ML090220324

Proposed Technical Specification (TS) Amendment TS 3.3.1, Reactor Trip System (RTS) Instrumentation

ML090220324
Person / Time
Site:	Catawba
Issue date:	01/20/2009
From:	Morris J Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML090220324 (58)

Text

P Duke JAMES R. MORRIS, VICE PRESIDENT cEnergy Duke Energy Carolinas,LLC Catawba Nuclear Station Carolinas 4800 Concord Road / CN01 VP York, SC 29745 803-701-4251 803-701-3221 fax January 20, 2009 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555

Subject:

Duke Energy Carolinas, LLC (Duke)

Catawba Nuclear Station, Unit 2 Docket Number 50-414 Proposed Technical Specification (TS) Amendment TS 3.3.1, Reactor Trip System (RTS) Instrumentation Pursuant to 10 CFR 50.4, 10 CFR 50.90, and 10 CFR 50.91 (a)(6), Duke proposes a one-time exigent limited duration extension of TS Surveillance Requirement (SR) 3.3.1.4 Frequency. SR 3.3.1.4 is a Trip Actuating Device Operational Test (TADOT) of the reactor trip breakers (RTBs) and reactor trip bypass breakers. The SR Frequency was recently revised by Catawba Amendments 247/240 to 62 days on a staggered test basis. Amendments 247/240 were issued by the NRC on December 30, 2008.

On January 8, 2009, during testing of the Unit 2 RTBs, personnel discovered a problem while attempting to test Train 2A RTB. Investigation to date indicates that the problem most likely lies in the contacts associated with Train 2A reactor trip bypass breaker cubicle cell switch. As a result of this issue, SR 3.3.1.4 cannot be performed for Train 2A reactor trip breaker. Both trains of the RTS are currently fully operable.

Duke is requesting, on a one-time basis, that the SR 3.3.1.4 Frequency for RTBs be extended until March 10, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />. The planned date and time for Mode 3 is March 7, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />. This represents a one-time extension of this SR Frequency by 20 days, as the SR is currently set to expire (including applicable grace period) on February 19, 2009. The details regarding the reason that the extension request is being made for both trains is explained fully in Attachment 1 to this letter. Duke is requesting that this TS SR Frequency extension be approved via a license condition to Facility Operating License (FOL) NPF-52. A similar precedent has been established for granting a temporary TS Completion Time extension at Catawba via a license condition. This extension will allow the repair of Train 2A reactor trip bypass breaker cubicle cell switch to be performed during the refueling outage and will prevent an unnecessary transient shutdown cycle of Unit 2.

www. duke-energy. corn

U. S. Nuclear Regulatory Commission January 20, 2009 Page 2 of 5 Unit 2 is currently at 100% power. Therefore, in order to avoid the unnecessary shutdown of Unit 2, Duke requests approval of this proposed license amendment on a one-time exigent basis by February 15, 2009. provides the technical information necessary to support this amendment request. contains the existing FOL pages marked up to show the proposed change. contains the retyped (clean) FOL pages. Attachment 4 contains a Catawba Probabilistic Risk Analysis (PRA) technical adequacy discussion. This request is considered a risk-informed license amendment request in accordance with NRC Regulatory Guides 1.174, 1.177, and 1.200.

In accordance with Duke administrative procedures and the Quality Assurance Program Topical Report, this proposed amendment has been previously reviewed and approved by the Catawba Plant Operations Review Committee and the Corporate Nuclear Safety Review Board.

Implementation of this amendment request will not require changes to the Catawba Updated Final Safety Analysis Report (UFSAR).

There are no regulatory commitments associated with this amendment request.

Pursuant to 10 CFR 50.91, a copy of this proposed amendment is being sent to the appropriate State of South Carolina official.

By copy of this letter, Duke is also notifying the NRC of an administrative error introduced during the issuance of Amendments 248/241 on January 9, 2009. Amendments 248/241 were followup amendments to Amendments 247/240. On page 4 of the FOL pages for the units, the amendment numbers were inadvertently reversed. Unit 1 (FOL NPF-35) should actually be Amendment 248 and Unit 2 (FOL NPF-52) should actually be Amendment 241. Duke is requesting that the NRC correct this error at the earliest opportunity.

Should you have any questions concerning this information, please call R. D. Hart at (803) 701-3622 or L. J. Rudy at (803) 701-3084.

Very truly yours, James R. Morris LJR/s Attachments

U. S. Nuclear Regulatory Commission January 20, 2009 Page 3 of 5 James R. Morris affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.

Jam" Morris, Vice President Subscribed and sworn to me: V/Z2O1 6 Oate Nold Pui My commission expires:

/Date

" ONy 7

0 LPNzOy4*

U. S. Nuclear Regulatory Commission January 20, 2009 Page 4 of 5 xc (with attachments):

L. A. Reyes, Region II Administrator U. S. Nuclear Regulatory Commission Sam Nunn Atlanta Federal Center, 23 T85 61 Forsyth St., SW Atlanta, GA 30303-8931 J. H. Thompson, Project Manager (CNS)

U. S. Nuclear Regulatory Commission 11555 Rockville Pike Mail Stop 8G9A Rockville, MD 20852-2738 A. T. Sabisch, Senior Resident Inspector U. S. Nuclear Regulatory Commission Catawba Nuclear Station S. E. Jenkins, Section Manager Division of Radioactive Waste Management Bureau of Land and Waste Management Department of Health and Environmental Control 2600 Bull Street Columbia, SC 29201

Commission Regulatory Nuclear S.

U.

20, 2009 January 5 of 5 Page (with attachments):

bxc (CNO IVP)

R.

J. Morris (CN01SM)

J.W. Pitesa (CNOISA)

T.M. Hamilton (CNOIRC)

R.D. Hart (CNOIRC)

L. J. Rudy (CNOIRC)

A. F. DriverJr. (EC05P)

R. L. Gill, (MGOIRC)

K. L. Ashe NCMPA-1 NCEMC PMPA File 801.01 Control Document RGC File ELL-EC050

ATTACHMENT 1

SUMMARY

DESCRIPTION DETAILED DESCRIPTION TECHNICAL JUSTIFICATION REGULATORY EVALUTION ENVIRONMENTAL ASSESSMENT

1.0

SUMMARY

DESCRIPTION Pursuant to 10 CFR 50.4, 10 CFR 50.90, and 10 CFR 50.91(a)(6), Duke proposes a one-time exigent limited duration extension of TS SR 3.3.1.4 Frequency. TS SR 3.3.1.4 is a TADOT of the RTBs and bypass breakers. The SR Frequency is 62 days on a staggered test basis. The requested extension would allow continued operation of Unit 2 for 20 days. The current SR is set to expire (including applicable grace period) on February 19, 2009.

On January 08, 2009, at approximately 0900 hours0.0104 days <br />0.25 hours <br />0.00149 weeks <br />3.4245e-4 months <br />, while performing alignment of Train 2A reactor trip bypass breaker, unexpected conditions were experienced in preparation for Train 2A RTB/SSPS testing. Investigation to date indicates that the problem is likely related to contacts associated with the bypass breaker cubicle cell switch. It has been determined that maintenance on the cubicle cell switch cannot be conducted with Unit 2 at power. Catawba plans to perform this maintenance during the upcoming Unit 2 End of Cycle 16 Refueling Outage scheduled to begin on March 7, 2009. In order to avoid an unnecessary shutdown of Unit 2, Duke requests approval of this one-time exigent license amendment request by February 15, 2009.

1.1 Background

The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and reactor coolant system pressure boundary during anticipated operational occurrences and to assist the engineered safety features systems in mitigating accidents.

Reactor trip switchgear, including the RTBs and reactor trip bypass breakers, provides the means to interrupt power to the control rod drive mechanisms and allows the control rods to fall into the core and shut down the reactor. The bypass breakers allow testing of the RTBs while the unit is at power.

The RTB TS required Functions must be operable in Mode 1 or 2 when the reactor is critical. In Mode 3, 4, or 5, the RTB TS required Functions must be operable when the RTBs or associated bypass breakers are closed, and the control rod drive system is capable of rod withdrawal.

TS SR 3.3.1.4 is a TADOT of the RTBs and bypass breakers. This SR must be performed on each bypass breaker prior to placing the breaker in service. The SR Frequency is 62 days on a staggered test basis.

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2.0 DETAILED DESCRIPTION On January 8, 2009, at approximately 0900 hours0.0104 days <br />0.25 hours <br />0.00149 weeks <br />3.4245e-4 months <br />, Unit 2 RTB/SSPS testing was being conducted. When the testing personnel attempted to rack in Train 2A reactor trip bypass breaker, they noted that the breaker was harder to rack in than in the past. They stopped work and notified supervision and thecontrol room. The.breaker was removed from the cubicle and was evaluated.

Due to the problem with the breaker, Unit 1 Train IB reactor trip bypass breaker was moved to Train 2A reactor trip bypass breaker's cubicle. Unit 2 RTB and SSPS testing was again initiated. Train 2A reactor trip bypass breaker was racked in and closed. After closing the breaker, personnel obtained unexpected testing results. They again stopped and notified supervision and the control room.

After evaluation, Train 2A reactor trip bypass breaker was opened and racked out per the restoration portion of the applicable procedure.

This issue was documented in Catawba Problem Investigation Process (PIP) C-09-00135.

Investigation to date indicates that the problem most likely lies in the contacts associated

• with the breaker cubicle cell switch. The cell switch in question provides Train 2A P-4 (reactor trip) signal to the safety functions of turbine trip and main feedwater isolation when Train 2A RTB is open and the bypass breaker is not racked in and closed. It also interfaces with non-safety related systems such as the condenser steam dump system and the main feedwater pump speed control system. The cell switch believed to be the problem does not affect the operation (i.e., open/close function) of any RTB itself. The SSPS General Warning feature is also supported by this cell switch. This feature trips the reactor if both trains of SSPS/RTBs are placed in the test/bypass mode simultaneously.

The postulated failure mechanism was evaluated for transportability to other Unit 2 trains/components and to Unit 1. The failure mechanism was determined to be limited to the identifiedcell switch. Other failure mechanisms ruled out by the transportability evaluation included human error, problems with the testing equipment, andproblems with the breaker itself.

Despite the fact that the failure mechanism itself is limited to Train 2A reactor trip bypass breaker cubicle cell switch, regulatory relief is also being requested for the SR 3.3.1.4 Frequency as it applies to Train 2B RTB/SSPS testing. Testing of the RTB as described in the UFSAR requires the testing of the trip function of the opposite train's bypass breaker. Racking Train 2A reactor trip bypass breaker to the TEST position may disturb the suspect cell switch and generate a General Warning Alarm. Since the other train is also bypassed at this time, this would generate a reactor trip. Based on the last successful performance of SR 3.3.1.4 on December 4, 2008 (for Train 2B), the latest date for which this SR can next be performed (including applicable grace period) is February 19, 2009, 2

which is prior to the start of the Unit 2 End of Cycle 16 Refueling Outage (March 7, 2009). Therefore, it is necessary to request relief from the SR 3.3.1.4 Frequency for both trains. Note that relief is being requested until March 10, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />. Although Mode 3 of the refueling outage is currently targeted to be achieved on March 7, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />, an extra 3 days has been incorporated into this request to account for any unexpected delays in achieving Mode 3.

Relevant Maintenance and Testing History Concerning RTBs and Bypass Breakers Following are prior examples of RTB/bypass breaker cell switch problems at Catawba:

On May 26, 1991, with Unit 1 in Mode 5, a main feedwater isolation occurred during racking out activities of the Train A reactor trip bypass breaker.

Operations personnel had previously started the Manual Reactor Trip Functional Test, but stopped to pursue higher priority work. Later, after shift change, Operations personnel resumed the procedure to align the breakers for Engineered Safety Features (ESF) Train A testing. During this alignment, the reactor trip bypass breaker was racked from the connect to the disconnect position. During breaker transit, the Operator heard relays activating and the apparent closure of main feedwater isolation valves. The main feedwater isolation was immediately reset and the valves were realigned for ESF testing. No problems were found with the breaker.

On September 23, 2004, the cell switch lever for RTB 2A was angled to the left rather than aligning at a right angle to the switch shaft. This had not caused any problem during operation, but it was misaligned enough that it needed to be corrected. The breaker contact plate must strike the cell switch lever in the proper position when the breaker is racked into the cubicle. A work order (WO) was written to correct this deficiency. When Maintenance personnel checked a cell switch kit out of the warehouse, the same problem was found with the new parts.

Initial examination indicated the lever was defective and did not orient squarely on the switch shaft. Engineering personnel inspected the three other cell switch kits in the warehouse and none of the others had the alignment problem. One of the good kits was checked out to use for the repair and the defective one was held for followup action. It appears that the lever installed in the RTB 2A cubicle and the first one checked out of the warehouse had the same problem. The levers in the other Unit 2 RTB cubicles were aligned properly.

On September 7, 2006, during RTB/SSPS testing, relay X4B failed to energize when Train lB reactor trip bypass breaker was racked out. Per the applicable procedure, Maintenance personnel notified the control room that the runback circuit for both feedwater pumps to minimum speed was defeated for a reactor trip. Also, the main feedwater pump recirculation valve (1CF6 and 1CF 13) automatic opening on a reactor trip would not have occurred due to the relay malfunction defeating the circuit. A review of the circuit concluded that the most 3

likely failed components were the cell switch (33) or the auxiliary relay (X4B).

Other than conductors (wiring), a cell switch, and the X4B relay, there were no other components in the circuit. The cell switch is a cam operated mechanism in the breaker cubicle that operates during the racking in or out of the breaker. It provides a closed contact to the relay X4B to energize it when the breaker is racked out. To determine the likely cause, a voltage measurement was to be performed to determine if the cell switch had actually provided the relay a signal to energize. When Maintenance personnel returned to the switchgear on the following day to perform the voltage measurement, the relay was found already energized (i.e., in its normal configuration). A monitoring frequency was established to provide additional assurance that the circuit would perform.

On November 16, 2006, a new cell switch to be installed in a RTB cubicle was found with cracked mounting threads. RTB cell switches are being replaced according to a "5R" frequency (every fifth refueling outage) switch replacement program. Each switch is mounted to a bracket in the breaker cubicle with two cap screws. The screws are inserted into threaded holes in the switch base. From a pre-installation inspection of one of the new switches, a Maintenance technician found a crack in the threads of one hole in the switch base. This switch was tagged not to be used and was turned over to Engineering personnel. No other new cell switches were found with this problem.

For the cell switch issue identified in this amendment request (Train 2A reactor trip bypass breaker cell switch), the planned method of repair is to remove and repair or replace the cell switch (either the complete assembly or the affected components).

As part of routine scheduled preventive maintenance, this cell switch was replaced in September 2007 during the Unit 2 End of Cycle 15 Refueling Outage and in March 2000 during the Unit 2 End of Cycle 10 Refueling Outage. Review of Train 2B and the equivalent Unit 1 trains identified the following preventive maintenance history (no corrective maintenance history was identified). The preventive maintenance replacement frequency is every fifth refueling outage (approximately every 7.5 years).

lA RTB Cell Switch Model WO 00882624 1EOC16 WO 01125193 1EOCl I WO 00945449 1EOC05 WO 00883354 1B RTB Cell Switch Model WO 00882625 1EOC16 WO 01125194 1EOCl1 WO 00945450 lEOC05 WO 00883355 2A RTB Cell Switch Model WO 00880400 2EOC15 WO 01726214 2EOC10 WO 00960668 2B RTB Cell Switch Model WO 00880402 2EOC15 WO 01726216 2EOC 10 WO 00960670 4

lA Bypass Cell Switch Model WO 00882623 lEOC16 WO 01125192 lB Bypass Cell Switch Model WO 00882626 lEOC16 WO 01125195 1EOCI1 WO 00945451 lEOC05 WO 00883356 2B Bypass Cell Switch Model WO 00880403 2EOC15 WO 01726217 2EOC10 WO 00960671 Since all Catawba RTBs and bypass breakers are identical and interchangeable, the last three years of test results for all breakers was reviewed. A total of 80 tests of RTBs and bypass breakers were successfully completed and all breakers properly opened in response to all diverse trip signals.

Summary of RTB tests from January 1, 2006 through December 31, 2008:

Trip Breaker Number of Tests Number of Failures IA 19 0 lB 20 0 2A 20 0 2B 21 0 Total 80 0 The system health associated with RTBs has been "green" since the second trimester of 2006. The system health was "yellow" in the first trimester of 2006 due to a problem with a RTB occurring during Unit 1 RTB/SSPS testing on March 23, 2006. Train IB RTB spuriously opened; no cause could be determined. The breaker was replaced with a spare. The breaker was examined by the vendor and the cause could not be determined.

The breaker was returned to the Unit 1 RTB B cubicle on July 13, 2006 and has passed all surveillance tests since being returned to service.

2.1 Intended Resolution of Proposed Amendment 10 CFR 50.91 (a)(6) states that where the NRC finds that exigent circumstances exist, in that a licensee and the NRC must act quickly and that time does not permit the publishing of a Federal Register notice allowing 30 days for prior public comment, and it also determines that the amendment involves no significant hazards considerations, the NRC will either issue a Federal Register notice providing for a limited period of opportunity for public comment or will utilize alternate means of communication as necessary to allow for public comment. The NRC will also require the licensee to explain the exigency and why the licensee cannot avoid it.

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2.2 Reason Exigent Situation Has Occurred Previous performances of SR 3.3.1.4 have been successful until this situation unexpectedly occurred on January 8, 2009. Upon discovery of this issue, Duke contacted the NRC to verbally provide all relevant available, information. Catawba management took appropriate action in support of a resolution to this issue. This license amendment request was developed and submitted after this situation occurred. However, due to the impending expiration of the SR 3.3.1.4 Frequency on February 19, 2009, insufficient time exists for processing this amendment request through normal channels. Sufficient time exists for processing this amendment request through exigent channels as delineated in 10 CFR 50.91 (a)(6).

2.3 Description of Proposed Changes Duke proposes the following license condition in Appendix B, Additional Conditions, for FOL NPF-52:

Amendment Number TBD Additional Condition The SR 3.3.1.4 Frequency of"62 days on a STAGGERED TEST BASIS" as it applies to Train 2A and Train 2B reactor trip breaker testing may be extended on a one-time basis to March 10, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />, upon which Unit 2 shall be in Mode 3 with reactor trip breakers open for the End of Cycle 16 Refueling Outage. Upon entry into Mode 3 with reactor trip breakers open for this refueling outage, this license condition shall expire.

Implementation Date February 19, 2009 3.0 TECHNICAL JUSTIFICATION Duke has qualitatively and quantitatively evaluated the risk impact for extending TS SR 3.3.1.4 a total of 20 days for both Train 2A and Train 2B reactor trip bypass breakers from February 19, 2009 until March 10,-2009.

Qualitative Assessment It was qualitatively determined that the overall risk impact on the requested SR Frequency extension was expected to be minimal since the Anticipated Transient Without-Scram (ATWS) contribution to the Core Damage Frequency (CDF) is less than 1% (reference 6

Duke LAR submittal to NRC dated December 11, 2007 to relax completion times and surveillance test intervals for the RTS and ESFAS) and the contribution to the Large Early Release Frequency (LERF) is less than 4%.

Additionally, the current PRA model reflects failure probabilities that support a 31-day staggered test basis Frequency for SR 3.3.1.4. When the 62-day staggered test basis surveillance test interval is implemented, the failure probabilities for reactor trip breakers (including common cause failure) will be based on the revised failure probabilities from NUREG/CR-5500, Vol. 2 (INEEL/EXT-97-00740), "Reliability Study: Westinghouse Reactor Protection System, 1984-1995", December 1998 as utilized in WCAP- 15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times", March 2003, which are about one order of magnitude lower than the current failure probabilities.

The net effect of this change will be to further reduce the importance of these components and their impact on this application. From the above, it is qualitatively assessed that the individual reactor trip breakers are of very low risk significance and that a surveillance test interval extension of 20 days would not affect this qualitative assessment.

Quantitative Assessment The subject SR verifies proper operation of the bypass breaker prior to it being placed in service. Upon failure of the cell switch, a turbine trip or a feedwater isolation signal would be generated. This initiates a reactor trip from full power. For the purposes of the PRA, extension of the surveillance test interval leads directly to an increased failure probability for the basic event, reactor trip breakers fail to open. The PRA directly models this condition.

Since the proposed extension is being requested for both Train 2A and Train 2B RTBs, the common cause event, QRPBKRSCOM, CCF of Reactor Trip Breakers To Open, is used for the analysis. The nominal base case probability of this occurrence is 1.6E-05.

The analysis consists of using an elevated failure probability for this event corresponding to the requested extension duration, and calculating the increase in CDF and LERF and comparing it to the base case CDF and LERF to obtain the dCDF and the dLERF.

The choice of the revised failure probability is made using the methodology discussed in the Industry Implementation Guidance for TSTF-358, Revision 6, "Missed Surveillance Requirements", TSTF-IG-06-01. The resultant conclusion that if a surveillance test interval is doubled, then for the second half of the interval (i.e., the extended part) the average failure probability of the event in question is three times the average failure probability of the first half of the interval is used. This assumes the increase in failure probability is linear. This can be graphically seen below:

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Fgure 2 Rela*o*sip Betweer Falure Probabhtrydd Teat Period for Fail-re MisSed Suroediaeces Probabibiy Failure motrabIbgIf Fadure moiaehtyIf a

SR petfrmri w0 SRr risaed se'udle 2ST Perform SR rere 312 AT Revised Average Falrtae mrot for

,miee SR 3

It Peaorm SR above

• er, Failure moo tare if foOG SR mioadied 1,1 AT Average (Base ceae PRA)

F.Irri mob -Ad I PRA V2?

TIo period Using the above to ratio the failure probability to the extension, a revised failure probability for QRPBKRSCOM for a 20-day extension is calculated as:

(20/62) x (4.8E-05-1.6E-05) + 1.6E-05 = 2.6E-05 This revised value when substituted into the PRA model provided the following results.

CDF/rx-yr CDFbase/rx-yr dCDF/rx-yr 1.850E-05 1.844E-05 6.OE-08 LRF/rx-yr ILERFbase/rx-yr dLERF/rx-yr

ý 1.29E-06 1.247E-06 3.2E-08 The values obtained represent a negligible increase in risk and meet Regulatory Guide 1.174 guidelines.

A sensitivity study is performed by multiplying the original failure probability for QRPBKRSCOM by a factor of 3 to obtain a revised failure probability of 4.8E-05. This value represents a surveillance test interval extension of 62 days. When substituted into the PRA model the results are:

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Sensitivity Case:

CDF/rx-yr CDFbase/rx-yr dCDF/rx-yr 1.862E-05 1.844E-05 1.8E-07 LERF/rx-yr LERFbase/rx-yr dLERF/rx-yr 1.348E-06 1.247E-06 1.OE-07 As before, the values obtained represent a very small increase in risk when compared to the guidelines in Regulatory Guide 1.174.

The sequences are all ATWS (initiated by loss of load or loss of feedwater) as expected.

Conclusion The calculated dCDF and dLERF values represent negligible increases in risk when compared to the Regulatory Guide 1.174 guidelines. As noted earlier, these results are conservative since they do not use the lower failure probabilities that are supportive of the 62-day staggered test basis Frequency for SR 3.3.1.4. The qualitative and quantitative assessments are in agreement and support a one-time 20-day extension for SR 3.3.1.4 for both Train 2A and Train 2B RTBs.

4.0 REGULATORY EVALUATION

4.1 Applicable Regulatory Requirements/Criteria Applicable regulatory requirements are contained in 10 CFR 50, Appendix A, General Design Criteria 20, 21, 22, and 23. These are stated below.

Criterion20--Protectionsystem functions. The protection system shall be designed (1) to ihitiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences and (2) to sense accident conditions and to initiate the operation of systems and components important to safety.

Criterion21--Protectionsystem reliabilityand testability. The protection system shall be designed for high functional reliability and inservice testability commensurate with the safety functions to be performed. Redundancy and independence designed into the protection system shall be sufficient to assure that (1) no single failure results in loss of the protection function and (2) removal from service of any component or channel does not result in loss of the required minimum redundancy unless the acceptable reliability of operation of the protection system can be otherwise demonstrated. The protection system shall be designed to permit periodic testing of its functioning when the reactor is in

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operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred.

Criterion22--Protectionsystem independence. The protection system shall be designed to assure that the effects of natural phenomena, and of normal operating, maintenance, testing, and postulated accident conditions on redundant channels do not result in loss of the protection function, or shall be demonstrated to be acceptable on some other defined basis. Design techniques, such as functional diversity or diversity in component design and principles of operation, shall be used to the extent practical to prevent loss of the protection function.

Criterion23--Protectionsystem failure modes. The protection system shall be designed to fail into a safe state or into a state demonstrated to be acceptable on some other defined basis if conditions such as disconnection of the system, loss of energy (e.g., electric power, instrument air), or postulated adverse environments (e.g., extreme heat or cold, fire, pressure, steam, water, and radiation) are experienced.

These four criteria will continue to be complied with for the duration of the operating cycle upon NRC granting approval of this amendment request. Both RTS trains and all RTS protection functions (including P-4) remain fully operable and all required redundancy continues to be maintained. The RTS continues to remain fully testable (apart from the identified issue) and the postulated failure mechanism is not transportable to other trains/components of Unit 2 or to Unit 1. In addition, even if the suspect reactor trip bypass breaker cell switch were to change state, this does not impact the operability of the automatic or manual reactor trip functions.

4.2 Precedent Amendments 247/240, issued by the NRC on December 30, 2008, extended the SR 3.3.1.4 Frequency to 62 days on a staggered test basis. The amendment request submitted herein, following approval by the NRC, will provide for a one-time extension of the current 62-day surveillance test interval.

4.3 Evaluation of Significant Hazards Considerations Duke has concluded that operation of Catawba Unit 2 in accordance with the proposed license condition does not involve a significant hazards consideration. Duke's conclusion is based upon its evaluation, in accordance with 10 CFR 50.91(a)(1), of the three standards set forth in 10 CFR 50.92(c).

Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

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Response: No.

The Reactor Trip System (RTS) serves as accident mitigation equipment and is not required to function unless an accident occurs. The reactor trip bypass breakers are utilized to support testing of the reactor trip breakers (RTBs) while at power. This equipment does not affect any accident initiators or precursors. The proposed extension of the Technical Specification (TS) Surveillance Requirement (SR) 3.3.1.4 Frequency for RTBs does not affect its interaction with any system whose failure or malfunction could initiate an accident. Therefore, the probability of an accident previously evaluated is not significantly increased.

The risk evaluation performed in support of this amendment request demonstrates that the consequences of an accident are not significantly increased. As such, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

Does the proposed amendment create the possibility of a new or different kind of accident from any previously evaluated?

Response: No.

This change does not create the possibility of a new or different kind of accident from any accident previously evaluated. No new accident causal mechanisms are created as a result of the NRC granting of this proposed change. No changes are being made to the plant which will introduce any new or different accident causal mechanisms.

Does the proposed amendment involve a significant reduction in the margin of safety?

Response: No.

Based on the availability of the RTS equipment and the low probability of an accident, Catawba concludes that the proposed extension of the surveillance test interval does not result in a significant reduction in the margin of safety.

The margin of safety is related to the confidence in the ability of the fission product barriers to perform their design functions during and following an accident situation.

These barriers include the fuel cladding, the reactor coolant system, and the containment system. The performance of these fission product barriers will not be significantly impacted by the proposed change. The risk implications of this request were evaluated and found to be acceptable.

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4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the NRC's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL ASSESSMENT The proposed change does not involve a significant hazards consideration, a significant change in the types of or significant increase in the amounts of effluents that may be released offsite, or a significant increase in individual or cumulative occupational radiation exposure. Therefore, the proposed change meets the eligibility criteria for the categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), an environmental assessment of the proposed change is not required.

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ATTACHMENT 2 MARKED-UP CATAWBA FOL PAGES

(2) Technical Specifications S .The.Technical Spe~@ ations contained in Appendix A, as revised through Amendment .No, *j)which are attached hereto, are hereby incorporated into this renewed operaITg license. Duke Energy Carolinas, LLC shall operate'the facility in accordance with the Technical Specifications.

(3), Updated Final Safety.Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002,. describes certain future activities to be completed before the period of extended operation. Duke shall complete these activities no later than February 24, 2026, and shall notify the NRC in writing when implementation of these activities is complete and can be

-verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall- be included In the, next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following issuance of this renewed operating license. Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

(4) Antitrust Conditions Duke Energy Carolinas, LLC shall comply with the antitrust conditions delineated in Appendix C to this renewed operating license.

(5) Fire-Protection Program (Section 95.1, SER, SSER#2, SSER #3, SSER #4, SSER #5)° Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final.Safety Analysis Report, as amended; for the facility and 'as approved in the SER through Supplement 5, subject to the following provision:

The licenseermay make changes to the approved fire protection program without prior approval of the Commission' only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.'

• 'The parenthetical notation following the title of this renewed operating license condition denotes the section of the Safety Evaluation Report and/or its supplements wherein' this renewed license condition is discussed.

Renewed License No. NPF-52...

Amendment No._

..(6) .. ititi Strategqies

.Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

(a) Fire fighting response strategy with the following elements:

1i. Pre-defined coordinated fire response strategy and guidance

2. Assessment of mutual aid fire fighting assets

3. Designated staging areas for equipment and materials

4. Command and control

5. Training of response personnel (b) Operations to mitigate fuel damage considering the following:

1. Protection and use of personnel assets

2. Communications

3. Minimizing fire spread

4. Procedures for implementing integrated fire response strategy

5. Identification of readily-available pre-staged equipment

6. Training on integrated fire response strategy

7. Spent fuel pool mitigation measures

.(c) Actions to minimize release to include consideration of:

1. Water spray scrubbing

2. Dose to onsite responders (7) Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No.0 are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

D. The facility requires exemptions from certain requirements of Appendix J to 10 CFR Part 50, as delineated below and pursuant to evaluations contained in the referenced SER and SSERs. These include, (a) partial exemption from the requirement of paragraph IIl.D.2(b)(ii) of Appendix J, the testing of containment airlocks at times when the containment integrity is not required (Section 6.2.6 of the SER, and SSERs # 3 and #4),

(b) exemption from the requirement of paragraph III.A.(d) of Appendix J, insofar as it requires the venting and draining of lines for type A tests (Section 6.2.6 of SSER #3), and (c) partial exemption from the requirements of paragraph lll.B of Appendix J, as it relates to bellows testing (Section 6.2.6 of the SER and SSER #3). These exemptions are authorized by law, will not present an undue risk to the public health and safety, are consistent Renewed License No- NPF 52 Amendment No.

Amendment Implementation Number Additional Condition Date 165 The schedule for the performance of new and By January 31, 1999 revised surveillance requirements shall be as follows:

For surveillance requirements (SRs) that are new in Amendment. No. 165 the first performance is due at the end of the first surveillance interval that begins at implementation of Amendment No. 165. For SRs that existing prior to Amendment No. 165, including SRs with modified acceptance criteria and SRs who intervals of performance are being extended, the first performance is due at the end of the first surveillance interval that begins on the date the surveillance was last performed prior to implementation of amendment No. 165. For SRs that existed prior to Amendment No. 165, whose intervals of performance are being reduced, the first reduced surveillance interval begins upon completion of the first surveillance performed after implementation of Amendment No. 165 172 The maximum rod average burnup for any rod Within 30 days of shall be limited to 60 GWd/mtU until the date of amendment.

completion of an NRC environmental assessment supporting an increased limit.

This amendment requires the licensee to use Prior to any entry administrative controls, as described in the into Mode 4 during licensee's letter of April 30, 2007, and Cycle 16 operation 233 evaluated in the Staff's Safety Evaluation dated October 31, 2007, to restrict the primary to secondary leakage through any one steam generator to 75 gallons per day and through all steam generators to 300 gallons per day (in lieu of the limits in TS Sections 3.4.13d. and 5.5.9b.3.), for Cycle 16 operation.

or'J INAiY-%r Pne' (eIv rl)Gg).

Renewed License No. NPF-52 Amendment No. 233 Amendment Implementation Number Additional Condition Date The SR 3.3.1.4 Frequency of "62 days on a February 19, 2009 STAGGERED TEST BASIS" as it applies to Train 2A and Train 2B reactor trip breaker testing may be extended on a one-time basis to March 10, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />, upon which Unit 2 shall be in Mode 3 with reactor trip

-breakers open for the End of Cycle 16 Refueling Outage. Upon entry into Mode 3 with reactor trip breakers open for this refueling outage, this license condition shall expire.

Renewed License No. NPF-52 Amendment No.

ATTACHMENT 3 RETYPED (CLEAN) CATAWBA FOL PAGES

(2) Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No which are attached hereto, are hereby incorporated into this renewed operating license. Duke Energy Carolinas, LLC shall operate the facility in accordance with the Technical Specifications.

(3) Updated Final Safety Analysis Report The Updated Final Safety Analysis Report supplement submitted pursuant to 10 CFR 54.21(d), as revised on December 16, 2002, describes certain future activities to be completed before the period of extended operation. Duke shall complete these activities no later than February 24, 2026, and shall notify the NRC in writing when implementation of these activities is complete and can be verified by NRC inspection.

The Updated Final Safety Analysis Report supplement as revised on December 16, 2002, described above, shall be included in the next scheduled update to the Updated Final Safety Analysis Report required by 10 CFR 50.71(e)(4), following issuance of this renewed operating license. Until that update is complete, Duke may make changes to the programs described in such supplement without prior Commission approval, provided that Duke evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

(4) Antitrust Conditions Duke Energy Carolinas, LLC shall comply with the antitrust conditions delineated in Appendix C to this renewed operating license.

(5) Fire Protection Program (Section 9.5.1, SER, SSER #2, SSER #3, SSER #4, SSER #5)*

Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report, as amended, for the facility and as approved in the SER through Supplement 5, subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

• The parenthetical notation following the title of this renewed operating license condition denotes the section of the Safety Evaluation Report and/or its supplements wherein this renewed license condition is discussed.

Renewed License No. NPF-52 Amendment No.

(6) Mitigation Strategies Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

(a) Fire fighting response strategy with the following elements:

1. Pre-defined coordinated fire response strategy and guidance

2. Assessment of mutual aid fire fighting assets

3. Designated staging areas for equipment and materials

4. Command and control

5. Training of response personnel (b) Operations to mitigate fuel damage considering the following:

1. Protection and use of personnel assets

2. Communications

3. Minimizing fire spread

4. Procedures for implementing integrated fire response strategy

5. Identification of readily-available pre-staged equipment

6. Training on integrated fire response strategy

7. Spent fuel pool mitigation measures (c) Actions to minimize release to include consideration of:

1. Water spray scrubbing

2. Dose to onsite responders (7) Additional Conditions The Additional Conditions contained in Appendix B, as revised through Amendment No. , are hereby incorporated into this renewed operating license.

Duke Energy Carolinas, LLC shall operate the facility in accordance with the Additional Conditions.

D. The facility requires exemptions from certain requirements of Appendix J to 10 CFR Part 50, as delineated below, and pursuant to evaluations contained in the referenced SER and SSER. These include: (a) partial exemption from the requirement of paragraph III.D.2(b)(ii) of Appendix J, the testing of containment airlocks at times when the containment integrity is not required (Section 6.2.6 of SSER #5), (b) exemption from the requirement of paragraph III.A.1 (d) of Appendix J, insofar as it requires the venting and draining of lines for type A tests (Section 6.2.6 of SSER #5), and (c) partial exemption from the requirements of paragraph 111.B of Appendix J, as it relates to bellows testing (Section 6.2.6 of the SER and SSER #5). These exemptions are authorized by law, will not present an undue risk to the public health and safety, are consistent Renewed License No. NPF-52 Amendment No.

Amendment Implementation Number Additional Condition Date The SR 3.3.1.4 Frequency of "62 days on a February 19, 2009 STAGGERED TEST BASIS" as it applies to Train 2A and Train 2B reactor trip breaker testing may be extended on a one-time basis to March 10, 2009 at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />, upon Which Unit 2 shall be in Mode 3 with reactor trip breakers open for the End of Cycle 16 Refueling Outage. Upon entry into Mode 3 with reactor trip breakers open for this refueling outage, this license condition shall expire.

Renewed License No. NPF-52 Amendment No.

ATTACHMENT 4 CATAWBA PRA TECHNICAL ADEQUACY DISCUSSION J

Review of Outstanding PRA Model Change Administrative controls exist to assure plant changes are reflected in the PRA model.

Outstanding plant changes not yet reflected in the model, and whether those would impact this analysis have been reviewed. The following five items were noted as applying to this analysis but having negligible impact on this analysis.

PRA Description Affect on Current Change No. Calculation C-09-0002 LAR 247/240 implemented a change to SR 3.3.1.4 Risk decrease. Current model is surveillance test interval from 31 days staggered test basis bounding.

to 62 days staggered test basis. The analysis by West.

utilized NUREG/CR-5500 data that are smaller than that used in the current model. Model needs to be revised to reflect this change.

C-07-0016 Add alternate feedwater makeup line to each Many of the cut sets S/G. (Reference Letter to NRC 2/26/07) involve a failure of SSHR.

This would be a risk reduction because of adding a new way to get feedwater to the steam generators. Therefore the current model is bounding.

C-07-0007 Consider not applying operator recovery event A review of the LERF cut XHM 1A 1BDHE, "Operators Fail to Supply sets indicates that there are Power to Hydrogen Igniters," to ATWS only three fast-acting sequences in which the time to core damage is ATWS sequences that relatively short. include operator action XHM1A1BDHE. The maximum cut set value is 1.8E-09. This has an insignificant impact on the results. (This recovery is not included in the CDF model.)

C-06-0003 Hydrogen igniter logic in the LERF model uses The LERF is overestimated the wrong power logic, by less than 1E-09/year.

Insignificant impact on present analysis.

C-05-0022 Missing failure modes for certain air-operated The omitted failure modes valves (AOVs) in the KC system fault tree and would be relatively small the CA system fault tree. contributors to CA system I unavailability and therefore I

do not have a significant impact on the present analysis.

PRA Technical Adequacy Discussion Regulatory Guide 1.200 Assessment In accordance with American Society of Mechanical Engineers, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications", ASME-RA-Sc-2007 and with Regulatory Guide 1.200, Duke has made an assessment of all the ASME Supporting Requirements (SRs).

This assessment is documented in approved procedures.

The Catawba PRA fully meets 224 of the 306 ASME PRA Standard Supporting Requirements (SRs), as modified by Regulatory Guide 1.200. In addition, 24 of the SRs are not applicable to the Catawba PRA, either because the referenced techniques are not utilized in the PRA or because the SR is not required for Capability Category II.

Of the 58 open SRs, 15 are of a technical nature. The remaining open SRs require enhanced documentation. However, none of the open items are expected to have a significant impact on the PRA results or insights, as discussed in Table A-I in the Supporting Documents section.

PRA Model The Catawba PRA is a full scope PRA including both internal and external events. The model includes the necessary initiating events (e.g., LOCAs, transients) to evaluate the frequency of accidents. The previous reviews of the Catawba PRA, NRC and peer reviews have not identified deficiencies related to the scope of initiating events considered.

The Catawba PRA includes models for those systems needed to estimate core damage frequency.

These include all of the major support systems (e.g., ac power, service water, component cooling, and instrument air) as well as the mitigating systems (e.g., emergency core cooling). These systems are generally modeled down to the component level, pumps, valves, and heat exchangers. This level of detail is sufficient for this application.

Truncation Limit Truncation limit is not an issue with this risk calculation. The analysis for the current configuration was performed at the same truncation level as the base case (5.OE-10 for CDF and 5.OE-11 for LERF). The event of interest was set to 1.0 initially in the analysis to ensure cut sets were not inappropriately being truncated when the final value was used. There is adequate representation of the expected failure in the results (appears in every cut set) and all appearances of the event in cut sets do not appear within a factor of 10 of the truncation limit. A sensitivity study determined that the Regulatory Guide 1.174 risk guidelines were met for this analysis.

Additionally, an explicit truncation limit analysis was performed for Revision 3a of the PRA 2

consistent with ASME standard and Regulatory Guide 1.200 requirements to ensure truncation limit would not be an issue for most applications.

Uncertainty and Sensitivity Duke agrees with the Regulatory Guide 1.177 statement that risk analyses of completion time extensions are relatively insensitive to uncertainties and that similar results are expected for surveillance test interval changes. The PRA did not credit equipment repair so there are no uncertainties to be evaluated for that issue. The sensitivity analysis presented in the technical justification addresses the important assumptions made in the submittal and shows that the risk resulting from the proposed surveillance test interval extension is relatively insensitive to uncertainties.

Results of Reviews with Respect to this LAR A review of the analyses (cut sets and pertinent accident sequences) post processing was made for accuracy and completeness. The process applied in post processing the cut sets for this analysis is identical to that utilized in the base case PRA. No changes to the post processing of cut sets are made for this analysis. This process is documented in Duke procedures.

Consistent with the work place procedures governing PRA analysis, this calculation has undergone independent checking by a qualified reviewer. Additionally the Catawba Plant Operations Review Committee (PORC) and Duke Nuclear Safety Review Board (NSRB) reviewed and approved the original license amendment request package.

Tier 2 and Tier 3 Discussion Tier 2 Assessment: Avoidance of Risk-significant Plant Equipment Outage Configurations Tier 2 provides reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is out of service consistent with the proposed TS change.

Duke has several Work Process Manual procedures and Nuclear System Directives, that are in place at Catawba Nuclear Station to ensure that risk-significant plant configurations are avoided.

The key documents are as follows:

• Nuclear System Directive 415, "Operational Risk Management (Modes 1-3) per 10 CFR 50.65 (a.4)".

• Nuclear System Directive 403, "Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10 CFR 50.65 (a.4)".

" Work Process Manual, WPM-609, "Innage Risk Assessment Utilizing ORAM-SENTINEL".

" Work Process Manual, WPM-608, "Outage Risk Assessment Utilizing ORAM-SENTINEL".

The proposed changes are not expected to result in any significant changes to the current configuration risk management program. The existing program uses a blended approach of quantitative and qualitative evaluation of each configuration assessed. The Catawba on-line 3

computerized risk tool, ORAM-Sentinel, considers both internal and external initiating events with the exception of seismic events. Thus, the overall change in plant risk during maintenance activities is expected to be addressed adequately in accordance with Regulatory Guide 1.174 and 1.177 considering the proposed surveillance test interval extension period.

Tier 3 Assessment: Maintenance Rule Configuration Control 10 CFR 50.65(a)(4), Regulatory Guide 1.182, and NUMARC 93-01 require that prior to performing maintenance activities, risk assessments shall be performed to assess and manage the increase in risk that may result from proposed maintenance activities. These requirements are applicable for all plant modes. NUMARC 91-06 requires utilities to assess and manage the risks that occur during the performance of outages.

As stated above, Duke has approved procedures and directives in place at Catawba to ensure the requirements of the Maintenance Rule are implemented. These documents are used to address the Maintenance Rule requirements, including the on-line (and off-line) Maintenance Policy requirement to control the safety impact of combinations of equipment removed from service.

More specifically, the Nuclear System Directives address the process; define the program, and state individual group responsibilities to ensure compliance with the Maintenance Rule. The Work Process Manual procedures provide a consistent process for utilizing the computerized software assessment tool, ORAM-SENTINEL, which manages the risk associated with equipment inoperability.

ORAM-SENTINEL is a Windows-based, computer program designed by the Electric Power Research Institute as a tool for plant personnel to use to analyze and manage the risk associated with all risk significant work activities including assessment of combinations of equipment removed from service. It is independent of the requirements of Technical Specifications and Selected Licensee Commitments.

The ORAM-SENTINEL models for Catawba are based on a "blended" approach of probabilistic and traditional deterministic approaches. The results of the risk assessment include a prioritized listing of equipment to return to service, a prioritized listing of equipment to remain in service, and potential contingency considerations.

Additionally, prior to the release of work for execution, Operations personnel must consider the effects of severe weather and grid instabilities on plant operations. This qualitative evaluation is inherent of the duties of the Work Control Center Senior Reactor Operator (SRO). Responses to actual plant risk due to severe weather or grid instabilities are programmatically incorporated into applicable plant emergency or response procedures.

4

External Events Discussion The Catawba PRA is a full scope model that includes both internal and external events. The following is a list of the reviews conducted on the PRA modeling which assures the technical adequacy of the existing PRA model with respect to external events:

• A peer review sponsored by the Electric Power Research Institute (EPRI) was conducted on the original Catawba PRA.

• An SER has been received on the IPE and IPEEE for Catawba.

• In March 2002, a peer review of the Catawba PRA was conducted as part of the WOG PRA Certification Program.

• In August 2008, a PRA Technical Adequacy Self-Assessment was conducted against the Supporting Requirements (SRs) in the ASME standard (American Society of Mechanical Engineers, "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications," ASME-RA-Sc-2007) and Regulatory Guide 1.200 for Catawba.

These previous reviews did not identify deficiencies related to the scope of external initiating events considered. No fundamental plant weaknesses or vulnerabilities with regard to external events were identified during the IPEEE examination for Catawba. There were no plant changes identified from the IPEEE that would significantly reduce the risk from external events. The seismic, fire, and tornado modeling that exists in the Catawba PRA is at the level of detail used to support the IPE and IPEEE submittals and is consistent with the ASME standard and Regulatory Guide 1.200 supporting requirements.

In general it has been noted previously (reference Duke LAR submittal to NRC dated December 11, 2007 to relax completion times and surveillance test intervals for the RTS and ESFAS) that RTS actuation signal failures or unavailabilities are very small contributors to the CDF for external events. For this specific application, the generated cut sets from this analysis that went into the dCDF and dLERF values were all ATWS sequences. Cut sets involving external events (i.e., fire, high winds, external flooding, and other external events) that were generated as a result of the increased failure probability of the basic event used to justify the proposed extension were also part of the base case CDF, and as such were eliminated from the final results in the calculation of the dCDF and the dLERF.

Seismic has a negligible effect on this analysis since the seismic frequency is low and the frequency of a seismic event combined with an ATWS is even lower and therefore very unlikely.

Additionally, other key plant equipment and supporting systems are more susceptible to the impact of a seismic event than the reactor vessel internals.

5

'ba PRA - Open ASME PRA Standard Supporting Requirements Technicaor Expected Impact on Metfor CNS? CNSRef Resolution Documentation Application u~t realisuc, appilcaoIe ki.e., irom similar plants) Catawba No impact is expected thermal hydraulic analyses to determine the Thermal- since success criteria are Perform analyses with the accident progression parameters (e.g., timing, Hydraulic consistent with peer plants AS-A9 Partial most up-to-date version of Technical temperature, pressure, steam) that could potentially Success per the PWROG PSA MAAP.

affect the operability of the mitigating systems. Criteria Database' (See SC-B4.) calcs.

For parameter estimation, GROUP components Catawba according to type (e.g., motor-operated pump, air- Failure Rate Revise the data calc. to This is a refinement to the operated valve) and according to the characteristics Database, segregate standby and equipment failure rates.

DA-B 1 of their usage to the extent supported by data: (a) Partial CNC- operating component data. Technical However, since most mission type (e.g., standby, operating) (b) service 1535.00 Segregate components by components are grouped condition (e.g., clean vs. untreated water, air) 0029, Rev. service condition to the appropriately, the overall 2, January extent supported by the data. impact should be small.

2006 EXAMINE coincident unavailability due to Developing maintenance for redundant equipment (both PRA Data, intrasystem and intersystem) based on actual plant Workplace Put in place a mechanism experience. CALCULATE coincident maintenance Procedure for identifying and The on-line risk tool unavailabilities that reflect actual plant experience. XSAA-110, quantifying coincident (ORAM-SENTINEL) and Such coincident maintenance unavailability can Rev. 4, July unavailabilities. Incorporate exstngplNTprEsses existing plant processes DA- arise, for example, for plant systems that have 2007; in the system models those and procedures are C13 "installed spares," i.e., plant systems that have more Partial Catawba maintenance events allowed Technical sufficient to identify high redundancy than is addressed by tech specs. For Component by technical specifications risk configurations. No example, the charging system in some plants has a Failure Rate where 2 or more significant impact on this third train that may be out of service for extended Denominato components have application.

periods of time coincident with one of the other r Estimates, maintenance events that are application.

trains and yet is in compliance with tech specs. SAAG 492, correlated with each other.

December L 1997 6

"" .. . . Technical or'T

• "*Resoechnialoo Expecte~d Impact on' Met for CNS? CNS Ref. Resolution Documentation

{Application Eppaction IDENTIFY, through a review of procedures and practices, those calibration activities that if performed incorrectly can have an adverse impact on the automatic initiation of standby safety equipment.

Based on preliminary evaluations using the EPRI HRA calculator, calibration errors that result in failure of a single channel are expected to Catawba fall in the low 10-3 range.

Human Calibration errors that Reliability result in failure of Analysis, Enhance the HRA to HR-A2 multiple channels are Partial CNC- consider the potential for Technical expected to fall in the low 1535.00 calibration errors.

10-5 range. Relative to 0030, Rev.

post-initiator HEPs, 0, December equipment random failure 2005 rates and maintenance unavailability, calibration HEPs are not expected to contribute significantly to overall equipment unavailability.

7

IDENTIFY which of those work practices identified above (HR-Al, HR-A2) involve a Met for CNS? CNS Ref.

_ _ _ _ _ _ I _ _

Resolution Technical or.

Documentation Ep

_Application pact on Relative to post-initiator HEPs, equipment random mechanism that simultaneously affects equipment in failure rates and either different trains of a redundant system or maintenance Identify maintenance and diverse systems [e.g., use of common calibration unavailability, calibration calibration activities that equipment by the same crew on the same shift, a HEPs are not expected to maintenance or test activity that requires could simultaneously affect HR-A3 No Technical contribute significantly to equipment in either different realignment of an entire system (e.g., SLCS)]. overall equipment trains of a redundant system unavailability. See the or diverse systems.

Expected Impact on Applications for requirement HR-A2 above.

PROVIDE an assessment of the uncertainty in the Pre-initiator HEPs are HEPs. USE mean values when providing point generally set to relatively estimates of HEPs. Develop mean values for high screening values.

HR-D6 of HEPs. Technical Thus the suggested data opre-initiator HEPs. refinement is not expected to have a significant impact on this application.

Characterize the uncertainty in the estimates of the Use of mean values for HEPs, and PROVIDE mean values for use in the HEPs is expected to result quantification of the PRA results. in an increase in post-initiator HEP values, in the base case model as well as for applications.

HR-G39 No Develop mean values for Technical However, a quantitative post-initiator HEPs. sensitivity study was performed for this application that showed that the resulting risk is very small compared to Regulatory Guide 1.174 guidelines.

8

Mfobr CNS?-, 'CN!$SRe ReottoDocumntaf~ion Resoluion hiato~ xetepplication REVIEW the plant-specific initiating event Initiating events (other experience of all initiators to ensure that the list of than ATWS) result in a challenges accounts for plant experience. See also plant trip and the IE-A7 generation of an LER.

These events are reviewed Catawba as part of the initiating Internal events analysis. Fire and Initiator Perform a review of the flood events that don't Event plant-specific initiating result in a reactor trip Frequency event experience of all could potentially impact IE-A3 Partial Technical Data, CNC- initiators to ensure that the the frequencies assigned 1535.00 list of challenges accounts to the fire and flood 0031, Rev. for plant experience. initiators. However, fire 0, January and flood sequences are 2006 not significant contributors to the delta CDF in the PRA analysis for the LAR. Thus this open SR does not have a significant imnact.

9

Technical or',,"

-Expected Impact on MeIt for CN .S? CNSR Ref. :Reslution, Documentation Applcto For each flood area not screened out using the For those flood areas requirements under IF-B Ib, IDENTIFY the SSCs addressed in the current located in each defined flood area and IF-A2) along flooding analysis, equipment flood propagation paths that are modeled in the important to accident internal events PRA model as being required to mitigation and the respond to an initiating event or whose failure associated critical flood would challenge normal plant operation, and are heights are identified.

susceptible to flood. For each identified SSC, Catawba However, given the IDENTIFY, for the purpose of determining its Flood expected increase in number Internal flood sequences susceptibility per IF-C3, its spatial location in the Analysis, of flood areas needed to are not significant area and any flooding mitigative features (e.g., CNC- satisfy requirement IF-A1, contributors in the present IF-C2c Partial Technical shielding, flood or spray capability ratings). 1535.00 additional equipment will analysis. No significant 0058, Rev. need to be identified and, impact associated with 0, December discussed in order to meet this open SR.

2005 the requirements of the ASME Standard. The current flooding analysis does not discuss flood mitigative features and this will have to be corrected to satisfy the requirements of the ASME Standard.

For the SSCs identified in IF-C2c, IDENTIFY the The current flooding Internal flood sequences susceptibility of each SSC in a flood area to flood- Catawba analysis identifies the are not significant induced failure mechanisms. INCLUDE failure by Flood submergence failure height contributors in the present submergence and spray in the identification Flood of the equipment important analysis. No significant process. ASSESS qualitatively the impact of flood- Analysis, to accident mitigation, but impact associated with IF-C3 induced mechanisms that are not formally Partial CNC - never addresses the impact Technical this open SR.

addressed (e.g., using the mechanisms listed under 1535.00 of spray. Spray as a failure Capability Category III of this requirement), by 0058, Rev, mechanism needs to be using conservative assumptions. 2005 0, Decembe adesdi h analysis addressed in the nlsso or a note made explaining why it was omitted.

10

Technical or Expected Impact on Met for CNS? CNS Ref. Resolution Documentation Ex Appeication iLflrN i ir i inter-area propagation mrougn me Internal flood sequences normal flow path from one area to another via drain Catawba Provide more analysis of are not significant lines; and areas connected via back flow through Flood flood propagation contributors in the present drain lines involving failed check valves, pipe and Analysis, flowpaths. Address analysis. No significant cable penetrations (including cable trays), doors, CNC- potential structural failure of impact associated with IF-C3b Partial Technical stairwells, hatchways, and HVAC ducts. INCLUDE 1535.00 doors or walls due to this open SR.

potential for structural failure (e.g., of doors or 0058, Rev. flooding loads and the walls) due to flooding loads and the potential for 0, December potential for barrier barrier unavailability, including maintenance 2005 unavailability.

activities.

INCLUDE, in the quantification, both the direct Catawba Internal flood sequences effects of the flood (e.g., loss of cooling from a Flood are not significant service water train due to an associated pipe Analysis, contributors in the present IFE6b rupture) and indirect effects such as submergence, Partial CNC- Address potential indirect Technical analysis. No significant jet impingement, and pipe whip, as applicable. 1535.00 effects. impact associated with 0058, Rev. this open SR.

0, December

-_ 2005 PERFORM a containment bypass analysis in a The conservative realistic manner. JUSTIFY any credit taken for Perform plant-specific T/H treatment will not mask scrubbing (i.e., provide an engineering basis for the calculations for SGTR. the contribution of non-decontamination factor used). Catawba Consider some credit for bypass events, because Simplified ISLOCA scrubbing; if no even if some credit were LERF credit can be given, then this given to scrubbing, the LE- Partial Methodolog should be documented. It is Technical unscrubbed bypasses Clo y, SAAG not known whether or not would still dominate 817, Rev. 1, the additional analysis will LERF over the non-October alter the LERF, but because bypass events. In 2004 these items dominate LERF, addition, the limiting risk a more realistic analysis metric in the present should be considered. analysis is CDF, not LERF.

11

N Ru Technical or Expected Impact on Met for CNS CNS Ref. Resolution Documentation I "Applicatio'n' In crediting HFEs that support the accident The only operator action progression analysis, USE the applicable expected to be important is Catawba This issue affects some requirements of para. 4.5.5, as appropriate for the RCS depressurization for Simplified small LOCAs. Because level of detail of the analysis. small LOCAs. However, LERF the small LOCA the current analysis lacks a Methodolog contribution to LERF is LE-C6 Partial formal dependency analysis Technical y, SAAG small, there is no for this action. The result is 817, Rev. 1, significant impact expected to be insensitive to October associated with this open this impact given that the 2004 SR.

SGTR so dominates the result.

PERFORM a realistic interfacing system failure probability analysis for the significant accident Catawba For MNS/CNS, the ND heat progression sequences resulting in a large early ISLOCA exchanger is assumed tosequences are release. USE a conservative or a combination of Analysis, provide the largest break not significant LE-D3 conservative and realistic evaluation of interfacing No CNC- flow area. The ISLOCA is a Technical contributors in the present system failure probability for non-significant 1535.00 coanalysis. No significant accident progression sequences resulting in a large 0053, Rev. dominant contributor and impact associated with early release. INCLUDE behavior of piping relief 0, January the evaluation is relatively this open SR.

valves, pump seals, and heat exchangers at 2006 conservative.

applicable temperature and pressure conditions.

For each accident sequence, IDENTIFY the Cut set review during model phenomenological conditions created by the Catawba integration and when accident progression. Phenomenological impacts Rev 3a PRA supporting applications include generation of harsh environments affecting Model should address this. Suggest temperature, pressure, debris, water levels, Integration adding this guidance to Phenomenological effects AS-B3 humidity, etc. that could impact the success of the Partial Notebook, workplace procedure Documentation are already considered in system or function under consideration [e.g., loss of CNC- XSAA-103. the model.

pump net positive suction head (NPSH), clogging 1535.00 of flow paths]. INCLUDE the impact of the 0061, Rev.

accident progression phenomena, either in the 2, July 2006 accident sequence models or in the system models.

12

Met for CNS? CNS Ref.

Resolution

~~~~~Technical Documentation or ExetdIpcon Expected Impact on I DocmenttionApplication F--, 1'I.iDLI*3ri Uei11IUIlI11s 01 - UUUIIUU-IICS, IallUrc modes, and success criteria consistent with Catawba Failure Rate corresponding basic event definitions in Systems Analysis (SY-A5, SY-A7, SY-A8, SY-AlO through Database, Revise the data calc. to DA- CNC- No impact is expected for SY-A13 and SY-B4) for failure rates and common No discuss component Documentation Ala 1535.00 documentation issues.

cause failure parameters, and ESTABLISH boundaries definitions.

boundaries of unavailability events consistent with 0029, Rev.

corresponding definitions in Systems Analysis (SY- 2, January 2006 A18).

DO NOT INCLUDE outliers in the definition of a Catawba group (e.g., do not group valves that are never Failure Rate Revise the data calc. to tested and unlikely to be operated with those that Database, include a specific discussion DA-B2 are tested or otherwise manipulated frequently) Partial CNC- of outlier treatment (i.e., do Documentation No impact is expected for 1535.00 any outliers exist? If so, documentation issues.

0029, Rev. how are these events 2, January considered and grouped?)

2006 13

• "* Technical or

• Expected Impact~on Met for CNS? CNS Ref. Resolution Documentation E p p action 9 Application When the Bayesian approach is used to derive a distribution and mean value of a parameter, CHECK that the posterior distribution is reasonable given the relative weight of evidence provided by the prior and the plant-specific data. Examples of tests to ensure that the updating is accomplished Catawba correctly and that the generic parameter estimates PRA are consistent with the plant-specific application Common Enhance the documentation include the following: (a) confirmation that the Cause to include a discussion of Bayesian updating does not produce a posterior Analysis, the specific checks No impact is expected for DA-D4 Partial Documentation distribution with a single bin histogram (b) CNC- performed on the Bayesian- documentation issues.

examination of the cause of any unusual (e.g., 1535.00 updated data, as required by multimodal) posterior distribution shapes (c) 0028, Rev. this SR.

examination of inconsistencies between the prior 0, December distribution and the plant-specific evidence to 2005 confirm that they are appropriate (d) confirmation that the Bayesian updating algorithm provides meaningful results over the range of values being considered (e) confirmation of the reasonableness of the Dosterior distribution mean value USE generic common cause failure probabilities Catawba Provide documentation in consistent with available plant experience. PRA SAAG 637 of the EVALUATE the common cause failure Common comparison of the probabilities consistentboundaries.

with the component Cause compon ofnthe Analysis, ~~component boundariesNoipciseetdfr Partial Analysis, assumed for the generic Documentation No impact is expected for DA-D6 boundaries. CNC- CC siae otoedocumentation issues.

CCF estimates to those 1535.00 assumed in the Catawba 0028, Rev. PRA to ensure that these 0, December boundaries are consistent.

2005 14

MI Technical or Expected Impact on Met for CNS? -

Resolution CNS Ref.- IDocumentation Resolut.on. [ Application When estimating HEPs EVALUATE the impact of the following plant-specific and scenario-specific performance shaping factors: (a) quality [type (classroom or simulator) and frequency] of the operator training or experience (b) quality of the Catawba written procedures and administrative controls (c) Human availability of instrumentation needed to take Reliability Document in more detail the corrective actions (d) degree of clarity of the Analysis, influence of performance No impact is expected for HR-G3 meaning of the cues/indications (e) human-machine Partial CNC- Documentation shaping factors on execution documentation issues.

interface (0)time available and time required to 1535.00 human error probabilities.

complete the response (g) complexity of detection, 0030, Rev.

diagnosis and decision-making, and executing the 0, December required response (h) environment (e.g., lighting, 2005 heat, radiation) under which the operator is working (i) accessibility of the equipment requiring manipulation (j) necessity, adequacy, and availability of special tools, parts, clothing, etc.

BASE the time available to complete actions on Catawba appropriate realistic generic thermal-hydraulic Human analyses, or simulation from similar plants (e.g., Reliability plant of similar design and operation) (See SC-B4.). Analysis, Enhance HRA No impact is expected for HR-G4 SPECIFY the point in time at which operators are Partial CNC- documentation accordingly. Documentation documentation issues.

expected to receive relevant indications. 1535.00 0030, Rev.

0, December 2005 CHECK the consistency of the post-initiator HEP Document a review of the quantifications. REVIEW the HFEs and their final HFEs and their final HEPs HEPs relative to each other to check their relative to each other to HR-G6 reasonableness given the scenario context, plant No confirm their reasonableness Documentation No impact is expected for history, procedures, operational practices, and given the scenario context, documentation issues.

experience, plant history, procedures, operational practices, and experience.

15

Metfr Nn Technical or Expected Impact on 14Metfor CM. CNS RefL Resolution Documentation K A c

,L-isUL i operator recovery acuons only i1, on a Catawba plant-specific basis: (a) a procedure is available and Human Develop more detailed operator training has included the action as part of Reliability documentation of operator crew's training, or justification for the omission for cues, relevant performance Analysis, one or both is provided (b) "cues" (e.g., alarms) that No impact is expected for HR-H2 Partial CNC- shaping factors, and Documentation alert the operator to the recovery action provided documentation issues.

1535.00 availability of sufficient procedure, training, or skill of the craft exist (c) 0030, Rev. manpower to perform the attention is given to the relevant performance 0, December action.

shaping factors provided in HR-G3 (d) there is 2005 sufficient mannower to Derform the action IDENTIFY those initiating events that challenge Catawba normal plant operation and that require successful Internal mitigation to prevent core damage using a Initiator structured, systematic process for identifying Event initiating events that accounts for plant-specific Frequency Enhance the IE Partial Data, CNC- documentation (as was done Documentation No impact is expected for features. For example, such a systematic approach may employ master logic diagrams, heat balance 1535.00 documentation issues.

fault trees, or failure modes and effects analysis 0031, Rev. i OSC-9068).

(FMEA). Existing lists of known initiators are also 0, January commonly employed as a starting point. 2006; Systems Analysis REVIEW generic analyses of similar plants to Catawba assess whether the list of challenges included in the Internal Ensure the list of challenges model accounts for industry experience. Initiator included in the Catawba Event PRA accounts for industry IE-A3a Partial Frequency experience using a more Documentation No impact is expected for Data, CNC- recent reference, such as the documentation issues.

1535.00 WOG PSA Model and 0031, Rev. Results Comparison 0, January Database - Revision 4.

2006 I_ II 16

Technical or Expected Impact on Met for CNS? CNS Ref. Resolution Documentation Appec ation Aplcto rtLKI uKm a systematic evatuation or eacn system Catawba where necessary (e.g., down to the subsystem or Provide documentation of a Internal train level), including support systems, to assess the systematic evaluation of all Initiator possibility of an initiating event occurring due to a plant systems, including Event failure of the system. USE a structured approach support systems (including Frequency No impact is expected for IE-A4 [such as a system-by-system review of initiating Partial those not explicitly modeled Documentation Data, CNC- documentation issues.

event potential, or an FMEA (failure modes and in the PRA), to assess the 1535.00 effects analysis), or other systematic process] to possibility of an initiating 0031, Rev.

assess and document the possibility of an initiating event occurring due to a 0, January event resulting from individual systems or train failure of the system.

2006 failures.

When performing the systematic evaluation Catawba required in IE-A4, INCLUDE initiating events Internal resulting from multiple failures, if the equipment Initiator failures result from a common cause, and from Event Enhance the IE IE-A4a system alignments resulting from preventive and Partial Frequency documentation (as was done Documentation No impact is expected for corrective maintenance. Data, CNC- documentation issues.

1535.00 in OSC-9068).

0031, Rev.

0, January 2006 In the identification of the initiating events, Catawba INCORPORATE (a) events that have occurred at Internal conditions other than at-power operation (i.e., Initiator during low-power or shutdown conditions), and for Event Enhance the IE IDA5 which it is determined that the event could also Partial Frequency documentation (as was done Documentation No impact is expected for occur during at-power operation. (b) events Data, CNC- in OSC-9068). documentation issues.

resulting in a controlled shutdown that includes a 1535.00 scram prior to reaching low-power conditions, 0031, Rev.

unless it is determined that an event is not 0, January applicable to at-power operation. 2006 17

Met for CNS? - " ' CNS

".. *Ref.

. *"I i * '

Resolution ,*,Technical or Documentation EExpected pce lImpact pcoon

f. RsoluionDocuentaionApplication 1- 1 IB S V 1Z W piaIi pers oUnneI kV.g., opraULIUon5, maintenance, engineering, safety analysis) to Obtain plant personnel input No impact is expected for IE-A6 No. Documentation determine if potential initiating events have been (as was done in OSC-9068). documentation issues.

overlooked.

REVIEW plant-specific operating experience for Catawba initiating event precursors, for the purpose of Internal identifying additional initiating events. For Initiator example, plant specific experience with intake Event Include review of precursor IE-A7 structure clogging might indicate that loss of intake Partial Frequency events for their potential to Documentation No impact is expected for structures should be identified as a potential Data, CNC- be initiating eventsi documentation issues.

initiating event. 1535.00 0031, Rev.

0, January 2006 COMBINE initiating events into groups to facilitate definition of accident sequences in the Accident Enhance the IE No impact is expected for IE-BI Sequence Analysis element (para. 4.5.2) and to No documentation (as was-done Documentation documentation issues.

facilitate quantification in the Quantification in OSC-9068).

element (para. 4.5.8).

USE a structured, systematic process for grouping Catawba initiating events. For example, such a systematic Internal approach may employ master logic diagrams, heat Initiator balance fault trees, or failure modes and effects Event Document a structured, IE-B2 analysis (FMEA). Partial Frequency systematic grouping of Documentation No impact is expected for Data, CNC- initiating events (as was documentation issues.

1535.00 done in OSC-9068).

0031, Rev.

0, January 2006 18

I Technical or Met for CNS? CNS Ref. Resolution Documentation Expected Impact on esou on 9Application GROUP initiating events only when the following can be assured: (a) events can be considered similar Catawba in terms of plant response, success criteria, timing, Internal and the effect on the operability and performance of Initiator operators and relevant mitigating systems; or (b) Event Enhance documentation of events can be subsumed into a group and bounded Frequency No impact is expected for IE-B3 Partial the grouping process (as was Documentation by the worst case impacts within the "new" group. Data, CNC- documentation issues.

done in OSC-9068).

DO NOT SUBSUME events into a group unless: 1535.00 (1) the impacts are comparable to or less than those 0031, Rev.

of the remaining events in that group, AND (2) it is 0, January demonstrated that such grouping does not impact 2006 significant accident sequences.

DOCUMENT the assumptions and sources Enhance the IE No impact is expected for IE-D3 uncertainty with the initiating event analysis. No documentation (as was done Documentation documentation issues.

in OSC-9068).

For each source and its identified failure Catawba Enhance the Internal Flood mechanism, IDENTIFY the characteristic of release Flood analysis to address the and the capacity of the source. INCLUDE: (a) a Analysis, potential for spray, jet IF-B3 characterization of the breach, including type (e.g., Partial CNC- impingement, and pipe whip Documentation No impact is expected for leak, rupture, spray) (b) range of flow rates (c) 1535.00 failures. Additionally, documentation issues.

capacity of source (e.g., gallons of water) (d) the 0058, Rev. document how these failures pressure and temperatureof the source 0, December are'included in the 2005 quantification.

19

M N Resolution R Technical or ected Impact on Met i6CNS?. CNS Ref. A, Resolution Documentation

__________________-I________________ __________-Application DOCUMENT the process used to identify flood sources, flood areas, flood pathways, flood scenarios, and their screening, and internal flood model development and quantification. For example, this documentation typically includes (a) flood sources identified in the analysis, rules used to screen out these sources, and the resulting list of sources to be further examined (b) flood areas used in the analysis and the reason for eliminating areas from further analysis (c) propagation pathways between flood areas and assumptions, calculations, or other bases for eliminating or justifying propagation pathways (d) accident mitigating Catawba Flood features and barriers credited in the analysis, the Analysis, Need to document how the extent to which they were credited, and associated justification (e) assumptions or calculations used in CNC- analysis addressed all of the No impact is expected for IF-F2 Partial Documentation 1535.00 items identified in this documentation issues.

the determination of the impacts of submergence, spray, temperature, or other flood-induced effects 0058, Rev. requirement.

on equipment operability (f) screening criteria used 0, December in the analysis (g) flooding scenarios considered, 2005 screened, and retained (h) description of how the internal event analysis models were modified to model these remaining internal flooding scenarios (i) flood frequencies, component unreliabilities/unavailabilities, and HEPs used in the analysis (i.e., the data values unique to the flooding analysis) 0) calculations or other analyses used to support or refine the flooding evaluation (k) results of the internal flooding analysis, consistent with the quantification requirements provided in HLR OU-D 20

• 'I eLUnilcMi or '

'ipce iulpuvL on-

.met for.C-NS? ,,CNýS Ref. -Resoluitioni "Docurnentation' .

tionIA A, 'tpic-P PROVIDE uncertainty analysis that identifies th( Catawba sources of uncertainty and includes sensitivity Simplified studies for the significant contributors to LERF. LERF Methodolog y, SAAG 817, Rev. 1, Perform and document October sensitivity studies to 2004; determine the impact of the No impact is expected for LE-F2 Partial Catawba documentation issues.

assumptions and sources of Rev 3a PRA model uncertainty on the Model LERF results.

Integration Notebook, CNC-1535.00 0061, Rev.

t 2, July2006 + +

IDENTIFY contributors to LERF and characterize LERF uncertainties consistent with the applicable requirements of Tables 4.5.8-2(d) and 4.5.8-2(e).

NOTE: The supporting requirements in these tables Catawba are written in CDF language. Under this Simplified requirement, the applicable requirements of Table LERF Compare LERF results and 4.5.8 should be interpreted based on LERF, Methodolog uncertainties to similar No impact is expected for LE-F3 Partial Documentation including characterizing key modeling uncertainties y, SAAG plants and include in the documentation issues.

associated with the applicable contributors from 817, Rev. 1, LERF documentation.

Table 4.5.9-3. For example, supporting requirement October QU-D5 addresses the significant contributors to 2004 CDF. Under this requirement, the contributors would be identified based on their contribution to LERF.

21

Met for CNS?, CNS Ref. Resolution TDocumentation Technical or, Expected Impact on DOCUMENT the relative contribution of Catawba contributors (i.e., plant damage states, accident Simplified progression sequences, phenomena, containment LERF Evaluate the relative challenges, containment failure modes) to LERF. Methodolog contribution of the various No impact is expected for LE-G3 Partial Documentation y, SAAG contributors to the total documentation issues.

817, Rev. 1, LERF.

October 2004 DOCUMENT assumptions and sources of Catawba uncertainty associated with the LERF analysis, Simplified Perform and document including results and important insights from LERF sensitivity studies to LE-G4 sensitivity studies. Partial Methodolog determine the impact of the Documentation No impact is expected for y, SAAG assumptions and sources of documentation issues.

817, Rev. 1, model uncertainty on the October LERF results.

2004 IDENTIFY limitations in the LERF analysis that Include in the LERF would impact applications. documentation an assessment that identifies No impact is expected for the limitations in the LERF documentation issues.

analysis that could impact applications.

DOCUMENT the quantitative definition used for Catawba significant accident progression sequence. If other Simplified than the definition used in Section 2, JUSTIFY the LERF Provide a discussion of the LEG6 alternative. Partial Methodolog s fit cut sets and Documentation No impact is expected for

- y, SAAG documentation issues.

817, Rev. 1, sequences.

October 2004 COMPARE results to those from similar plants and Perform and document a QU-D3 IDENTIFY causes for significant differences. For comparison of results Documentation No impact is expected for example: Why is LOCA a large contributor for one between the CNS PRA and documentation issues.

plant and not another? other similar plants.

22

Met for N Ref.esoluTechnical or' Expected Impact on Met for CNS? CNS Ref Resolution Documentation Application

? 9fcain EVALUATE the sensitivity of the results to model Perform and document a set uncertainties and assumptions using sensitivity of sensitivity cases to analyses [Note (1)]. determine the impact of the No impact is expected for QU-E4 .No Documentation assumptions and sources of documentation issues.

model uncertainty on the results.

23

Met for CNS?

CNS Ref.

- /"-: '*

Resolution T-Techncal Technical or or Documentation

"""i Expected Impact on Application DOCUMENT the model integration process, including any recovery analysis, and the results of the quantification including uncertainty and sensitivity analyses. For example, documentation typically includes (a) records of the process/results when adding nonrecovery terms as part of the final quantification (b) records of the cutset review process (c) a general description of the quantification process including accounting for systems successes, the truncation values used, how recovery and post-initiator HFEs are applied (d) the process and results for establishing the truncation Catawba screening values for final quantification Rev 3a PRA demonstrating that convergence towards a stable Model result was achieved (e) the total plant CDF and Integration Expand the documentation No impact is expected for QU-F2 contributions from the different initiating events Partial Notebook, of CNS PRA model results documentation issues.

and accident classes (f) the accident sequences and CNC- to address all required items.

their contributing cutsets (g) equipment or human 1535.00 actions that are the key factors in causing the 0061, Rev.

accident sequences to be nonsignificant (h) the 2, July 2006 results of all sensitivity studies (i) the uncertainty distribution for the total CDF (j) importance measure results (k) a list of mutually exclusive events eliminated from the resulting cutsets and their bases for Elimination (1) asymmetries in quantitative modeling to provide application users the necessary understanding regarding why such asymmetries are present in the model (in) the process used to illustrate the computer code(s) used to perform the quantification will yield correct results process.

24

Technical or .... "

Met for CNS? CNS ReL. Resolution Documentation Expected Impact on

______ ____________ ?_______* Application DOCUMENT the quantitative definition used for Catawba significant basic event, significant cutset, significant Rev 3a PRA accident sequence. If other than the definition used Model in Section 2, JUSTIFY the alternative. Integration Document the required No impact is expected for QU-F6 Partial Notebook, Documentation definitions. documentation issues.

CNC-1535.00 0061, Rev.

2, July 2006 SPECIFY success criteria for each of the key safety Catawba functions identified per SR AS-A2 for each Thermal- Improve the documentation SCA4 modeled initiating event [Note (2)]. Partial Hydraulic on the TH bases for all No impact is expected for Success safety function success documentation issues.

Criteria criteria for all initiators.

calcs.

CHECK the reasonableness and acceptability of the results of the thermal/hydraulic, structural, or other supporting engineering bases used to support the Catawba success criteria. Examples of methods to achieve Thermal-this include: (a) comparison with results of the same Hydraulic acce eview othe D n No impact is expected for SC-B 5 analyses performed for similar plants, accounting Partial Success acceptability review of the Documentationissues.

for differences in unique plant features (b) Ccess T/H analyses is performed.

comparison with results of similar analyses Criteria performed with other plant-specific codes (c) check by other means appropriate to the particular analysis DOCUMENT the success criteria in a manner that Catawba facilitates PRA applications, upgrades, and peer Thermal- Improve the documentation SC-Cl review. Partial Hydraulic on the TH bases for all Documentation No impact is expected for Success safety function success documentation issues.

Criteria criteria for all initiators.

calcs.

25

.Technical or Expected Impact on r Documentation Met for CNS? -CNS Ref. Resolution

_ _ _ _ _ _ _ _ _ _Application .

DOCUMENT the processes used to develop overall PRA success criteria and the supporting engineering bases, including the inputs, methods, and results. For example, this documentation typically includes: (a) the definition of core damage used in the PRA including the bases for any selected parameter value used in the definition (e.g.,

peak cladding temperature or reactor vessel level)

(b) calculations (generic and plant-specific) or other references used to establish success criteria, and identification of cases for which they are used (c) Catawba identification of computer codes or other methods Thermal- Improve the documentation used to establish plant-specific success criteria (d) a Hydraulic on the TH bases for all No impact is expected for SC-C2 Partial Documentation description of the limitations (e.g., potential Success safety function success documentation issues.

Criteria criteria for all initiators.

conservatisms or limitations that could challenge calcs.

the applicability of computer models in certain cases) of the calculations or codes (e) the uses of expert judgment within the PRA, and rationale for such uses (0)a summary of success criteria for the available mitigating systems and human actions for each accident initiating group modeled in the PRA (g) the basis for establishing the time available for human actions (h) descriptions of processes used to define success criteria for grouped initiating events

~1~

or accident seauences

_________________________________________________ +/- ________________ +/- _____________ .J____________________________ I _________________ I __________________________

26

oTechnical or Expected Impact on Met for CNS? CNS Ref. Resolution Documentation Application In meeting SY-A12 and SY-A13, contributors to system unavailability and unreliability (i.e.,

components and specific failure modes) may be excluded from the model if one of the following screening criteria is met: (a) A component may be excluded from the system model if the total failure probability of the component failure modes resulting in the same effect on system operation is SY- at least two orders of magnitude lower than the System Provide quantitative No impact is expected for Partial Documentation A14 highest failure probability of the other components analyses evaluations for screening. documentation issues.

in the same system train that results in the same effect on system operation. (b) One or more failure modes for a component may be excluded from the systems model if the contribution of them to the total failure rate or probability is less than 1% of the total failure rate or probability for that component, when their effects on system operation are the same.

COLLECT pertinent information to ensure that the systems analysis appropriately reflects the as-built and as-operated systems. Examples of such information include system P&IDs, one-line diagrams, instrumentation and control drawings, spatial layout drawings, system operating System Need to update references No impact is expected for SY-A2 procedures, abnormal operating procedures, Partial Documentation analyses per XSAA- 115. documentation issues.

emergency procedures, success criteria calculations, the final or updated SAR, Technical Specifications, training information, system descriptions and related design documents, actual system operating experience, and interviews with system engineers and operators.

27

ResoltionTechnical or Exeted impact on, Met for CNS? CNS Ref. Resotion Documentation

__...__. *Application PERFORM plant walkdowns and interviews with Enhance the system system engineers and plant operators to confirm documentation to include an that the systems analysis correctly reflects the as- up-to-date system walkdown built, as-operated plant. checklist and system engineer review for each System No impact is expected for SY-A4 Partial system. Consider revising Documentation analyses documentation issues.

workplace procedure XSAA-106 to require that such documentation be revisited with each major PRA revision.

ESTABLISH the boundaries of the components required for system operation. MATCH the definitions used to establish the component failure data. For example, a control circuit for a pump does not need to be included as a separate basic event (or events) in the system model if the pump failure data Enhance systems analysis used in quantifying the system model include No impact is expected for SY-A8 No documentation to discuss Documentation control circuit failures. MODEL as separate basic documentation issues.

component boundaries.

events of the model, those subcomponents (e.g., a valve limit switch that is associated with a permissive signal for another component) that are shared by another component or affect another component, in order to account for the dependent failure mechanism.

28

foNS N f R o Technical or - Expected Impact on Met for CNS? CNS Re. Resolution Documentation

? Application Application iLiliN I ir i 3%s Lmat may oe requireu OopCrate in conditions beyond their environmental qualifications. INCLUDE dependent failures of multiple SSCs that result from operation in these adverse conditions. Examples of degraded environments include: (a) LOCA inside containment with failure of containment heat Cut set review during removal (b) safety relief valve operability (small applications should address SY- LOCA, drywell spray, severe accident) (for BWRs) System No impact is expected for Partial this. Suggest adding this Documentation B15 (c) steam line breaks outside containment (d) debris analyses documentation issues.

guidance to workplace that could plug screens/filters (both internal and procedure XSAA- 103.

external to the plant) (e) heating of the water supply (e.g., BWR suppression pool, PWR containment sump) that could affect pump operability (f) loss of NPSH for pumps (g) steam binding of pumps (h) harsh environments induced by containment venting or failure that may occur prior to the onset of core damage IDENTIFY spatial and environmental hazards that Per Duke's PRA modeling may impact multiple systems or redundant guidelines, ensure that a components in the same system, and ACCOUNT walkdown/system engineer for them in the system fault tree or the accident interview checklist is sequence evaluation. Example: Use results of plant included in each system walkdowns as a source of information regarding notebook. Based on the System No impact is expected for SY-B8 spatial/environmental hazards, for resolution of Partial results of the system Documentation analyses documentation issues.

spatial/environmental issues, or evaluation of the walkdown, summarize in the impacts of such hazards. system write-up any possible spatial dependencies or environmental hazards that may impact system operation.

DOCUMENT the system functions and boundary, System Enhance system model No impact is expected for SY-C2 the associated success criteria, the modeled Partial analyses documentation to comply Documentation documpat isse s.

components and failure modes including human analyses with all ASME PRA documentation issues.

29

" i': .....,. i] ,*TechnicalT n lExpected or - " on*

Impact Met for CNS?.' CNS Ref. Resolution Documentation Application UCLIUIIS, aUU a uescrHpuon1 oI XILUeleuI uepeuiiueLuieS Standard requirements.

including support system and common cause failures, including the inputs, methods, and results.

For example, this documentation typically includes:

(a) system function and operation under normal and emergency operations (b) system model boundary (c) system schematic illustrating all equipment and components necessary for system operation (d) information and calculations to support equipment operability considerations and assumptions (e) actual operational history indicating any past problems in the system operation (f) system success criteria and relationship to accident sequence models (g) human actions necessary for operation of system (h) reference to system-related test and maintenance procedures (i) system dependencies and shared component interface (j) component spatial information (k) assumptions or simplifications made in development of the system models (1) the components and failure modes included in the model and justification for any exclusion of components and failure modes (m) a W description of the modularization process (if used)

(n) records of resolution of logic loops developed during fault tree linking (if used) (o) results of the system model evaluations (p) results of sensitivity studies (if used) (q) the sources of the above information (e.g., completed checklist from walkdowns, notes from discussions with plant personnel) (r) basic events in the system fault trees so that they are traceable to modules and to cutsets.

(s) the nomenclature used in the system models.

30