ML20206A743

Forwards Comments Generated Based on Review of NRC Ltr Re Preliminary Accident Sequence Precursor Analysis for Byron Station,Unit 1

ML20206A743
Person / Time
Site:	Byron
Issue date:	04/22/1999
From:	Krich R COMMONWEALTH EDISON CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
NUDOCS 9904290013
Download: ML20206A743 (7)

Text

r-Commonwealth Edison Company

• O 14(Ni Opus Place

.' Downers Grove,11. f41515-5701 April 22,1999 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455

Subject:

Review Comments Regarding the Preliminary Accident Sequence Precursor Analysis for Byron Station, Unit 1

Reference:

NRC letter," Review of Preliminary Accident Sequence Precursor Analysis of Operational Condition at Byron Station, Unit 1," dated March 12,1999.

/

The reference letter provided the preliminary Accident Sequence Precursor (ASP) analysis of an operational condition that was discovered at Byron Station, Unit 1, on 4 September 12,1998. This condition was reported to the NRC in Licensee Event Report /Pd/

(LER) 50-454/98-018. The operational condition discussed in the LER was the trip of the 1 A Emergency Diesel Generator (EDG) on an engine low lube oil pressure signal during the first minute of a test run. In the reference letter, the NRC requested that the preliminary ASP analysis be reviewed and comments provided within 30 days of receipt of the letter (i.e., provide comments by April 21,1999). In a telephone conference between representatives of Commonwealth Edison (Comed) Company and the NRC, it was agreed that the comments could be submitted on April 22,1999. The review of the analysis has been completed and comments are attached. These comments were generated based on our review of the reference letter and information obtained during a telephone conference held on April 12,1999, between representatives of Comed, NRC, and Oak Ridge National Laboratory.

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.a April 22,1999 U. S. Nuclear Regulatory Commission Page 2 Should you have any questions concerning this letter, please contact Mr. J. A. Bauer at (630) 663-7287.

Respectfully,

/

R. M. Krich Vice President - Regulatory Services Attachment cc: Regional Administrator- NRC Region lli NRC Senior Resident inspector - Byron Station

Attachment Review Comments Regarding Preliminary Accident Sequence Precursor Analysis for Byron Station, Unit 1

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We have reviewed the preliminary Accident Sequence Precursor (ASP) analysis of an operational condition that was discovered at Byron Station, Unit 1, on September 12, 1998. This condition was reported to the NRC in Licensee Event Report (LER) 50-454/98-018. The operational condition discussed in the LER was the trip of the 1 A Emergency Diesel Generator (EDG) on an engine low lube oil pressure signal during the first minute of a test run. The results of this review are as follows.

Event Description

. The " Event Description" section contained in the ASP analysis document is accurate. The ASP documentation appropriately characterized the sequence of events and the failure mechanism that was provided in LER 50-454/98-018.

Additional Event-Related Information

. The " Additional Event-Related Information" section contained in the ASP analysis document is accurate with respect to the configuration of the plant, the design of the Emergency Diesel Generators (EDGs) at Byron Station, and the continued ,

availability of the 1B EDG. l I

Modelina Assumptions

. In the "Modeling Assumptions" section of the ASP analysis document, the assumption that the 1 A EDG was unavailable for 18 days is overly conservative.

There is reasonable assurance that the 1 A EDG became unavailable on l September 3,1998, and was therefore, unavailable for 11 days instead of 18 days. LER 50-454/98-018 did indicate that although the actual failure point could not be determined, the EDG was considered unavailable for 11 days from September 3,1998, until September 14,1998. The basis 'or this consideration is that plant operators identified a lifting relief valve on the u EDG on September 3,1998. Prior to SeptemL9r 3,1998, there was no indication of this lifting relief i valve. Although the initial operability deterraination that was performed after identification of the lifting relief valve did not consider the potential for a plugged

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lube oil strainer, there is a reasonable belief that the condition did not exist prior  ;

to September 3,1998, since the lifting relief valve would have t'een noted by plant operators on daily rounds or other plant personnel during the routine course of activities.

I e in the ASP analysis document, it appears that the assumptions overly compensate for the potential for a common mode failure of the remaining EDGs.  :

There is no indication that the remaining three EDGs were ever impacted by the )

particular event documented in LER 50-454/98-018. The Byron Station l

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Technical Specifications required plant operators to immediately perform an l' assessment of the common mode failure potential for the 1B EDG In addition, temporary modifications were installed on all four of the EDGs following this event to allow plant operators to monitor the EDG lube oil strainer differential j l

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• e pressures to ensure that the condition was not common to more than the one generator. No evidence to date has been identified which supports the common mode failure assumptions contained in the ASP analysis document. This conclusion is supported by the fact that maintenance is not performed on multiple EDGs at one time and there is no single dedicated crew that is responsible for performing maintenance on all the EDGs. Lack of attention to detail by maintenance personnel is one of the significant contributors identified in the root cause analysis for this event. Therefore, given the objective evidence, including inspection activity during the condition, there is little reason to believe that the identified condition had significant common cause potential. Our preliminary calculations indicate that a re-characterization of the failed condition of the 1 A EDG as a non-common cause potential failuro results in a net increase in Core Damage Probability of less than 1.0E-6.

• The design basis for the Byron Station is such that any single EDG is capable of providing sufficient AC power

• provide the capability to safely shutdown both units in the event of a Station Blackout (SBO). This design basis is documented in Byron /Braidwood Updated Final Safety Analysis Report (UFSAR) section 8.3.1.1.2.2, " Emergency Onsite Power Sources (Diesel Generators). Credit does I not appear to be given to this design basis in the "Modeling Assumptions" section

, of the ASP analysis document. We would suggest that such credit is

! appropriately taken by multiplying each " MULTI-UNIT LOOP" cutset associated with a SBO sequence, none of which contain a common-cause EDG failure term, l by the value represented by basic event "EPS-XHE-XM-OU."

l l '. It appears that a value of 0.8 was used as the failure probability for offsite power

! recovery for all sequences. This value, in most cases, is overly conservative.

[ Furthermore, this value appears to be used in all sequences, regardless of the

! expected accident progresr. ion time to core damage.

For the Byron Station Updated Probabilistic Safety Assessment (PSA), there were essentially three different post-SBO scenarios postulated. The first post-SBO scenario, which best correlates to Sequence 18-2 in the ASP analysis document, has a successful diesel-driven Auxiliary Feedwater (AFW) pump combined with a Reactor Coolant Pump (RCP) Seal Loss of Coolant Accident (SEALLOCA) probability that results in the core being uncovered at eight hours.

The eight hour period is based on a reasonable assumption that battery depletion occurs 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> into the event and results in AFW failure. However, there is sufficient secondary invantory in the steam generators and primary inventory in the RCS to provide an additional four hours prior to core damage when considering the reduction in decay heat that has occurred in the first four hours following the initiating event. Thermal hydraulic analysis performed for the Byron Station Individual Plant Examination (IPE) has demonstrated the core will remain covered for at least two hours with this primary and secondary inventory available immediately following such an initiating event. In the analysis, decay heat was initially assumed to be at its maximum value and was reduced exponentially as a function of time. Therefore, use of ar AC powe. non-recovery

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l l probability corresponding to an eight hour period would be more appropriate for l this sequence.

4 The second post-SBO scenario in the Byron Station Updated PSA, which best correlates to Sequence 18-9 in the ASP analysis document, includes the same plant conditions discussed in the first scenario, except that the core does uncover (i.e. the SEALLOCA is sufficiently large) in less than eight hours, such that recovery of AC power at eight hours is of no value for avoiding core damage.

Sequence 18-9 does credit such recovery. But with a 0.8 AC power non- I recovery probability, there appears to be a presumption that very little time is available prior to core damage following the RCP seal failure. Given our offsite AC power non-recovery probability versus time after Loss of Offsite Power (LOOP)/ Dual Unit Loss of Offsite Power (DLOOP) events curve, the AC power non-recovery probability of 0.8 appears to be reasonable for this sequence.

The third post-SBO scenario in the Byron Station Updated PSA, which best correlates to Sequence 18-22 in the ASP analysis document, postulates the failure of the diesel-driven AFW pump. As demonstrated in the thermal hydraulic analysis performed for the Byron Station IPE, AC power recovery must occur within two hours in order to avoid core damage. Although there is a potential for a large enough SEALLOCA to uncover the core in less than two hours, rendering the recovery of AC power meaningless, accounting for this will have a second or ,

third order effect on overall Core Damage Frequency, as this is already in a low  !

probability sequence. Therefore, use of an AC power non-recovery probability I corresponding to a two hour period would be more appropriate for this sequence.

In addition, the ASP analysis document event tree included Sequence 18-20.

This sequence postulates the cycling of a pressurizer Power Operated Relief Valve (PORV), presumably due to ar expected reactor coolant system pressure transient following the initial turbine trip and loss of the condenser and the steam dump valves. The scenario continues with the PORV failing to re-close, resulting in an effective small break Loss of Coolant Accident (LOCA). Again, a 0.8 AC power noa-recovery probability was assigned. Thermal hydraulic analyses from the Byron Station IPE indicate that such a scenario (i.e., the largest small break 1 LOCA) would progress for slightly more than two hours prior to core damage occurring. Therefore, use of an AC power non-recovery probability corresponding to a two hour period would be more appropriate for this sequence.

Given the previous discussion of Sequences 18-2,18-9,18-20, and 18-22, use of AC power non-recovery probability values that correlate to time durations of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, respectively, after the LOOP /DLOOP event would be more appropriate for the sequences where the time to core damage is 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, respectively. The AC power non-recovery probability values in the Byron Station Updated PSA database for these time durations are 0.316 and 0.032, respectively.

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• These AC power non-recovery probability values were derived from Electric Power Research Institute (EPRI) Report TR-106306, " Losses of Off-Site Power at U. S. Nuclear Power Plants - Through 1995," dated April 1996. This study covered approximately the same time period as NUREG/CR-5496, " Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1980 - 1996," dated November 1998, which is referenced in the ASP analysis document. In addition, EPRI Report TR-106306 covered more industry events than NUREG/CR-5496 and was in a final published form, whereas NUREG/CR-5496 was only in draft form at the time we performed our AC power non-recovery probability calculations.

The determination of the AC power non-recovery probability values was accomplished via a thorough review of EPRI Repott TR-106306 and of the LOOP /DLOOP events in its database. Certain events that clearly did not apply were excluded. Primary examples of excluded events pertain to those caused by hurricanes and salt spray. Hurricanes were only partially excluded to give some representation of the recent Davis Besse tomado event. In addition, any single unit LOOP at a multi-unit site which was terminated by simply cross-connecting to another unit's power supply was also excluded, in order to obtain a more accurate picture of offsite AC power recovery. The remairiing events were re- f plotted on a chart and curve fit. The two hour duration value was determined from the curve fit. For the eight hour duration value, a value from the curve fit was interpolated to avoid non-conservative predictions by the curve fit equation in the region of curve corresponding to eight hours. The resulting AC power non-recovery probability values are considered reasonable and reflective of actual industry experience, as applied to Byron Station.

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