 1, the Authority submitted a proposed Technical Specification Change Request (JPTS-95-007) for James A. FitzPatrick Nuclear Power Plant. This technical specification proposes to revise allowed out-of-service times for single inoperable Emergency Diesel Generators (EDGs) to accommodate on-line maintenance of the EDGs.

In Reference 2, the Authority provided a response to a request for additional information (RAI). On June 14,1996, the NRC asked additional questions. In the enclosure to this letter each question is restated followed by our response. These responses were '

discussed preliminarily during a conference call with the NRC staff on June 17,1996.

We have reviewed Reference 2 and the enclosure to this letter and have concluded that

, this response does not change the proposed amendment or rnodify any of the conclusions

! stated in the Significant Hazards Consideration Evaluation previously submitted in Reference 1.

l 9609180254 960912 PDR ADOCK 05000333 /

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l Should you have any questions regarding this response, please contact Mr. Art Zaremba.

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t Very truly yours, I

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William ahill, J .

Chief Nuclear Officer cc: JPTS-95-007 File U.S. Nuclear Regulatory Commission l- 475 Allendale Road King of Prussia, PA 19406 Office of the Resident inspector U.S. Nuclear Regulatory Commission P.O. Box 136 Lycoming, NY 13093 l Ms. Karen Cotton, Acting Project Manager i Project Directorate 1-1 Division of Reactor Projects -l/ll U.S. Nuclear Regulatory Commission Mail Stop 14 B2 Washington, DC 20555 i

l Mr. F. William Valentio, President New York State Energy, Research and Development Authority 2 Rockefeller Plaza Albany, NY 12223-1253 1

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Attachment to JPN-96-038 Resoonse to Reauest for Additional Information Related to Emeraency Diesel Generator Technical Soecification Chanae (TAC No. M94611)

Question 1: i Probabilisitic safety assessment (PSA or PRA) l l

Your IPE, submitted on September 13,1991, stated that both EDGs in one EDG train must function together during a LOCA with a LOOP. Can any one EDG mitigate SBO? What are success criteria for the station blackout (SBO) condition at FitzPatrick? Is this modeled in the PRA? Please explain.

Response 1:

As noted in Section 6 of the IPE, Unique Plant Safety Features, any one EDG can mitigate the effects of SBO in the absence of a LOCA--plant shutdown can be achieved with one EDG. This was modeled in the IPE.

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l l Question 2:

Do you have a cross-tie capability between the two EDG trains? If so, please explain what it does to your risk profile.

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There is no EDG output cross-tie capability at FitzPatrick between the two EDG trains. '

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l Question 3:

What review of the PRA has been made to ensure that the PRA represents the as- I built, as-operated plant, and contains the fine structure (resolution) necessary to l evaluate the proposed TS requirements? Were any changes made to the PRA due to such reviews?

Response 3:

Prior to its submission, the IPE was reviewed by plant staff and an outside team of experts (details provided in response to question 8). Subsequently, it went through a Step 2 NRC review by NRC staff and contractors. No change to the submitted i model was required as a result of the latter.

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The level of detail within the IPE analysis is more than sufficient to support this request, in particular, the causes of failure or unavailability of individual EDGs and of their support systems were modeled. l l

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Technical Soecification Chance (TAC No. M94611)

Question 4: l l

Your current PRA may be different from your IPE. Explain the major differences.

Among those differences,is there anything related to LOOP /SBO sequences?

Response 4:

The IPE report is to be updated in the next year. Among the changes to be made to the IPE are the use of an updated data base, the revision of internal flooding analysis, and changes to fault tree models made to reflect modifications made l subsequent to the submission of the initial IPE. These last include changes made in j response to recommendations arising out of the original IPE: they are listed in the final section of this reply. Of particular importance in diminishing the risk associated with SBO sequences is a modification to the fire protection system to provide EDG jacket cooling water directly through the cross tie of the ESW System. However, the models used in conjunction with this current request do not reflect these changes--they contained the PRA models for the plant previously audited and approved by the NRC.

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Question 5:

Please provide the minimal cut set truncation cutoff used to quantify the plant CDF changes. In particular, indicate what efforts were made to avoid underestimation when the impact calculated was negligible or non-existent.

Response 5:

l A conservative dimensionless truncation value of 10*, excluding the initiating event frequency and human recovery analysis, was used in accident sequence quantification. This value ensures that sequences with a probability of at least ,

about three orders of magnitude below the reported core damage frequency were - l examined in the IPE and this present request.

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Question 6:

Provide a discussion of the loss of offsite power (LOOP) events at your facility.

Response 6:

A loss of offsite power event occurred at FitzPatrick on October 31,1988. At the time, the plant was in the 65th day of a refueling outage, with a variety of equipment out of service for testing and maintenance. The plant was receiving >

power over the 115-kV Lighthouse Hill line, the other 115-kV line being out of service for maintenance at its remote terminal. A momentary interruption occurred on the Lighthouse Hillline, probably because of transmission line problems induced by high winds. With off-site power unavailable for 30 seconds, the EDGs started automatically and powered the vital buses. With the vital buses energized, initial

- efforts were directed toward other systems. The vital buses were re-energized with.

off-site power about one hour after the momentary interruption.

Because the plant was in a configuration that is not permitted during normal operation, this event was characterized a Category IV event. Such an event is defined in EPRI TR-106306s, Losses of Off-Site Power at U.S. Nuclear Power Plants-Through 1995, "No off-site power available during cold shutdown because of special maintenance conditions that do not occur during or immediately following operation".

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' Resnonse to Reauest for Adcitional Information Related to Emeraencv Diesel Generator I Technical Soecification Chanae (TAC No. M94611)

Question 7: l l

Explain what severe weather conditions you are expecting at your facility and how i this was addressed in the PRA.

Response 7:

Severe weather in the form of high winds, tornadoes, high lake levels, heavy rainfall and lake icing was addressed in the FitzPatrick IPEEE. A report on this IPEEE was i submitted to the NRC on June 26,1996.

The methodologies employed in the IPEEE to evaluate the impact of severe weather such as high winds, tornadoes, and external floods were the iterative methodologies suggested by NUREG-1407. These methodologies entailed identifying significant changes to the plant and to the characterization of severe l weather events and the determination of their impact on plant safety. For example, in evaluating high winds and tomadoes, recent data from the National Weather Service was evaluated and the issues raised in NRC Information Notice 93-53, relating to lessons learned from the effects of Hurricane Andrew, were addressed.

A similar review was conducted to identify any significant changes to the characterization of extemal flooding or changes to the plant that might alter its susceptibility to external flooding. In utilizing recent National Weather Service probable maximum precipitation data and other recent data on lake levels, this review ensured that Gl 103, " Design for Probable Maximum Precipitation" and the response of the Authority to this were properly addressed.

In addition, an analysis was performed to determine the likelihood of a tornado-induced station blackout event occurring because of a loss of offsite power and damage to the EDG ventilation systems ductwork. Event trees were developed to describe possible sequences of events that may follow each tornado initiator in developing these event trees, the objective was to define the most probable combinations of successful and unsuccessful responses to the initiating tornado events. The analysis tracked individual successes and failures until a final core state was determined. The probabilities of final core states were summed to yield the frequency of core damage resulting from tornado induced station blackout events. The analysis demonstrated that a scenario in which a tornado strikes both the 115-kV and 345-kV switchyards and the EDG building makes a negligible (2.94 x 10 4/ year) contribution to the plant core damage frequency. Given that the IPE has reported a frequency of 1.75 x 10-e per year for station blackout events leading to core damage, the Authority concluded that such tornadoes do not result in any significant change in the internal core damage frequency. A copy of this analysis is included as Attachment A.

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• Attachment to JPN-96-038 Resoonse to Reauest for Additional Information Related to Emeraency Diesel Generator Technical Soecification Chanae (TAC No. M94611) l It should also be noted that, as a result of the analysis, a note has been included in the abnormal operating procedure for hurricanes, tornadoes and high winds (AOP-

13) warning that low pressures associated with these events could threaten the integrity of the air intake duct work supplying the EDG room ventilation system and detailing actions that would ensure adequate ventilation of the switchgear room and j an adequate supply of combustion air to the EDGs should the duct work be l damaged. These actions require that the switchgear room doors be opened or that l

an opening be created in the damaged duct work.

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! Question 8:

Please describe the peer reviews performed on your current PRA. Indicate which reviews were performed in-house versus those performed by outside consultants.

Summarize their overall conclusions and insights.

Response 8:

4 The methodology, data, results, and conclusions of the IPE were reviewed at several levels:

NYPA Systems Analysis Group staff and consultants examined each other's work i at each stage of development. These reviews focused on the accuracy and consistency within their areas of expertise.

4 NYPA Corporate staff from the nuclear licensing, operations and maintenance, and engineering departments were kept informed of the progress made; they reviewed the methodology and guidelines document, the system work packages and accident i sequences.

4 Cognizant departments at FitzPatrick including licensing, operations, maintenance, training, instrumentation and control, planning, and technical services reviewed the system work packages and accident sequences at two formal site reviews. They also reviewed the insights and recommendations derived from the study at a third j formal review.

a A formalin-house independent review of the draft IPE report was conducted by a review team comprising:

l a Technical advisor to the Executive Vice President, Nuclear Generation (Chairman of the Review Committee) e Manager, Nuclear Safety Evaluation: Chairman, Safety Review Committee (SRC) l e Director, Quality Assurance a Senior Nuclear Licensing Engineer, FitzPatrick i

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Finally, three outside experts also made a detailed review of a draft of the final IPE report. The independent review team and outside experts concluded that the study had been performed in a logical, reasonable, and thorough manner. The comments made by the internal review team and outside experts largely pertained to details of the analysis and the interpretation and depiction of systems and sequences of events. Suggestions for improvements were, for the most part, incorporated into the report.

A detailed description of the comments made by the independent review team and outside experts has been provided by the Authority to the NRC in response to a request for additional information. A copy of this response (item 1 in Letter to NRC from R. A. Beedle, Response to Request for Additional Information Regarding Individual Plant Examination, James A. FitzPatrick Nuclear Power Plant, JPN 046, September 1,1992) is included as Attachment B.

In addition to the above reviews of the IPE, NRC staff performed a more detailed

" Step 2" review. The NRC staff initiated contracts with Science & Engineering Associates, Inc. to audit level 1 system models: Scientech Inc. and Energy Research Inc. to audit level 2 accident progression and containment performance models; and Concord Associates to audit human reliability models. On January 27-29,1993, the review team and contractors made a site visit and walked through plant areas important from a PRA perspective. Plant personnel and analysts involved in the technical analysis were interviewed, " tier 2" information (selected fauh trees, notebooks, and associated calculations) were audited, and the training simulator was visited. The contractors' reviews and their findings and conclusions '

are documented in the following Technical Evaluation Reports (TERs):

James A. Fit 7 Patrick Step-2 IPE: Front End Audit [ SEA 93-553-05-A:1];  :

Step 2 Review J.A. FitzPatrick Nuclear Plant IPE Submittal Human Reliability l Analysis [CA/TR-93-19-05]; j t

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-Technical Evaluation Report of the J.A. FitzPatrick Individual Plant i Examination (IPE) Back-end Submittal [ERl/NRC 93-102). 1 An NRC Staff SER closing the review was issued on May 9,1994. I

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Resoonse to Reauest for Additional Information Related to Emeraency Diesel Generator l Technical Specification Chanae (TAC No. M94611) I Question 9:

Quantitative results Please provide the following calculations and quantitative PRA results due to the AOT extension. If your current PRA is different from the IPE, provide two separate results for the IPE and the current PRA:

(1) Change in average CDF (Am(CDF)): j m(CDF) = average CDF (per year) m2(CDF) = The conditional rn(CDF) with the proposed 14 day AOT in place mi(CDF) = The m(CDF) with the current AOT in place Therefore, Am(CDF) '= m2(CDF) - m (CDF) 3 Response 9:

i Average point estimate CDF, m(CDF)

= 1.50 x 10-e / year.

Conditional point estimate CDF with proposed 14 day AOT in place , m2(CDF) ,

= 1.49 x 104 / year.

Average point estimate CDF with current AOT in place , mi(CDF)

= 1.47 x 10-8 / year.

.. . Am(CDF) = m2(CDF) - mi(CDF)

= 2.00 x 10 e / year.

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Question 10:

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Change in instantaneous CDF (ACDF,):

l CDF,(2) = The conditional CDF when the plant is in the AOT CDF(1) = The base CDF with On EDG AOT at all I = a particular AOT configuration with an EDG unavailable Therefore, ACDF, = CDF,(2) - CDF(1)

Response 10:

Conditional CDF when the plant is in the AOT, CDF,(2) = 1.58 x 10'*/ year.

The base CDF with no EDG AOT at all, CDF(1) = 9.55 x 10-7/ year.

l ACDF, = CDF,(2) - CDF(1) = 1.58 x 10'*- 9.55 x 10'7 = 6.25 x 10~7/ year, j l

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Question 11:

Change in conditional core damage probability (ACCDP):

CCDP(2) = The CCDP with the proposed 14 day AOT CCDP(1) = The CCDP with the current 7 day AOT Therefore, ACCDP = CCDP(2) - CCDP(1)

Response 11:

CCDP(2) = 14-day CCDP ='(1.58 x 10-e/365) x 14 = 6.06 x 10~8 CCDP(1). = 7 day CCDP = (1.58 x 10'/365) x 7 = 3.03 x 10~'

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A CCDP = CCDP(2) - CCDP(1) = 3.03 x 10-e I

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Question 12:

Change in large early release frequency (ALERF)

LERF(2) = LERF with proposed AOT in place LERF(1) = LERF with current AOT in place Therefore, ALERF = LERF(2) - LERF(1)

Response 12:

The FitzPatrick IPE estimated that the conditional large release probability is 0.41 for all core damage events. Based on the CDF o't 1.47 x 10e/ year, the large release frequency is 6.03 x 10-7/ year.

Given a conditional point estimate CDF, with the proposed 14 day AOT in place, of 1.49 x 10-e / year, the large release frequency will be 6.11 x 10-7 / year. Therefore, the change in large release frequency is equal to [6.11 x 10'7 / year - 6.03 x 10-7

/yearl = 8 x 104/ year.

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Question 13:

What are the projected average corrective maintenance and preventive maintenance downtimes for EDGs used in your calculations? Explain how they are obtained.

Have you performed any sensitivity analyses on your CM and PM downtimes that affect the risk results in the previous question? If so, please discuss insights gleaned from the study.

Response 13:

Discussions between FitzPatrick EDG system engineer and FitzPatrick planning and scheduling personnel on the maximum time required for EDG corrective and preventative maintenance have concluded that tha maximum maintenance outage period required for an EDG is 8 days. FitzPatrici Administrative Procedure AP-05.13 require maximum outage times not to exceed 60 percent of a total LCO AOT. For an 8 day maintenance period, this impaies an LCO period of approximately 14 days.

The conditional core damage probability CCDPs for AOTs of 7 to 14 days have been computed assuming only one EDG is out of service (CDF of 1.58 x 10 4/ year).

The values are presented below:

i Outaae Period (days) CCDP

7 3.03 x 10-8 8 3.46 x 10-8 9 3.90 x 10-8 l I 10 4.33 x 10-8 11 4.76 x 10-8 12 5.19 x 10*

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Question 14:

Have you performed any sensitivity analysis for this requested AOT change? If so, discuss how your results ensure the PRA results in your application are robust and away from a " cliff" or sudden increase in the risk profile.

Response 14:

A simple screening sensitivity analysis was performed. This analysis entailed taking multiples of the 0.02 anticipated EDG maintenance unavailability (ie, unavailabilities of 0.04,0.06, and 0.08) and computing the corresponding CDF on the master cutset equation. The results are presented below:

Maintenance Unavailability for All EDGs CDF (/ year) 0.04 1.51 x 10'"

0.06 1.54 x 10-8 0.08 1.57 x 104 The relatively small change in CDF for large changes in maintenance unavailability is due to EDG redundancy at FitzPatrick and to the dominance of loss of offsite power events with subsequent failure of emergency service water as the cause of core damage. The vulnerability with respect to emergency service water has, however, been dramatically reduced by the use of the fire water cross-tie to EDG jacket coolers.

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Question 15:

(B) Given the AOT plant configuration, what does your PRA indicate are the other risk-significant systems? Is he significance the same for each EDG, or EDG combination? Please explain the results.

Response 15:

In the proposed AOT configuration, a failure of the emergency service water (ESW) system poses a potential vulnerability to EDG operation as it did in the original configuration. However, as a result of the iPE, modifications have been completed to allow fire water to be used for EDG jacket cooling and thus reduce the contribution from the loss of ESW to EDG operation.

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Question 16:

For the systems you identified in the previous question, how would you ensure that no risk-significant plant equipment outage configurations would not occur while the plant is subject to the LCO proposed for modification? Is the bases for this i assurance reflected ;.7 your procedures or TS7 Response 16:

As stated in Section Ill.3 of our proposed TS amendment (Reference 1), the Authority will verify that the required systems, subsystems, trains, components,  ;

and devices that are required to mitigate the consequences of an accident are l available and operable before removing an EDG for extended preventive maintenance. The bases for this assurance is reflected in our administrative procedures governing control of maintenance and compliance with TS LCO  !

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! Question 17:

l l Have you thoroughly reviewed your TS to see if there are needs for any other changes to your TS or TS bases (in addition to the TS amendment items you are currently requesting) due to your request of EDG extension from 7 to 14 days?

l Please identify any TS changes made to ensure that the plant will not enter any risk-significant plant configuration while in the AOT.

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We have thoroughly reviewed the TS and have concluded no other TS changes are necessary, i

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Question 18:

(C) Are you capable of performing a "real-time" assessment of the overall impact on safety functions of related TS activities before conducting maintenance activities including removal of any equipment from service? I Please explain how this tool, or other processes, will be used to ensure that risk-significant plant configurations will not be entered during the AOT? l Response 18:

Although the Maintenance Rule requires assessment of risk when performing maintenance and testing activities under paragraph (a)(3), a "real time" assessment 4 is not required. Nevertheless, FitzPatrick has recently approved and is now implementing a change to our work control process in which risk assessments will be performed as a matter of routine for activities during power operation that are i not already addressed by our existing procedure for LCO rnaintenance.

This risk assessment process is integral to our procedure for work control. It considers probabilistic factors based on pre-analyzed configurations consistent with our 13 week rolling system schedule in developing weekly schedules.

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Question 19:

Explain how you are going to address the ' issue of configuration and control, consistent with the Maintenance Rule,i.e., evaluate the impact of maintenance activities on plant configurations.

Response 19:

Our work planning process determines risk impact of planned maintenance activities. . When the risk impact is determined to be high, we seek to minimize the risk through one of two mechanisms. The first option is to veschedule t,e work, the second option is to provide a contingency should rescheduling not be feasible.

Emergent work items must be considered insofar as they result in a change to the previously evaluated risk profile. Activities not within the scope of what has been previously analyzed are deferred unless additional guidance, based on probabilistic evaluation of plant configuratjor;, is received from our PRA group.

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