PLA-6526, Amendment Request No. 305 to Unit 1 and No. 276 to Unit 2: One-Time Extension of Tec Spec 3.8.1 Supplemental PRA Information, PLA-6526
| ML091880321 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 07/01/2009 |
| From: | Spence W Susquehanna |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| PLA-6526 | |
| Download: ML091880321 (22) | |
Text
William H. Spence President and Chief Nuclear Officer PPL Susquehanna, LLC 769 Salem Boulevard Berwick, PA 18603 Tel. 610.774.3683 Fax 610.774.5019 Whspence@pplweb.com I
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JUL 01 2009 U. S. Nuclear Regulatory Commission Document Control Desk Mail Stop OP 1-17 Washington, DC 20555 SUSQUEHANNA STEAM ELECTRIC STATION AMENDMENT REQUEST NO. 305 TO UNIT 1 LICENSE NPF-14 AND AMENDMENT REQUEST NO. 276 TO UNIT 2 LICENSE NPF-22: ONE-TIME EXTENSION OF TECH SPEC 3.8.1 SUPPLEMENTAL PRA INFORMATION PLA-6526 Docket Nos. 50-387 and 50-388
References:
- 1) PLA-6480, Mr. W. H. Spence (PPL) to Document Control Desk (USNRC), "Susquehanna Steam Electric Station Amendment Request No. 305 to Unit 1 License NPF-14 and Amendment Request No. 276 to Unit 2 License NPF-22:
One Time Extension of Technical Specification 3.8.1 Allowable Completion Time for Offsite AC Circuits," dated March 24, 2009.
- 2) PLA-6505, Mr. W. H. Spence (PPL) to Document Control Desk (USNRC), "Susquehanna Steam Electric Station Amendment Request No. 305 to Unit 1 License NPF-14 and Amendment Request No. 276 to Unit 2 License NPF-22: One Time Extension of Technical Specification 3.8.1 - PRA Supplemental Information, " dated April 30, 2009.
- 3) PLA-6509, Mr. W. H. Spence (PPL) to Document Control Desk (USNRC), "Susquehanna Steam Electric Station Amendment Request No. 305 to Unit I License NPF-14 and Amendment Request No. 276 to Unit 2 License NPF-22: One Time Extension of Technical Specification 3. 8.1 - Supplemental Electrical Information," dated May 12, 2009.
- 4) E-mail, B. Vaidya (NRC) to D. Filchner (PPL), "Request for Additional Information (RAIs) Re: License Amendment Request for One-time extension of Allowable Outage Time in TS 3.8.1, LCO ACTION A3, from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 10 days for replacement of Transformer ST-20 (TAC NOS. ME0969 and ME0970) - PRA Supplemental Information, " dated May 29, 2009.
In accordance with the provisions of 10 CFR 50.90, PPL Susquehanna, LLC (PPL) submitted a request for amendment to the Technical Specifications (TS) for Susquehanna Units 1 and 2 in Reference 1.
During an Api-l 20, 2009, teleconference between PPL and the Nuclear Regulatory Commission (NRC) staff, the NRC requested additional probabilistic risk assessment At-oo!
Document Control Desk PLA-6526 (PRA) information to support the NRC acceptance review of Reference 1. PPL provided this information to the NRC in Reference 2.
Based on teleconferences held between PPL and the NRC on April 30 and May 1, 2009, PPL provided (Reference 3) the NRC with supplemental electrical information to support the NRC acceptance review of Reference 1.
In an e-mail dated May 29, 2009 (Reference 4), the NRC staff requested additional PRA information. A conference call was conducted on June 10, 2009, to discuss the information request. Attachment 1 to this letter is PPL's response to that request, and, unless otherwise stated is probabilistically based. contains a revised list of regulatory commitments, which supersedes the originally identified commitments in Reference 1.
The supplemental PRA information for each of the responses and the revised commitments contained herein, does not affect the no significant hazards consideration included in Reference 1.
Please direct any questions regarding this response to Ms. Brenda W. O'Rourke - Nuclear Regulatory Affairs, at (570) 542-1791.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on:
7-/
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W. H. Spence Attachments: 1) Responses to PRA Questions
- 2) Revised List of Regulatory Commitments Copy: NRC Region.I Mr. R. Janati, DEP/BRP Mr. F. W. Jaxheimer, NRC Sr. Resident Inspector Mr.,B. K. Vaidya, NRC Project Manager to PLA-6526 Responses to PRA Questions
Attachment to PLA-6526 Page 1 of 14 NRC PRA QUESTION 1:
Section 4.2.1.1 of the Enclosure of Reference 1 identifies that the loss of offsite power (LOOP) initiation frequency is explicitly calculated by a fault tree which is capable of assessing the impact of an out-of-service transformer. Section 4.2.1.2 identifies that the impact of the transformer is evaluated in the plant-centered LOOP initiating event. The licensee is requested to provide additional details of this model for the staff to better understand the cause-effect relationship of the out-of-service transformer and the plant-centered LOOP frequency for this application:
- a.
Identify the transformer failure modes, failure probabilities, treatment of common cause failure of transformers, and the calculated frequencies for plant-centered LOOP when both transformers are available and when one transformer is unavailable.
- b.
Typically, a fault tree model for an initiator involving two redundant components must assume a mean-time-to-repair applicable in the model when one transformer fails, after which the redundancy is re-established. This is established in the mission time of the remaining operable component. In this case, the calculations should not assume any repair of the out-of-service transformer, because the calculation is based on the core damage frequency (CDF) over an entire year while in the outage configuration, and then the 10-day exposure time is used to calculate the incremental conditional core damage probability (ICCDP). Confirm that no credit has been taken for repair and restoration of ST No. 20 in the fault tree calculation of the plant-centered LOOP frequency for this application.
- c.
Identify whether credit is taken in the PRA model for restoration of offsite power given a plant-centered LOOP as the initiating event, and if so, provide the non-recovery probability, its basis, and its applicability to the specific configuration which will exist during the 10-day outage.
PPL RESPONSE:
Response to la The transformer failure mode used in the PRA model is FAILS TO OPERATE. The transformers are modeled in an initiating event type fault tree (i.e., a given transformer fails to operate for one year and the second "backup mode" transformer fails to operate for three days after failure of the other. After three days, the Technical Specifications require a plant shutdown. The transformer frequency for failing the one-year mission time is 9.99E-03 and the probability of failing a three-day mission time is 8.2 1E-05.
The initiating event plant centered fault tree is an OR gate with three inputs, a basic event for plant centered LOOPs (which represents a common mode failure), and two
Attachment to PLA-6526 Page 2 of 14 AND gates - one for each transformer in the "lead" with the other transformer in backup. The plant centered LOOP frequency with both transformers in service (I/S) is 2.43E-03 and with ST No. 20 out of service (OOS) the frequency is 3.98E-02.
Response to lb The SSES risk model does not credit repair of ST No. 20.
Response to Ic The SSES model does credit recovery of offsite power for a plant-centered LOOP.
The non-recovery probability is given by the following formula as a function of recovery time:
PA r = e -` /,a)"
Where; p,,r - probability of non-recovery t plant centered power restoration time(hours) a Weibull shape parameter 0.610
,8 Weibull scale parameter 0.330 The basis for the above listed formula is "Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1986-2003," NUREG/CR-INEEL/EXT-04-02326.
Given a LOOP and run time failures of the emergency diesel generators, the SSES risk model assumes that the run time failures occur at the time of the LOOP. This assumption adds conservatism to the LOOP model in that all diesel run time failures would not be at time zero. Given this assumption, each sequence is reviewed to determine the latest time off site power can be recovered in order to prevent core damage when using the Core Damage Frequency (CDF) model and the latest time off site power can be recovered to prevent a release when using the Large Early Release Frequency (LERF) model. These "times" then become t in the above equation for their respective applications.
The use of the probability of non-recovery for a plant-centered LOOP while in a 10 day outage for ST No. 20 is appropriate. In order to have a plant centered LOOP both sources of off site power need to be lost. To recover off site power, only one off site source needs to be restored. With one transformer OOS, SSES will still have one transformer that can be restored. Therefore, it is appropriate to use the probability of non-recovery for a plant-centered LOOP.
Attachment to PLA-6526 Page 3 of 14 NRC PRA QUESTION 2:
Section 4.2.1.1 of the Enclosure of Reference 1 identifies the configuration of the onsite AC power sources. The licensee is requested to provide additional details regarding PRA modeling of these systems:
- a.
Describe the applicability of common cause failures between the four emergency diesel generators and the fifth diesel generator, and if appropriate, the basis for not assessing any common cause failure of the fifth diesel generator.
- b.
It is stated that the fifth diesel generator may be placed into service within 90 minutes; provide the human error probability used in the PRA for this action, and the basis of the calculation, including availability of procedures, and the capability to accomplish the task using only on-shift staff and pre-staged tools and equipment.
- c.
There is no discussion of the assumptions regarding timing of the use of the 480V portable diesel generator. Discuss the use of this equipment with regards to the time required to place it into service and how it is credited in the PRA; provide the human error probability used in the PRA for this action, and the basis of the calculation, including availability of procedures, and the capability to accomplish the task using only on-shift staff and pre-staged tools and equipment.
- d.
Describe how the human error dependency for aligning the fifth diesel generator and the portable diesel generator is addressed in the PRA model, if the PRA credits both recovery actions in the same cutset.
- e.
Describe the sensitivity of the risk results to crediting the fifth diesel generator and the portable diesel generator.
- f.
Describe any assumptions in the PRA regarding repair of diesel generators. If repairs are credited, describe how the human error dependency between those repairs and the actions to align the fifth diesel generator and the portable diesel generator are addressed, if the PRA credits both repairs and recovery actions in the same cutset.
- g.
One of the open findings and observations (F&O) from the 2003 peer review (Attachment 4 of Reference 1) addressed the age of the plant-specific failure data used in the PRA model, and identified 1999 as the end of the data period. The disposition of this F&O states that the diesel generators use plant-specific data, but did not identify if more recent data was applied. Identify what plant-specific failure data has been used for the diesel generators in this application; if recent (post-1999) data is not incorporated, then describe the diesel generator performance over this 10-year period and justify that the PRA model failure probabilities are appropriate for this application.
Attachment to PLA-6526 Page 4 of 14 PPL RESPONSE:
Response to 2a The SSES risk model uses common cause factors (CCF) between the four normally aligned diesels generators and also between the four diesels and the fifth diesel generator. The CCF for the fifth diesel is assessed as a conditional CCF given that there is a common cause failure of two, three or four of the normally aligned diesel generators.
Response to 2b The human error probability (HEP) to place the fifth diesel generator in service is 1.15E-1. The basis for this calculated HEP is the sum of two methods 1) the Cause Based Method (An Approach to the Analysis of Operator Actions in Probabilistic Assessment - EPRI TR-100259) and 2) the execution failure probability -Technique for Human Error Rate Prediction (THERP) (NUREG/CR-1278).
The procedure used to makeup the diesel substitution is a readily available Operating Procedure. The operators frequently use this procedure to substitute the fifth diesel generator for one of the four normally aligned diesel generators. This substitution occurs on the average 7 times per year. This substitution is made with the on-shift personnel (no one needs to be "called out" to support the substitution). There are no special tools or equipment required for the substitution and the breakers that need to be manipulated are all at the location where they are needed.
Response to 2c The 480V portable diesel generator is credited after four hours from the cue of loss of normal power supply to the A or B battery chargers. The A and B batteries power HPCI, RCIC and ADS. The actual hookup task requires one hour and another hour is allotted to start the diesel generator. The HEP for this task is 2.93E-2. The basis for this calculated HEP is the sum of two methods 1) the Cause Based Method (An Approach to the Analysis of Operator Actions in Probabilistic Assessment - EPRI TR-100259) and 2) the execution failure probability -Technique for Human Error Rate Prediction (THERP) (NUREG/CR-1278).
The procedure used to hook up the portable diesel generator is a readily available Emergency Operating Procedure. The hook up of the portable diesel generator is made with the on-shift personnel (no one needs to be "called out" to support the hook up). All tools required for the hook up are located at the portable diesel generator.
Attachment to PLA-6526 Page 5 of 14 Response to 2d The PRA credits both operator actions in the same cutset. To account for the operator action dependency, the model uses a dependent operator action, assuming high dependence, to address the failure to align the E DG for one of the failed A - D diesel generators and the failure to hook up the portable diesel generator. The basis used for this calculation is the Handbook of Human Reliability Analysis with Emphasis on Nuclear Power plant Applications, NUREG/CR-1278.
Response to 2e A sensitivity case for the dependent operator error of failing to align the E DG and failing to tie in the portable diesel generator was performed using the base cutset file for the 5th and 9 5th percentile values. The result of the 9 5 th percentile sensitivity study was an increase in CDF by 30% and an 18% increase in LERF from the base model values.
Response to 2f The SSES risk model does not credit repair of the diesel generators.
Response 2g This application used the same diesel generator failure data that was used for the peer review model. The common cause failure data in this application was updated from the peer review model using the INEEL/NRC Database for CCF Event from 1980-2001.
To address the issue of theplant's diesel generator performance, a sensitivity case was performed. In the sensitivity case, generic diesel failure data from NUREG 6928 was used in conjunction with more recent plant specific data. The NUREG contains data through the year 2002. The NUREG generic data was then updated using plant specific failure data from 2003-2008. The resulting updated failure to start and failure to run data along with revised CCF (based on the updated failure to start and failure to run data) was used for the sensitivity case. The result was a decrease in CDF. Therefore, it is concluded that the diesel failure data used in the application is conservative (yields a higher risk value).
Attachment to PLA-6526 Page 6 of 14 NRC PRA QUESTION 3:
The licensee described the approach applied to the quantitative evaluation of fire risk for this application (Section 4.2.1.2 of the Enclosure to Reference 1, Attachment 1 of Reference 2). The licensee is requested to provide the following additional information/clarifications:
- a.
Reference 1 states that an assumption is made that all fires not manually suppressed progress to a large fire which damages all cables and equipment in the zone.
Reference 2 (Question #2, "Quantification of Fire Risk") states that fire risk considers both the probability of non-suppression and the probability of a fire progressing to a large fire. Reference 2 (Question #2, "Assumptions") also states that all fires progress to large fires. Reconcile these three statements and clearly identify the assumption made relating to suppression and the magnitude of fires.
- b.
References 1 and 2 state that an assumption is made when a fire zone includes cables affecting both ST No. 20 (the out-of-service transformer) and ST No. 10 (the sole remaining transformer providing offsite AC power to both units), the risk metrics were doubled to account for ST No. 20 being unavailable. Confirm that this assumption is consistent with the response to RAI la, above, regarding the change in frequency of plant-centered LOOP events for the one transformer available configuration.
- c.
The fire risk is only presented for unit 1. There is no discussion in either of the submittals to address the applicability of these risk results to unit 2, and the basis for that conclusion, including the assessment of any unit 2 specific configuration issues which could affect the fire risk calculations. Confirm the applicability and basis for the unit 1 fire risk calculations to unit 2.
- d.
Reference 2 (Attachment 1, Question 2, "General Approach") states that an assumption is made that cables fail open. This may be non-conservative for zones containing cables for normally closed circuit breakers connecting ST No. 10 to the plant electrical busses, in that an open circuit failure might leave the breaker closed, but a short circuit failure could result in spurious actuation of the breakers, interrupting offsite power. Provide an assessment and disposition of the potential for and failure impacts of spurious breaker actuations for the available offsite circuits.
PPL RESPONSE:
Response 3a The effect of a fire in each fire zone was assessed by using the SSES cable and raceway database. This database includes the cables associated with each system credited in our Appendix R analysis, the raceway the cables are routed through, and the fire zone(s) for each of these raceways. Given this information and a fire in a fire
Attachment to PLA-6526 Page 7 of 14 zone, all the equipment that has unprotected cables routed though that fire zone was not credited. Once the impact of a fire in a fire zone was assessed, the equipment not affected by the fire (no cables in the fire zone) was reviewed to determine if there was sufficient equipment to satisfy the screening criterion (the screening criterion is described in PLA-6505, Reference 2). If the fire zone screened out (i.e., the screening criterion was met), no further analysis was performed for that fire zone.
The fire zones that did not screen out had their conditional core damage probability and conditional large early release probability calculated.
The quantification for each fire zone used a data base specific to the cause of a Loss of Off-Site Power (LOOP). If the fire in a specific zone was assumed to cause a LOOP (whether or not ST No. 20 was in service), the database used for that zone did not credit LOOP recovery. If a fire in a specific zone would not cause a LOOP, the database used credited LOOP recovery.
Once the conditional core damage and large early release probabilities were calculated, the frequency of each was determined by the following formula:
Fire CDF = U 1 -CDP
- Total FF
- Suppression
- Probability of Large Fire Fire LERF = U 1-LERP
- Total FF
- Suppression
- Probability of Large Fire Where:
" Fire CDF is the Core Damage Frequency due to a fire in a fire zone.
Fire LERF is the Large Early Release Frequency due to a fire in a fire zone.
- U1-CDP is the Unit 1 Conditional Core Damage Probability due to a fire in a fire zone.
- U 1 -LERP is the Unit 1 Conditional Large Early Release Probability due to a fire in a fire zone.
" Total FF is the Total Fire Frequency for the fire zone (data from the SSES IPEEE)
" Suppression is the probability of manual suppression failing to extinguish the fire (probability of suppression failing is 0.1 which is consistent with NEI 00-01, Nuclear Power Plant Fire Protection paragraph 4.2.1.5.)
- Probability of a Large Fire is the probability that, given a fire in a fire zone, it progresses to a large fire (probability of the large fire progression is 0.01 which is consistent with NEI 00-01, Nuclear Power Plant Fire Protection paragraph 4.2.1.4).
Attachment to PLA-6526 Page 8 of 14 To be consistent with the fact that the fire impacts can only be assessed by PPL on a fire zone basis, the fires need to ultimately be large fires. Hence, the statements in the cited references were made.
Response to 3b The issues in question l a deal with the calculated frequencies for plant-centered LOOP when both transformers are available and when one transformer is unavailable. Both of these situations represent an initiating event. 'They are exclusive of a fire since a fire is also an initiating event.
When PPL stated that the risk metrics were doubled to account for ST No. 20 being unavailable, this was an effort to properly account for a fire causing a LOOP in a fire zone. In these particular fire zones, a large fire would also have caused a LOOP with both ST No. 10 and ST No. 20 available. With ST No. 20 unavailable, it was assumed that since only about half the cables need to be damaged by a fire to cause a LOOP, a fire is twice as likely to cause a LOOP. However, all equipment that has unprotected cables routed in the fire zone is still considered unavailable due to the fire.
Response to 3c The Unit 1 fire risk results are representative of the fire risk for Unit 2. The Unit 1 and common equipment credited in the Unit 1 fire risk analysis is equivalent to the same equipment in Unit 2. The power supplies and cooling requirements come from similar sources. For example, the Unit 1 RHR A pump is powered by the Unit 1 A 4 kV bus and cooled by Emergency Service Water (ESW) division 1 and the Unit 2 RHR A pump is powered by the Unit 2 A 4 kV bus and cooled by Emergency Service Water (ESW) division 1. ESW is a common system with the capability to cool both units simultaneously.
For the major equipment important to fire risk the Unit 1 and 2 Reactor Buildings have an identical equipment layout. The equipment that is on the north side of the Unit 1 Reactor Building is on the north side of the Unit 2 Reactor Building and so forth. The Reactor Buildings share a common wall on Unit l's south and Unit 2's north side. The control structure is centered on this common wall to the west of the Unit 1 and 2 Reactor Building. Each Unit has equipment divisionally separated north to south (i.e., division 1 equipment is on the south side and division 2 equipment is on the north side), except for RCIC. RCIC is a division 1 system located between the division 2 HPCI system and the division 2 RHR pumps on the north side of each unit.
Attachment to PLA-6526 Page 9 of 14 Considering the symmetry and similarity between the units, identical system performance characteristics, identical spatial and cooling requirements, and compliance with Appendix R; PPL has concluded the fire risk for Unit 1 is representative of the fire risk for Unit 2.
Response to 3d Although the General Approach states that the cables fail open, no credit is taken for equipment or off site power if the unprotected cables for each are routed though a fire zone that has a postulated fire.
NRC PRA QUESTION 4:
Reference 1 provides a qualitative assessment and disposition of seismic events and external fires and floods, but does not address other external events (transportation and nearby facility accidents, toxic gas, high winds and tornadoes). Provide a disposition of these events for this application. (The staff has accepted that such events are not significant contributors to risk if the plant design conforms to the 1975 Standard Review Plan criteria, which is typically discussed in the Individual Plant Examination of External Events.)
PPL RESPONSE:
Response to 4 The other external events, transportation and nearby facility accidents, toxic gas, high winds and tornadoes are not significant contributors to risk. PPL's compliance with 1975 Standard Review cited from PPL's IPEEE is as follows:
"The acceptance criteria of SRP Sections 2.2.1 and 2.2.2 are met because the SSES FSAR provides adequate descriptions of the locations and distances of nearby (within five miles of the plant) industrial, military, and transportation facilities, the nature and extent of activities conducted at the identified facilities, the products and materials likely to be processed, stored, used, or transported at the facilities or to and from the facilities, and statistical data or worst case assumptions on the potential hazard from the materials.
The SSES FSAR also provides analyses either to establish that the probability of accidents such as exposure to hazardous chemical releases (sulfur dioxide and ammonia) is less than 1.0 E-07 above which the event has to be included in the
- plant design basis, or that under pessimistic assumptions the consequences of accidents such as explosions, fires, or liquid spills do not adversely affect plant
Attachment to PLA-6526 Page 10 of 14 safety, because the nearest safety-related structures and components of the plant are at a greater distance from the hazard than the damage zone of the hazard. The acceptance criteria of SRP Section 2.2.3 are, therefore, met."
NRC PRA OUESTION 5:
Reference 1 Attachment 3 identifies a regulatory commitment (#4) addressing the availability of systems and components which are associated with the licensee's tier 2 evaluation of potentially risk-significant configurations in accordance with Regulatory Guide (RG) 1.177. The licensee is requested to address the following concerns:
- a. The commitment wording is that the listed systems and components "...will be required to be available during the ST No. 20 replacement...", and then states "Elective maintenance will not be performed..." and then identifies actions to be taken if the system or component is unavailable due to causes other than elective maintenance. The staff assumes that the intent of this commitment is that the systems and components will be available unless an unplanned failure occurs, and that no elective maintenance, preventive maintenance, planned testing, or any other activity which is not absolutely required to be performed during the transformer outage will be conducted. Reword this commitment to be less ambiguous.
- b. The commitment includes a risk evaluation of any emergent unavailability of the systems and components "to determine if the basis for the proposed one-time change to LCO 3.8.1 remains valid...". The intent of the tier 2 evaluation recommended in RG 1.177 is to specifically identify and prohibit such high riisk configurations, not to commit to evaluate the risk if such configurations occur; that is the scope of the tier 3 process.
Based on the risk significance of the fifth diesel generator and the portable diesel generator determined in the response to RAI 2e, above, and the risk significance of the other systems and components in the scope of commitment #4, it may be appropriate for the TS to directly include the requirement for availability of some of the systems and components during the extended outage of ST No. 20, and to provide for an immediate plant shutdown if these components are unavailable.
Assess the risk impacts of the unavailability of these systems and components, and if appropriate, provide the appropriate TS control in the one-time amendment changes.
- c. The unavailability of the emergency diesel generators during the ST No. 20 outage appears to be addressed by existing plant Technical Specification (TS) action requirements (TS 3.8.1, Condition D) which would apply when a diesel generator and an offsite circuit are both unavailable. It is unnecessary to make any
Attachment to PLA-6526 Page 11 of 14 additional commitment for such components, and the licensee may wish to remove the diesel generators from the list.
PPL RESPONSE:
Response to 5a PPL revised the commitment wording as suggested by the NRC. See Attachment 2 for the revisions to the regulatory commitments.
Response to 5b PPL used its PRA to identify risk-significant plant equipment outage configurations while ST No. 20 is OOS. The method used the cutset file Risk Achievement Worth (RAW) for equipment with ST No. 20 OOS. If the RAW was two or greater then the equipment was considered and the resolution is addressed below.
This method identified the following risk significant equipment already covered by Technical Specifications with short LCO times (twelve hours or less):
125 VDC batteries and busses 3 or more SRVs inoperable
- Standby Liquid Control - not able to inject e
Diesel Generators
- 4kVESS buses
8 ESW pump house fans 3 or more RHRSW pumps
- 2 CS injection valves
- 2 RHR injection valves
- 2 or more ADS valves
Attachment to PLA-6526 Page 12 of 14 Since the identified items of equipment are covered by short LCO times, no further actions are required other than to comply with the applicable LCOs if this equipment is OOS.
The following are combinations of equipment OOS that are risk significant and are not covered by a short term LCO:
- Any suppression chamber to drywell vacuum breakers being open
- Inability to perform suppression pool cooling by either division
- Unavailability of any ESW pump
& Unavailability of any RHR pump 125 VDC battery chargers (A and B)
If any of the above equipment is OOS for the listed reason, the ST No. 20 maintenance work will not commence, and the 10-day LCO for ST No. 20 will not be entered until such time the equipment is restored to service.
The following equipment with the listed failure modes is not covered by Technical Specifications and was determined to be risk significant. If any of the listed conditions exist, the 10-day LCO for ST No. 20 will not be entered.
" The portable diesel generator is not available.
" The containment vent valves HV1(2)5703 or HV1(2)5704 are known to be failed closed (i.e., the valves can not be manually opened).
- Turbine Building Closed Cooling Water (TBCCW) Heat Exchangers and temperature control valve (not TS components). The listed TBCCW components, if failed, would cause a unit outage; therefore, there is no need to place operational restrictions on the TBCCW equipment, and the equipment is not included in the regulatory commitment list.
Note that Diesel Generator E did not meet the criterion for risk significance (RAW > 2) and, therefore, is not listed above. However, its availability is still considered important during the 10-day LCO for ST No. 20. Thus, Diesel Generator E is included on the list of regulatory commitments.
Per our response to RAI 5c in Reference 1, the commitment list and the list of equipment identified in Section 4.1 have been revised to delete Diesel Generators A, B, C, and D since their unavailability is covered by a short term LCO. The E
Attachment to PLA-6526 Page 13 of 14 Diesel Generator will remain on the list consistent with PPL's conclusion that it is important to have it available during the ST No. 20 outage.
Response 5c TS 3.8.1 Condition D does address the situation of having one startup source and one diesel generator unavailable. PPL will remove the diesel generators from the commitment list.
NRC PRA OUESTION 6:
Section 4.2.1.2 of the Enclosure of Reference 1 includes a section on dual unit shutdown issues. The licensee is requested to address the following concerns related to shared diesel generators:
- a. The standby diesel generators are not identified as a common system that may be needed for both units to shutdown. It is not clear if the diesel generators are dedicated to a unit, or if not, how the electrical loads between units are split amongst the four diesel generators. It is also not clear whether the failure of more than one diesel generator still permits both units to safely shutdown. The FSAR chapter 8 states that failure of one of four diesel generators still permits safe shutdown of both units. Describe the configuration of the electrical system as it pertains to sharing of diesel generators between the units.
- b. For dual unit plants with shared systems, if a common initiating event will challenge both units to safely shutdown simultaneously, the PRA must not credit the same equipment for mitigating the event in both units. Describe how the SSES PRA model addressed shared systems for this application for the case of a plant-centered LOOP (such as a failure of the ST No. 10 transformer), where both units lose offsite power and must rely upon the shared onsite diesel generators.
PPL RESPONSE:
Response to 6a The standby diesel generators are shared equipment and required by both units given a loss of off site power. The following is from FSAR chapter 8.3:
"The diesel generators are shared by the two units. There are a total of five diesel generators. Diesel Generators A, B, C and D are normally assigned to the safety-related load groups. Diesel Generator E is capable of being substituted for any of the Diesel Generators A, B, C or D without violating the independence of the
Attachment to PLA-6526 Page 14 of 14 redundant safety-related load groups. Only four diesel generators can be aligned to the safety-related load groups. When a diesel generator is aligned, it is connected to the 4.16 kV bus of the assigned load group per unit. The capacity of the aligned diesel generators (assuming one of the aligned diesels fails) is sufficient to operate the engineered safety features loads of one unit and those systems required for concurrent safe shutdown of the second unit.
If off-site power is available, the LOCA signal in one unit and a false LOCA signal in the other will shed 2 RHR motors and 2 core spray motors of each unit and sequentially start 2 RHR and 2 core spray motors as shown in Table 8.3-lb.
This is done in order not to exceed the utilization voltage limitation of connected equipment and to provide at least the minimum core cooling requirements of both units. Under the modified core cooling arrangement, 2 RHR pumps (one in each loop) and 2 core spray pumps (both in the same loop) will satisfy the minimum cooling requirements of each unit. Approximately ten minutes after the above event the operator will be able to determine which is the false-LOCA unit and shutdown non-essential loads in the non-LOCA unit. In case off-site power is not available, the loading is the same as discussed above, but the sequencing is slightly altered as shown in Table 8.3-lb."
As stated in the FSAR, the diesel generators are not dedicated to a specific unit or unit's loads. Loss of any one of the four aligned diesel generators, without replacement by the fifth diesel, permits LOCA shutdown response on one unit, while also permitting non-LOCA safe shutdown on the other unit.
From a design basis standpoint, loss of either the A and C diesels or the B and D diesels, without replacement by the fifth diesel, will permit the non-LOCA safe shutdown on both units. As stated in, Reference 1, PPL is committing to have Diesel Generator 'V' available for substitution for any of the four normally aligned diesel generators. With the Diesel Generator 'E' available for substitution, the failure of any two diesels will assure a division of electrical power is available and will allow non-LOCA safe shutdown on both units.
Response to 6b The response to question 6a addresses this question. Note that the same equipment may be used to mitigate the event in both units given that the equipment either has the capacity or the analysis has accounted for half the capacity. PPL does not credit common equipment unless the equipment has the capability to provide mitigation functions to both units.
to PLA-6526 Revised List of Regulatory Commitments to PLA-6526 Page 1 of 4 REVISED LIST OF REGULATORY COMMITMENTS The following table identifies those actions committed to by PPL Susquehanna in PLA-6480, dated March 24, 2009. Based on questions received on May 29, 2009, from the NRC, this list of regulatory commitments is revised. Additions are shown in bold italics and deletions are shown by s.
Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Ms. Brenda W. O'Rourke.
REGULATORY.COMMITMENTS D
Date/Event, All commitments will be applicable prior to and/or during the transformer replacement, as indicated below:
- 1. Grid and Switchyard Restrictions:
The following mitigating measures will be taken to increase the ability to identify and take appropriate actions before a problem arises with ST No. 10 during the transformer replacement:
0 Predictive maintenance trending data will be reviewed for ST No. 10.
Review of ST No. 10 corrective maintenance work order.
Engineering to trend Operator Rounds data for ST No.
10 on a weekly basis.
Engineering Inspections of ST No. 10 for obvious signs of degraded conditions will be performed. These will include:
> Visually inspect the high voltage bushings and other insulators on ST No. 10 daily.
)
Perform periodic thermography inspections of ST No. 10.
Before transformer replacement Before transformer replacement One month prior to the scheduled ST No. 20 replacement work window.
During transformer replacement to PLA-6526 Page 2 of 4 O
REGULATORYr '-MMITMENTS':
";i.
Due Date/Event Trend ST No. 10 and Bus 10 voltage levels and monitor daily.
> Perform daily engineering rounds of ST No. 10 to monitor overall performance.
" Operator Rounds (enhanced based on the INPO SOER 02-
- 3) will be increased to once per shift from once per day for ST No. 10, except for the bushing oil level check which will be done once per day.
" Activities within the confines of the plant that may result in a loss of ST No. 10 during the ST No. 20 replacement will be prohibited.
" Activities that may result in a loss of ST No. 10 during the ST No. 20 replacement will be prohibited.
" For the duration of the ST No. 20 replacement, Transmission and Distribution Operations will NOT grant any work requests that would jeopardize the reliability of ST No. 10. This includes, but is not limited to, canceling any requests that would cause ST No. 10 to operate in a radial manner.
" Geomagnetic activity from solar storms will be monitored.
- 2. The SSES risk management process will assess the risk impacts of planned and emergent work during the ST No.
20 replacement.
- 3. PPL will take into consideration plant conditions, including other equipment out of service, and implementation of compensatory actions to assure adequate defense-in-depth while ST No. 20 is replaced.
- 4. The following systems and components will be required to be available during the ST No. 20 replacement to reduce the plant risk. Elective maintenance will not be performed on these systems and components. Any failed system or component will be returned to available status as soon as During transformer replacement During transformer replacement During transformer replacement During transformer replacement Before and during transformer replacement During transformer replacement During transformer replacement Prior to beginning and during transformer replacement to PLA-6526 Page 3 of 4
"..REGULATORY COMMITMENTS Due Date/Event possible. (The failed system/component shall be worked around the clock.) 1-f.n..f th1-8 System.
r O....Of.t.
pr m tly a poa r SI P tov=a 3L Q=Czon to k d trI n f12 a
h roanovalid, and withint 1n h0ur-, oontaot tha AN12C Station Portable Diesel Gen - Blue Max Diesel Generator A ESS 480V Motor Control Diesel Generator B ESS 480V Motor Control i1o Gcno.....
'A'*O Diooo1 Gon.ra.o 'B'h
" Diesel Generator 'E' U-1 125V DC Battery Charger 1D613 U-1 125V DC Battery Charger 1D623
" RHR LOOP A Injection OB ISO VLV, (Unit 1)
" RHR LOOP A Injection Flow Control VLV, (Unit 1)
" RHR LOOP B Injection Flow Control VLV, (Unit 1)
" RHR LOOP B Injection OB ISO VLV, (Unit 1)
" U-2 125V DC Battery Charger 2D613
" U-2 125V DC Battery Charger 2D623
" RHR LOOP A Injection Flow Control VLV, (Unit 2)
" RHR LOOP A Injection OB ISO VLV, (Unit 2)
" RHR LOOP B Injection OB ISO VLV, (Unit 2)
RHR LOOP B Injection Flow Control VLV, (Unit 2)
" RHR/RHRSW Cross Tie Valves, (Unit 1)
RHR/RHRSW Cross Tie Valves, (Unit 2)
HPCI (UNIT 1)
" HPCI (UNIT 2)
" RCIC (UNIT 1)
RCIC (UNIT 2)
- 5. If any of the below listed equipment is OOS for the listed Prior to beginning reason, the ST No. 20 maintenance work will not transformer replacement commence, and the 10 day LCO for ST No. 20 will not be entered until such time as the equipment is restored to service.
to PLA-6526 Page 4 of 4 S-.*REGULATORY COMMITMENTS-Due Date/Event- :-
" Any suppression chamber to drywell vacuum breakers being open
" Inability to perform suppression pool cooling by either division
" Unavailability of any ESWpump
" Unavailability of any RHR pump
" The containment vent valves HVi(2)5703 or HVi(2)5704 are known to be failed closed (i.e., the valves can not be manually opened).
- 16. If ST No. 10 degrades, SSES will immediately evaluate During transformer the impact to determine operability of ST No. 10.
replacement