ML20216H617
| ML20216H617 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 04/06/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20216H589 | List: |
| References | |
| 50-369-98-02, 50-369-98-2, 50-370-98-02, 50-370-98-2, NUDOCS 9804210203 | |
| Download: ML20216H617 (22) | |
See also: IR 05000369/1998002
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-369, 50-370
License Nos:
NPF-9 NPF-17
Report No:
50-369/98-02, 50-370/98-02
Licensee:
Duke Energy Corporation
Facility:
McGuire Nuclear Station Units 1 and 2
Location:
12700 Hagers Ferry Road
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Huntersville NC 28078
Dates:
January 25. 1998 - March 7, 1998
Insper, tors:
S. Shaeffer. Senior Resident Inspector
M. Sykes, Resident Inspector
M. Franovich, Resident Inspector
E. Lea, Regional Inspector (Sections 02.4 and E1.1)
Approved by:
C. Ogle, Chief, Projects Branch 1
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Division of Reactor Projects
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9804210203 980406
Enclosure 2
ADOCK 05000369
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EXECUTIVE SUMMARY
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McGuire Nuclear Station. Units 1 and 2
NRC Inspection Report 50-369/98-02, 50-370/98-02
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covered a six-week
period of resident inspection: in addition it includes the results of an
announced inspection by a regional inspector.
Doerations
The licensee reported three events in accordance with the requirements
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of 10 CFR 50.72. (Section 01.2)
Plant systems operated as expected following a malfunction of the Unit 2.
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main generator exciter voltage regulator.
Operators responded
appropriately during a voltage regulator malfunction and subsequent
reactor trip. An NRC identified discrepancy between reactor trip
breaker train actuation times was appropriately addressed by the
licensee. (Section 02.1)
Operators responded promptly and appropriately to the loss of motor
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control center 2MXA.
The licensee s efforts to identify the root cause
were inconclusive. (Section 02.2)
Accessible components of the Unit 1 and Unit 2 containment spray systems
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were properly aligned.
Material condition was adequate with the
exception of valve 2NS38B. (Section 02.3)
Operator response was adequate once the reactor was manually tri) ped,
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following a significant multiple rod drop event. However, a weacness
was identified in McGuire procedure AP/1/A/5500/14. Rod Control
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Malfunction. Revision 2. for addressing multiple dropped rods.
Procedure ambiguity and training deficiencies associated with response
to multiple rod drop events contributed to additional burdens placed on
the operators in response to the event. Once the weakness was
identified, the licensee took immediate actions to assure that cdequate
guidance was available to the operators to address potential future
dropped rod events. (Section 02.4)
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Further followup on the licensee's previous industry experience review
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regarding multiple rod drop events was identified as an Unresolved Item.
(Section 02.4)
Prior to an actual event involving multiple dropped rods, the exchange
of information between control room operators was conflicting following
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a pre-job briefing associated with troubleshooting efforts for rod
control system alarms.
Key operations personnel did not fully discuss
or evaluate the technical bases or merit for establishing a consistent
approach to addressing potential multiple dropped rod scenarios.
(Section 02.4)
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finntenance
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The licensee *s )ost-trip investigation, repair, and testing of the
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malfunctioning Jnit 1 main generator voltage regulator verified proper
equipment operation prior to returning the unit to 100 percent power
output.-(Section M2.1)
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One example of'a violation of Technical Specification 6.8.1 wn
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identified for failing to establish adeguate instructions for the repair
.of the ICF35 valve actuator.
This resulted in degraded operation of the
containment isolation valve.
In addition..the licensee *s documentation
of repair activities associated with valve ICF35 was poor. (Section
M2.2)
Spurious malfunction of Unit 1 Rod Control system power supply fuses
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-resulted in a multiple drop rod event.
(Section 02.4)
A second example of Technical Specification 6.8.1 was identified due to
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maintenance technicians failing to follow station procedures for the
installation of lower containment purge inlet isolation valve IVP8 seal
ring adjusting screw. The failure to follow established procedures
resulted in IVP8B being in a degraded condition. (Section M2.3)
Maintenance practices in applying sealant to containment purge valves
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was identified as a weakness that ultimately resulted in failure of
lower containment purge inlet isolation valve IVP88. (Sectior, H8.1)
Enaineerina
Following the manual reactor trip due to multiple dropped rods, the
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licensee was aggressive in establishing a special team to perform an
investigation of apparent cause and assessment of plant response.
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Resolution of identified technical issues was adequate to support unit
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restart.
(Section El.1)
An Unresolved Item was identified to investigate the adequacy of
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maintenance procedures in meeting Technical 5)ecification requirements
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during repairs of refueling water storage tanc level instrumentation
system and containment pressure control system components. (Section E3.1
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and Section E3.2)
Plant Sucoort
Locked high radiation doors were properly controlled high radiation and
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contamination areas were properly posted, and radiological area survey
maps were updated to accurately reflect radiological conditions in the
respective areas. (Section R1.1)
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Reoort Details
Summary of Plant Status
Unit 1
' Unit 1 began the inspection period at approximately 100 percent power. On
February,9,1998. the reactor was manually tripped following an unexpected rod
drop event. Unit 1 was returned to power operation on February 11, 1998. On
February 14, 1998, the: licensee reduced rated reactor )ower to ap)roximately
25 percent to repair main feedwater isolation valve IC 35. On Fe)ruary 15.
1998, the licensee returned Unit 1 power' output to 100 percent. On March 2,
1998, the licensee reduced reactor power to aaproximately 15 percent to repair
.a hydraulic fluid leak at the main turbine. On March 3. 1998, the licensee
returned Unit 1 power to 100 percent and operated at 100 percent throughout
the remainder'of the reporting period.
Unit'2
Unit 2 began the inspection period at approximately 100 percent power. On
February 22, 1998, an automatic reactor trip occurred following a turbine
trip, after a main generator exciter voltage regulator malfunction.
The unit
returned to power operation on February 24, 1998.
On March 3. 1998. Unit 2
reactor power was momentaril
cfeedwater system transient. y reduced to approximately 93 percent following a
On March 7. 1998, the licensee reduced reactor
power from 100 percent to perform an ins
during security modification activities.pection of a 6900 V bus duct damaged
At the end of the period. Unit 2
power escalation to 100 percent was in progress.
- Review of Uodated Final Safety Analysis Reoort -(UFSAR) Commitments
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While performing inspections discussed in this report, the inspecters reviewed
the applicable portions of the UFSAR that were related to the areas inspected.
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The inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures, and parameters.
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I. Ooerations
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- Conduct of Operations
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01.1 General Comments (71707)
usingInshectionProcedure71707,theinspectorsconductedfrehuent
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reviews o ongoing plant operations. In general, the conduct o
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operations was professional and safety-conscious, including response to
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several complex transients. S)ecific events and noteworthy observations
are detailed in the sections w11ch follow.
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01.2 ~10 CFR 50.72 Notifications
a.
Insoection Scone (71707)
During the inspection aeriod, the licensee made the following
notifications to the NRC as required or for information purposes. The
inspectors reviewed the. events for impact on the operational status of
the facility and. equipment.
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b.
Observations and Findinas
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1.
On February 9.1998, the licensee notified the NRC of a manual reactor trip from 100
drop)ed into the core. percent power after several control rodsSince the c
not )een specifically analyzed. the licensee evaluated the
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>otential that-the plant was in an unanalyzed condition. On
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r bruary 10. 1998, the licensee updated the notification to state
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that an event; specific evaluation had been com
was bounded by the applicable UFSAR analysis. pleted and the event
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This event is
further discussed in Section 02.4.
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2.
On February 15. 1998, the licensee notified the NRC of a
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notification to state and local agencies following a transformer
oil spill in the McGuire switchyard.
On February 16, 1998, the
licensee updated the notifications when the oil spill was
determined to have migrated to a nearby creek.
3.
On February 22, 1998, the licensee notified the NRC of an
automatic Unit 2 reactor trip. The trip occurred after.a main
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generator exciter voltage regulator caused a turbine-generator
trip from 100
Section 02.1. percent power. This event is further discussed in
c.
Conclusions
The inspectors concluded that the licensee reported the events in
accordance with the requirements.of 10 CFR 50.72.
02
Operational Status of Facilities and Equipment
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02.1 Automatic Reactor Trio Followina Voltaae Reaulator Malfunction
a.
Insoection Scoce (71707 and 40500)
.The inspectors responded to the station to evaluate plant and personnel
response following an automatic Unit 2 reactor trip.
b.
Observations and Findinas
On February 22. 1998. McGuire Unit 2 automatically tripped from 100
percent when the main turbine tripped due to a generator trip.
The
automatic reactor trip was expected when the turbine tripped with
reactor power greater than 48 percent. The turbine trip occurred after
a malfunction of the Unit 2 main generator exciter voltage regulator.
Reactor o)erators manually started both motor-driven auxiliary feedwater
pumps. T1e turbine-driven auxiliary feedwater pump automatically
started due to Lo-Lo Level in 2 of 4 steam generators. The 2B emergency
diesel generator automatically started, but was not required to sup)1y
safety-related loads. The unit was stabilized in Mode 3 and both t1e 2B
emergency diesel generator and the auxiliary feedwater system were
returned to standby..
The inspectors res onded to the hicer.
lant after notification of the event
through the NRC Regional Duty Of
The inspectors reviewed alarm
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log reports and Sarameter data trends. Trend data indicated that the
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malfunction of t1e voltage regulator resulted in a significant voltage
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Operators responded to the transient, but were unable to
regain control of the main generator output. A generator trip occurred
as a result of loss of field. The voltage transient caused a momentary
undervoltage condition on the B Train 4160V Essential Power Bus 2ETB
resulting in the 2B emergency diesel generator automatically starting.
During reviews of plant response data, the inspectors noted
discrepancies in reactor tri
Operator Aid Computer (OAC).p breaker actuation times obtained from theThe po
between A and B Train actuation. The licensee immediately evaluated the
OAC points and determined that the computer generated time stamp for the
B reactor trip breaker was incorrect. The licensee provided the
inspectors with confirmatory information that the actual switchgear
actuation times were within the 150 millisecond acceptance criteria.
The discrepancy between reactor trip breaker train actuation times was
appropriately addressed by the licensee. The inspectors verified that
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no undervoltage condition occurred on 2 ETA. which would have caused an
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automatic start of the 2A emergency diesel generator. The licensee
determined that specific operations guidance should be developed for
responding to malfunctions of exciter voltage regulator.
The guidance
was developed and provided to operations prior to restart.
The licensee immediately began a reactor trip) investigation in
accordance with Nuclear System Directive (NSD 505. Investigation of
The apparent cause identified by the licensee was a
failed voltage regulator firing circuit card.
The inspectors attended
licensee restart status meetings and the Plant Operations Review
Committee meeting to confirm that identified issues had been resolved
prior to Unit 2 restart.
The inspectors noted that the licensee
appropriately addressed the restart issues.
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c. Conclusions
The inspectors concluded that plant systems performed as expected
following malfunction of the Unit 2 main generator exciter voltage
regulator. Operators responded appropriately to changing plant
parameters although no specific guidance had been provided for voltage
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regulator malfunction.
fn NRC-identified discrepancy between reactor
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trip breaker train actuahon times was appropriately addressed by the
licensee.
02.2 Main Feedwater Transient Followina loss of Motor Control Center 2MXA
a.
Insoection Scooe (71707)
The inspectors responded to the control room, following a notification
by the licensee of a Unit 2 main feedwater transient, to monitor
operator performance and evaluate plant response.
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b.
Observations and Findinas
On March 3.1998, operators responded to a loss of motor control center
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2MXA. Ground fault protective relays had tripped open the normal supply
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breaker and the alternate supply breaker did not automatically close due
to the fault.
The loss of power affected main feedwater pump
recirculation valves. The valves failed open diverting a portion of the
main feedwater to the condenser hotwell. The steam generator level
control system responded as expected to the feed / steam flow mismatch.
Main feedwater flow increased and pump suction pressures approached the
pump trip setpoints. The standby condenser hotwell
started on low main feedwater pump suction pressure.pum) automatically
T1e 2A condensate
booster pump did not start because the bearing oil pump had been
disabled by the loss of 2MXA.
Operators recognized the potential for a
main feedwater pump trip and reduced turbine-generator load to
approximately 93 percent.
The inspectors reviewed trend data and plant alarm logs to evaluate
plant response to the loss of 2MXA and the subsecuent feedwater system
transient. The inspectors noted that the OAC incicated a maximum
thermal power best estimate of approximately 103.9 3ercent of reactor
rated thermal power. The inspectors investigated tie computer
calculation inputs to confirm that the best estimate calculation was
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based on an error in secondary heat balance. The computer calculation
was verified to be false.
The inspectors examined nuclear
instrumentation system trends confirming that the licensee did not
exceed rated reactor thermal power limits.
The licensee performed inspections and tests of protective relays and
motor control center loads to identify the cause for the protective
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relay actuation.
The licensee performed visual inspection of accessible
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motor control center compartments.
At the close of the inspection
period, the licensee was unable to identify the apparent cause for the
ground fault relaying. but had an open problem report to pursue the
issue.
c.
Conclusions
The inspectors concluded that operators responded promptly and
appropriately to the loss of motor control center 2MXA.
Licensee
efforts to identify the root cause were inconclusive.
02.3 Unit 1 and Unit 2 Containment Sorav systems (CSS) Walkdown
a.
Insoection Scoce (71707)
The inspectors completed detailed inspections of selected portions of
the Unit 1 and Unit 2 CSS to assess material conditions and verify
proper system alignment. Field verification of valve position,
electrical breaker alignment, and main control room indication were
performed. The inspectors also verified local containment
control system (CPCS) (a sub-system of CSS) panel status. pressure
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b.
Observations and Findinas
Material condition of equipment was adequate with the exception of valve
2NS388.
Valve 2NS38B is a safety-related discharge valve from the RHR
system to the containment spray header. The inspector observed actuator
fluid leaking onto the floor.
No work request had been generated. The
inspectors informed the licensee of the actuator oil leak and the
licensee included 2NS38B into their fluid leak monitoring (FLM) program
to determine additional actions
The inspectors also observed
indications of boric acid leaks on other system components that were
reported to operations. Additionally, the inspectors confirmed the
licensee had an established program to monitor system leakage outside
containment to ensure Jost-accident radioligical doses would be
maintained within esta]lished limits.
No system alignments or other
deficiencies were identified,
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Conclusions
The inspectors confirmed that the selected portions of the Unit 1 and
Unit 2 containment spray systems were properly aligned.
With the
exception of valve 2NS38B. material condition was adequate.
02.4 Manual Reactor Trio Followina Multiole Control Rod Insertion
a.
Insoection Scooe (71707)
The inspectors responded to a manual Unit 1 reactor trip that occurred
on February 9, 1998. The inspectors observed operator performance,
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interviewed licensee personnel, and reviewed documentation to assess the
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operators' pre-trip and post-trip performance. Additional review of the
rod control s
Section E1.1.ystem failure investigation process was discussed in
b.
Observations and Findinas
On February 9.1998, the licensee initiated the manual reactor trip when
pressurizer pressure decreased to approximately 1950 psig.
The decrease
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in pressurizer pressure occurred as the result of multiple control rods
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unexpectedly dropping into the core. Documentation reviewed by the
inspectors indicated that eight rods dropped fully into core and three
rods fell partiall
10:26:03 a.m..
The rods were from
three rod groups. y into the core atAs plant parameters changed and pressu
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approached the automatic trh setpoint of 1945.psig. the manual reactor trip was initiated at 10:27:39 a.m.
Plant equipment responded to the
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manual trip as expected and the plant was safely shutdown to Mode 3.
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other major equipment anomalies were noted.
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The inspectors determined by interviewing licensee personnel and
reviewing documentation that the rods dropped due to a loss of DC power
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supply number 4 (PS4). The power supply was lost while technicians were
p(erforming troubleshooting activities on redundant power supply number 3
PS3) to identify the cause for an earlier rod control non-urgent
failure alarm.
Both power supplies were located in rod control system
power cabinet 280.
During the troubleshooting activities and coincident
with the rod drop, a rod control urgent failure annunciator also alarmed
and cleared instantly.
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Maintenance technicians determined that a failure of PS3 had caused the
rod control non-urgent failure alarm to annunciate, but was not related
to the rod control ur ent alarm. The technicians re) laced PS3 and were
restoring the AC supp
to PS3 when the Rod Control
Jrgent Alarm was
received and the cont 1 rods dropped into the core.
In response to the alarm, operators referred to abnormal operating
procedure AP/1/A/5500/14 Rod Control Malfunction. Revision 2, for
guidance.
Post-event documentation indicated that AP-14 was referred to
by the operators each time an alarm associated with the rod control
system was received.
The sequence-of-events log contained an entry for
time 10:26:03: "AP-14 was consulted; main steam pressure, )ressurizer
pressure level falling." The operators manually tripped tie reactor at
10:27:09, narrowly avoiding an automatic trip.
During interviews with the operators, the inspectors determined that the
issue of multiple dropped control rods had been previously discussed
between operating shifts.
Specifically, the previous shift's SR0 stated
that during a pre-job briefing, which was conducted in conjunction with
the previously mentioned troubleshooting activities, the unit operators
were instructed to immediately trip the reactor should multiple rods
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drop into the core. The guidance to immediately trip the reactor, was
communicated to the on-coming shift's reactor operators (on duty at the
time of the event).
However, when the on-duty SR0 was told of the
decision made by the previous crew, the SRO instructed the operators to
follow procedure AP-14, which did not require the reactor to be
immediately tripped if multiple rods drop)ed. The' procedure directed
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the operators to "Begin unit shutdown to 3e in Mode 3 within 6
hours...."
The inspectors concluded that this exchan!e of pertinent information
between control room operators was confli ting. Specifically, key
control room personnel failed to fully discuss or evaluate the technical
bases or merit for establishing a consistent approach to addressing
multiple dropped rod scenarios.
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The inspectors reviewed the licensee's safety evaluation for the
deletion of the negative flux rate trip, approved by the NRC in 1994, to
determine what changes to the abnormal operating procedure, if any, were
required to address the removal of the negative flux rate trip as it
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pertained to multiple dropped rods. The inspector also reviewed the
modification package to determine if any operator training was required
to provide the operator E"idance on how to handle multiple dropped rods
once the negative rate trip was removed. The inspectors did not
associated with the modification, quired as a result of the changes
identify any training that was re
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nor did the inspectors identify
specific procedure changes to address multiple dropped rods.
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After completing the review of the modification package, the procedures
and training material, the ins)ectors concluded that there were
weaknesses in the licensee *s a) normal operating procedure AP-14, Case
III, in that it did not require the operators to immediately address the
addressed in 03/1/A/61)D/22. Unit 1 Data Book,ple dropped rods were
issue of multiale drop)ed control rods. Multi
Revision 473. Guidelines
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for Recovering Misaligned / Drop)ed Control Rod. OP/1/A/6100/22 required
that the reactor be promptly slutdown, but did not define the. term
address y".
The inspector also concluded that lack of clear guidance to
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the issue of multiple dropped rods, when coupled with this type
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of rod drop event. could lead to the plant being operated outside the
assumptions identified in Chapter 15 of the UFSAR (See Section E1.1)..
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The licensee evaluated existing procedures, and contacted the vendor and
other utilities to obtain information pertaining to multiple dropped
rods. As a result of the reviews and research conducted. the licensee
revised their procedure to provide clearer guidance to the operators in
the event a similar event were to occur in the future. The inspectors
reviewed these changes and found them acceptable.
For the specific
McGuire rod drop event, the licensee determined that the involved rod
Battern did not place the unit outside the bounds identified in the
FSAR.
Conclusions
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The inspectors concluded that the exchange of pertinent information
between control room operators was conflicting. Specifically. key
control room personnel failed to fully evaluate the technical bases or
merit for estabiishing a consistent approach to addressing multiple drop
rod scenarios.
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manually tripped,perator response was adequate once the reactor was
following the multiple rod drop event.
However, the
inspectors concluded that the guidance provided in AP-14. Case III. for
addressing multiple dropped rods was weak.
Procedure ambiguity and
training deficiencies associated with response to multiple rod drop
events contributed to additional burdens placed on the operators in
response to the event. Once the weaknesses were identified. the
licensee took actions to assure that adequate guidance was available to
the operators to address multiple dropped rod events in the future.
Further followu 'on the licensee's previous industry experience review
regarding) multi le rod drop events, will be identified as Unresolved
Item (URI 50-3 9.370/98-02-03: Followup on Licensee's Previous
Industry Experience Review Regarding Multiple Rod Drop Events.
II. Maintencnce
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Conduct of Maintenance
M1.1 General Comments
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a.
Insoection Scone (61726 and 62707)
The inspectors observed portions of the following work activities:
Procedure / Work Order
Title
PT/1/A/4209/01A
NV Pump 1A Performance Test
PT/2/A/4350/02B
28 Diesel Generator Operability Test
PT/1/A/4401/01B
KC Train 1B Performance Test
PT/2/A/4600/01
RCCA Movement Test
b.
Observations and Findinas
The inspectors witnessed selected surveillance. tests to verify that
approved procedures were available and in use; test equipment was
calibrated: test prerequisites were met: system restoration was
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completed: and acceptance criteria were met.
In addition, the
inspectors reviewed or witnessed routine maintenance activities to
verify, where applicable, that approved procedures were available and in
use, prerequisites were met, equipment restoration was completed, and
maintenance results were adequate.
c.
Conclusion
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The inspectors concluded that the observed surveillance activities were
completed satisfactorily.
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M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Malfunction of Unit .7 Main Generator Exciter Voltaae Reaulator
a.
Insoection Scoce (62707)
The inspectors evaluated licensee actions to identify and resolve
malfunctions of the Unit 2 main generator exciter voltage regulator.
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b.
Observations and Findinas
As a result of a main generator voltage regulator failure. Unit 2
automatically tripped from 100% power. The licensee examined the failed
regulator to identify the apparent root cause.
The licensee identified
a malfunctioning pulse generator circuit board in one of the two firing
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circuitry drawers. The circuit card was returned to the vendor for
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further failure analysis.
Following restart, but prior to aligning the unit to the electrical
grid, the licensee conducted additional testing of the voltage regulator
while the generator was at no load conditions.
The testing was
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performed in accordance with approved temporary station procedure
TT/2/B/9700/182. Unit 2 Generator Voltage Regulator Functional
Verification. Revision 0.
The inspectors monitored the test evolution
and reviewed the test procedure. The inspectors confirmed that a
malfunction of the voltage regulator or associated equi) ment during the
test evolution would not have the potential to impact t1e plant during
the test. As a result of the testing, the licensee confirmed proper
operation of the voltage regulator, specifically, the firing circuitry
and pulse generator cards.
Following the test, the licensee aligned the
unit to the grid and escalated power to 100 percent. A recorder was
installed to continuously monitor regulator performance during power
escalation and 100 percent steady-state operation.
No further turbine
control abnormalities were observed.
c.
Conclusions
The inspectors concluded that the licensee's investigation, repair, and
testing of the malfunctioning main generator voltage regulator
approariately verified equipment condition prior to returning the unit
to 10] percent power output.
M2.2 Main Feedwater Isolation Valve Hydraulic Fluid Leak
a.
Insoection Stone (62707)
The inspectors evaluated licensee performance in responding to hydraulic
fluid valve actuator deficiencies for main feedwater containment
isolation valve ICF35.
b.
Observations and Findinas
On February 14. 1998, the licensee received indication of excessive
hydraulic pump operation at the valve actuator for main
feedwater/ containment isolation valve ICF35.
The licensee performed
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visual inspection of the actuator and discovered hydraulic fluid leak at
an accumulator fitting.
The accumulator has a nitrogen charge to
provide the closing force for the valve on a feedwater isolation signal.
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Initial attem)ts to tighten the fitting resulted in increased leakage.
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The licensee >1alted the maintenance until further plans could be
established.
The licensee reduced power to approximately 25 percent and closed and
de-energized the affected valve.
Main feedwater was supplied to the
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Unit 1 A steam generator through the auxiliary feedwater nozzle. The
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licensee depressurized and drained the hydraulic system prior to
removing the failed fitting. The licensee determined that the fitting
had a damaged 0-ring. The fitting and 0-ring had not been properly
installed during previous maintenance. A replacement fitting was
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installed. hydraulic fluid was added, and the valve was stroke time
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tested in accordance with PT/1/A/4253/03A. Revision 25. and
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PT/1/A/4253/038. Revision 23. Main Feedwater Valve Train A and Train B
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Stroke Timing.
Valve stroke times were within acceptable ranges and the
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valve was declared operable.
In the past because of numerous feedwater isolation valve hydraulic
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fluid leaks requiring unit power reductions the licensee developed and
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initiated station modifications to remove this fitting during previous
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maintenance / refueling outages.
However, the licensee decided to defer
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replacement of the fittings for valve ICF35.
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On February 23. 1998.- the licensee received indication of excessive
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hydraulic system pump operation for ICF35.
Investigation of the
actuator revealed no active hydraulic system leaks: however, the
hydraulic system fluid inventory was approximately 2 quarts low. The
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licensee added the necessary hydraulic fluid. performed pump capacity
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testing to verify proper pump operation and returned the system to
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o)erable.
No power reduction was necessary. The licensee determined
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tlat the low oil level was due to entrained air in the system and fluid
reservoir that aided in providing a false indication of system
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inventory.
The gradual dissipation of air from the system resulted in
increased operation of the hydraulic pump.
Based on reviews of completed maintenance procedures and discussions
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with maintenance personnel, the ins)ectors determined that the guidance
provided to perform venting of the lydraulic system following corrective
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maintenance was inadequate to ensure complete removal of air from the
hydraulic system. The expedited repair exacerbated this problem in that
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adequate time for the entrained air to dissipate was not incorporated
into the procedural guidance. This failure to provide adequate guidance
'.
50-369/98 g of valve ICF35 will be identified as an example of violation
for ventin
02-01: Failure to Follow and/or Provide Adequate Procedures
,
for Maintenance on Unit 1 Containment Isolation Valves. The inspectors
1
also noted that the completed procedure did not accurately reflect
performance of the specific venting activities accomplished. This
documentation weakness was conveyed to station management. The licensee
acknowledged the documentation deficiencies and stated that actions will
be initiated to emphasize management expectations for the accuracy of
documentation.
!
c. Conclusion
The inspectors concluded that the licensee failed to establish adequate
'
guidance for the repair of the ICF35 valve actuator which resulted in
degraded operation of the containment isolation valve. The inspectors
l
.
.
11
also concluded that the licensee's documentation of repair activities
for valve ICF35 was poor.
M2.3 Recurrino Deoradation of Unit 1 Containment Purae Valve 1VP88
a.
Insoection Scone (62707)
The inspectors reviewed the repairs associated with Unit 1 containment
purge inlet valve IVP8B performed on January 31, 1998.
This was the
second time in the last three months that IVP8B was found in a de
condition during a local leak rate test (LLRT) (see section M8.1) graded
.
b.
Observations and Findinos
'
On January 29, 1998, the licensee discovered increased leakage through
valve IVP8B during a quarterly LLRT of penetration IM456. Valve IVP8B
is a 24-inch butterfly valve that is a normally closed containment
isolation valve. The valve was degraded with b aka
3400 standard cubic centimeters per minute (sccm) (ge at approximately
6900 sccm is the
failure limit). A retest was performed on January 30, 1998 and leakage
had '.e reased to 4350 sccm.
Valve IVP88 was repaired without opening
the valve and a
January 31, 1998. post-maintenance LLRT was successfully performed on
During the repair of IVP8B on January 31, 1998.
discovered that one set screw was not tightened. plant personnel
which coincided with
the location of the leak. There are 24 adjusting set screws evenly
spaced around the circumference of the valve that hold the elastomer
seat ring in place. Maintenance 3rocedure MP/0/A/7600/042. Fisher T-
Ring 9200 Series Butterfly) Valve Corrective Maintenance. Revision 7
(used during 1E0C11 outage , requires that each of 24 adjusting set
screws be tightened 1/4 turn, one at a time. until the seat ring
contacts the seat at one point and that screws are tightened until the
seat ring contacts the seat in all areas. The licensee indicated that
the seat ring was installed during the previous Unit I refueling outage.
Contrary to the above. maintenance personnel who had replaced the seat
ring during the previous Unit I refueling outage failed to properly
install the adjusting screws that hold the elastomer seat in place.
After several quarterly LLRT tests, the seat ring ultimately deformed to
the point where it protruded from the retaining ring. The inspectors
identified this as a second example of VIO 50-369/98-02-01: Failure to
Follow and/or Provide Adequate Procedures for Maintenance on Unit 1
Containment Isolation Valves.
c.
Conclusions
The inspectors concluded that the re) air on January 31. 1998 of
degraded containment purge valve IVP38 was a
additional- exam)le of a violation of TS 6.8.ppropriate. However. an
1 was identified.
Maintenance tecinicians who had worked IVP8B during the previous Unit 1
refueling outage failed to properly install the seat ring in accordance
with a plant maintenance procedure and resulted in IVP8B being in a
degraded condition.
,
.
-
12
M8
Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) URI 50-369.370/97-18-02 Potentially Inadequate Corrective
Action for Use of Sealant on Containment Purge Isolation Valves
This URI documented the inspectors * concerns with maintenance practices
and the circumstances related to a failure of containment p/A/ge air
'
l
ur
inlet valve IVP88. The inspectors reviewed procedure MP/0
7600/042.
Fisher T-Rin
Revision No.g 9200 Series Butterfly Valve Corrective Maintenance.
8. and Work Order 97095980-01 for the repair of valve
IVP8B. The inspectors also interviewed cognizant personnel.
On November 7. 1997, the licensee determined that containment
penetration IM456 failed a leak rate test due to excess leakage through
containment purge valve IVP8B. The inspectors reviewed the corrective
actions and interviewed maintenance personnel. Containment penetration
1M456 consists of purge valves IVP8B and IVP9A that are the outboard
(located in the annulus) and inboard isolation valves, respectively.
Both valves are normally closed. The inspectors were concerned that (1)
adequate corrective action had not been taken when the same penetration
had failed leak rate testing due to leakage through IVP9A earlier in
1997, and (2) that flange sealant may not be qualified for post-accident
conditions since arocedures did not specify use of flange sealant.
In
each case for IVP3B and IVP9A. the failure was attributed to excess
flange sealant that dripped onto the valve seat which prevented full
closure of the valve.
A quarterly surveillance )erformed on October 30, 1997. revealed
increased penetration leacage (490 sccm) from the previous surveillance
(2 sccm). The failure limit was 6900 sccm.
In an attempt to reduce
leakage below a station goal of 100 sccm. the licensee made minor valve
adjustments and cycled the valve to gain better closure. The licensee
clarified that failure of IVP88 had occurred after the valve was cycled
between November 6 and 7, 1997. The valve failure mechanism was
attributed to sealant that had dripped from the flange onto the valve
seat T-ring. The root cause of the problem was a maintenance work
practice error when too much sealant was applied to the flange and
dripped out when the flanges were torqued during previous work on the
valve. When the valve was opened, the excess sealant spread out on the
T-ring and obstructed the valve disc when attempting to re-close the
valve.
Presence of sealant in the valve would not have caused a
failure if the valve had remained closed.
The licensee attributed the
increased leakage seen prior to cycling the valve due to disc movement
from spring relaxation.
In order to reduce flange leaka
for minor flange imperfections.ge. sealant had been used to compensate
The inspectors determined that the
material safety data sheet (MSDS) for the sealant-indicated that the
material was qualified for containment temperatures that could be seen
in a design-basis post-accident environment at McGuire. The sealant is
a Cate
Guide. gory.1 material as identified in the licensee's Power Chemistry
L
Corrective actions included in part. (1) instructing
maintenance p(2) enhancement of the maintenance procedure to requireerso
j
valves, and
1
visual inspection and cleaning of the valve seat area.
The inspector
!
concluded that these corrective actions were adequate.
.
,
.
13
The inspectors concluded that maintenance personnel practices in
applying sealant to containment purge valves was a weakness that
ultimately resulted in failure of valve IVP8B (after cycling the valve)
l
and placed the unit in a degraded condition.
However, corrective
!
actions taken to provide better guidance and prohibit the use of sealant
i
on similar containment isolation valves were adequate to prevent
recurrence. This item is closed.
III. Enoineerina
El
Conduct of Engineering
El.1 Rod Control Sv-tam Failure Investiaation
a.
Insoection Scote (37551)
The inspectors reviewed documentation and interviewed licensee personnel
to determine if the licensee performed an adequale assessment of the
multiple dropped rod event.
The inspectors specifically looked for
information associated with identifying the root cause and evaluating
system performance.
b.
Observations and Findinas
Following the event, station management requested that a detailed
evaluation of plant performance be conducted. The licensee organized a
Failure Investigation Process (FIP) team to perform an assessment of the
multiple dropped rod event.
The team was tasked with identifying the
root cause and evaluating plant response.
During the investigation process, the FIP team concluded that the rods
dropped-into the core due to a momentary loss of rod control system
power at cabinet 280. The FIP team also identified that the event, as
it occurred had not been analyzed in Chapter 15 of the UFSAR.
Specifically, the UFSAR Chapter 15 dropped rod analysis considered
combinations of different dropped rods within the same group. The event
that occurred on February 9. 1998, involved dropped rods from three
separate rod groups.
Because the dropped rods were not in the same
group there was a concern of exceeding the Departure from Nucleate
Boiling Ratio limits.
However, after further evaluation of the event,
the licensee determined that this specific multiple dropped rod event
was bounded by the existing UFSAR analyses.
The inspectors determined that the rods dropped due to a faulty fuse
holder associated with power scoply 4 (PS4).
The faulty fuse holder
created conditions that led to 'a momentary loss of power to the rod
control system power cabinet 2BD.
Following the event, a technical
evaluation team was able to recreate the failure by manipulating a fuse
holder adjacent to the suspect fuse holder. The sus ect fuse holder
indicated an intermittent open condition. The fault fuse holder was
l
removed for electrical and metallurgical testing. T e results from the
l
testing were inconclusive.
After addressing root cause concerns, engineering also addressed the
inspectors questions associated with control rod travel. Specifically
.why control rods in Control Bank D did not fall completely into the
core. Following a review of documentation and interviews with licensee
,
personnel, the inspectors determined that the momentary loss of power
.
14
was not of sufficient duration to allow full travel of the selected
control bank. The inspector also concluded that the electrical and
mechanical components of the rod control system responded as designed
due to t M momentary loss of power.
c.
Conclusions
The inspectors concluded that the licensee was aggressive in
establishing a special team to perform an assessment of the event. The
1
assessment teams identification and resolution of issues was adequate to
support unit restart.
E3
Enaineerina Procedures and Documentation
E3.1 Unit 1 Refuelina Water Storace Tank (RWST) Level Channel 1 Inocerable
a.
Insoection Scooe (37551. 62707. 90712)
The inspectors reviewed the facts and circumstances related to an
inadvertent removal of an inoperable Unit 1 RWST level channel 1
instrument 1FWLP5010. from the trip
required calibration on January 28 ped condition while performing a TSPlant pr
1998.
TS. the DBD. and the UFSAR were reviewed.
Licensee Event Report (LER)
50-369.370/98-01 was also evaluated. The inspectors discussed the
situation with plant personnel
reviewed the procedures, and attended
the PORC review of the event.
b.
Observations and Findinas
At approximately 10:30 on January 28. 1998, the licensee entered the TS
action statement for an inoperable RWST level channel. The inoperable
channel was placed in the tripped condition in accordance with TS
requirements to su) port channel calibration. This channel is one of
three RWST level clannels that provide input to the two out of three
.
logic for the automatic realignment from the RWST to the containment
sum) on low RWST level following a certain desi
Tec1nical S)ecification 3.3.2. Instrumentation.gn basis accidents. Table 3.3-3 req
that with t1e number of operable RWST level channels less than the total
number of channels, operation may proceed until performance of the next
required operational test provided the inoperable channel is placed in
the tripped condition within one hour. The inspectors confirmed that
'
the channel was placed in the tripped condition within the requisite
time.
However, durin
current alarm module,g corrective maintenance to repair a defective
the licensee improperly and unknowingly removed
the channel from the tripped condition for approximately 30 minutes.
The maintenance activity to replace a defective current alarm module was
performed in accordance with procedure IP/0/A/3250/020. Revision 3. RIS
Alarm Module Calibration and IP/0/A/3090/002. Revision 18. Instrument
and Electrical Troubleshooting. This failure to meet the TS
requirements was identified by the licensee following replacement of the
defective current alarm module.
The RWST level instrument relays are designed to trip or actuate when
energized. With channel 1 inoperable and untripped, this configuration
of two channels.gency core cooling system realignment logic to two out
reduced the emer
In this configuration, the RWST low level swapover did
not satisfy the single failure assumptions of the plant's design sis.
.
I
15
!
The licensee did not consider this failure to meet TS requirements risk
!
significant, citing that the emergency procedures and the UFSAR Chapter
i
6 recognized that manual realignment can be performed prior to affecting
ECCS operability.
However, the inspectors were concerned that manual
operator action may not be timely based on a review of previous NRC
operator licensing findings that noted slow operating crew
300).g training activities (reference Inspection Report 50 perfo
durin
369.370/97-
The licensee had acknowledged this operator performance issue,
and have attempted to improve opervor efficiency in working through
steps in the emergency procedures.
The licensee has attributed the RWST problem to an inadequate procedure.
The inspectors verified corrective actions that included correcting
alant procedures to allow for appropriate repairs of current alarms for
RWST level instrumentation.
Inspectors questioned the licensee if an
evaluation had been performed of the number of previous times failed
current alarms were replaced and the duration of the repairs.
The
licensee indicated that a past operability evaluation and root cause
analysis would be performed.
The inspectors concluded that the TS action statement did not permit
untripping of an inoperable channel.
Pending NRC review of the past
operability evaluation, this is identified as one of two examples of
Unresolved Item 50-369.370/98-02-02. Potential Non-compliance With
Technical S)ecifications for Inoperable ESF Instrumentation for RWST
Level and C)CS.
The inspectors questioned if there were other systems that could be
susceptible to this type of problem.
On February 17. 1998, the licensee
identified that a similar event had occurred on the Unit 2 Train B CPCS
(see section E3.2)
c.
Conclusions
An Unresolved Item was identified for adequacy of maintenance procedures
to support repairs of defective components in the RWST level
instrumentation system and to maintain the required TS position for an
inoperable RWST level channel during repairs.
E3.2 Unit 2 Containment Pressure Control System (CPCS) Train B Inocerable
H
a.
Insoection Scone (37551. 62707. 90712)
Inspectors reviewed the facts and circumstances related to an
inadvertent removal of a Train 8 CPCS channel from the start permissive
while replacing a failed loop >ower supply.
Plant procedures,
applicable TSs. the DBD and tie UFSAR were reviewed. LER 50-369.
370/98-01, was also evaluated.
The inspectors discussed the situation
,
with plant ]ersonnel, reviewed the procedures, and attended the PORC
review of t1e event.
b.
Observations and Findinas
On February 17. 1998. for Train B CPCS the licensee discovered that
maintenance work )erformed on January 29. 1998, to replace failed loop
power supply 2NSL)5510 resulted in the loop not being maintained in the
trip condition as required by Technical Specification 3/4.3.2.
Engineered Safety Features Actuation System Instrumentation. Table 3.3-
r
.
.
l
16
3.
Technical Specification Table 3.3-3 requires that with any of the
eight CPCS channels inoperable place the ino erable channel in the
start permissive mode within one hour and app y the applicable action
!
statement (Containment Spray - TS 3.6.2. Cont inment Air Return / Hydrogen
l
Skimmer - TS 3.6.5.6).
This was performed in order to work on the
!
failed power supply.
During replacement of the power supply 2NSLP5510. maintenance
technicians removed fuses to isolate 1.he device.
Removal of the fuses
resulted in de-energizing relays that provided control functions and
maintained the CPCS in the start permissive.
De-energizing the relays
!
effectively defeated the action taken to place the channel in the start
l
permissive. Defeat of the start permissive rendered the CSS 2B pump
inoperable since the pump was not capable of automatic or manual start.
4
The inspectors questioned the number of failed loo) power supplies for
CPCS channels that were repaired in accordance wit 1 the subject
procedures in the past. Inspectors ccncluded that defeat of the CPCS
start permissive on January 29, 1998, was contrary to the requirements
of TS Table 3.3-3 for CPCS.
Pending further NRC review, this is
identified as the second example of Unresolved Item 50-369.370/98-02-02.
Potential Non-compliance With Technical Saecifications for Inoperable
ESF Instrumentation for RWST Level and CPCS.
c.
Conclusions
!
An Unresolved Item was identifisd for adequacy of maintenance procedures
to support repairs of defective components in the CPCS and to maintain
the required TS position for an CPCS channel during repairs.
IV. Plant Sucoort
R1
Conduct of Radiation Protection and Chemistry
R1.1 General Comments (71750)
The inspectors made frequent tours of the controlled access area and
reviewed radiological postings and worker adherence to protective
clothing re
controlled,quirements.
Locked high radiation doors were properly
high radiation and contamination areas were properly posted.
,
'
and radiological area survey maps were updated to accurately reflect
radiological conditions in the respective areas.
V. Manaaement Meetinas
,
X1
Exit Meeting Summary
The resident inspectors 3 resented the inspection results to members of
,
l
licensee management at t1e conclusion of the inspection on March 11. 1998.
The licensee acknowledged the findings presented.
No proprietary information
t
was identified.
i
l
l
l
.
.
17
PARTIAL LIST OF PERSONS CONTACTED
Licensee
l
Barron..H., Vice President. McGuire Nuclear Station
Bhatnagar. A. , Su>erintendent. Plant Operations
Boyle, J., Civil / Electrical / Nuclear Systems Engineering
Byrum. W., Manager, Radiation Protection
Cash. M., Manager. Regulatory Compliance
'Dolan. B.
Manager. Safety Assurance
Evans W.
Security Manager
Geddie. E., Manager. McGuire Nuclear Station
i
Herran. P., Manager. Engineering
Loucks. L. Chemistry Manager
Thomas, K. , Superintendent. Work Control
Travis
B., Manager. Mechanical Systems Engineering
INSPECTION PROCEDURES'USED
IP 71707i
Conduct of 0)erations
IP 62707:
Maintenance Observations
IP 61726:
Surveillance Observations
.
IP 40500.:
Effectiveness of Licensee Controls in Identifying. Resolving, and
Preventing Problems
IP 37551:
Onsite Engineering
IP 71750:
Plant Support
IP 92902:
Maintenance - Followup
IP 90712:
Licensee Event Report Review
i
i
'
-
.
.
18
ITEMS OPENED. CLOSED, AND DISCUSSED
OPENED
l
50-369/98-02-01
Failure to Follow or Provide Adequate Procedures
'
for Unit 1 Containment Isolation Valve
Maintenance (Sections M2.2 and M2.3)
l
50-369.370/98-02-02
Potential Non-compliance With Technical
Specifications for Inoperable Engineered Safety
l
Feature Instrumentation for Refueling Water
Storage Tank Level and Containment Pressure
'
Control System (Sections E3.1 and E3.2)
50-369.370/98-02-03
Followup on Licensee's Previous Industry
'
Experience Review Regarding Multiple Rod Drop
Events (Section 02.4)
CLOSED
50-369.370/97-18-02
Potentially Inadequate Corrective Action for Use
i
of Sealant on Containment Purge Isolation Valves
i
(Section M8.1)
,
I
9 ,
.
19
l
LIST OF ACRONYMS USED
CFR-
Code of Federal Regulations
--
CPCS
Containment Pressure Control System
-
CSS . -
Containment S) ray System
-
-
Design Basis bcument
DCN
Design Change Notice
-
DES
-
Duke Engineering Services
' ECCS
-
'
-
Emergency Procedure
i
,
-
ESF-
Engineered Safety Feature
j
-
Failure Investigation Process
--
,
'
FLM
Fluid Leak Monitor
j
-
IFI
-
Inspector Followup Item
IN-
Information Notice
-
IR
LER
-
. Inspection Report
.
i
-
Licensee Event Report
i
-
Local Leak Rate Test
I
-
MSDS -
. Material Safety Data Sheet
-
Non-Cited Violation
i
NRC
-
Nuclear Regulatory Commission
NRC Office of Nuclear Reactor Regulation
-
NSD
Nuclear Site Directive
-
Net Positive Suction Head
-
0AC
Operator Aid Computer
-
0MP
Operations Management Procedures
-
Public Document Room
-
Problem Investigation Process
-
PORC. -
Plant Operations Review Committee
-
Rod Control Cluster Assembly
RCCA
--
RWST -
. Refueling Water Storage Tank
. SCCM
Standard Cubic Centimeters Per Minute
-
TS
Technical Specifications
-
UFSAR -
i
-
Updated Final Safety Analysis
Unresolved Item
-
-
Violation
. W0
Work Order
-
..