ML20210N734
| ML20210N734 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 08/18/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20210N708 | List: |
| References | |
| 50-413-97-09, 50-413-97-9, 50-414-97-09, 50-414-97-9, NUDOCS 9708260105 | |
| Download: ML20210N734 (32) | |
See also: IR 05000413/1997009
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Notice of Violation 3
withholding of such material, you muit tpecifically identify the portions of
your response that you seek to have witkield and provide in detail the bases
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for your claim of withholding (e.g., explain why the disclosure of information
will create an unwarranted invasion of personal privacy or provide the
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confidential commercial or financial information). If safeguards information
l 1s necessary to provide an acceptable response, please provide the level of
protection described in 10 CFR 73.21.
Dated at Atlanta, Georgia
this 18th day of August, 1997
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Enclosure 1
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U. S. NUCLEAR REGULATORY COMMISSION
REGION 11
Docket Nos: 50-413, 50 414
Report Nos.. 50-413/97 09. 50 414/97-09
Licensee: Duke Power Company
Facility: Catawba Nuclear Station. Units 1 and 2
Location: 422 South Church Street
l Charlotte. NC 28242
Dates: June 8 - July 19, 1997
Inspectors: J. Zeiler. Acting Senior Resident inspector
R. L. Franovich, Resident inspector
M. Giles. Resident inspector (In Training)
N. Economos Region 11 Inspector (Sections M8.1. 2. 3. 4)
R. M. Moore. Region 11 Inspector (Sections 08.1. E2.1 )
Approved by: S. M. Shaeffer. Acting Chief
Reactor Projects Branch 1
Division of Reactor Projects
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Enclosure 2
9708260105 970818
PDR ADOCK 05000413
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EXECUTIVE SUMMARY
Catawba Nuclear Station. Units 1 & 2
NRC Inspection Report 50 413/97-09, 50 414/97 09
This integrated inspection included aspects of licensee operations.
maintenance, engineering, and plant support. The report covers a 6-week
period of resident ins)ection; in addition, it includes the results of
announced inspections ay Regional reactor safety inspectors.
Doerations
e
A Non Cited Violation (NCV) was identified for failure to declare three
ice condenser intermediate deck doors inoperable and log an associated
Technical Specification Action item Log entry after identifying ice
buildup on the doors. This item along with several other minor human
performance weaknesses indicated a need for greater attention to detail
and questioning attitude by operations personnel during the performance
of routine activities (Section 01.1).
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The root cause evaluations of a reactor coolant pump trip and subsequent
reactor trip were adequatel
involve human error or nonconservative y performed. The cause
decision of theThe
making. trip protective
did not
relaying associated with the short bus of 2TB functioned as designed.
However, a delay in troubleshooting activities to locate the source of
the associated ground indicated that the ground received a low priority
status in the work schedule and that trained personnel were not readily
available to troubleshoot ground indications in a timely manner (Section
w.2).
Control room operators were effective in precluding a turbine runback by
reducing reactor power to 50% before the 28 Main Generator Power Circuit
Breaker opened on low air pressure. The licensee's root cause
evaluation was detailed, and actions to prevent recurrence were
considered adequate (Section 01.3).
The decision to deviate from the preferred normal alignment of
Lower Containment Ventilation Unit (LCVU) operation to support
planned maintenance exhibited non-conservative work scheduling and
operatorjudgement. This resulted in lower containment air
temperature increasing slightly above the adjusted Technical
Specification limit for a brief period of time. The LCVU
operating procedures did not address the adverse impact of
removing two LCVUs from service simultaneously, nor did the
procedure address the interaction between LCVU operation and
integrated containment ventilation systems. These procedural
inadequacies were identified as a NCV (Section 01.4).
A violation (first example) for failure to follow procedure was
identified related to Operations failure to adequately document 10 CFR
50.59 screening evaluations (Section 08.1).
Enclosure 2
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Maintenance
e A Failure In!estigation Process (FIP) team was thorough in investigating
the cause of an electrical flash in a 600 Volt breaker cubicle
associated with Motor Control Center 2MXM. The root cause indicated
configuration and procedure weaknesses in the method of locking out 600
Volt breaker cubicles to the maintenance position. Adaquate corrective
actions to prevent recurrence of this incident were implemented (Section
M1.1).
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The licensee's identification of a technician's failure to follow a leak
rate test procedure that resulted in an invaild test of valve 2NV-874
during the previous refueling outage was an example of good questioning
attitude: however, the procedure completion review was untimely. The
Plant Operations Review Committee performed a thorough review of
subsequent activities to aroperly retest the valve. Good engineering
support was arovided, bot 1 in developing a leak rate test procedure and
briefing paccage for the evolution. The failure to follow the leak rate
test procedure was identified as a Violation (Section M1.2).
Enaineerina
e The licensee's identification of a discrepancy between primary and
secondary thermal power indication exhibited attention to detail in the
review of plant data. Actions to initiate a FIP team to investigate the
root cause were appropriate and steps to reduce reactor power until the
discrepancy was understood were conservative. Replacement of a faulty
T,,, card was well-planned, coordinated and controlled and executed in
an expediticas manner (Section El.1).
o Resolution of Design Base Document (DBD) open items was generally
adequate. However, a violation (second example) for failure to follow
procedure was identified related to Engineering's failure to enter DBD
open items into the Problem identification Process as required by
procedure and stated in the licensee's response to the Des'.gn Basis
50.54f letter (Section E2.1).
e The licensee's corrective action audit that assessed the resolution of
Self-N iated Technical Audit findings was identified as a strength in
correc " ve action performance (Section E2.1).
e The licensee adequately addressed the Emergency Diesel Generator 10 CFR
Part 21 issue related to potentially defective intake / exhaust springs
(Section E2.1).
- Based on in-office review of the licensee *s March 31, 1997, annual
summary on 10 CFR 50.59 changes, onsite review of the licensee's 10 CFR
50.59 evaluations, and audit of the licensee's procedures, the inspector
concluded that the licensee had complied with t1e provisions of the
regulation for the changes listed in the annual summary (Section E3.1).
Enclosure 2
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Plant Suncort
e Radiological control practices observed during the inspection period
were considered to b(. proper (Section R1.1).
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Enclosure 2
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Reoort Details
- Summary of Plant Status
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Unit 1 operated at or near 100% power during the inspection period.
l On June 26, a Unit 2 reactor trip occurred on low Reactor Coolant System loop
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flow as a result of an electrical ground fault which de energized the
electrical bus that powers the "2B' Reactor Coolant Pump (RCP). The unit was
returned to 100% power operation on June 29. Power was reduce 1 to 50% on July
2 to preclude a turbine trip / reactor trip u)on the anticipated failure of ;
Main Generator Power Circuit Breaker (PCB) 23. A solenoid (or pilot) valve '
associated with the air supply to all three main generator PCB poles had
failed, rendering the air system unable to deliver air to the breaker. The
solenoid valve was replaced, and the unit was returned to 100% power the
following day. Reactor power was reduced to 99.3% on July 15 in response to a
discrepancy between primary and secondary thermal power indications. The
discrepancy was attributed to feedwater venturi defouling and hot leg
streaming, and did not reflect an actual temperature difference. The unit
returned to 100% power on July 17 and operated at or near 100% power for the
remainder of the inspection period.
Review of UDdated Final Safety Analysis Report (UFSAR) Commitm_gn_t1
While performing inspections discussed in this report, the inspector reviewed
the applicable portions of the UFSAR that were related to the areas ins)ected.
The inspector verified that the UFSAR wording was consistent with the o) served
plant practices, procedures, and/or parameters.
I. Operations
01 Conduct of Operations
01.1 General Comments (71707)
The inspector conducted frequent control room tours to verify proper
staffing operator attentiveness and communications. and adherence to
approved )rocedures. The inspector attended daily operations turnover
and Site )irection meetings to maintain awareness of overall plant
operations. Operator logs were reviewed to verify operational safety
and compliance with Technical Specifications (TS). Instrumentation,
computer indications, and safety system lineups were periodically
reviewed from the Control Room to assess o)erability. Plant tours were
conducted to observe equipment status and Jousekeeping. Problem
Identification Process (PIP) reports were routinely reviewed to assure
that potential safety concerns and equipment problems were reported and-
resolved,
in general, the conduct of operations was professional and safety
conscious. Good )lant equipment material conditions ar.d housekee ing
were noted througaout the report period. However, as addressed b low,
sevcral minor operator human performance deficiencies were identified
Enclosure 2
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involving a failure to enter a TS Action Statement, failure to identify
equipment status anomalies, and failure to properly document a Technical
Specification Action item Log (TSAIL) entry.
Failure to Declare Unit 2 Ice Condenser Intermediate Deck Doors
inoDerable and Enter ADolicable TS Action Statement
On June 17 at 2:38 p.m., while performing the weekly TS surveillance on
the intermediate deck doors the licensee identified that three doors
had ice buildup (reported to be less than one half inch thick). The
function of these doors is to open during a des.gn basis accident to
ensure that the containment loss Of Coolant Accident (LOCA) atmos)here l
would be diverted through the ice condenser. Upon discovery of t1e ice,
a test procedure discrepancy was entered and a work request was
initiated to remove the ice. However, work to remove the ice or
investigate the extent of the impact on the door opening function was
not initiated due to problems with personnel accessing containment
through the containment airlock door. Later that night, the oncoming
Shift Work Manager became aware of the previces day's problem and
-contacted engineering personnel to perform an operability evaluation of
the condition. The following morning, the inspector reviewed the
results of this evaluation. The evaluation concluded that the " ice
condenser" was operable. This was based primarily-on a previous McGuire
Nuclear Station analysis that showed up to one-third of the intermediate
deck doors could fail to open and there would still be enough ice
condenser flow area for LOCA heat removal. The inspector determined the
evaluation focused to narrowly on the ice condenser system operability
and failed to adequately evaluate the operability of the intermediate
deck doors, especially with regard to consideration of information in
the applicable TS and Bases.
TS 3.6.5.3 requires the intermediate deck doors be operable in Modes 1-
4. TS Surveillance Recuirement 4.6.5.3.2 requires a 7-day verification
that the intermediate ceck doors be closed and free of frost
accumulation. The TS Bases also states that impairment by ice, frost.
or debris is considered to render the doors inoperable, but capable of
opening. Based on this, the inspector concluded that operations
personnel had failed to declare the three doors inopera]le and follow
the Action Statement of TS 3.6.5.3.a when the problem was initially
identified. This action statement allowed power operation to continue
for up to 14 days provided ice bed temperature was monitored at least
once per four hours and the maximum ice bed temperature was maintained
less than or equal to 27*F. The licensee initiated PIP 2-C97-2014-to
investigate this incident.
On June 18. after repairing the containment airlock, ice was removed
from the three intermediate deck doors. The cause of the ice buildup
was found to be the failure of heat tracing on an ice condenser air
handling fan drain line, which prevented adequate draining of defrost
condensate. The heat tracing was subsequently repaired. The licensee
Enclosure 2
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determined during activities to remove the ice that all three doors were
l not blocked to the extent that would have prevented their opening during
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a LOCA. The inspector also noted that the ice bed monitoring system was
operational during the period that ice was on the doors and control room
annunciator alarms would have alerted the operators of anomalous ice bed
temperatures. Therefore, the ins)ector considered the safety
consequences of this incident to )e minimal.
The inspector reviewed Operations Management Procedure (OMP) 2-29.
Technical Specifications Action Item Log. Step 3.4 requires that non-
compliance with a Limiting Condition For Operation requiring operation
in a TS Action Statement, be logged in TSAll. The ins)ector determined
that a TSAll entry was not logged for this condition w1en ice was
identified on the doors rendering them inoperable. The failure to
declare the doors inoperable and enter a TSAll entry for t % applicable
TS Action Statement in accordance with OMP 2-29 was identitied as a
Violation of TS 6.8.1. Procedures and Programs. This failure to follow
procedures constitutes a violation of minor significance and is being
treated as a Non-Cited Violation (NCV). consistent with Section IV of
the NRL Enforcement Policy. This item is identified as NCV 50 414/97-
09 01: Failure to Declare Ice Condenser Intermediate Deck Doors
Inoperable and Log Appropriate TSAll Entry.
Auxiliary Shutdown Panel Volume Control Tank (VCT) Instrumentation Drift
During a walkdown of the four Motor Driven Auxiliary Feedwater Shutdown
Panels, the inspector identified that three of the four VCT level
indications were not reading accurately. There is one VCT gauge on each
Shutdown Panel. Gauge indications differed from control room
indications by as much as 20 percent level. The ins)ector alerted
operations-personnel to-the problem and noted that t1ey were very
responsive in initiating corrective actions. Due to subsequent problems
in calibrating the gauges and unavailability of like parts, engineering
modifications were developed and implemented to replace the gauges with
more accurate models. Based on discussions with Instrumentation and
Electrical (IAE) personnel, it was indicated that most likely, the
gauges had drifted out of accuracy over a long period of-time.
The inspector reviewed periodic surveillance test procedures associated
with verifying Shutdown Panel instrumentation indications. VCT level
was not among the indications checked periodically. The inspector
noted. however, that VCT level was not required by TS to be o)erable
from the Shutdown Panels. However, the VCT indication could )e
potentially used during operation from the Shutdown Panels. It was also
apparent that-there had been opportunities to have identified the gauge
output drift during the periodic surveillances of other Shutdown Panel
instrumentation.
Enclosure 2
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Unit 2 Power Rance Channel NI-42 Soare Window Illuminated
On June 27. 1997, the day after Unit 2 tripped on low Reactor Coolant
System flow, the inspector noticed an annunciator window on the Nuclear
Instrument (N1) 42 Power Range drawer that was illuminated. The
annunciator window was labeled " spare" and appeared to serve no
function. The inspector questioned the control room operators about the
illuminated window. The window apparently first illuminated following
the trip; however, the operators were not aware that the window was
illuminated, nor the reason for the condition. Based on subsequent
discussions with reactor engineering personnel, the inspector learned
that this spare annunciator window was previously used as the negative
rate trip indication light. During the previous refueling outage. this
trip function was isolated from the reactor protection logic, the
modification that implemented the rate trip change was supposed to have
removed the bulb from these windows on all of the N1 drawers. .It was
believed that the bulb in the NI-42 drawer was removed, but may have
been reinstalled by lAE personnel by mistake during subsequent NI
maintenance activities following the refueling outage. The light was
extinguished once the rate trip function was reset and the bulb. removed.
The licensee initiated a PIP to address this problem.
TS Loaaina Error for Trackina Containment Airlock Door Seal Surveillance
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On July 11, 1997, during review of the Unit 2 TSAIL. the inspector
noticed an incorrect entry that was made on July 9. The entry was for
tracking a TS required 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> airlock door seal test following opening
of the airlock door on July 9. The time required for the test to be
performed was listed in TSAIL as July 16 instead of July 12. The
inspector discussed the error with operations personnel who corrected
the entry. It was also indicated that the seal test was scheduled to be
performed that same day. Based on this, the inspector determined the
test would not have been missed even though the TSAll was incorrect.
The inspector was concerned that the TSAll error had not been identified
over the two previous two days that the problem existed.
Individually, the above problems had little actual safety consequences.
however, in the aggregate represented the need for greater attention to
detail and questioning attitude by operations personnel during the
performance of routine activities.
01.2 Unit 2 Reactor Trio on low Reactor Coolant System Flow-
a. Insoection Scope (71707. 937,01).
On June 26 a Unit 2 reactor trip from 100% power occurred when the 2B
Reactor Coolant Pump (RCP) tripped and caused a loss of flow signal in
the associated loop. The inspector discussed the unit trip with
engineering, operations and maintenance personnel, as well as reviewed
the associated electrical diagrams. Unit Trip Report and Pl? 2-C97-2221.
Enclosure 2
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i b, Observations and Findinas
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On June 21. a negative leg ground was detected on ron vital distribution
bus 2CDB. The ground subsequently was traced to tre 125 VDC control
l power circuit of breaker 2T6 6. On June 26. the b"eaker was opened to
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facilitate troubleshooting the cause of the ground. The Instrument and .
Electrical (IAE) technicians noticed that the breaker failure initiation l
relay in 2TB 6 control cubicle was chattering, but continued with their i
troubleshooting activities. Shortly thereafter, a reactor trip
occurred.
The licensee determined that. the source of the ground fault was the
breaker pushbutton, a Cutler-Hammer E30 model, lhe pushbutton had '
failed and created a negative leg-to ground fault on 2CDB. The
pushbutton internals had changed state when 2TB 6 was tripped open
during troubleshooting, introducing a fault path to the positive leg.
Noise from the cabinet ground was induced through the switch and the
breaker failure initiation relay (94B) coil, causing it to chatter and
eventually actuate to trip the incoming breaker on the short bus of 2TB.
The auto close function of the 2TB tie breaker was blocked by a lockout
rela
bus,y, and the bus de-energized. The 2B RCP. which is supplied from the
tripped, and the subsequent low flow in the B loop caused a reactor
trip.
The inspector discussed the reactor trip with operations and engineering
personnel to determine if the root cause involved a human error. The
chattering of the relay, generated when 2TB 6 was opened, could have
been stop)ed if the IAE technicians had reclosed the breaker when they
noticed tlat relay chattering. However, they did not understand what
was causing the chattering at the time. The inspector concluded that
the IAE technicians responded appropriately by leaving the breaker in
the opened position since the cause and impact of the relay chattering
were not understood.
The inspector inquired about the time delay between ground detection
(identified on a Saturday) and troubleshooting activities (initiated the
following Wednesday). l.icensee personnel indicated that Single Point Of
Contact (SPOC) technicians were not trained and qualified to use the
ground chasing equipment. As a result a'stempts to locate the ground
could not be made until the following Monday when a trained IAE
technician would be available. Also, priority status was not associated
with troubleshooting the ground indication early in the week. In
addition, the inspector determined that only two techniciant on site
were fully qualified to use the ground-chasing equipment to locate the
source of a ground, and that_one of those technicians had been offsite
since February and was not scheduled to return until October of this
year. A shortage of trained personnel available to perform the
troubleshooting contributed to the delay. At the end of the ins)ection
period, the delay in investigating the ground, associated contri)uting
factors, and appropriate corrective actions were not addressed within
the licensee's corrective action program.
Enclosure 2
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The unit was restarted on June 28 after trip list activities were
performed and minor equipment problems were corrected. The licensee is '
planning to document the reactor trip in a Licensee Event Report.
l c. Conclusions
The inspector concluded that root cause evaluations of the reactor trip
were adequately performed. The cause of the tt!p did not involve human
error or non conservative decision making. The protective relaying
associated with the short bus of 2TB functioned as designed. The
inspector determined that, although the delay in troubleshooting
activities to locate the source of the ground did not affect the outcome
(reactor trip), challenges existed in the following areas: (1)
associating appropriate priority to locating ground indications in a
timely manner, and (2) ensuring that trained personnel are avullable to
troubleshoot ground indications. At the end of the inspection period,
efforts to address the delay, understand its causes, and identify
corrective actions were not evident in the licensee's corrective action
program.
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01.3 Unit 2 Downoower in Response to Generator Outout Breaker Trouble
a. insoection Scone (71707)
On July 2. Unit 2 control room operators received a generator breaker
trouble alarm and identified a continuous decrease in minimum close air
3ressure on 28 Main G2nerator Power Circuit Breaker (PCB). Operators
Jegan a rapid load reduction, and the PCB automatically tripped after
reactor power reached 50%. The inspector reviewed PIP 2 C97 2177 and
discussed the downpower and associated equipment failure with licensee
personnel.
b. Observations and Findinos
On July 2, the Main Generator PCB 2B Trouble annunciator alarmed in the
control room. Control room operators determined that there was a
continuous decrease in air 3ressure on the 28 Main Generator PCB,
indicating an approach to 11e minimum air pressure is required to open
the breaker. Air
' the resulting arc. pressure is required
Since the to openofthe
safety function thebreaker andtodissipate
PCB was open, it
was designed to automatically open before the minimum pressure required
for this function is reached. The minimum tri
Generator PCB 2B is between 446 and 452 psig. p pressure on Main
To preclude an automatic turbine runback on the potential automatic
opening of the PCB operators began a rapid load reduction, The PCB
automatically tripped after reactor power reached 50%. No overcurrent
alarms were received on Main Transformer 2A.
The license deternJned that a solenoid (or )ilot) valve associated with I
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the air sup)1y to a:1 three main generator )CB poles had failed,
rendering t1e air system unable to deliver air to the breaker.
Normally, the solenoid valve receives signals from the breaker poles to
Enclosure 2
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supply air to them. When the air pressure on any pole reaches
a> proximately 485 psi.-a pressure switch actuates and the solenoid valve
sluttles to pneumatically control a regulator that delivers air to the
breaker poles. When air pressure is restored to 500 psi the signal
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from the pole to the solenoid is terminated.
Station PIP 2-C97-2177 documented the root cause of the solenoid
failure. The failed solenoid was new and had been installed during the
April 1997 refueling outage. The component failure was attributed to a
deformed nylon bushing. The valve had been assembled to compensate for
the defect which initially allowed the valve to operate as designed.
However, the valve's internal components drifted from their assembled
positions over time and eventually were unable to engage with the
valve's lower assembly, thereby preventing air flow to the poles.
To address the potential that newly purchased solenoid valves could be
installed with problems, the licensee had revised procedure
IP/0/B/4974/01, Main Generator PCB Maintenance. - Revision 5 of the
procedure included a Note between Steps 10.3.7 and 10.3.8. The-Note
read: "If pilot valve is replaced, ensure pilot valve has been
disassembled and inspected for pro >er assembly and components. or
rebuilt prior to installation." T1e inspector verified that this
procedure change had been made,
c. Conclusions
The inspector concluded that control room operators were effective in
)recluding a turbine runback by reducing reactor power to 50% before the
3CB opened. The licensee's root cause evaluation was detailed and
actions to prevent recurrence were adequate.
01.4 Lower Containment Air Temoerature Exceeded for Short Duration
a. Insnection Stone (71707)
On June 30. the licensee was performing maintenance on the Unit 2
Lower Containment Ventilation Units (LCVUs). While the 2A and 20
LCVUs were out of service, the lower containment temperature
increased to 117.4'F. The inspector reviewed apalicable operating
procedures. TS. the FSAR, tagout requirements, tie innage work
schedule, and PIP 2 C97-2127. The inspector also discussed the
-issue with operations, engineering and work control personnel.
b. Observations-and Findinas
During normal operation. the Containment Chilled Water (YV)
chillers service various containment loads including the LCt!Us and
the Reactor Coolant Pump (RCP) Motor Air Coolers. 0_n June 30,
preventive maintenance (PM) and electrical motor testing were
scheduled for the 2A and 20 LCVUs. The 2A LCVU was removed from
Enclosure 2
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service first. After the PM for the 2A LCVU was completed, but i
before motor testing was completed, operations personnel decided
to remove the 2D LCVU for PM. The 2D LCVU was removed from ,
service at 10:55 a.m. While both LCVUs were out of service, lower
containment temperature increased. To compensate for the
temperature increase, control room operators adjusted the
o)eration of the remaining inservice LCVUs (2B and 2C) from
"iormal" to "High Speed." and then to " Max Cool." However, for a !
brief period of time lower containment temperature had exceeded
the high high temperature Operator Aid Computer (0AC) alarm
setpoint of 115.6'F and the adjusted TS limit of 117.2*F.
ultimately reaching 117.4'F. Lower containment temperature was ,
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above 117'F for approximately 3 minutes before it was restored to
within TS limits. The Action required by TS 3.6.1.5 was to
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restore the air temperature to within the limits within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or
be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Since the
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bich lower containment temperature existed for only a few minutes. -
th6 licensee was in compliance with the TS action. .
At anroximately 11:10 a.m., operations personnel decided to post)one
the M on the 2D LCVU. recall the associated tags and return the _CVU to
service until the 2A LCVU was restored to operation. While operators i
were returning the 2D LCVU to service and all three LCVUs to normal
alignment, the YV chillers in service (A and C) trip >ed on low flow.
Based on a review of the circumstances surrounding t1e trip of the A and ,
C YV chillers, the inspector discerned that the following took place.
When the B and C LCVUs were taken to " Max Cool" in an effort to reduce !
lower containment temperature, the flow control valves in the chiller
loop fully opened as designed, and thermostatic control of,the chilled
water supply was lost. When operations subsequently restored the D LCVU
to service and returned the LCVUs to normal operation, thermostatic i
control of the flow control valves was reinstated. The existing
temperature caused the flow control valves to throttle closed, and the
chillers tripped on low load. Normal alignment with the A and B YV
chillers was established within 30 minutes of the chiller trips. The C
YV chiller had also been restarted, but tripped after running for 10
minutes. Shortly thereafter, containment temperatures were restored to
normal levels.
Operations surveillance procedure PT/1/A/4600/02A. Mode 1 Periodic
Surveillance Items. Enclosure-13.1. Periodic Surveillance Items Data,
approved January 23, 1997, provides surveillance acceptance criteria in -
accordance with the lower containment temperature limits imposed by TS 3.6.1.5. Lower containment minimum and maximum air temperature limits
are based on the average inlet temperatures of the operating LCVUs.
Temperature readings associated with non running LCVUs provide
indication of static air temperature and therefore, are not used to
determine average containment air temperature. Therefore. temperature
':mits are adjusted conservatively as a function of uncertainty (because
of the reduced sample size) in generalizing local indications to average
Enclosure 2
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containment air temperature. As the number of LCVUs in service
decreases, the temperature limit decreases (becomes more conservative).
With two LCVUs running. the lower containment TS limit of 120*F was
adjusted to 117.2'F.
The Containment Lower Compartment Ventilation Subsystem as
described in the FSAR is designed to maintain a maximum
temperature of 120*F in the lower compartment during rnrmal plant
operation. During normal operation, three units (each providing
33.3% capacity) are in service, and one unit is on standby.
Technical Specification Interpretation 3.6.1.5 states that 3
!
containment air temperature can be maintained with one active
component out-of-service (i.e., three LCVUs in service).
Based upon a review of the FSAR and TS as well as discussions
with on-shift operators, the inspector determined that the 4
decision to remove the D LCVU from service while preventive
maintenance (PM)s on the A LCVU were ongoing was non conservative
and caused lower containment temperature to exceed the adjusted TS
limit.
The inspector also determined that problems existed with procedure
OP/2/A/6450/01. Containment Ventilation Systems. dated June 15. 1994,
which controls the configuration of the LCVUs. The procedure did not
provide adequate guidance to address the impact of removing two LVCus
from service on lower containment temperature. Operations Management
Procedure 2-18. Tagout Removal and Restoration Procedure. Revision 46.
Responsibility 4.8. states that the person placing or removing tag (s)
shall check procedures affected and any outstanding tagouts associated
with that procedure / system for any adverse effects. Because the adverse
impact of removing 2 LCVUs from service was not addressed in the
procedure, this responsibility could not be effectively realized.
n addition, procedure OP/2/A/6450/01 did not address the interaction
between LCVU operation and integrated Containment Ventilation (VV)
Systems. Step 2.7.3 of OP/2/A/6450/01. Enclosure 4.12. LCVU Additional
Cooling and YV Chiller Trip Prevention directs the operator to ensure
that three LCVUs are in the " NORM" position. The performance of this
step caused the A and C YV chillers to trip. Procedure
slowly reduce the demand on the system was not provided, guidance
nor was a to
precaution or note provided to warn of the potential to induce a chiller
trip as a function of load demand changes.
The inspector also noted that no procedure guidance was available for
swapping between running and_non running LCVU units. OP/2/A/6450/01.
Enclosure 4.2. Lower Containment Ventilation Unit Startup and Normal
Operation, provided procedural guidance for starting up the system by
placing three LCVUs in operation. Enclosure 4.7. Lower Containment
Ventilation Unit Shutdown provides procedural guidance for shutdown of
the system by placing all four LCVU switches in the OFF position.
Enclosure 2
-
l
10
However, no procedural guidance existed for stopping an individual LCVU
and subsequently restarting it or making other required alignment
changes needed to facilitate the performance of the PM. The inspector
recognized that this lack of procedural guidance was unrelated to the
l
lower co'itainment temperature increase and the YV chiller trips.
The inspector also identified a minor discrepancy in the planned
l innage work schedule. The 2A LCVU had two work items planned to
be worked which included a PM and electrical motor testing. The
PM on the 2A LCVU was scheduled to be completed at 12:00 p.m. on
June 30, 1997. The motor electrical testing on the 2A LCVU was
scheduled to be completed at 1:00 p.m. on June 30. The PM on the
20 LCVU was scheduled to commence at 12:00 p.m. on June 30.
immediately following the scheduled completion of the PM on the 2A
LCVU.
This schedule allowed both the A and 0 LCVUs to be out of
service for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, which was non conservative and not in
accordance with the alignment described in the FSAR.
c. Conclusions
The inspector concluded that the decision to deviate from the
preferred normal alignment of LCVU operation to support planned
maintenance exhibited non conservative work scheduling and
operator judgement. As a result. lower containment temperature
increased slightly above the adjusted TS limit for a brief period
of time. However, temperatures were reduced below the adjusted TS
limit within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> as required by the TS action requirement.
Therefore, exceeding the lower containment air temperature on
plant equipment had minor safety significance and did not pose a
threat to safety related equipment. The LCVU operating procedures
did not address the adverse impact of removing two LCVUs from
service. simultaneously. nor did the procedure address the
interaction between LCVU operation and integrated containment
ventilation systems. These procedural inadequacies constituh a
violation of TS 6.8.1. Procedures and Programs. This failure
constitutes a violation of minor significance and is being treated
as a NCV. consistent with Section IV of the NRC Enforcement
Policy. This item is identified as NCV 50-414/97-09-02:
Inadequate LCVU Operating Procedure.
08
,
Hiscellaneous Operations Issues (92901)
08.1 (Closed) Un.reigh.ed_Ltem (URI) 50-413.414/94-13-02: Emergency Operating
Procedure (EOP) 50.59 Evaluations Not Reviewed by Nuclear Safety Review
Board (NSRB) as Required by TS
This item was related to an apparent failure to meet the TS requirement
for the NSRB to review 50.59 evaluations for E0P changes. The
inspector's review determined that the re
being appropriately reviewed by the NSRBThe quired 50.59 evaluations
licensee's were
procedures had
Enclosure 2
__-_______ __-_ - _ _ - .
11
been inconsistent in defining the 10 CFR 50.59 screening evaluation and
the 10 CFR 50.59 Unreviewed aafety Question (US0) evaluation. The TS
requirement was intended for the NSRB to review the 10 CFR 50.59 U50
evaluations. Nuclear Site Procedure NS0-209, 10 CFR 50.59 Evaluations.
Revision 6. was revised after 1994 to clearly define the two
evaluations. The licensee initiated a change to NSD 703. Administrative
Instruction for Station Procedures, to clearly distinguish on the
procedure change process documentation whether the evaluation performed
was a screening evaluation or an USQ evaluation. The inspector reviewed
,
' three US0 evaluations for E0P changes and verified the US0 evaluation
i
had been sent to the NSRB_for review. A 1995 evaluation had been
reviewed and two 1997 evaluations were scheduled for review at the next
NSRB meeting. The inspector concluded that this issue was adequately
resolved and the TS requirements had been met by the licensee.
During the invettigation of the above issue, the inspector reviewed
a) proximately 20 examp',cs of 10 CFR 50.59 screening evaluations for E0P
c1anges and identified a deficiency in the licensee's procedure
implementation of this activity. Specifically, the justifications for
the screening questions were inadequate in many changes. The
justifications were inadequate in that they only repeated the screening
question as a negative statement. NSD 209, 10 CFR 50.59 Evaluations.
Revision 5. required the doca,3ntation of justification for responses to
50.59 screening questions. It further stated that justifications should
be complete enough so that an independent reviewer cculd come to the
same conclusion. The following E0P change 50.59 screening evaluations
were inadequate and did not meet the applicable procedure requirements:
o EP/2/A/5000/FR 1.2 dated November 17, 1995
e EP/1/A/5000/FR-1.1 dated September 19. 1996
- OF/1/A/6350/08 dated February 28. 1996
e EP/2/A/5000/F-0 dated March 26, 1997
e EP/1/A/5000/FR H.1 dated August 16, 1996
- EP/1/A/5000/FR-H.1 dated January 30, 1995
This failure to follow NSD 209 for 10 CFR 50.59 screening evaluations,
is identified as the first example of Violation (VIO) 50 413.414/9/-09-
04: Failure to Follow Procedure. The inspector did not identify any
US0 condition related to the inadequate 50.59 screening evaluations.
The inspector noted that the 50.59 screening evaluations for E0P changes
were performed by the Operations organization. Previous inspections of
50.59 evaluation performance have concluded that the Engineering
organization performed to a high standard in this area for 50.59
evaluations related to modifications. Although both organizations
Enclosure 2
12
receive the same training and use the same procedures. Operation's
performance in this activity was deficient as previously noted. The
inspector reviewed a 1997 50.59 USO evaluation for an E0P change. This
evaluation was good in that it included a well detailed justification
for responses to the USQ evaluation questions. This indicated that the
>
Operations deficient performance was related only to the 50.59 screening
evaluations.
II. Maintenance
l
M1 Conduct of Maintenance
1
M1.1 Electrical Flash Durinn Breaker Preventive Maintem nte
a. Inspection Stone (62707)
The inspector reviewed the circumstances and the licensee's corrective
actions associated with an electrical flash that occurred inside a 600
Volt non safety-related breaker cubicle while periodic breaker PM was
being performed. The electrical flash resulted in a minor personnel
injury and extensive damage to the breaker cubicle.
b. Observations and Findinas
On June 3. 1997, an Instrumentation and Electrical (IAE) technician was
aerforming PM on 600 Volt breakers 2MXM-F09C and 2MXM-F090. These
areakers supplied power to two Unit 2 ice condenser refrigeration air
handling fans. The PM activity involved testing the overcurrent
protective devices associated with the breakers. The technician had
removed breaker F09C from its cubicle and was in the process of removing
breaker F090 from its cubicle. While removing F090, an electrical ficsh
occurred in the F09C cubicle, which was located directly above F09D.
The technician received minor facial burns. but was not seriously
injured. Breaker F09C was electrically welded in its cubicle as a
result of the electrical fault, The inspector responded to the breaker
work location and noted good licensee immediate actions in response to
the incident. These actions included terminati' 11 PM work, roping
off the area for personnel safety consideratior . nd initiating a
Failure Investigative Process (FIP) to determine the root cause of the
electrical fav a.
On June 6, 1997. Motor Control Center 2MXM was de energized, and the
breaker cubicle for F09C inspected. The damage to the bus was minimal;
however, the stabs for F09C were badly damaged and recuired replacement.
Both breakers F09C and F09D were repaired, tested, anc returned to
service. The inspector attended the PORC meeting conducted to discuss
the repair plans and noted that management performed a thorough review
of the plans with good discussions on the impact of the work planned on
the plant. The repairs were completed without incident.
Enclosure 2
_____ -
13
The FlP team was thorough in their investigations and determined that
the stabs b? hind breaker F09C had come in contact with the energized
bus. Since the breaker power connecting cables had been determed and
left untaped in the bottom of the breaker cubicle. an electrical ground
path was created when the cables were re energized. The FIP determined
the method for racking the breaker out in the maintenance position was
inadequate. In the maintenance position a lock tab on the front of the
breaker cubicle had been used to position the breaker away from the bus;
l however this method did not provide sufficient distance between the bus
and stabs. While this method had not resulted in any problems in the
past, the result of having two breakers in the maintenance position,
located one above the other, created an even smaller bus / stab distance
that resulted in electrical flash over.
As a result of the FlP investigations, instrumentation procedures
governing work on 600 Volt breakers were revised to change the method of
racking out these breakers for maintenance. Instead of using the lock
tab, procedures directed that a padlock be placed on the breaker or the
bteaker be removed completely to ensure adequate stab / bus distance is
maintained. In addition, IAE personnel involved with breaker work were
to be provided training on this new method of racking 600 Volt breakers
out to the maintenance position.
c. Conclusions
The inspector concluded that the FlP team was thorough in investigating
the cause of the electrical flash. The root cause evaluation revealed
configuration weaknesses in the method of locking out 600 Volt breaker
cubicles to the maintenance position. The inspector determined that the
licensee adecuately implemented corrective actions to prevent recurrence
of this incicent.
M1.2 'Jngdeounte Leak Rate lest of Unit 2 Containment Isolation Valve
a, insoection Scope (40500. 61726. 62707)
On June 4,1997, the licensee identified that Unit 2 containment
isolation valve 2NV 874 had not been properly Type C leak rate tested in
accordance with 10 CFR 50. Appendix J during the previous. refueling
outage. On June 6. the valve was properly tested and failed the Type C
leak rate test. -The valve disc was replaced, and the valve was
successfully tested on June 7. The licensee submitted LER 50 414/97-004
. to document the inadecuate leak cate test conducted during the outage.
The inspector reviewec the circumstances associated with the inadequate
testing, attended PORC meetings to discuss retesting valve 2NV-874
online, witnessed aspects of the June 6 retest, reviewed leak rate test
results, and discussed the incident with engineering and Operations Test
Group (OTG) personnel,
Enclosure 2
_ -
i
14
b. Observations and Findinas
On &ne 4.1997 the OTG Suaervisor was conducting a procedure
completion verification of Jnit 2 Periodic Test (PT) procedure
PT/2/A/4200/01C. Containment Isolation Valve t.eak Rate Test. This
procedure had been performed during the previous refueling outage in
1
April 1997. During the review, the supervisor idcntified that Step
2.2.3 of Enclosure 13.7. Penetration No. M228 Type C 1.eak Rate Test had
been marked "Not Applicable by the OTG technician performing the test.
,
I
resulting in the step not being performed. This step required test vent I
flow path valve 2NV 873 to be opened while testing inside containment
isolation check valve 2NV 874 (associated with the Standby Makeup System '
flowpath to the reactor coolant pump seals). Without an open test vent
flowpath, the leak rate test on 2NV 874 had been invalid.
The inspector verified that appropriate actions were implemented upon
identification of the invalid lea ( rate test. These actions included
2NV 874 being declared inoperable and in accordance with TS 3.6.3, the
outboard containment isolation valve (2NV 872A) in the penetration was
closed and power was removed from the valve operator within four hours.
The inspector attended the June 5 and 6 PORC meetings conducted to
discuss activities to retest 2NV-874. Management thoroughly discussed
the impact on the plant with testing the valve while online. In
addition engineering developed a special leak rate test procedure and a
detailed briefing package explaining the necessary actions for
controlling the retest activities.
On June 6. the inspector witnessed aspects of the leak rate test on 2NV-
874. The inspector noted that testing was well controll?d and performed
in accordance with the test procedure.- The valve was not able to be-
pressurized and resulted in-a failed leak rate test. Valve maintenance
was performed resulting in replacement of the valve disc and disc
spring. A subsequent leak rate test was performed following the
maintenance activity. The inspector reviewed the results of this
testing which verified that leakage was within acceptable limits.
Following successful testing 2NV 874 was declared operable and the
penetration was returned to its normal configuration,
c. n
C_Qn.clusions
The inspector concluded the identification by the OTG Supervisor of a
procedure discrepancy that resulted in an invalid leak rate test of nD-
874 was an example of good questioning attitude. The PORN performed a
thorough review of subsequent activities to properly perform the leak
rate test. Good engineering support was )rovided, both in developing a
leak rate test procedure and briefing paccage for the evolution.
The inspector noted that the procedure completion review was not
performed by the OTG Supervisor following actual completion of all
testing or prior to plant startup from the refueling outage. Since this
Enclosure 2
_ _ _ _
-
. . - _ . __- --_ --- - - - - - . . - - _- _.
15
l was the only review that was recuired following test procedure
completion, the inspector consicered the review untimely. Had this
review been completed prior to plant startup, this problem may have been
identified and corrected arior to the unit entering a mode recuiring
containment integrity. T1e failure to open test vent valve 2hV-873
during/4200/01C
PT/2/A was identified as a violation of TS 6.8.1. leak
This rate testing of
issue
is identified as Violation E0-414/97-09 03: Failure to Follow Procedure
Results in Invalid Local Leak Rate Test of Valve 2NV 874.
M8 Miscellaneous Maintenance Issues (92902.
l M8.1 (Closed) VIO 50 413. 414/97-01-01: Failure to Include all Structures.
S stems and Components in the Scope of the Maintenance Rule as Required
This violation was identified when the inspectors determined that the
licensee had incorrectly excluded a number of structures. systems and
components from the scope of the Maintenance Rule. The licensee
acknowledged the violation and issued a Problem Investigation Process
! and, track the progress made in addressing the issues. The systems
affected included Nuclear Sampling (NM). Main Steam to Auxiliary
Equi) ment (SA). Auxiliary Building Chilled Water (YN) and Ice Condenser
l
'
Hitti Pins (NF). Following a review by the site Expert Panel these
systems or components were added to the scope of the Maintenance Rule.
Corrective actions taken or planned included a review of the 239
'
functions that had been excluded from the Maintenance Rule scope. This
review was scheduled for completion in December 1997.- and will be
documented in PIP No. 0-C97-0419, In addition, structures and functions
excluded from the Maintenance Rule will be reviewed for Generic Scoping
applicability. The due date for this review is also December 1997. The
inspectors concluded the licensee's corrective actions were appropriate.
,
M8.2. (Closed V10 50-413.414/97 01-04: Failure to implement the Requirements
of (a)(1) and (a)(2) of the Maintenance Rule
l This violation was identified when the inspectors determined that the
l licensee was using Forced Outage Rate (FOR) instead of Unplanned
l Capability loss Factor (UCLF) as a Plant Level Performance Criteria for
' monitoring A2 systs....; 3er 10 CFR 50.65. The concern was that FOR was
not as sensitive as UC F in detecting declining performance in some
systems.
The licensee acknowledged the violation and took appropriate action to
correct the problem. The licensee incorporated the Plant Transient
Criteria as part of the Forced Outage Criteria. This combination of
criteria was intended to provide appropriate equivalent defense in depth
monitoring as the Unplanned Capability Loss Factor. A Plant level
Enclosure 2
l
._ - -- -
1
16
l
Performance Criteria called Plant Transients, which defined unacceptable
performance was added to Engineering Directives Manual (EDM)-210 as Rev.
i
'
4. The inspectors concluded the licensee's corrective actions were
appropriate. l
I
M8.3 (Closed) Insoector Followuo item (IFI) 50 413.414/97-01-02: Followup and
'
Review of Licensee Procedure to implement the Requirements of (a)(1) and
(a)(2) of the Maintenance Rule after issuance of Regulatory Guide 1.160,
Rev.2
i
EDM-210." Requirements for Monitoring the Effectiveness of Maintenance
at Nuclear Power Plants or the Maintenance Rule " Rev. 5. revised the
definition of Maintenance such that it was now in agreement with
Regulatory Guide 1.160. Rev. 2, dated March 1997. Revision 5 of the EDM
now considers any operator action performed in support of Maintenance as
a Maintenance Preventable Function Failure (MPff) candidate. In
addition, the flow gra)h of Appendix A to the subject EDM, were revised
for clarity. One of tie two was revised from Vendor Error to Off-site
Vendor Services while the other from Operations or Plant configuration
control to Operation or Plant Configuration Control not associated with
a maintenance activity. The inspectors concluded the licensee's
i
corrective actions were appropriate.
M8.4 (Closed) IFT 50-413.414/97-OL-01 Followup on Licensee Actions to
Provide Performance Criteria for Structures After Resolution of this
Issue
EDM-210. " Requirements for Monitoring the Effectiveness of Maintenance
- at Nuclear Power Plants or the Maintenance Rule." Rev. 5. changed the
3erformance criteria for all Maintenance Rule structures to comply with
legulatory Guide 1.160. Rev. 2. This criteria applies to both risk and
non-risk significant Maintenance Rule structures.
EDM 410. " Ins)ection Program for Civil Engineering Structures and
Components." Rev. 1. dated June 16, 1997, is the controlling document
for monitoring and assessing civil engineering structures and' components
to the requirements of 10 CFR 50.65 and Regulatory Guide 1.160,.Rev. 2.
dated March 1997. It provides examination guidelines, acceptance
criteria and documentation requirements. As such. Catawba civil
,
engineering was responsible for implementing the ins)ection program for
l structures and components. The inspectors reviewed EDM-410. Rev. 1 for
content and adequacy. The inspectors noted that the procedure provided
adequate guidelines and the acceptance criteria contained within,
followed Regulatory Guide 1.160. Rev. 2 guidelines for acceptable and
. unacceptable performance criteria.
l
l Through discussions and document review, the inspectors ascertained that
the inspection program for structures was adequately administered and
implemented. Responsible engineers had received training and were
familiar with Maintenance Rule requirements as they applied to their
area of responsibility.
5
Enclosure 2
L ___ _-- _ . _ _ _. .. . _ __.. _ _ _ _ __ , /
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ - _ __ _________
17
At the close of this inspection. 39 structures had been inspected and an
additional 120 were scheduled for inspection by year's end. Ins)ection
per the revised EDMs -210 and -410 commenced on July 1, 1997. T1e
inspectors reviewed the licensee's classroom training material. ES-CN-
97-21. used to cormiunicate Regulatory Guide 1.160. Rev. 2 guidelines.
Training of personnel was held between June 9 and 18. 1997. The
inspectors concluded the licensee's corrective actions were ap]ropriate.
III. Enaineerina
El Conduct of Engineering
El.1 Primary and Secondary Thermal Power DiscreDancy
a. -Insoection Stone (37551)
On July 15 the licensee discovered a discrepancy of approximately 0.6%
between the Unit 2 primary and secondary thermal power indications.
Secondary thermal
was reduced to 99.7%)power
andwas immediately
a FIP team was reduced
initiated to to determine
99.3% (reactor
the power
cause of the discreaancy. The inspector attended management briefings
by the FIP team mem)ers on the progress of their investigation: reviewed
associated TS and TS Interpretations: and discussed the issue with
Operations. Engineering and Maintenance personnel.
b. Observations and Findinas
On July 15. Operations personnel were notified by the reactor
engineering group that there was a 0.6% discrepancy between primary and
secondary thermal power indications, and that actual thermal Jower might
be greater than the secondary thermal power (the designated tiermal
power best estimate) indication. The reactor engineering group
discovered, during a routine review of secondary plant parameters, that
primary thermal power had slowly increased over time since the Unit 2
restart from the April 1997 refueling outage. A FIP team was initiated
to determine the cause of the discrepancy, and control room operators
decreased reactor aower to 99.3%. Tae reactor was operated at 99.3%
power until the FI) team could determine the cause of the discrepancy.
The FIP team determined, during the course of their investigation, that
theT,Yto586.9F.
587.3 indication had responded
Operations been drifting downward T,,,
by decreasing since May 11, 1997, from
to minimize
the T * /T error. Lowering T,,, caused the reactor to increase AT to
maint'aIn,r,,actorpowerequaltosecondarypower.
e The drift in the T,,,
indication resulted in changes in T Tm T,,, and AT but did not
cause a change in indicated or actud3 primary and secondary thermal
power. Although the FIP team could not attribute this indication drift
to the primary / secondary thermal power indication discrepancy they
determined that a degraded 7300 process card was responsible for the
Enclosure 2
_. . - . - . . _ .
}
l
18
drift and initiated plans to have the card replaced after the root cause
of the power indication discrepancy was identified.
The FIP team also determined that indicated feedwater flow had decreased
while steam flow had remained constant. This was attributed to
feedwater venturi defouling as a function of the new cycle (restart from
the April refueling outage was in early May). the recent reactor trip
(June 26), and was the recent rapid downpower (July 2). The result of
defouling was a decrease in indicated feedwater flow with a
consequential decrease in indicated secondary thermal Operations
maintains secondary Thermal Power Best Estimate (TPBE) power.
near 100% by
periodically opening flow control valves, which in turn causes primary
power to increase to maintain T
defouling caused an increase in.,, for and
actual 100% power level.
indicated The
primary gradual
thermal
power, as well as actual secondary thermal power. However, the
resultant discrepancy between indicated and actual secondary thermal
)ower accounted for approximately 0.10% to 0.15% of the 0.6% discrepancy
)etween primary and secondary indicated thermal power.
The major contributor (0.3% to 0.4%) to the discreaancy between primary
and secondary thermal power was determined by the IP team on July 16 as
hot leg streaming. According to Westinghouse, hot leg streaming refers
to the inability to accurately characterize bulk hot leg temperature.
The licensee examined data from the Unit 2 Beginning of C.rcle and
identified changes in the behavior of this phenomenon from previous
cycles. S)ecifically. calculations revealed that indicated Tw had
increased ay 0.2*F and caused indicated primary thermal power to
increase. As discussed above these changes were originally masked by
the decrease in primary tem -
T,,,/T,,, as a function of T,,,peratures accompanying the decrease in
indication drift.
Hot leg streaming has occurred in previous cycles on both units and has
resulted in as high as a 1.0% difference between primary and secondary
thermal power. To account for this, an adjustment factor in the OAC
calculation corrects the discrepancy.
The FIP team concluded that sea:dary thermal power had always been
accurately and correctly indicated, and that primary thermal power
indication did not reflect an actual increase in power level above TS
limits. The inspector discussed the impact of the primary thermal power
indication on Reactor Protection System setpoints and functions.
According to the reactor engineering group, the venturi defouling and
hot leg streaming factors did not constitute a sufficient temperature
error to warrant adjustment via the Reactor Coolant System (RCS)
Temperature Calibration Procedure, which is run quarterly. The OPAT and
OTAT trip strings remained within their TS limits. In addition, the
nuclear instrumentation system is calibrated to secondary thermal power,
so the associated overpower trip setpoints were unaffected.
Enclosure 2
,
_,
-
-.-.-.c. _. ---
_ _ _ _ - _ _ _ _ - - - - _ _ _ _ - - - - -
- - - - - -
-
19
Reactor Power was increased to 99.5% on July 16 and the degraded T,q
card was replaced on July 17. The inspector attended the prejob brief
for the card replacement and observed the work activity in the control
room. The replacement was successfully completed within less than 1
hour and without incidence. At the end of the inspection period, the
3a license was considering either performina periodic manual calculations
to the correct the thermal power aiscrepancy, or conducting a full
calorimetric to account for the deviation.
c. Conclusiqn_q
,
- The inspector concluded that the licensee's identification of the
E thermal power discrepancy exhibited attention to detail and a thm
review of plant data. Actions to initiate a FlP team to invr a
g root cause were appropriate, and steps to reduce reactor po'
discrepancy was understood were conservative and indicative
positive nuclear safety ethic. Replacement of the faulty T, ,a was
well-planned. coordinated and controlled, and executed in an expeditious
manner.
E2 Engineering Support of Facilities and Equipment
.
E2.1 Review of Corrective Actions
a. Inspedjon Scooe (37550. 92903)
The inspector reviewed Engineering corrective actions to resolve open
itens identified during the development of the station Design Base
Documents (DBDs) and findings from Self-initiated Technical Audits
(SITAs). Also reviewed were the licensee's actions to address a 10 CFR
Part 21 issue related to a defective Emergency Diesel Generator (EDG)
intake / exhaust valve spring. Anplicable regulatory requirements
included 10 CFR 50 Appendix B. ESAR. Technical Specifications and
implementing licensee procedures.
b. Observations and Findinos
DS_Qs
Developed between 1990 and 1994. DBDs consolidated design and licensing
documentation for selected station systems and programs. The ]rocedure
guidance for development and maintenance of DBDs was provided ay
Enoineering Directives Manual . EDM-170. Design Specifications, revision
'
5. Open items were evaluhed for operability during the DBD development
and Licensee Event Reports (LERs) initiated as required. EDM-170
required the remaining items to be entered into the Problem
Investigation Process (PIP) for tracking and resolution. Additionally,
the l u ensee's February 10. 1997. response to the 10 CFR 50.54f letter
related to the Adequacy and Availability of Design Basis Information.
P stated that DBD open items woeli be ente 1 4 into the PIP for trackir.g
N and resolution.
Enclosure 2
.
Mi
20
TM inspector reviewed the resolution of open item in the Reactor
coolant System DBD to sample the adecuacy of item resolution activity.
Approximately 20 items were evaluatec to verify that the PIP and
interfacing station programs evaluated and resolved the open item
issues. The items were adequately resolved.
An independent industry audit of Catawba in late 1996, identified as a
finding the numerous lon9-term unresolved DBD open items. The response
to the finding was to initiate a blanket PIP (PIP 0-C97-0595 dated
March 5,1997) to cover the systems with the identified open items.
Many of these open items were not previously in the PIP process. The
PIP corrective actions established a schedule to resolve and close the
referenced DBD open items by September 1. 1997,
During this inspection, the inspector identified additional E 'en
items which were not entered into the PIP process nor incluau .d the
blanket PIP. The open items.were included in DBD CNS-1435.00-0002. Post
Fire Safe Shutdown, revision 4. and DBD CNS-1465.00-00-0018. Station
Blackout (SBO) Rule, revision 2. Although not entered into the PIP
3rocess. the licensee provided meeti g documentation indicating the Post
rire Safe Shutdown open items were being evaluated. These items were
identified by a November 1995 electrical post fire shutdown review
performeo after the initial DBD development and entered into the DBD by
revision 4 at that time. There was no c: :umented evaluation of
o)erability or A
tie PIP process.ppendix R commitments
Following which
the inspector's would haveof
identification been
this addressed
issue by
the licensee initiated PIP 0-C97-1918 to track resolution of these open
items. The inspector identified no significant safety concerns related
to the open items reviewed. This failure to follow procedure for
resolution of DBD open items is identified as the second example of
Violation 50-413.414/97-09-04: Failure to Follow Procedure.
SITAS
The ins)ector reviewed a recently comp'eted SITA report dated June 11.
1997, w11ch reviewed the adequacy of resolution of SITA findings. The
scope of the audit was good in that it reviewed the resolution of 80
findings from four previous SITAs. The depth of the audit was good in
that corrective act ans were verified through the extent of station
programs (e.g. . PIP work requests, modification etc. .) involved in the
resolution. The findings were well defined and demonstrated an
independent and objective audit. Corrective actions for the findings
hcd not yet been developed.
EDG 10 CFR Part 21 Notice
The inspector ruiewed the licensee's actions to address a Cooper
Industries 10 CFR Part 21 notice regarding potentially defective EDG
intake / exhaust valve springs which was applicable to Catawba. The
notice was initiated in 1991 and revised on May 1. 1997. The licensee
had included an inspection for the spring defect into the EDG
maintenance procedure. A defective spring was identified at Catawba in
1996. The spring was replaced. analyzed, and sent to the vendor for
'
Encloture 2
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21
further analysis. The licensee's respon.e to the notice on this issue
was appropriate,
c. Conclusions
Resolution of DBD open items was generally adequate in that no safety
significant issues were identifieo in the open items. A violation was
identified for failure to follow licensee procedure requirements to
enter open DBD open items into the station PIP process for tracking and
. resolution. The audit of SITA corrective actions demonstrated that the
licensee was aggressively following SITA findings and is identified as a
strength in corrective action performance. Additionally, the licensee
adequately addressed the EDG 10 CFR Part 21 issue related to potentially
defective intake / exhaust springs.
E3 Engineering Procedures and Documentation
E3.1 Chanaes. Tests. and Exneriments Performed in Accordance With
10 CFR 50.59 (thru December 31. 1996)
a. Insoection Scone (37551)
'
f
By letter dated March 31, 1997. Duke Power Company (the licer.see)
submitted its annual summary of all changes, tests, and experiments,
which were completed under the provisions of 10 CF,150.59 for the period
through December 31. 1996. The licensee's March 31, 1997, summary
included approximately 380 changes made during the subject period. The
inspector evaluated these changes against the p,avisions of the
regulation.
<
b. Observations and Findinas
In accordance with 10 CFR 50.59, a licensee may: (1) make changes in
the facility as described in the safety analysis report, (2) make
changes -in the procedures as described in the safety analysis report,
and (3) corduct tests or experiments not described in the safety
analysis report, without prior Commission approval, unless the change
involvy a changc in the Technical Specifications or an Unreviewed
Safety duestion (US0). The regulation defines an US0 as a proposed
action that: (a) may increase the probability of occurrence or
consequences of an accident or malfunction of equipment important to
safety previously evaluated in the safety analysis report, or (b) may
create a possibility for an accident or malfunction of a different type
than any previously evaluated in the safety analysis report or (c) may
reduce the margin of safety as defined in the basis for any Technical
Specification.
The inspector reviewed the licensee's current (dated March 10. 1997)
version of Nuclear System Directive 209. "10 CFR 50.59 Evaluations."
which is patterned after NSAC-125. " Guidelines for 10 CFR 50.59 Safety
Enclosure 2
.
_ _ _ _ _-- __ --
22
Evaluations." June 1989. This document requires that changes be
evaluated against the appropriate Final Safety Analysis Report (FSAR).
Technical Specifications, end NRC Safety Evaluation Report sections to
determine if there is need for revision. Specifically, the criteria
specified by 10 CFR 50.59 are broken down into seven (7) questions. For
a change to be qualified for 10 CFR 50.59, the answers to all seven
questions must be "no". Based on review of this document, and the
review of the licensee's 10 CFR 50.59 evaluations. the inspector
concluded that the licensee's directive appropriately reflects the
criteria of this regulation and that. if followed accordingly, should
ensure that a change would be correctly performed under this regulation.
The inspector performed an in-office review of the licensee's summary to
determine the nature and safety significance of each change. Through
this review, the inspector selected the following changes for more
detailed review onsite:
e Exempt Changes:
Exempt Change CE-3176
Exempt Change CE-3705
Exempt Change CE-3759
Exempt Change CE-4745
Exempt Charge CE-4746
Exempt Change CE-4821
Exempt Change CE-4822
Exempt Change CE-7416
Exempt Change CE-7977
Exempt Change CE-8126
Exempt Change CE-8182
Exempt Change CE-8245
Exempt Change CE-8410
Exempt Change CE-61008
Exempt Change CE-61162
e Miscellaneous Changes:
SIMULATE (a computer code) Version 4
- Modifications:
NSM CN-11371
NSM CN-20396
o 0:?rable But Degraded Evaluations:
PIF 2-C97-0157
PIP 2-096-3250
e Operability Evaluations:
Enclosure 2
_
~
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23
Operability Evaluation dated 2/15/94
Operability Evaluation dated 2/18/94
Operability Evaluation dated 6/28/94
e Procedure Channes:
OP/1/A/6200/11
AM/2/A/5100/07
OP/2/B/6200/33. Change 4 Rev. 4
OP/1/A/6550/14
PT/1/B/4700/82
The ins ector determined that these changes were correctly evaluated
under t e provisions of 10 CFR 50.59
During the in-office and onsite reviews, the inspector made a number of
observations and has communicated them to licensee personnel:
- The use of nuke-specific system identifiers in the annual summary
(which is submitted to the NRC and is thus available to the
l
public) is discouraged unless the licensee provides a key in the
l summary. These identifiers do not bear any apparent correlation
l to the actual systems (e.g. , NC = reactor coolant system. KC =
l component cooling system, etc..). The inspector made a similar
observation on the summary submitted on March 2~. 1996 (see
Inspection Report 50-413.414/96-10).
'
o The licensee's corresponding revision of the UFSAR. per 10 CFR
50.71. lags behind 10 CFR 50.59 evaluations. The next u)date of
the UFSAR. scheduled for late 1997. should capture all tie changes
that are within the scope of the UFSAR.
e While the licensee had acceptably evaluated all the changes
audited by the inspector, a number of them eppeared in the summary
with insufficient information for a reader to even determine what
system was involved, or what change was made. The inspector
recommended a several-sentence description. identifying the
system, the component, and the nature of the change, and
accompanied by a several-sentence evaluation. Despite this
problem with the summary, the evaluations were found to be
thorough and in compliance with 10 CFR 50.59. The licensee was
aware of this aroblem with the summary and has initiated actions
to correct suc1 weakness by revising its guidance document. NSD
209 (see Problem Investigation Process Form 0-C97-2027. dated June
19. 1997).
- The term " Exempt Changes" may cause confusion in the context of 10
CFR 50.59. It is a term internal to the licensee's docunentation.
It pertains to changes that "do not require the Modification
Enclosure 2
- _ _ _ _
1
b
24
Program controls for configuration management and therefore are
specifically exempted from the requirements to process an
editorial NM or NSM." According to licensee personnel, an " exempt
change" is essentially a minor change.
e The summary contained a significant number of errors, which stated
the opposite of the actual facts. For example, test procedure
TT/1/A/9200/88 states "there are Unreviewed Safety Questions
associated with this test procedure" when the onsite evaluation
shows that there was no unreviewed safety question. The licensee
submitted a letter on July 9, 1997, correcting such errors.
c. Crnclusions
Based on in-office review of the licensee's March 31, 1997, annual
summary on 10 CFR 50.59 changes, onsite review of the licensee's 10 CFR
50.59 evaluatius, and audit of the licensee's 3rocedures, the inspector
concluded that the licensee had complied with t1e provisions of the
regulation for the changes listed in the annual summary.
l
IV. Plant Suocort
R1 Radiological Protection and Chemistry Controls
R1.1 Tours of the Radiolooical Control Area (RCA) (71750)
The inspectors periodically toured the RCA during the inspection period.
t Radiological control practices were observed and discussed with
!
radiological control personnel, including RCA entry and exit, survey
postings locked high radiation areas, and radiological area material
conditions. The inspector concluded that radiological control practices
were proper.
V. Management Meetinas
X1 Exit Meeting Summary
The inspectors ) resented the inspection results to members of licensee
management at t1e conclusion of the inspection on July 11 and July 23. 1997.
The licensee acknowledged the findings presented. No proprietary information
was identified. Dissenting comments were not received from the licensee.
Enclosure 2
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.,
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t
25
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Bhatnager. A. . Operations Su>erintendent
Birch. M. . Safety Assurance ianager
Coy., S., Radiation Protection Manager
Forbes. J., Engineering Manager
Jones. R.. Station Manager
Harrall. T., Instrument and Electrical Maintenance Superintendent
Kelly. C.. Mainteriance Manager
Kimball . D. , Safety Review Group Manager
Kitlan. M., Regulatory Compliance Manager
'
Nicholson. K., Compliance Specialist
Peterson. G., Catawba Site Vice-President
Tower. D., Regulatory Compliance
l
,
4
Enclosure 2
u
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26
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and
Preventing Problems i
IP 61726: Surveillance Observation
IP 37550: Engineering
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Activitia
IP 92901: Followup - Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 93702: Prompt Onsite Respense to Events
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
i
50-414/97-09-01 NCV Failure to Declare Ice Condenser
Intermediate Deck Doors Inoperable and Log
Appropriate TSAIL Entry (Section C1.1)
50-414/97-09-02 NCV Inadequate Lower Containment Ventilation
Unit Operating Procedure (Section 01.4)
'
50-414/97-09-03 VIO Failure to Follow Procedure Results in
Invalid Local Leak Rate Test of Valve 2NV-
874 (Section M1.2)
50-413.414/97-09-04 VIO Failure to Follow Procedure - Two Examples
(Sections 08.1. E2.1)
Closed
50-413.414/97-01-01 VIO Failure to Include All Structures Systems
and Components in the Scope of the
Maintenance Rule as Required by 10 CFR
50.65(b) (Section M8.1)
50-414.414/97-01-02 IFI Followup and review of licensee procedure
to implement the requirements of (a)(1)
and (a)(2) of the Maintenance Rule after
issuance of Revision 2 of Regulatory Guide
1.160 (Section M8.3)
50-413.414/97-01-03 IFl Followup on Licensee Actions to Provide
Performance Criteria for Structures After
Resolution of this Issue (Section M8.4)
Enclosure 2
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27
50-413.414/97-01-04 VIO Failure to implement the requirements of
(a)(1) and (a)(2) of the Maintenance Rule
(Section M3.2)
50 413.414/94-13-02 URI Emergency Operating Procedure 50.59
Evaluations Not Reviewed by Nuclear Safety
'
Review Board as Required by TS (Section l
08.1)
<
l List of Acronyms
! CFR -
Code of Federal Fagulations
DBD -
Design Basis Documents
EDG -
EDM -
Engineering Directives Manual
E0P -
Emergency Operating Procedure
FIP -
Failure Investigative Process
FSAR -
Final Safety Analysis Report
IAE -
Instrument and Electrical
IFI -
Inspector Followup Iten
IST -
Inservice Testing
LCVU -
Lower Containment Ventilation Unit
LER -
Licensee Event Report
LLRT -
Local Leak Rate Test
MPFF -
Maintenance Preventable Function Failure
NCV -
Non Cited Violation
NM -
Nuclear Sampling
NRC -
Nuclear Regulatory Commission
NSD -
Nuclear Site Directive
NSRB -
Nuclear Safety Review Board
DAC -
Operator Aid Com] uter
POR -
Public Document Room
PIP -
Problem Investigation Process
PM -
Preventive Maintenance
asig -
Pounds Per Square Inch Gauge
RCA -
Radiologically Controlled Area
RCP -
Reactor Coolant Pump
RCS -
RG -
Regulatory Guide
SA --
Main Steam to Auxiliary Equipment
SB0 -
Station Blackout Role
SITA - Self Initiated Technical Audit
SPOC -
Single Point of Contact
TPBE - Thermal Power Best Estimate
TS -
Technical Specifications
TSAIL - Tech Spec' Action Item Log
UCLF - Unplanned Capability loss Factor
UFSAR - Updated Final Safety Analysis Report
Enclosure 2
_
28
URI- -
Unresolved Item-
USO -
Unreviewed Safety Question
VDC' -
Volts direct current
.
VIO -
Violation
-VV -
Containment Ventilation
WO -
Work Order
YN -
Auxiliary Building Chilled Water
l
Enclosure 2
_