ML20149F929
| ML20149F929 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 07/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20149F893 | List: |
| References | |
| 50-413-97-08, 50-413-97-8, 50-414-97-08, 50-414-97-8, NUDOCS 9707220372 | |
| Download: ML20149F929 (31) | |
See also: IR 05000413/1997008
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U.S. NUCLEAR REGULATORY' COMMISSION
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REGION II'
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Docket Nos:
50-413, 50-414
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License Nos:
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- Report Nos.
50-413/97-08, 50-414/97-08
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licensee:
Duke Power Company
Facility:
Catawba Nuclear Station. Units 1 and 2
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Location:
422 South Church Street
Charlotte, NC. 28242
~ Dates:
April 27 - June 7, 1997
Inspectors:
R. J. Freudenberger, Senior-Resident Inspector
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J. Zeiler. Acting Senior Resident. Inspector
P.
A.' Balmain. Resident-Inspector
R. L. Franovich, Resident' Inspector
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N. Economos. Region II Inspector (Sections M1.3)'
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H. L. Whitener, Region II Inspector (Sections M1.4)
Approved by:
-S. M. Shaeffer Acting Chief
Reactor Projects Branch 1
Division of Reactor Projects
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Enclosure 2
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EXECUTIVE SUMMARY
Catawba Nuclear Station. Units 1 & 2
NRC Inspection Report 50-413/97-08. 50-414/97-08
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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 ]y Regional reactor safety and inspectors.
Doerations
A Violation was identified for inadequate and untimely corrective
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actions to determine operability of a Main Feedwater Containment
Isolation Valve (1CF-51) following control room indication of low
nitrogen actuator pressure.
Contributing to this was an inadequate
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alarm response which failed to specify the alarm setpoint range or
require actions to be completed within the safety significance and
Technical Specification (TS) allowed action timeframe for an inoperable
valve (Section 01.2).
The cuality of licensee's containment cleanliness inspections following
the lnit 2 End-of-Cycle 9 (2EOC9) refueling outage was poor and had
declined from previous outages.
However, the debris identified in the
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Unit 2 lower containment would not have readily transported to the
Emergency Core Cooling System (ECCS) sump screens or impacted ECCS
performance. Appropriate corrective action to reinspect and remove all
debris from containment was performed (Section 01.3).
On May 9. a rapid power reduction from 100 percent power to 67 percent
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power was implemented on Unit 2 as a result of a significant main
turbine hydraulic oil leak.
Identification of the oil leak by a non-
licensed operator was an example of good attention to detail.
Operations adequately controlled the power maneuver and activities to
repair the hydraulic oil leak were accomplished without incident
(Section 01.4).
A Non-Cited Violation (NCV) was identified for an isolated instance
where excessive overtime was not authorized. The overtime control
program was generally ef fective; however, several weaknesses were
identi fied.
For example, the absence of timesheet audits to determine
if unauthorized overtime in excess of Technical S]ecification guidelines
was being worked was considered a limitation of t1e licensee's overtime
control program.
No formal record. independent of payroll timesheets.
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existed for monitoring hours worked.
As a result, no alternative means
for verifying that overtime (specifically excessive overtime worked by
exempt personnel who may perform safety-related functions) was being
provided.
(Section 06.1).
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Enclosure 2
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Maintenance
A NCV was identified for an inadequate procedure which resulted in the
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inadvertent autostart of Nuclear Service Water (NSW) pumps.
An IFI was
identified regarding reportability of NSW system actuations (Section
M1.2).
The high number of equipment motor failures experienced over the last
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couple of years was attributed in part, to organizational changes.
programmatic deficiencies, inadequate resources, high work loads and
management's failure to take a proactive role in this area. A NCV was
identified regarding these previous problems which was related to the
lack of procedures to control preventive maintenance, storage and
transportation of motors.
Following the completion of Self-Assessment-
and Root Cause Analysis inspections, necessary steps _to establish a more
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comprehensive preventive maintenance program for electric motors were
established.
The present program provides-for adequate inspections.
testing, and trending of motors in storage and in use.
Procedures to
control receiving, storage and. transporting of motors within and out of
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the_ Duke system have been established, . At the present time, engineering
and-technical resources in charge of the electric motor maintenance
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program appear to be adequate (Section M1.3).
Management focus on air operated valve maintenance has .resulted in
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improved performance. Air operated valve program elements were in place
and an Engineering Directive was in development. Observed maintenance
was performed well with good management involveme'nt (Section M1.4).
Enaineerina
The licensee's pursuit and resolution of a small nonconservative thermal
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power calculation error identified in the new plant computers was an
example of good questioning attitude (Section E1.1).
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The licensee's initial evaluation of a potential vulnerability involving
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air entrainment in the suction aiping of the Auxiliary Feedwater System
and subsequent air binding of t1e pumps was prompt and conservative.
Effective interim compensatory actions were implemented to ensure
Auxiliary Feedwater System operability until completion of the
evaluation. An Unresolved Item was identified regarding a potential for
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air binding the Auxiliary Feedwater pumps (Section E2.1).
Plant Sucoort
Overall, radiation control practices were found to be proper.
In one
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instance (i.e;. higher than normal radiation background in the men's
auxiliary building change facility), radiation protection personnel did
not demonstrate a questioning attitude and initiate appropriate actions
until questioned by the inspector (Sections R1 and R2)
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The licensee's performance during the annual emergency exercise was
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considered appropriate.
Particularly good performance by personnel in
the Operations Support Center was noted (Section P1).
Enclosure 2
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Maintenance of the protected area perimeter fence and conduct of
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security and safeguards activities were found to be appropriate (Section
S1).
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Enclosure 2
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Report Details
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Summary of Plant Status
Unit 1 operated at or near 100% power during the inspection period.
Unit 2 was shut down for a refueling outage at the beginning of the inspection
report period.
The Unit entered Mode 2 (Startup) on May 1 and reached full
power on May 8.
On May 9. power was reduced on Unit 2 to 67% in order to
repair a main turbine hydraulic oil leak.
Unit 2 operated at or near 100%
power for the remainder of the inspection period.
Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments
While performing inspections discussed in this report, the inspector reviewed
the applicable portions of the UFSAR that were related to the areas inspected'.
The inspector verified that the UFSAR wording was consistent with the observed
plant practices, procedures, and/or parameters.
I. Doerations
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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 procedures.
The inspector attended daily operations turnover
and Site Direction meetings to maintain awareness of overall plant
operations.
Operator logs were reviewed to verify operational safety
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and compliance with Technical Specifications (TS).
Instrumentation,
computer indications, and safety system lineups were periodically
reviewed from the Control Room to assess operability.
Frequent plant
tours were conducted to observe equipment status and housekeeping.
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 plant equipment material conditions and housekeeping
was noted throughout the report period.
S)ecific events and noteworthy
observations are detailed in the sections Jelow.
01.2 Inocerable Main Feedwater Containment Isolation Valve (71707)
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a.
Insoection Scooe
The inspector reviewed the licensee's failure to promptly determine the
operability of Unit 1
"C" Main Feedwater Containment Isolation Valve
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(CFCIV) ICF-51 following receipt of a control room alarm indicating low
valve actuator pr' essure.
Seventeen hours following receipt of the
alarm, actions were completed to measure actuator accumulator pressure.
At that time it was determined that pressure was below the setpoint for
valve o)erability. The licensee determined the valve had been
inoperaale since the alarm was received, resulting in a failure to meet
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the allowable action times of TS 3.6.3 for an inoperable containment
isolation valve. .The inspector discussed the incident with operations.
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engineering. and safety assurance personnel, as well as reviewed
associated alarm responses and PIP 1-C97-1037 involving this incident.
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b.
Observations and Findinas
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On -April 3,1997, at 6:08 a.m. . 'the Unit 1 Control Room operators
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received a computer alarm indicating low pressure in the accumulator
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-that-supplies nitrogen to the actuator which closes the "C" CFCIV. ICF-
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51; A work request was initiated for maintenance personnel to determine
the actual pressure in the accumulator.
Following shift turnover,'the
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work request was assigned to the Single Point of Contact (SPOC)
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maintenance staff.
However. instead of working this job during day-
shift, operations directed SPOC to work planned activities on the
Component Cooling Water System associated with the entry of.both units
in a 72-hour TS action statement.
At 7:00 p.m.
when the on-coming
night shift returned. it was realized that accumulator pressure had
still not been checked.
At 11:18 p.m., after resolving problems in
locating the necessary pressure instrumentation. SP0C personnel
installed local pressure gauges and measured 2000~psig in the
accumulator. The required pressure necessary to ensure the valve would
close was 2050^psig.
The accumulator was recharged to its normal
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pressure of 2780 psig. .The licensee initiated PIP 1-C97-1037 to address
the potential past inoperability of the valve and the reason why the
pressure measurement was not performed until more than 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />
following receipt of the alarm. This inadequate and untimely response
is considered a violation of 10 CFR 50. Appendix B. Criterion XVI for
inadequate corrective actions
On May 8. the licensee determined that ICF-51 had been inoperable during
the aeriod that accumulator pressure was below 2050 psig. This pressure
was )ased on the valve vendor's calculated pressure for ensuring that
there was sufficient nitrogen pressure to close the valve. Since the
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exact time that pressure decreased below this setpoint could not be
conclusively determined the time used was based on when the alarm first
annunciated.
The inspector reviewed the actions required by the computer alarm
response for low CFCIV accumulator nitrogen pressure. .The actions
required operations to contact the Operations Work Manager and initiate
a work request for maintenance to determine operability (via checking
the accumulator pressure) and recharge the accumulator. The alarm
response procedure was determined to be inadequate, in that, it failed
to provide the actual alarm setpoint range (2050 - 2150 psig) or provide
actions for checking nitrogen pressure commensurate with the timeframe
allowed by TS 3.6.3 for a potentially inoperable CFCIV. This is
considered a violation of TS 6.8.1.
The operators had believed that the
setpoint was 2100 psig and were unaware that the pressure switch for the
alarm could have been set anywhere between 2050 and 2150 psig. This
misunderstanding resulted in lower priority being placed on ensuring
actions to check nitrogen pressure were accomplished within a reasonable
.timeframe. The inspector also noted that the associated work request
Enclosure 2
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was given a priority of "I" indicating routine scheduling and not "E"
(emergent) for high priority work having potential operability or TS
consequences.
The ins)ector reviewed the safety consequences of the valve being
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inopera)le during the period. The main feedwater system would have
still been capable of performing its safety function even if 1CF-51 had
failed to close. The safety function of 1CF-51 is to terminate
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feedwater flow in both directions in order to prevent excessive forward
feedwater flow and/or steam generator blowdown during various design
basis accidents. The valve closes automatically on Phase A Containment
Isolation and Feedwater Isolation signals. The prevention of excessive
-forward feedwater flow would have been mitigated by main feedwater pump
trip functions and isolation of the feedwater flow control valve which
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also receives a feedwater isolation signal.
Steam generator blowdown
isolation would have been accomplished via the feedwater isolation check
valve located directly upstream of 1CF-51.
TS 3.6.3 states that if a containment isolation valve is inoperable the
valve shall be restored to operable within four hours or closed or
otherwise be in Hot Standby in the following six hours.
Since the valve
was potentially inoperable for-17 hours and 10 minutes, the licensee had-
failed to meet the action requirements of.TS 3.6.3.
c.
Conclusions
The inspector determined that operations staff actions for a control
room alarm indicating potential inoperability of CFCIV 1CF-51 were
inadecuate and untimely.
Contributing to the lack of work priority
placec on determining valve operability was an inadequate alarm response
which failed to specify the alarm setpoint range or require actions to
be completed within the safety significance and TS allowed action
timeframe for an inoperable CFCIV.
This issue was identified as a
violation of TS 6.8.1 and 10 CFR 50. Appendix B. Criterion XVI
(Violation 50-413/97-08-01:
Inadequate Alarm Response Results in
. Inadequate and Untimely Corrective Actions for Valve Operability
Determination.)
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01.3 Unit 2 Containment-Cleanliness Walkdowns (71707. 61726. 62707)
a.
Inspection Scooe
On April 28. the inspector identified several small items of trash and
debris inside the Unit 2 containment building during routine walkdowns
performed following the Unit'2 refueling outage. The inspector reviewed
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the' licensee's corrective actions to perform additional inspections of
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the containment and PIP 2-C97-1453
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Observations and Findinas
The walkdown was performed during Mode 3 prior to the unit startup from
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refueling outage 2EOC9 after the licensee had completed TS recuired
containment cleanliness inspections. The inspector identifiec. debris
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and trash, including a plastic face shield, a watch discarded tie
wraps. nuts and bolts.
The inspector observed that cleariliness
standards had declined from observations made during previous outages.
The licensee initiated a PIP and performed additional inspections of
lower containment. Approximately 15 pounds of additional debris were
removed by the licensee following these inspections. The debris was
found mainly inside the crane wall area in lower containment which is
not directly adjacent to the Emergency Core Cooling System (ECCS) sump
screens.
Debris is not easily transportable to the ECCS sump screens
from these areas and would not have adversely impacted ECCS performance.
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The inspector found acceptable conditions in the pipe chase areas
directly adjacent to the ECCS sump screens. These areas were in much
better condition than those located inside the crane wall.
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c.
Conclusions
The quality of licensee's containment cleanliness inspections following
the Unit 2 End-of-Cycle 9 (2E0C9) refueling outage was poor and had
declined from previous outages.
However, the debris identified in the
Unit 2 lower containment would not have readily transported to the ECCS
. sump screens or impacted ECCS performance.
The licensee took
appropriate actions to reinspect and remove all debris from containment.
01.4 Unit 2 Main Turbine Hydraulic Oil Leak and Power Reduction (71707.
62707)
a.
Insoection Scope
On May 9 the licensee performed a rapid power reduction of Unit 2 from
100 percent power to 67 percent power as a result of a significant main
turbine hydraulic oil leak.
The inspector observed control room
activities during the
aow(r reduction and reviewed the licensee's
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actions to repair the lydraulic oil leak.
b.
Observations and Findinas
The hydraulic leak was discover J by a non-licensed operator who was
investigating an unusual odor in the Unit 2 turbine building. The leak
was caused by a failed 0-ring located on a solenoid valve (2LH-93)
associated with main turbine combined intercept vahe CIV-3. At the
time of discovery the leakrate was estimated at 2 gpm and approximately
75 gallons of hydraulic oil had been lost.
The licensee initiated the
power decrease of Unit 2 to less than the automatic reactor trip
permissive interlock power level for a main turbine trip. A main
turbine trip would have occurred if the hydraulic oil leak had
continued.
The inspector observed that control room activities were
well controlled during the power reduction.
The licensee was successful in reducing the leakage from a steady stream
of about 2 gpm to a leakrate of several drops per minute.
Inspections
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of similar solenoid valves ce performed on both units and no other
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instances of leaking valves were identified. After the leak was
Enclosure 2
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stabilized and the main turb'ine hydraulic oil reservoir was replenished.
the licensee returned the unit to full power and initiated frequent
monitoring of the leak.
The licensee completed repairs on May 13 to
seal the leak-(Work Order 97040075-02),
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- Conclusions
identification of a main turbine hydraulic oil leak.by a non-licensed
operator was a good example of diligence and awareness of plant
equipment conditions which prevented a main turbine / reactor trip. The
control room staff performed well during the subsequent rapid power
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reduction and licensee actions to repair the leak were appropriate.
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Operations Organization and Administration
06.1 Control of Overtime (71707)
a.
Insoection Stone
The inspector performed an overtime audit:to determine if overtime hours
were worked in accordance with regulatory requirements and the
licensee's administrative controls during the most recent ~ Unit 2
refueling outage.
The inspector reviewed:
Catawba Technical
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Specification 6.2.2. Unit Staff: NRC Generic Letter 82-12. Nuclear Plant
Staff Working Hours. and associated clarifying correspondence: NRC Generic Letter 83-14. Definition of " Key Maintenance Personnel:" and
Duke Power Nuclear Station Directive 200, Overtime Control.
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b.
Observations and Findinas
Technical Specification 6.2.2.f 3rovides guidelines for limiting the
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working hours of station staff w1o perform safety-related functions.
In
part, the guidelines state that:
(1) an individual should not be
permitted-to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight, excluding shift turnover
time: and (2) an individual should not be' permitted to work more than'16
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-hours in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour
period., nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period, all excluding shift
turnover time.
The TS also states that any deviation from the
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guidelines shall be authorized by the Station Manager or his designee.
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or higher levels of management. in accordance with established
procedures and with documentation of the basis for granting the
deviation.
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Nuclear Site Directive (NSD) 200 Overtime Control, effective date
December 27, 1996, provides administrative guidance to limit the working
hours of peo)le who perform safety-related functions.
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recognizes tlat excessive working hours can impact an employee's fitness
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for duty and states ~that employees working excessive hours will be
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assessed for fitness for duty each day a limit is exceeded. The NSD
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specifies that all work hours must be considered when calculating
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overtime. delineates the guidelines in TS 6.2.2.f. and requires that
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authorization to exceed-the guidelines be obtained from one member of
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line supervision and the Station Manager or designee in advance.
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Enclosure 2
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Authorization of overtime must be documented per NSD 200. Appendix A,
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" Request for Work Hours Extension."
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-The licensee routinely reviews work hour extension forms to determine if
they are being filled out completely and in accordance with NSD-200.
Station PIP 2-C97-1821 was initiated to document numerous violations of
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NSD-200 that had occurred during the recent Unit 2 refueling outage and
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were identified during the subsequent periodic review of the work hour
extension forms.
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To determine if the licensee was controlling the use of overtime in
compliance with TS 6.2.2.f. the inspector obtained payroll timesheets
for a sample of exempt (salaried) and non-exemat (wage-earning) plant
workers.
The inspector identified instances w1ere the timesheets of
non-exempt plant workers indicated that overtime had exceeded TS limits.
The inspector requested copies of the completed " Request for Work Hours
Extension" forms for individuals who worked overtime in excess of
administrative and TS guidelines. The inspector received authorization
forms for the majority of instances where overtime was excessive.
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specific instances, where authorization forms were not available, the
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licensee explained that either the limits were exceeded by small amounts
of time that were considered " shift turnover" time, or the timesheets
inaccurately indicated that time was charged to work that was not
performed.
The latter explanation involves payment for work that was
scheduled. but postponed without sufficient prior notice.
Employees and
vendors were compensated for their scheduled time even though they were
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not onsite.
The inspector identified one instance where an individual's
authorization for overtime was not available. A work hour extension
form was provided to verify that authorization had been given for the
individual's crew to perform critical outage support activities:
however, the supervisor failed to recognize that the individual's name
had.been inadvertently left off the list. The inspector considered this
oversight an isolated violation of the NSD-200 requirement that
excessive overtime be authorized. This isolated occurrence did not
indicate any programmatic failure to control overtime or pervasive non-
compliance with TS and administrative requirements. The inspector is
not aware of any adverse impact on plant equipment as a result of the
violation. Therefore, this violation, which is of minor safety
significance. is characterized as Non-Cited Violation (NCV) 50-414/97-
08-02: Failure to Authorize Overtime in Excess of Administrative Limits,
consistent with Section IV of the NRC Enforcement Policy.
The inspector asked the licensee if reviews of timesheets were performed
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to determine if overtime hours are being worked without the required,
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documented authorization. The licensee responded that the scope of
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their audits is limited to administrative reviews to ensure that the
work hour extension forms that are filled out are done so correctly and
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in accordance with NSD-200 requirements: they do not review timesheets
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to determine if unauthorized overtime is being worked. The inspector
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considered such audits to be potential performance measures for
determining the effectiveness of NSD-200 and the program it governs.
Enclosure 2
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The absence of these audits .or some alternative process for measuring
the effectiveness of the program in controlling the use_of overtime was
considered a limitation of the program.
During'the course of the inspection the inspector identified a
discrepancy between one em)1oyee'.s timesheet and onsite/offsite data
provided to the-inspector-Jy the. security organization. The
' onsite/offsite data reflected the times that the employee arrived onsite
and left the site.
This data'was availabic only from A)ril 21 to April.
30. 'The timesheets indicated that the employee had worced 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> a
day every day during tha month of April.
However. the onsite/offsite
data indicated that, between April 21 and April 27. the.em)loyee worked-
between 13 and 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> a day.
The inspector determined tlat, although-
the employee in question did not typically perform safety-related
functions during the outage, other employees who did perform safety-
related functions potentially could engage in similar time-recording
practices if no administrative procedure or process prevented it.
The inspector asked if an alternative (to payroll timesheets) record for
documenting hours worked was required; the licensee res-)onded that the
NSD required the individual and supervisor to keep tract of hours
worked,-and that no formal process for performing this function was
required.
The inspector quastioned the licensee's ability to monitor
the use of overtime when an L curate and correct record of hours worked
was not maintained for all employees, particularly exempt, salaried
employees who may not be compensated for overtime and, therefore, may
not document it on a payroll timesheet.
The licensee reiterated that
supervisors and individuals were expected to monitor the use of
overtime.'and that this expectation was the mechanism by which overtime
was controlled. The ins)ector considered that the absence of a formal
and auditable record of lours worked was a shortcoming of the licensee's
program for verifying .that TS requirements are met.
The inspector examined the provisions in NSD-200 for assessing an
employee's fitness for duty. The NSD states that employees working
excessive hours will be assessed for fitness for duty each day a limit
is exceeded, and that the assessment must be performed shortly before
overtime is to occur; specifically within the same day or same shift.
- This provision allowed assessments to be Jerformed as many as 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
before the overtime work was to begin. T1e inspector determined that
the NSD may not provide adequate direction to ensure that a' fitness for
duty assessment would be performed in sufficiently close proximity to
the overtime work to ensure that the assessment was valid at the
beginning of the work.
c.
Conclusions
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The inspector concluded that the isolated instance where excessive
overtime was not authorized constituted a minor violation of NSD-200.
which was characterized as a Non-Cited Violation. The absence of
timesheet audits to determine if unauthorized overtime in excess of'TS
guidelines was being worked was considered a limitation of the
licensee's overtime control program.
No formal record, independent of-
payroll ~ timesheets, existed for monitoring hours worked. As a result,
Enclosure 2
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no alternative means for verifying that overtime (specifically excessive
overtime worked by-exempt personnel who may perform safety-related
functions) was being provided. The inspector did not identify any-
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adverse impact on safety-related equipment or plant operation as a
result of these programmatic issues.
Followup of the licensee's
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programmatic controls will be tracked as Inspector Followup Item-(IFI)
50-413.414/97-08-03: Overtime Control Program Limitations. Aside from
the programmatic issues noted. the inspector concluded that the
licensee's overtime control program was generally effective.
08
Miscellaneous Operations Issues (92901)
08.1
(Closed) Licensee Event Reoort (LER) 50-413/96-001:
Unit Shutdown
Required By Tuchnical-Specifications
1
This event was also discussed in NRC Inspection Report 50-413.414/96-01.
The licensee complied with TS time limits for performing the unit
shutdown. Acceptance criteria provided in procedures for verifying main
- feedwater pump runback circuitry status during reactor tri) breaker
testing were conservative.
The purpose of the status chect was to
ensure a feedwater pump runback would not be initiated when the reactor
tria breaker testing was completed and the trip breakers were placed
bac( in service. The inspector reviewed the licensee's corrective
actions and verified procedure revisions were completed. The licensee
updated the LER (commitment change letter dated December 4. 1996) to
require installation of minor modifications CNCE-61214 and 61215 to
eliminate the need to perform this ) articular circuit status check. The
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inspector verified by reviewing wor ( order documentation (Work Order 96055051) that the Unit 1 modification was implemented.
This event did
not constitute a violation of NRC requirements.
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08.2 (Closed) LER 50-414/96-004:
Containment Floor and Equipment Sump Level
Alarm Inoperability due to an Operator Aid Computer Error
)
A random computer equiament error in the Unit 2 plant computer caused
the alarm function to 3e suppressed.
The Unit 1 computer had previously
been replaced in June 1996, with a computer that is not susceptible to
this type of error. The inspector verified by reviewing a sample of
completed datasheets that the licensee performed a periodic operability
verification of TS related Unit 2 computer points until the computer was
replaced in April 1997.
This LER was a minor issue and was closed based
on this review-.
II. Maintenance
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M1
Conduct of Maintenance
M1.1 General Comments (61726 and 62707)
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a.
Insoection Scope
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The inspector observed all or portions of the following maintenance
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related Work Orders (W0s) and reviewed the associated documentation:
Enclosure 2
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9
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WO~97040075-02
Repair Unit 2' Main Turbine-Hydraulic 011 Leak
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-Auxiliary Feedwater Turbine Motor Testing
IP/1/B/3030/09
SB System Turbine Bypass Valve Calibration
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b.
Observations and Findinas
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The inspector observed that these activities were performed by personnel
who were experienced and knowledgeable of their assigned tasks. Work'
)
3rocedures were present at the work location and being adhered to.
3rocedures provided sufficient detail and guidance for the intended
activities. Activities were properly authorized and coordinated with
operations prior to performance. Test equipment in use was calibrated.
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procedure prerequisites were met, and system restoration was completed.
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c.
Conclusions
The inspector concluded that routine maintenance activities were
performed satisfactorily.
M1 2 Autostart of Nuclear Service Water Pumos Durina Maintenance (62707)
a.
Jnsoection Scool
On May 20, 1997. during maintenance on the Unit 1 125VDC/120VAC vital
instrument and control power system a low Nuclear Service Water (NSW)
Pit level signal was generated. All four NSW pumps received an
autostart signal and two idle pumps started. The unit operators entered
,
Abnormal Procedure AP/0/A/5500/20. Loss of NSW Case.2: Loss of NSW Pit
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Level. to verify that the NSW system was not needed and secured the
unneeded NSW pumps. The inspector discussed the occurrence with
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operations and regulatory compliance personnel; reviewed associated
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operating and abnormal operating procedures; reviewed several station
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PIPS and the facility's TS and FSAR: and reviewed NUREG-1022. Event
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Reporting Guidelines for 10 CFR 50.72 and 10 CFR 50.73 reports.
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b.
Observations and Findinas
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In 1995, during a Unit 2 refueling outage the licensee identified a
power alignment where a vital AC bus could be powered from regulated
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power for an extended period of time during refueling outages. This
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alignment facilitated the conduct of outage-related maintenance. The
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licensee recognized that when safety-related inverter 1EIA was removed
from service for maintenance, level transmitters 1RNLT7400 und
ORNLT7390 as well as the associated NSW Pit A and B level channels.
would be powered from a regulated power supply.
Similarly, when safety-
,
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related inverter 2EIA was removed from service for maintenance, level
transmitter 2RNLT7400 and its associated NSW Pit level channel, would be
powered from a regulated power supply.
Because NSW Pit level
instruments were required during Modes 1-4 on the o)erating unit (at
!
that time. Unit 1). this alignment was allowed on tie operating unit for
no more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before shutdown was required by TS 3.8.3.1.
The
Enclosure 2
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licensee initiated PIP 0-C95-1809 to address the impact of this
alignment on safety-related equipment.
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One of the corrective actions from PIP 0-C95-1809 was to revise
OP/1(2)/A/6350/08. Enclosure 4.9. 1EIA Shutdown and Return to Service.
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and Enclosure 4.12. 1EID Shutdown and Return to Service, to direct
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control. room operators to declare.the. associated NSW Pit level
instruments-inoperable when their power supply was placed on Regulated
Power. -This would allow maintenance to continue for longer than a 24-
hour period. Additionally, control room operators would refer to TS 3.3.2. Engineered Safety Features Actuation System Instrumentation, and
take appropriate action.
With one channel of NSW Pit level
instrumentation inoperable. TS 3.3.2 required that the inoperable
channel be placed in the tripped condition within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
With more
than one channel inoperable. TS 3.3.2 required that the NSW system be
aligned for NSW Pond recirculation within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The revised
procedure was approved on February 28, 1996.
Subsequent to the February 28. 1996, procedure revision. another change
to OP/1(2)/A/6350/08. Enclosures 4.9 and 4.12 was made to add the
appropriate model work order number (91002943).that would be issued to
support placing the NSW pit level channels in the tripped condition when
the associated inverter was removed from service and regulated power was
aligned to the distribution bus. The procedure change was made for both
units and was approved February 20. 1997.
Two out of three logic for low NSW pit level initiates the following'
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actions: (1) swap of the NSW pump suction to the Nuclear Service Water
Pond (NSWP): and (2) an automatic start of the NSW pumps.
Inverter 2EIA
supplies vital power to one NSW Pit level. instrument: placing that
instrument channel in the tripped position would not satisfy the logic
for these two actions.
However, since inverter 1EIA supplies vital
. power to two NSW Pit level instruments, tripping those instrument-
channels would satisfy the logic for these two actions.
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On May 20. 1997, during maintenance on the 125VDC/120VAC vital
instrument and control power system, a low Nuclear Service Water (NSW)
Jit signal was generated when the two channels powered from 1EIA. which
lad been removed from service for maintenance, were placed in the
tripped condition.
In response to this low level signal, all four NSW.
pumps received an autostart signal and started. This system response
was not anticipated, nor was it included in the scope of procedure
OP/1(2)/A/6350/08. Enclosure 4.9.
The licensee determined that an
Engineered Safety Features (ESF) had not occurred because the NSW system
was not defined in the FSAR as an ESF system.
The inspector questioned
this basis. since the NSW system does perform ar. ESF function (to
provide cooling water to the component cooling system heat exchangers
and, thereby, serve as the heat sink for containment cooling).
The
licensee generated PIP 0-C97-1715-to clarify what NSW system actuations
constitute an ESF Actuation.
This issue is characterized as IFI 50-
413.414/97-08-04: Reportability of NSW System Actuations.
For this
specific issue, the licensee reasoned that, since a safety injection
signal did.not initiate the NSW pump starts to mitigate an event that
Enclosure 2
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required containment cooling, the pump start did not constitute an ESF
function and was not reportable.
The inspector agreed with this
conclusion.
The licensee determined that the root cause of the pump start was an
inadequate procedure. The procedure change records indicate that the TS
and FSAR chapter associated with Electric Power Systems were consulted.
As a result, the appropriate actions for TS 3.2.2 were not delineated in
the procedure, and the impact of trip]ing two channels of NSW Pit level
were not recognized.
The procedure clange to direct plant workers to
place NSW Pit level instrumentation in the tripped condition should have
a3 plied to and been made for Unit 2 procedures only since only one
clannel of NSW Pit level instrumentation was rendered inoperable by the
inverter maintenance.
The inspector concluded that the inadequate procedure was a violation of
TS 6.8.1. Procedures and Programs.
However, the impact on plant
,
equi] ment was of minor safety significance.
Therefore, this violation
is claracterized as NCV 50-413/97-08-05: Inadequate Procedure Results in
Autostart of the NSW Pumps, consistent with Section IV of the NRC
The inspector verified that, on May 21, 1997. OP/1/A/6350/08 was revised
to remove the reference to model work order 91002943 for tripping the
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NSW Pit level instruments associated with inverters 1EIA and 1EID.
c.
Conclusions
A NCV was identified for inadequate procedure.
The inspector concluded
that a more thorough review of the FSAR and of the TS associated with
the ESF function of the NSW system may have revealed the
inappropriateness of tripping two channels of NSW Pit level
instrumentation.
The inadequate procedure did not pose a threat to
safety-related equipment or render a safety-related component
Corrective actions for the NCV were timely and appropriate.
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An IFI was identified to further review NSW ESF reportability.
M1.3 Maintenance of Electric Motors (62700)
a.
Insoection Scooe
2
This inspection was performed to determine by document review, work
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observation and interviews, the apparent cause for increased electric
motor failures over the past two year period.
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b.
Observations e
Findinas
The inspector reviewed the following documentation to ascertain the
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extent of the problem, the underlying reason (s) for these failures and
the corrective actions taken to prevent their recurrence:
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Electric Motor Failures
Root Cause Analysis (11-21-96)
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Enclosure 2
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CTS-09-96
Electric Motor PM Program (12-
2-96)
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SA-97-61(CN)(SRG)~
Assessment of Warehouse
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Material Control (5-21-97)
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CNS Site Focus Issue
System Reliability'(6-2-97)
~ Initiative: NO. 17 Motors
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SM/0/A/5130/001
Preventive Maintenance for
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Medium Voltage Motors in
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Storage
[
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SM/0/A5130/002
Inspection and Testing of
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Motors
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Backaround
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By review of the above documents and through discussions with the
licensee's component engineer in charge of electric motor maintenance.
the inspector ascertained that electric motor failures at Catawba
indicated an increasing trend since the fourth quarter.of 1994. Most of
these failures were evaluated as electrical in nature.
The licensee's
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Self-Assessment evaluated the failure rate and determined that it was
a) proximately double that of the industry.
The underlying reasons for
tieses. problems as determined by the licensee's Assessments and Root
Cause Analysis included _ human factors, organizational and management
deficiencies, personnel changes., programmatic deficiencies and a failure
to implement existing Technical Support Program (TSP) instructions.
Findinal
Prior to establishing the present organization with assignment of
. specific responsibilities towards maintenance of electric motors, the
responsibility for testing electric motors had been assigned to a group
out of the licensee's General Offices. As such, the program lacked good
coordination and communications between key individuals.
For example,
the site organization did not have easy access to test data feedback or
have control over the type of tests performed. This made tracking and
- trending motor performance difficult to implement.
Vendor Maintenance Monitoring - In reference to motor repair work
. performed by vendors, the-documents reviewed revealed that the
organizational structure and the program in place at the time did not
provide for good communications between Catawba Maintenance and the
vendor (s). As such, the licensee accepted repaired motors from the
vendor when these motors were not in a condition suitable for service.
This was evidenced by problems with the Unit 1 Heater Drain Tank C1
motor and Unit 2 Condensate Booster Pump C motor.
Technical Support Program - The TSP for small and medium size electric
motors was. established to provide guidance and information for
maintenance on electric motors and to establish certain goals for the
Enclosure 2
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Preventive Maintenance (PM) program.
These goals were designed to
reduce failures of motors critical to )lant operation by trending
performance and repairs as required.
iowever, the documents reviewed
revealed that TSP recommendations for PM of small and medium motors were
essentially ignored by supervision.
In general. this was attribut
3 +o
changes in staffing due to the reorganization and management's app 6itat
lack of skills and knowledge to recognize the seriousness of the
problem.
Failure of the Unit 2 Cooling Tower Fan A7 and Instrument Air
Compressor D motors were examples of failures due to PM program
inadequacies and management's failure to take a proactive role in this
area.
PM of Flectric Motors in Storage - On or about September 10. 1996, the
licensee determined that the spare Containment Spray (NS) motor was
inadequately stored in the contaminated warehouse, in that the warehouse
heater was not energized. This problem was documented in PIP No. 0-C96-
2488.
In addition to this problem, the licensee's investigation
identified other large motors stored without heaters energized. The
latter were stored ir ?n "old" warehouse located outside of the
protected area. Th a oblem evaluation section of the PIP found motor
PM procedure IP/0/A/3851/03 to be inadequatc. in that it did not provide
instructions to ensure that motor heaters were energized as required and
that no a)propriate action was taken to repair broken heaters.
To
correct t11s problem the licensee generated modification CNCE8015.
Completion of the corrective action on this modification was scheduled
for June 30. 1997.
Assessment of Warehouse Material Control - Between April 23-28, 1997
the licensee performed an assessment of activities associated with
onsite receiving, storing. shipping and controlling of motors and other
equipment both onsite and offsite.
The assessment, which was documented
under Report Nos. SA-97-61(CN)(SRG). was conducted in response to
damages identified on a spare Nuclear Service Water (RN) Pump motor
while undergoing pre-installation testing following its release from
storage.
Details of the damages and repairs performed were documented
in PIP 2-C97-1166.
Findings, evaluation and corrective actions
associated with this assessment were documented in PIP 0-C97-1621. A
review and evaluation of the findings were as follows:
(1) there were
no procedures which adequately detailed the correct methods of
performing preventive maintenance, moving or shipping of motors, and
responsibilities applicable to each of these activities were not
assigned to any one individual or group; and (2) there were no
procedures to define the necessary controls for equipment loaned out to
other Divisions or companies to assure proper maintenance and
suitability for use upon their return.
In response to the )roblems described above, the licensee took specific
action to correct t1e immediate problems and generated a Nuclear Site
Directive (NSD). Storage and Handling of Motors. to address the issue on
a broader basis. Areas covered included:
receiving. storage, off- and
on-line testing, in-storage testing. issuing and transportation of
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motors.
Enclosure 2
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This licensee identified problem of a failure to provide adequate
procedures for handling and conducting preventive maintenance of motors
in storage was determined to' be a violation of 10 CFR 50. Appendix B.
Criterion V. " Procedures. "- This licensee identified and~ corrected
violation was treated as a NCV consistent with Section VII.B.1 of the
This issue was identified as NCV 50-413.414/97-
08-06:
Inadequate Motor Preventive Maintenance and Control Procedures.
Work' Observation
As a followup to the aforementioned document review. the inspectors
observed preventive maintenance testing performed on the Auxiliary
Feedwater (CA) Pump Turbine. 2 Sump Pump Motor "B".
The testing was
performed'per procedure SM/0/A/5130/002. -Tests performed on this motor
included meggering, digital low chmmeter resistance polarization index.
visual and functional.
The testing was performed under Work Order No.
97037274-02. using a Baker Motor Analyzer. S/N016.
Test results
attained were well within acceptance criteria. All equipment used for
this test were properly identified and within designated calibration
timeframe.
Personnel involved in the test appeared knowledgeable, and
followed the above-mentioned procedure in executing their tasks.
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Insoection of Motors in Storace
The inspector, accompanied by the responsible component engineer,
inspected small, medium and large motors stored in Warehouses No. 2 and
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4.
Storage conditions appeared to be consistent with ANSI N45.2.2.
Level "B" requirements, including environmental control, protection
against physical damage and airborne contamination.
In Warehouse No. 4
the inspector noted that three pump motors associated with fuel pool
cooling, volume control and "C". heater-drain systems did not have their
heaters energized.
However, the com3onent engineer indicated that a
decision had been made to modify ratler than fix-the existing heaters
which did not work properly and could damage the motors if energized.
c.
Conclusions
This inspection revealed that electric motor failures had increased-
significantly over the last couple of years.
This increase of failures
was attributed in part to organizational changes, programmatic
deficiencies. human factors inadequate resources, high work loads, and
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management's failure to take a proactive role in this area.
Following
completion of the Root Cause Analysis Report and Assessments on the
Electric Motor PM Program and Warehouse Material Control, the licensee
took appropriate measures to improve conditions in this area. An NCV
was identified regarding inadequate motor PM and control procedures.
M1.4 Review of Maintenance Activities Associated With Air Ooerated Valves
(62700)
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a.
Insoection Scooe
During this report period, the inspector reviewed the licensee's
Enclosure 2
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activiti.es for maintenance of Air Operated Valves (A0Vs). Areas
reviewed included, but was not limited to. A0V maintenance program
attributes including PM and Corrective Maintenance (CM). valve outage
assessments, maintenance rework program assessments, valve related PIPS.
and valve testing.-
b.
Observations and Findinas-
The-inspection'was a general look 'at various aspects of the = licensee's
A0V activities to determine.that Management had been actively focused on
maintaining A0Vs important to safe and reliable operation of the plant.
A0V Proaram Elements
A formal, structured program had not been implemented for A0Vs at this
time.
However, the elements of a program had been developed and
controlled by the engineering and maintenance groups. Control of these
elements were assigned to an engineering valve s)ecialist who was
responsible for the program and was involved wit1 problem resolutions.
The engineer had been tasked with development of an A0V program document
(i .e. . an engineering directive for A0Vs). This document was scheduled
on the management calendar to be completed by the end of 1997. The
document will be coordinated with all three Duke Power sites.
The. licensee had performed a review of the ADV and' solenoid valve
population and application. A population of 2.348 ADVs-had been
identified.
There were 169 active A0Vs identified in safety significant
systems.
From a review of the licensee *s documentation, the inspectors
noted the following program elements:
active valves were stroke time tested per ASME Code requirements
e
482 safety-related solenoid valves were maintained through the
e
. Environmental Quali.fication Program
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50 of the most critical actuators / valves were scheduled for
rebuild / replacement under a recently initiated program (Model PM
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work orders would be established to automatically perform this-
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function at 8-10 year frequencies)
68 high energy, normally closed valves were monitored for leakage
e
using infrared techniques
diagnostic. testing was used in calibration and setup of control
e
valves using state of the. art equipment
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A0Vs/ solenoid valves were trended in the Failure Analysis Trending
e
system
approximately 150 PMs had been developed based on an operating
e
experience database
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Enclosure 2
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procedures had been developed for the various aspects of
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A0V/ solenoid valve maintenance
Positioner Calibration
The inspector witnessed the positioner calibration on A0V 1SB24 (Sir
. operated steam dump control valve).
The inspector observed the pre-job
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briefing and reviewed the work order. procedure IP/1/B/3030/09 (SB
LSystem Turbine Bypass Valve Calibration) and the procedure's data sheet
results. The inspector also observed the work-in progress. An approved
arocedure was present and followed on the job: personnel were
(nowledgeable and skilled in the task: and an Instrumentation and
Electrical technician was present for on-the-job-training to expand
skills. The job was performed in a controlled and professional manner.
Instrument Air System
The licensee had previously noted high dew point temperatures and
excessive moisture in the instrument air s
-problems and a number _of system failures. ystem. resulting in valve
Modification CN 50431
replaced the three reciprocating air compressors with two centrifugal
compressors. and the refrigerant dryers with two heatless. air-purge
desiccant dryers.
The dew point was reduced from the 50-70 degree range
to minus 30 degrees.
System failures have trended down from a high of
16 in 1995 to none so far in 1997.
The inspector considered that this
was a positive step to improve system / plant performance and reliability.
MSIV Issue
The inspector reviewed the failure of Main Steam isolation Valve (MSIV)
,
1SM1 to close in the required stroke time on March 7. 1995, against the
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recommendations of NRC Information Notice (IEN) 87-28.-Air System
Problems At U.S. Light Water Reactors, and IEN 88-24. Failures of Air
Operated Valves Affecting Safety-Related Systems, to determine if the
failure of MSIV 1SM1 had been due to the causes discussed in IEN 88-24.
Licensee documentation confirmed they had reviewed the safety-related
solenoid valve a) plication with the vendors as a result of IEN 88-24 and
,
1
concluded that t1ese valves would operate against as high as 150 psi air
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system pressures.
Maximum instrument air system pressure for Catawba
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was 115 psi.
MSIV solenoid valves were missed in this survey, in that
they were supplied as a part of a whole manifold assembly.
Subsequent'
testing and re-evaluation of the 1SM1 past operability (PIP C96-0751)
indicated that the root cause of the failure was an intermittently
sticking solenoid valve, possibly in conjunction with marginal spring
force.
No other MSIV at Catawba or McGuire has had this problem.
To
reduce the possibility of future failures, the licensee installed
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stronger springs in Units 1 and 2 MSIV solenoids. The inspector
concluded that failure of MSIV ISM 1 to meet its stroke time was an
isolated event.
Enclosure 2
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Self-Assessments
The . inspector reviewed outage critiques for U1EOC8, U1EOC9. and U2E0C7.
These critiques dealt largely with improving efficiency through better.
organization, planning and communication. One deficient area was valve
. maintenance rework.
Review of an assessment report on the Maintenance -
Rework Program (MNT 15-97) showed that the cause for maintenance rework
items fell into three general areas: Work Practices, Design / Equipment.
and Planning / Procedure / Training. Approximately 60% of rework items were
in the Work Practice area.
In the area of valves, a review of over
three years of data indicated a significant reduction in rework items.
-It appeared that management focus on reduction of rework items has shown
positive results,
c.
Conclusions
Management focus on Air Operated Valve maintenance has resulted in
improved performance.
Air operated valve program elements were in place
and an Engineering Directive was in development. Observed maintenance
was performed well with good management involvement.
h8
Miscellaneous Hafntenance Issues (92902)
M8.1- (Closed) Unresolved Item (URI) 50-413.414/96-16-02:
Nonconservative
RCS Controlled Leakage Test
Surveillance procedure PT/1(2)/A/4150/01. Reactor Coolant System
Controlled Leakage Verification, was not being performed to simulate the
system flowpath as it is described in the current TS basis. The TS
basis states that the controlled leakage limitation restricts operation
when the total flow supplied to the reactor coolant pump seals exceeds
40 gpm with the modulating valve in the supply.line (NV-294) fully open
at a nominal Reactor Coolant System pressure of 2235 )sig.
However, the
surveillance test had been performed with NV-294 in t1e normal
modulating position to control charging flow. This was not conservative
because the accident analysis assumes a station blackout concurrent with
a loss of coolant accident. and the valve fails to the open position on
a loss of power to ensure that adequate seal injection is provided.
The licensee initiated an appropriate procedure change to
PT/1(2)/A/4150/01 and determined that with the modulating valve fully
open, Reactor Coolant System Controlled Leakage was within allowable
limits. The inspector reviewed PIP 2-C97-1010, which documented the
results of subsequent surveillance tests that were performed from
October 10. 1996. through February 28. 1997.
The ins >ector determined
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that total seal injection flows continued to fall wit
1in the acceptance
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criterion of 40 gpm.
The inspector also reviewed the supporting
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documentation associated with the Emergency Core Cooling Systems' past
operability evaluation and discussed the evaluation with engineering
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personnel.
The analysis indicated that with modulating valve NV-294
fully open during a large break loss of coolant accident, flow to the
seals would not-have exceeded the limit assumed in the accident
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. analysis, and sufficient flow would have been provided to the core.
The
Enclosure 2
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inspector concluded that the Emergency Core Cooling Systems were past
This Unresolved Item is closed, as is associated LER
50-413/96-09. Inadequate Reactor Coolant Controlled Leakage Test.
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M8.2 (Closed) LER 50-413/96-09:
Inadequate Reactor Coolant Controlled
Leakage Test
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(Details pertaining to this item are discussed in Section M8.1)
III. Engineerina
El
Conduct of Engineering
E1.1 Nonconservative Thermal Power Calculation Error (71707. 37551)
a. Insoection Stone
On May 9. the licensee identified a small nonconservative error in the
o)erator aid computer thermal ]ower calculation.
The inspector reviewed
t1e licensee's evaluation of t1e significance of the error (PIP 0-C97-
1589) verified modifications were installed to correct the error, and
reviewed UFSAR commitments related to the accuracy of thermal power
measurements.
b. Observations and Findinas
The operator aid computer thermal power calculation is used by control
room operators as the primary indication to control the reactor thermal
power within the licensed power limit of 3411 megawatts-thermal.
During
the final stages of the Unit 2 power ascension testing following its
recent refueling outage, the licensee identified a small discrepancy
between the operator aid computer thermal power indication and the
measured main generator electrical output.
This discrepancy prompted c
detailed review of the thermal power calculation.
The licensee's reviEv
identified that an incorrect constant (coefficient of thermal expansion)
was used in the plant computer's thermal power calculation which
resulted in an error with a magnitude of 0.3 percent in the
nonconservative direction. This caused indicated power to read 0.3
percent below actual )ower. The licensee's review determined that the
error existed since tie new operator aid computers were placed inservice
(September 1996 for Unit 1 and April 1997 for Unit 2). The old and new
computer systems used different calculation techniques for generating
this constant which were not realized until the detailed review of the
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thermal power calculation was performed. A power discreaancy was not
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detected following the Unit 1 startup in September 1996 3ecause normal
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process instrumentation uncertainty errors masked the 0.3 percent
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calculation error.
The inspector reviewed UFSAR and safety analysis commitments for
uncertainties for the thermal power indication.
The UFSAR and safety
analysis assume an error of 2 percent for this parameter and use an
assumption of 102 percent rated thermal power as the initial condition
Enclosure 2
l
19
for accident analyses.
The licensee's General Office personnel
performed a review of the actual uncertainty of the thermal power
measurement and found, based an previous calculations, that the actual
uncertainty of the indication was 1.52 percent. An addition of 0.3
percent error caused by the incorrect constant resulted in a total
uncertainty of 1.82 percent, which is within the analyzed uncertainty.
Based on this, the inspector considered that the error resulting from
using the incorrect constant was of minor safety significance.
The
licensee revised the constant by performing a software change to both
unit's computers.
The inspector verified by reviewing Variation Notices
VN-CN-11329AS and VN-CN-21329Y that the constant was corrected. The
inspector also verified by reviewing o)erator aid computer group display
data printouts that this constant had Jeen input properly into the plant
computers.
The ins)ector reviewed the power history printouts for both units and
found tlat they were conservatively operated below 100 percent power.
Normally, thermal power was controlled at 99.8 percent to 99.9 percent
power based on a review of data for the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> averaged thermal power
calculation.
There were no excursions above 100 percent power
identified during this review.
c. Conclusions
The licensee's pursuit and resolution of a small nonconservative thermal
power calculation error identified in the new plant computers was an
example of good questioning attitude. The error had minor safety
significance because of its small magnitude and did not result in
exceeding the 2 percent uncertainty required by the Updated Final Safety
Analysis Report and assumed in safety analyses.
E2
Engineering Support of Facilities and Equipment
E2.1 Potential Air Bindina of Auxiliarv Feedwater Pumos
a.
Insoection Scoce (37551)
During an auxiliary feedwater (CA) suction source reliability review at
the McGuire Nuclear Station, engineering personnel identified a
potential vulnerability of the CA system to air entrainment in the
suction piping to the CA pumps and subsequent air binding of the pumps.
The licensee determined that the potential vulnerability applied to the
Catawba Nuclear Station (CNS) as well.
The inspector discussed the
issue with Engineering personnel: reviewed the facility's TS and UFSAR:
reviewed station PIP 0-C97-1579 and a 10 CFR 50.72 notification of
potential inoperability of the CA system: reviewed information provided
from the pump vendor; assessed the appropriateness of compensatory
actions; and verified that compensatory actions had been effectively
implemented.
Enclosure 2
-- . . - -
20
b.
Observations and Findinas
Because they provide condensate quality water, the normal suction
sources for CA are the shared CA condensate storage tank (CACST). the
respective unit's upper surge tank (UST) and the respective unit's
condenser hotwell.
iowever, these sources do not meet seismic
requirements.
Therefore, the assured suction source for the CA system
is NSW which is not of condensate quality.
Unit 2 TS 3.7.1.5 requires
that the Condensate Storage System, which consists of the CACST. UST and
-Condenser Hotwell, be operable during Modes 1 through 3 with a contained
water volume of at least 225.000 gallons.
This TS requirement is not
applicable to Unit 1.
'
If the CA system automatically starts, a low CA pump suction pressure
will cause pump suction to swap to the Nuclear Service Water system.
Similarly, a low CACST level signal will cause pressure switch 0CSPS5030
to close CACST outlet valves 1/2CA-6 (if the control switch is in auto).
This automatic function prevents the introduction of air into the system
piping after the CACST has been depleted.
Control board switches also
enable a reactor operator to manually close the valves from the control
room.
The valves are powered from the Blackout Power System to ensure
that the CA pumps are protected from air binding during a station
blackout event.
On May 8. Catawba engineering personnel identified three mechanisms
whereby air entrainment in the suction piping to the CA pumps could
cause air-binding of all three CA pumps (2 motor-driven and 1 turbine-
driven).
The three issues were:
vortexing of _the CACST. vortexing_ of
the UST, and depletion of the CACST.
The licensee determined that
specific conditions were necessary to cause vortexing of the CA and the
UST.
Specifically, high CA system flow rates (e.g. . during a main
steamline break accident) and a small range of tank levels were required
for vortexing to occur.
Similarly, a dual unit loss of offsite power coincident with a main
steamline break on one unit is a condition necessary for CACST depletion
to cause air entrainment in the CA system piping. A second condition
necessary for CACST depletion to result in air entrainment is a negative
pressure (less that atmospheric 3ressure) at the junction of the CACST
and the UST discharge piping. T1is condition would essentially educt
air into the suction piping downstream of the junction.
The CA pump vendor was contacted to evaluate pump operability under the
postulated air entrainment scenarios. The vendor responded that the
,
length of aiping from the CACST to the CA pumps was sufficient to
preclude tie any generated vortex from reaching the suction of the
pumps.
Any small amount of air that might be entrained in the suction
line if the postulated vortex did not break up would be forced through
the pum) by the. inertia of the fluid in the piping without any
noticea31e affect on the pump.
The vendor was unable, however, to provide assurance that CACST
depletion, concurrent with UST supplying the CA pumps, would not cause
Enclosure 2
. _ .
. - .
21
pump damage as a result of air entrainment from the emptied CACST into
the suction piping to the Jumps. This scenario posed a real possibility
that sufficient air could )e drawn into the pump suction piping and to
the pump, to cause pump failure.
The failure mechanism is referred to
as a break in suction whereby air trapped in the pump casing would
,
preclude water from entering the pump.
The pump would run dry and be
severely damaged.
_
The vendor indicated that a small amount of air would be passed through
i
the pump without any noticeable affect whereas a large amount of air
would cause a suction pressure drop to the NSW auto swap to setpoint.
The vendor was unable to quantify the mid-range amount of air entrained
in the water that would cause this failure without extensive analysis
'
and modeling.
Engineering personnel have contracted a separate vendor
to quantify the air factor required to cause pump failure. The results
of their analysis and the associated past operability evaluation are not
formally completed.
This issue is characterized as URI 50-413.414/97-
08-07:
Potential Air Binding of Auxiliary Feedwater Pumps, pending the
completion of the hydraulic analysis and past operability evaluation.
The licensee submitted a 10 CFR 50.72 notification to the NRC regarding
the potential air binding problem.
The licensee also implemented
compensatory actions to protect the CA pumps from the postulated air
i
binding failure-until the analysis is completed.
Compensatory actions
consisted of: (1) closing ICA-6 and 2CA-6 to eliminate the potential for
'
air binding the CA pumps as a result of CACST depletion: (2) maintaining
each units UST full to minimize the risk of an autoswap to the NSW
system on low AFW pump suction pressure; and (3) implementing Abnormal
Procedure (AP)-06. Loss of Steam Generator Feedwater, upon any CA-
autostart. The inspector verified that these compensatory actions.
either had been taken or were communicated to the control room operators
'
via Operations Technical Memorandum #97-01.
The inspector also verified
that the requirements of Unit 2 TS 3.7.1.5 to maintain a volume of
225.000 gallons of water in the Condensate Storage System were being
met.
c.
Conclusions
The inspector concluded that the licensee's effo,ts to determine if the
concern identified at the McGuire Nuclear Station was applicable to
Catawba were prompt.
Consultation with off-site resources to determine
the amount of air that would cause pump failure was appropriate, and
compensatory actions to prevent air-binding of the CA pumps in the
interim were conservative. An Unresolved Item was identified regarding
the potential for air binding the Auxiliary Feedwater pumps.
.E8
Miscellaneous Engineering Issues (92903)
E8.1
(Closed) Acoarent Violation 50-41?.414/97-04-01: Auxiliary Feedwater
System Single Failure Design Deficiency
During an inspection conducted January 6 through 23, 1997, the NRC
examined the facts and circumstances associated with a licensee-
Enclosure 2
_.
.
-
-
22
identified design deficiency that rendered the auxiliary feedwater
system outside its design basis.
On January 9.1997, Licen.see Event
Report (LER) 50-413/96-012 was submitted to communicate this
determination. and on January 17 Revision 1 to the LER was submitted to
provide additional information and corrective actions.
The NRC's inspection findings associated with this issue were documented
in NRC Inspection Report 413.414/97-04.
The issue was characterized as
Apparent Violation (EEI) 50-413.414/97-04-01: Auxiliary Feedwater
System Single Failure Design Deficiency.
By letter dated February 18.
1997, the NRC notified the licensee of an exercise of discretion in
.
accordance with Section VII.B.3 of the Enforcement Policy.
The letter
documented the closure of the apparent violation and completed the NRC's
.
action on the issue.
Accordingly, the apparent violation is
administrative 1y closed.
IV. Plant Sucoort
,
P1
Conduct of Emergency Preparedness Activities
Pl.1 Emeraency Exercise (71750)
On May 7. the resident inspectors observed the licensee's annual
emergency exercise. The exercise was conducted from the training
"
simulator and included Technical Support Center. Operations Support
Center, and Emergency Operations Facility activation with limited
participation by offsite organizations.
Inspector observations included
simulator. Technical Support Center, and Operations Support Center
functions.
The inspectors noted particularly good performance by
personnel in the Operations Support Center to recognize that a field
team was to be dispatched with multiple tasks to be performed.
The
tasks were divided and more than one team was dispatched to perform the
tasks. The inspector observed the licensee's critique and noted that
i
discrepancies and strengths identified were appropriately characterized.
In general, the inspectors concluded that licensee performance during
the drill was appropriate.
R1
Radiological Protection and Chemistry Controls
R1.1 Tours of the Radioloqical Control Area (RCA) (71750)
The inspectors periodically toured the RCA during the inspection period.
Radiological control practices were observed and discussed with
radiological control personnel, including RCA entry ind exit, survey
postings, locked high radiation areas, and radiologicel area material
conditions.
The inspector concluded that radiation control practices
were proper.
-
Enclosure 2
. . -.
.. - - . . - - . _ - - - . - . - - - . - . - -
- - - - . . .
- - - - - -
1
y
,
23'
R2-
Status of Radiological Protection and Chemistry Facilities and Equipment
I
R2.1 Backaround Radiation Levels in the Vicinity of Whole Body Friskers
]
(71750)
,
During a plant tour on April 28. the inspector noted that two whole body
'
friskers located in the men's change facility (located in the Auxiliary
j
!
Building) were in an alarm condition that indicated high background
radiation levels. -One of the friskers had been removed from service.
the other appeared to be available for use. The inspector contacted
-
Radiation Protection Surveillance and Control and was informed that the
i
4
friskers had been checked and were acce) table for. use.
The inspector
also noted that hand held friskers in t1e area were reading a higher
radiation background than normal, but still within limits to perform an
acceptable survey.
The inspector questioned the cause for the higher than normal radiation
background with licensee radiation protection supervision. Apparently,
a waste system line in the vicinity of the change room has caused
~j
elevated background levels in the past. After questioning by the
inspector, the licensee initiated PIP C-97-1463 to address the issue.
The line was subsequently flushed and the background radiation levels
returned to normal
l,
The inspector noted that radiation protection personnel did not
demonstrate a questioning attitude and initiate appropriate actions.
including initiation of a PIP, until the ins)ector questioned the whole
~
body frisker alarms and the cause of the higler than normal background
radiation.
'.
S1
Conduct of Security and Safeguards Activities
S1.1 fgneral Comments (71750)
1
'
During the period, the inspectors toured the protected area and noted
that the perimeter fence was intact and not comaromised by erosion or
disrepair.
I:olation zones were maintained on Joth sides of the barrier
i
and were free.of objects which could shield or' conceal an individual.
The inspectors periodically observed personnel. packages, and vehicles
entering the protected area and verified that necessary searches,
visitor escorting, and special purpose detectors were used as applicable
prior to entry.
Lighting of the perimeter and of the protected area was
acceptable and met illumination requirements.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors ) resented the inspection results to members of licensee
management at t1e conclusion of the inspection on June 12, 1997.
The licensee
acknowledged the findings presented.
No proprietary information was
identified.
Enclosure 2
24
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
Harrall. T. , Instrument and Electrical Maintenance Superintendent
Kelly, C.. Maintenance Manager
Kimball. D., Safety Review Group Manager
!
Kitlan
M.. Regulatory Compliance Manager
McCollum. W., Catawba Site Vice-President
Nicholson, K., Compliance Specialist
Peterson. G.. Station Manager
1
Enclosure 2
_ _ _
25
INSPECTION PROCEDURES USED
'
IP 37551:
Onsite Engineering
IP 61726:
Surveillance Observation
IP 62700:
Maintenance Program Implementation
IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
'
50-413/97-08-01
Inadequate Alarm Response Results in Inadequate
and Untimely Corrective Actions for Valve
Operability Determination (Section 01.2)
50-414/97-08-02
Failure to Authorize Overtime in Excess of
,
Administrative Limits (Section 06.1)
50-413.414/97-08-03
IFI
Overtime Control Program Limitations (Section
06.1)
'
50-413.414/97-08-04
IFI
Reportability of NSW System Actuations (Section
M1.2)
50-413/97-08-05
Inadequate Procedure Results in Autostart of the
NSW Pumps (Section M1.2)
50-413.414/97-08-06
Inadequate Motor Preventive Maintenance and
,
Control Procedures (Section M1.3)
50-413.414/97-08-07
Potential Air Binding of Auxiliary Feedwater
Pumps (Section E2.1)
G_losed
l
50-413/96-001
LER
Unit Shutdown Required By Technical
Specifications (Section 08.1)
l
50-414/96-004
LER
Containment Floor and Equipment Sump Level Alarm
l
Inoperability due to an Operator Aid Computer
Error (Section 08.2)
l
Enclosure 2
l
26
50-413.414/96-16-02
Nonconservative RCS Controlled Leakage Test
(Section M8.1)
50-413/96-09
LER
Inadequate Reactor Coolant Controlled Leakage
Test (Sections M8.1, M8.2)
50-413.414/97-04-01
Auxiliary Feedwater System Single Failure Design
Deficiency (Section E8.1).
List of Acronyms
!
AFWCST-
Auxiliary Feedwater System Condensate Storage Tank
ANSI
-
American Nuclear Standards Institute
A0V
-
Air Operated Valve
ASME -
American Society of Mechanical Engineers
CA
-
Auxiliary Feedwater System
CFIV -
Main Feedwater Containment Isolation Valve
CFR
Code of Federal Regulations
-
ECCS -
Apparent Violation
-
-
End of Cycle
-
Engineered Safeguards Feature
FSAR -
Final Safety Analysis Report
GL
-
Generic Letter
IFI
-
Inspector Followup Item
IN
-
Information Notice
IR
-
Inspection Report
MSIV -
-
Non Cited Violation
NRC
-
Nuclear Regulatory Commission
NS
-
NSD
-
Nuclear Site Directive
-
Nuclear Service Water
NSWP -
Nuclear Service Water Pond
-
Public Document Room
Problem Investigation Process
-
-
Preventive Maintenance
psig -
Pounds Per Square Inch Gauge
-
Quality Assurance
-
Radiologically Controlled Area
-
Reactor Coolant Pump
-
-
Regulatory Guide
-
Radiation Protection
-
Main Steam System Bypass to Condenser
-
Safety Injection
-
Select Licensee Commitments
-
Main Steam System
SPOC -
Single Point of Contact
SRG
Safety Review Group
-
TS
-
Technical Specifications
Enclosure 2
.
27
UFSAR -
Updated Final Safety Analysis Report
i
-
Unresolved Item
UST
-
Upper Surge Tank
Volts, alternating current
VAC
-
VDC
Volts, direct current
-
-
Violation
VN
-
Variation Notice
-
Work Order
4
!
Enclosure 2