Catawba N. S. – 2012 CDBI

1. Catawba N. S. – 2012 CDBI Inspection Preparation and Operating Experience

2. Relationship to CM • Every question that comes up in a CDBI is an allegation of CM upset • Resolution of the question is achieved by invoking your Corrective Action Process and ultimately, if needed, the CM Process Model • The Inspection Results are a report card for how well you maintained CM equilibrium or your intentions to restore it • These terms are more meaningful after mastering CM-101

3. CM Equilibrium Restoration ChangeFacility ConfigurationInformation? ChangeDesign Requirements? ChangePhysicalConfiguration? EvaluateIdentifiedProblem orDesiredChange DoNothing More No No No CM Equilibrium Yes Yes Yes Design RequirementsChange Process Physical ConfigurationChangeAuthorizationProcess Facility ConfigurationInformationChange Process 3 CM Equilibrium • SSCs performing as expected • People are being trained • Procedures are in place and being followed • CM Program is being monitored/trended

4. Catawba CDBI 2012007 Inspection SSCs selected for CDBI • CA Pump Suction & Discharge Check Valves (i.e., CA-8, -10, -12, -23, -28, -33) • ND Pumps and Motors • ND-36B • RN-347B • EDG Governor • EDG Starting Air • SSF Ventilation • RN Strainers • PORVs (i.e., NC 34A) • SSF Standby Make-up Pump • SG PORVs • MSIVs • MOV FW-27A • 1DGBA • 1ETA18 • SSF Pressurizer Heaters • YD Backup to NV-A Pump

5. Advance Information Requests • ND Pump • List of the CRs generated during the last 3 years (searchable with descriptions) • System Health Reports (last 3 years) • Completed TS surveillance procedures with results (last 3 years) • Completed IST procedures with results (last 3 years) • Calculations/Basis that support the IST/TS surveillance test acceptance criteria • List of Preventative/Corrective Maintenance (last 3 years) • Applicable Operating Procedures • Applicable Alarm Response Procedures • Pump and Motor Vendor Manuals • NPSH Calculation • Vortexing Calculation • Pump Curves • Vibration testing and analysis (last 3 years) • Lube oil testing and analysis (last 3 years) • Applicable Part 21 Screenings/Evaluations (last 10 years) • Applicable Licensee Commitments • Seismic Calculation

6. Deficiency #1 & 2- prep results • SOER 99-01 “Loss of Grid” Analysis • NRC GL 2006-02 (and RIS 2004-05 & RIS 2011-12, rev 1) “Grid Reliability and Impact on Plant Risk and Operability of Offsite Power • Related to Tech Spec 3.3.5 “Loss of Voltage” and Tech Spec 3.8.1 “AC Sources” -Offsite Power and Diesel Generator (including D/G Load Sequencer)

7. Koeberg Event • Their event resulted in equipment ITS tripping on overcurrent protection before the D/G auto start setpoints were reached. Grid voltage decayed (400 kV to 309 kV in 10 minutes) resulting from peak loads and a main line out for maintenance. September 1998 • "Clearly establish with your grid operator that your nuclear power plant is the most important customer they have -- if they have to load-shed everyone else off the grid to keep you supplied, they had better be prepared to do it." Dave Crymble, Operating Manager, Koeberg (the only Commercial Nuclear Plant in South Africa)

8. Deficiency #1 • Operating within our 10 minute timer which has actuated anticipating grid degradation (actual voltage <degraded voltage setpoint 3766 volts < 4160) • Safety related motors operating at reduced voltage draw more current and heat up during a non-accident condition • Breakers have potential to trip on overload settings • If they trip, a subsequent SI signal would not start these motors-manual resets in field required which are Compensatory Measures not currently in place • Outside Design and Licensing Basis • Must show that that motors would NOT trip before 10 minutes

10. Deficiency #2 • Operating just above the degraded voltage setpoint (actual voltage >degraded voltage setpoint 3766 volts < 4160) • Postulate an SI Signal which initiates D/G Load Sequencer loading large Safety Related motors • Does Essential Bus Voltage drag down System voltage to the point that the LOV (TS 3.3.5 3500 volts Nominal value) relays actuate? • This would essentially be a “Double Sequence” whereby a LOCA (SI signal) could cause a LOOP • Our UFSAR describes how the D/G load sequencer would operate – shed bus and start over; LOCA/LOOP sequence vs LOCA only. Safety Analysis assumes either a LOCA at T=0 or LOCA /LOOP at T=0 but not a LOCA then a time delay followed by a LOCA/LOOP sequence

11. SOER 99-01 “Loss of Grid” Analysis • ODP (RIS 2005-20) Process entered= OBDN • Existing Tech Spec LOV Allowable Value is non-conservative w.r.t. existing Instrument setpoint Uncertainty calc results- Revised calc: reduced uncertainty from 7.395% to 1.6% • We have maintained actual LOV setpoints higher than permitted via Tech Spec Allowable Value (via IP - cal procedure) • Tech Spec change required to change LOV (and possibly Degraded Voltage) Nominal and Allowable setpoints to clear OBDN. Additionally, we desire more Design Margin to delayed double sequence potential.

12. LOV and Degraded Voltage Overlap • If you assume the positive drift of LOV relay equal to negative difference allowed by Tech Specs, overlap of DV setpoint exists (LOV drift above DV value). Degraded voltage recovery is never possible as LOV always actuates. This is related to the frequency of LOOP. • Beyond the above scenario, just considering negative allowable values, a LOCA (or other SI) can result in a delayed LOCA/LOOP (Double Sequence) if setpoints are inadequately spaced

13. SBO Recovery – D/G Starting Air Tanks • Reg Guide 1.155 Station Blackout requirements • The absence of adequate check valve back-leakage criteria would allow Starting Air tanks from bleeding down below acceptable values during 4 hour coping period • Therefore, they would not allow for starting the EDGs at the end of SBO Coping period

14. SBO Recovery- cont’d • Corrective Action program entered to drive necessary procedure changes and equipment to enable D/G start (via re-pressurization of D/G Starting Air Tanks) following 4 hour SBO • Instrument Uncertainty calc also generated for pressure gauges utilized for Tech Spec Surveillance • No citation from NRC since Licensee Identified in Corrective Action program.

15. Uncoordinated PM Frequencies Impact Design Basis • PM Frequency for ND Pump seals extended to 6R and motor bearing extended to 12R • ND Thrust Bearing Rating Life Calculation assumes 5R for both • NRC inquired about the discrepancy by comparing the PM performed (info requested once ND System selected) to the calc • ODP ,Operability process entered=OPERABLE • Uncoordinated PM frequencies not reconciled with Design Basis calculations CAN undermine Design BASES • Relationship between Design Bases and Maintenance (PM frequency) clearly tied

16. OPS Changes Valve Operation method Undermines Design Basis • OPS changed the way valve 1WL807B (outboard CIV) was operated from an Isolation valve to more like a control valve to control NCDT level. • Normally this valve cycled once per day for the NC Leakage calculation for Tech Spec surveillance for which NCDT level is an input • This significant increase in operating cycles resulted in the EMO exceeding its 2000 cycle EQ limit • NCV for this issue; 10CFR50 App B Criterion 5(Instructions)

17. OPS Changes Valve Operation method Undermines Design Basis • ODP Process (RIS 2005-20) entered=OBDN • Better communication between OPS and Engineering OR better monitoring and trending by Engineering of the way OPS is using equipment could have prevented this

18. Safe Shutdown Facility • SSF at Catawba designed for Sabotage, Fire and Loss of All AC • Maintains Hot Standby for 72 hours using TD Aux Feedwater Pump • NC Pump Seal cooling and Reactivity Control maintained via 26 gpm pump from borated Spent Fuel Pool suction source • Check valves at each NC pump had inadequate TAC (1gpm) to support Functionality of SSF (SLC vs Tech Spec in RIS 2005-20 space) at Tech Spec limits of NC leakage. • NCV for this issue – Interim Comp Measures invoked • SLC 16.7-9 requires NC leakage sum < 20 gpm, reduced to 15 gpm until testing completed

19. Safe Shutdown Facility cont’d • The basis for the leakage limit is an indication of “leak-tightness” of NC System • Total Leakage=unidentified + identified + ΣNCP #1 seal leak-off. Typically 0 + near zero + ~ (10) gpm < 15 gpm. The interim 15 gpm limit allows for increased seal leakage with heat-up during SSF event until check valves are tightened up. • Following Outages involved machining valve seats to meet new tighter TAC (0.2 gpm) supported by new calc revision

20. ND Pump flow : Tech Spec volt/freq variations • NRC team question the ability of ND pump to perform under Tech Spec allowed variations in D/G voltage (+10, -5 %) and frequency (+/- 2%) • Essential bus electrical loadings also questioned • WCAP-17308 guidance employed • ODP process entered=OPERABLE

21. CDBI Critique • Assessment went well. Some CA’s still open after team on site. These were determined by Challenge Board to be less significant • Every problem involves a Component, which is part of a System which has a Design Basis. Interaction within Organization is vital. • Monitoring and trending of SSCs is first line of defense against erosion of Operating margin. Being aware of design assumptions and how plant is operated is directly related to establishing initial conditions from which Design Margin can be assessed (valve EQ issue).

22. Corrective Action Process • During Prep we wrote 4 PIPs (CRs) and entered the ODP with an OBDN resulting in planned Tech Spec change for LOV and Degraded Voltage setpoints; ITS 3.3.5 • During On-Site Inspection we wrote 19 CRs and entered the ODP 7 times. 1 (valve EQ cycle issue) resulted in an OBDN and NCV; 1 was Functional (SSF check valves back-leakage) but non-conservative and was NCV