Catawba N. S. – 2012 CDBI
Inspection Preparation and
Operating Experience
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
CM Equilibrium
Restoration
Evaluate
Identified
Problem or
Desired
Change
Change
Design
Requirements
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CM
Equilibrium
Yes
Design
Requirements
Change Process
CM Equilibrium
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3
No
Change
Physical
Configuration
?
Yes
Physical
Configuration
Change
Authorization
Process
No
Change
Facility
Configuration
Information
?
Yes
Facility
Configuration
Information
Change Process
SSCs performing as expected
People are being trained
Procedures are in place and being followed
CM Program is being monitored/trended
No
Do
Nothing
More
Catawba CDBI
2012007
Inspection SSCs selected for CDBI
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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
Advance Information Requests
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ND Pump
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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
Deficiency #1 & 2- prep results
• SOER 99-01 “Loss of Grid” Analysis
• NRC GL 2006-02 (and RIS 2004-05 & RIS 201112, 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)
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)
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
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
SOER 99-01 “Loss of Grid” Analysis
• ODP (RIS 2005-20) Process entered= OBDN
• Existing Tech Spec LOV Allowable Value is nonconservative 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.
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
SBO Recovery – D/G Starting Air Tanks
• Reg Guide 1.155 Station Blackout
requirements
• The absence of adequate check valve backleakage 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
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.
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
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)
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
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
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
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
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).
Corrective Action Process
1. 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
2. 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 backleakage) but non-conservative and was NCV