ML20149G688
| ML20149G688 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 06/16/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20149G674 | List: |
| References | |
| 50-369-97-08, 50-369-97-8, 50-370-97-08, 50-370-97-8, NUDOCS 9707240014 | |
| Download: ML20149G688 (37) | |
See also: IR 05000369/1997008
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
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Docket Nos:
50-369. 50-370
License Nos:
Report No:
50-369/97-08. 50-370/97-08
Licensee:
Duke Power Company
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Facility:
McGuire Generating Station, Units 1 & 2
Location:
12700 Hagers Ferry Rd.
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Huntersville. NC 28078
Dates:
April 6 - May 17.1997
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Inspectors:
S. Shaeffer. Senior Resident Inspector
M. Franovich. Resident Inspector
M. Sykes. Resident Inspector
N. Economos. Regional Inspector (E2.1. E4.1)
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S. Rudisail
Regional Inspector (E2.2)
R. Moore. Regional Inspector (P8.1)
Approved by:
C. Casto. Chief. Projects Branch 1
Division of Reactor Projects
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Enclosure 2
9707240014 970616
ADOCK 05000369
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EXECUTIVE SUMMARY
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McGuire Generating Station. Units 1 & 2
NRC Inspection Report 50-369/97-08. 50-370/97-08
This integrated inspection included aspects of licensee operations. engineer-
.ing, maintenance, and plant support. The report covers a six-week period of
resident and Region inspection.
Ooerations
The refueling and restart of Unit 1 from the refueling / Steam Generator
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Replacement Project (SGRP). outage was conducted in a good manner.
Operations control of the restart activities was good: however.
increased operator attention to detail could have prevented a reactor
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trip which occurred during startup testing activities (Section 01.1)
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The' licensee reported a variety of events in accordance with the
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requirements of 10 CFR 50.72 (Section 02.1)'.
Operators responded appropriately to inadvertent main feedwater pump
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trias and resulting Auxiliary Feedwater (CA) Engineered Safety Features
(ES ) actuation.
An Unresolved Item was identified to evaluate the
licensee's root cause investigation process concerning the valve vault
level switches (Section 02.2).
Startup evolutions, including Unit 1 preparation for criticality and
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zero power physics testing, were well controlled. Significant
improvements in the reactivity management program have occurred in the
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last few years as a . result of a 1995 reactivity excursion during startup
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at the Catawba plant.
Briefing packages for the evolutions were
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-detailed and highlighted specific items to help focus operators on
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conducting safe plant manipulations.
Operations-and Engineering
management oversight of the evolutions was evident (Section 04.1).
Plant Operations Review Committee (PORC) presentation / evaluation of
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component mispositioning data was beneficial.
Licensee management was
committed to make additional changes to necessary processes to further
improve performance in this area of configuration control (Section
07.1).
The inspector concluded that the presentation of the' Unit 1 Cycle 12
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core reload change summary to the PORC was well
3repared and allowed the
PORC members to assess changes incorporated in t1e new reactor core
parameters. The proposed reactor physics training for PORC members
should further improve their knowledge in assessing this area (Section
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07.2).
Maintenance,
Review of the performance of a variety of Emergency Core Cooling System
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pump performance testing completed during the Unit 1 SGRP/ refueling
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Enclosure 2
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outage indicated that the identified pump performance was within limits.
System flow balancing was accomplished in accordance with the
established procedures (Section M1.1).
Maintenance technicians demonstrated a good questioning attitude in
identifying a residual heat removal pump motor bearing problem.
The
station response to the potentially degraded residual heat removal pump
upper motor bearing was conservative and provided for improved equipment
reliability (Section M2.1).
Licensee actions in correcting and restoring a failed condensate booster
pump motor was good.
The inspectors also noted this motor failure as
another example of the overall motor reliability concern that was
previously identified and recognized by the licensee (Section M2.2).
Licensee preparation, planning and execution of the Unit 1 ESF testing
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equipment was exceptional.
Equipment operated as designed with minimal
necessary repairs.
Good equipment performance during the test was
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determined to be indicative of good outage maintenance and testing
(Section M2.3).
The inspector concluded that the decision to repair a leaking conoseal
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connection was conservative and the repair activities were accomplished
in a safe manner,
However, during disassembly of the degraded
component, root cause determination techniques could have been better
incorporated (Section M2.4).
A Violation was identified regarding inadequate analog channel
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operational test procedures for testing power range channels N-41 and
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N-42.
The licensee's evaluation of the resulting reactor trip and
subsequent restart assessments were adequately performed (Section M3.1).
Unit 1 reactor building had been adequately returned to operational
condition prior to power operation.
Significant improvements in reactor
building material condition and housekeeping were achieved (Section
M4.1).
The outage management group was effective in planning, scheduling, and
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managing refueling outage activities.
Established station and SGRP
outage exposure goals were aggressive. Good ALARA (As Low As Reasonably
Achievable) exposure planning was evident (Sectiori M4.2).
The licensee has developed a good process for evaluating and planning
maintenance evolutions according to their associated risk.
Maintenance
management has been effectively implementing the process and increasing
the site overall awareness of risk associated maintenance evolutions.
This area was identified as a strength (Section M7.1).
The licensee placed appropriate emphasis on foreign material exclusion
within the main generator housing (Section M7.2).
Enclosure 2
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Two Non-Cited Violations were identified concerning:
the failure to
maintain complete and accurate information; and the failure to follow
procedure.
Once identified. the licensee was proactive in assuring that
required quality assurance documents were complete and accurate in all
material aspects.
All other issues were corrected in a timely manner
(Section M8.1).
Enaineerina
An Inspector Follewup Item was identified concerning several potential
challenges to the CA suction supplies which were identified by the
licensee.
Compensatory measures to prevent potential CA condensate
storage tank vortexing were prompt and effectively implemented. The
aggressive schedule to incorporate design modifications to eliminate the
vortexing concerns were also positive actions to maintain CA system
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reliability (Section E1.1).
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The licensee's identification and corrective actions taken for the
missing swivel bracket bolts in a Unit 1 ice condenser basket were
adequate (Section E2.1).
Corrective actions for previous FNQ ty)e fuse failures were adequate.
Licensee personnel were cognizant of tie issue scope and implementation
of the associated modification was well performed (Section E2.2).
Licensee followup inspection for Oconee related pipe failures was
adequate.
Repairs to moisture separator reheater drain branch
connections were sufficient to meet the applicable code requirements
(Section E4.1).
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Plant Sucoort
The licensee provided adequate monitoring of a small Unit 2 steam
generator "A" tube leak and had previously established conservative
administrative primary to secondary leakage limits as compared to TS
allowable limits. The leak appeared to exhibit some steady growth
characteristics (approximately nine gallons per day at the end of the
inspection period (Section R4).
The licensee's sponsoring of the routine Emergency Planning (EP) Task
Force Meeting was indicative of good management support of the EP area.
The meeting facilitated open discussions to improve existing EP
processes and the licensee's interaction with the local officials during
events (Section P2.1).
The licensee's fire prevention efforts regarding a previous turbine oil
spill event were effective in preventing a potential fire threat to the
turbine building. Contingency measures were well established (Section
F1.1).
Enclosure 2
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Report Details
Summary of Plant Status
At the' beginning of the inspection period. Unit 1 was defueled, in day 52 of
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the planned 86-day End of Cycle (E0C) 11 steam generator replacement / refueling
outage. Throughout the period. Steam Generator Replacement Project (SGRP)
activities were conducted in a safe manner,
Specific SGRP reviews were
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documented in. inspection reports 369/97-03. 97-05, and 97-07. During the
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period. SGRP activities were completed, the unit was. refueled, and Engineered
Safety Features (ESF) system testira completed. On May 14. during' MODE 3 (Hot
Standby) preparations for restart a reactor trip occurred due to procedural
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inadequacies associated with bypassing power range trip channels and
permissives.
After conducting a post trip review. startup evolutions resumed
and theLunit was started on May 15.
Later the same. day, the licensee-
identified that an intermediate range power detector had failed and needed to
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be replaced. The unit was shutdown to MODE 5 (Cold Shutdown) for the
-replacement of the detector.
At the end of the inspection period, the unit
was in MODE 3 preparing for MODE 2 (Startup) operations.
Unit 2 began the period operating at approximately 100 percent power. On
April 18. Unit 2 power was reduced to approximately 28 percent to allow for
additional mwifications to the Main Feedwater (CF) isolation valve solenoids
to prevent overtemperature conditions.
In addition, condenser tube leakage
troubleshooting was conducted. - After appropriate testing, the unit returned
to 100 percent power on- April 21. The unit then operated at approximately 100
percent power for the remainder of the inspection period.
Review of Undated Final Safety Analysis Reoort (UFSAR) Commitments
While performing inspections discussed in this report. the inspectors 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/or parameters.
I. Operations
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Conduct of Operations
01.1=' General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general the conduct of
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operations was professional and safety-conscious; specific events and
noteworthy observations are detailed in the sections below. The
refueling and restart of Unit 1 from the refueling / steam generator
replacement outage was conducted in a good manner. Operations control
of the restart activities was good; however, increased operator
attention to detail could have prevented a reactor trip which occurred
during startup testing activities (see )aragraph M3.1).
In addition to
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the. issues discussed in this report, otler final steam generator
replacement outage inspections were detailed in NRC Inspection Reports
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369/97-03. 97-05 and 97-07.
Enclosure 2
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02 Operational Status of Facilities and Equipment (71707)
02.1' 50.72 Notifications
a.
Insoection Scoce
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During the inspection period, the licensee made the NRC event'
notifications listed below. The inspectors reviewed the events for
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impact on the operational status of the facility and equipment.
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b,
Observations' and Findinas
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On April 8.1997, the licensee made a report in accordance with 10
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CFR 50.72 regarding a Notification of Unusual Event (NOUE)
condition.
Specifically, the event involved two vendor employees
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who had discontinued employment, and entered the protected area
prior to security being notified to delete their security badges.
The NOUE was conservatively declared due to the subject
" intrusion".
Upon discovery. the individuals were located and
escorted off-site within nine minutes of the entry.
The
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individuals did not enter a vital area.. On April 9. the NOUE was
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retracted after investigation revealed there was no malicious
intent on the part of the individuals to harm plant employees or
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. equipment.
The individuals had re-entered the protected area for
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the purpose of retrieving personal items.
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-On May 12. 1997, the licensee made a report in accordance with 10
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CFR 50.72 due to an ESF actuation involving starting of the Unit 1
Auxiliary Feedwater (CA) pumps on a loss of main feedwater. The
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loss of main feedwater was determined to be inadvertently caused
by actuation of exterior , odin steam valve vault (MSVV) Hi Hi level
switches. This event is further discussed in Section 02.2. The
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licensee plans on submitting a Licensee Event Report (LER) on the
subject event.
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On May 12, 1997, the licensee made a report in accordance with 10 CFR 50.72 due to a potential degraded condition regarding air
entrainment of the CA system through vortexing of the CA
Condensate Storage Tank (CST). This and other associated problems
are further discussed in Section E1.1.
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On May 14. 1997, the licensee made a report in accordance with 10 CFR 50.72 due to a reactor trip on Unit I during MODE 3.
An ESF
actuation of feedwater isolation also occurred as a result of the
conditions as ex)ected. This event is further discussed in
Section M3.1.
T1e licensea plans on submitting an LER on the
subject event.
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On May 14. 1997, the licensee made a report in accordance with 10 CFR 50.72 due to briefly entering Technical Specification (TS) 3.0.3 for having both trains of source range )ower instrumentation
inoperable. The condition was associated wit 1 the above report
Enclosure 2
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The licensee plans on
concerning the Unit 1 reactor trip.
submitting an LER on the subject event.
c.
Conclusion
The inspector concluded that the licensee reported the above events in
accordance with the requirements of 10 CFR 50.72.
02.2 Unit 1 ESF Actuation due to triooina of Main Feedwater oumos
a.
Insoettion Scoce
an ESF actuation occurred involving the automatic start
The unit was in
On May 12, 1997,
of the Unit 1 CA pumps on a loss of main feedwater.The inspector reviewed the ES
MODE 3 at the time of the event.
actuation to assure safety equipment reacted as expected.
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b.
Observations and Findinas
due to inadvertent actuation of the Unit 1 exterior Ma
This circuitry has safety-related. 2
Vault (MSVV) Hi Hi level switches.out of 3 logic and provides flood prote
Qualification (EQ) within the valve vaults by initiating a frddwaterThe loss of
trip signal on Hi Hi valve vault level.the automatic start of both trains
Steam Generator (SG) blowdown, and started available nuclear service
The inspector verified that the equipment actuated asNo
required and operators appropriately responded to the conditions.
water pumps.
control room alarms were received prior to the event.
At the end of the inspection period, the licensee had initiated a
failure investigation process and were focusing on potential All of
manufacturing deficiencies associate with the level switche
The inspectors also raised questions concerning the testing
This item will be
outage.
adequacy of the switches after installation.
369/97-08-01, Root Cause of MSVV
identified as Unresolved Item (URI)
Level Actuation, pending completion of the licensee's root cause
investigation.
c.
Conclusions
i te inspectors concluded that the operators resaonded appropriately to
ae inadvertent main feedwater pump trips and tae result
Item was identified to evaluate the conclusions of the licensee'
dctuation.
cause investigation.
Enclosure 2
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Operator Knowledge and Performance (71707)
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04.1 Overview of Unit 1 Criticality /Startuo Activities
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Insoection Scope
During the inspection period, the inspector witnessed preparations for a
criticality and zero power physics testing for Unit I restart.
b.
Observations and Findinas
One of the evolutions witnessed included the preparations for .
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criticality and Zero Power Physics Testing (ZPPT) of Unit 1.
The
inspector focused on overall control of the ) reparations. operator-
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-awareness of plant parameters, interactions aetween operators involved
.in the restart and reactor engineering personnel monitoring reactor
status. The inspector noted good communications between operators and
reactor engineering personnel discussing preparations for criticality.
During the inspector's~ observation, operators appeared to be well
informed of-anticipated changes in plant parameters for an approach to
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criticality.
The ins)ector also reviewed the pre-job briefing package for.the
approac1 to criticality and ZPPT evolutions and attended one of the
briefing sessions.
Nuclear Site Directive (NSD) 304. Reactivity
Management requires that reactor startups be treated as an infrequently
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performed evolution. The purpose of the briefing was to discuss with
operators and other involved personnel how the a]proach to criticality
and withdrawal of the control rods was going-to )e controlled and
performed.
Emphasis was placed on plant parameters the operator at the
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controls should monitor: limits on reactivity additions: and the
frequency for monitoring. Communication lines between reactor
engineering personnel and operators were clearly delineated. Command
and control functions were well established.
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In addition, the briefing included discussions on low power events at
other stations and the UFSAR design basis event of an uncontrolled rod
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withdrawal to heighten operator awareness to these potential problems.
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During the exit meeting. the inspector commented that the role and
responsibilities of Instrumentation and Electrical (IAE) technicians in
the command and communication lines could be included in future briefing
packages as a potential enhancement.
It did not appear that any-
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communication problems among the operators, reactor engineers, and IAE
technicians significantly contributed to a reactor trip during the power
range instrument calibration (see Section M3.1).
In addition to the
above, plant personnel used conservative practices such as setting power
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range reactor trip setpoints to no higher than 5% full power (Technical
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Specifications require below 25% full power) and the nuclear engineering
manager requiring that the qualified reactor engineer and the dedicated
Senior Reactor Operator (SRO) independently calculate the estimated
critical rod position.
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Enclosure 2
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c.
Conclusions
The inspector concluded that the startup evolutions, including Unit 1
preparation for criticality and ZPPT were well controlled and
accomplished in a professional manner. The inspector acknowledges the
significant improvements in the reactivity management program that have
occurred in the last few years as a result of a 1995 reactivity
excursion during startup at the Catawba )lant.
Briefing packages for
the evolutions were detailed and highlig1ted specific items to help
focus operators on conducting safe plant manipulations.
Operations and
Engineering management oversight of the evolutions was evident:
specifically. Operations Shift Manager (OSM) involvement with the
operator at the controls.
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Quality Assurance in Operations (40500)
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07.1 Review of Misoosition Comoonent Trend Data
a.
Insoection Scooe
Assessment of the licensee's focus on component mispositioning events.
b.
Observations and Findiras
On April 29. the inspectors attended a presentation to McGuire
management regarding recent evaluations of plant mispositioned component
trends.
The purpose of the meeting was to evaluate available
information to determine what additional measures may be necessary to
address the current levels of mispositioned components.
The review was
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presented by the mispositioned component cocrdinator and included the
most recent 1996 summary report of misposition problems.
Historical
data of previous years data and efforts taken to address previous trends
were discussed in detail.
The team concluded that although the
significance of the events had substantially declined, the number of
mispositionings being identified were not ideal.
It was recognized that
the threshold for reporting problems in this area had been lowered:
therefore, more less significant issues were expected.
Operations. Maintenance, and plant Chemistry management also provided
insight to actions taken to date and proposed additional steps being
implemented to address specific areas identified for improvement.
These
included increased personal awareness for configuration control, focus
on the use of self-checking trainino aides, verifying procedural
adequacy ::ad implementing preoperational valve lineups.
Other areas for
im)rovement were also discussed which included improving component
la)eling and various group assessments to further identify areas for
improvement. The inspector discussed several areas outside of the
licensee's mispositioned component program sco)e area which may have
applicability. The licensee agreed to researc1 those areas for
potential incorporation.
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c.
Conclusion
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The inspector concluded that the evaluation of component mispositioning
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data was beneficial.
Licensee management was committed to make
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additional changes to necessary areas to further improve performance in
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this area of configuration control.
07.2 Plant Ooerations Review Committee (PORC) Review of Unit 1 Core Reload
Parameters
a,
Insoection Scope
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Assessment of PORC's review of the Unit 1 core reload change summary.
b.
Observations and Findinas
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On April 29, the PORC was presented with a summary of the McGuire Unit 1
Cycle 12 core reload change summary.
The Reactor Engineering supervisor
presented the information to allow the PORC to review changes
incorporated in the reinstalled core parameters. The inspectors
considered that the information was presented in a logical manner which
allowed the PORC to assess changes from the previous to the current core
design.
Differences in the parameters were discussed and determined to
remain within TS allowable limits.
The presentation also discussed the
status of generic issues associated with fuel and rod cluster
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assemblies.
The PORC concluded that the changes associated with the
Unit 1 reload were appropriate.
The engineering supervisor also
informed the PORC that a training lesson was being developed for the
PORC members and other management to further heighten their awareness of
core operating parameters and design variations.
This would increase
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the PORC members' knowledge of these activities to provide better
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oversight of this area.
c.
Conclusion
The inspector concluded that the presentation of the Unit 1 Cycle 12
core reload change summary to the PORC was well
3repared and allowed the
PORC members to assess changes incorporated in t1e new core parameters.
The proposed reactor physics training for PORC members should further
improve their knowledge in assessing this area.
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Miscellaneous Operations Issues (92700)
08.1
(CLOSED) LER 50-370/96-03:
Unit 2 Reactor Trip Occurred Due To Reactor
Coolant Pump Motor 2B Failure.
The inspectors conducted followup ins]ection of the licensee's actions
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to resolve concerns associated with t7e failure of the Unit 2B Reactor
Coolant Pump (RCP) motor on May 22, 1996. The motor failure was the
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result of a stator fault.
Protective relaying circuits functioned as
designed to protect the motor and the resulting single loop loss of flow
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caused a reactor trip. The windings were determined to be
Enclosure 2
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insufficiently secured to prevent operational vibration from degrading
the stator. winding insulation.
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The ins]ectors noted during previous reviews that'each of the Unit 1 and
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Unit 2 RCP motor stators had been refurbished or replaced following the -
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stator fault event with the exception of the 1A RCP motor. The-
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currently installed RCP motor stators had at.least 90 percant of the
stator end turns secured to the surge ring to provide sufficient
rigidity to prevent vibration induced degradation of the winding-
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insulating material.
During the recently completed Unit 1 E0C11 outage,
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the licensee completed replacement of the Unit 1 A RCP motor stator.
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The 1A stator replacement was the final corrective action identified in
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LER 50-370/96-03 to be completed.
Based on the licensee's response in correcting the potential trip
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hazar'ds associated with stator degradation and completion of the
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closed.
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments (61726. 62707)
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The inspectors witnessed selected surveillance tests to. verify that
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approved procedures were available and in use. test equipment in use was
calibrated. test prerequisites were met, system restoration was
completed, and acceptance criteria were met.
In addition, resident
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inspectors reviewed and/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.
a.
Insoection Scooe and Observations
The inspectors reviewed portions of. the following work activities:
PT/1/A/4204/04C - Residual Heat Removal (ND) Pump 1A and IB Head
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Curve Testing
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PT/1/A/4209/12A - Charging (NV) Pump 1A and Valve Testing
PT/1/A/4209/128 - NV Pump 1B and Valve Testing
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PT/1/A/4206/15A - Safety Injection (NI) Pump 1A and Valve Testing
PT/1/A/4206/15B - NI Pump 1B and Valve Testing
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PT/1/A/4204/04C - ND Pump.1A and 1B Head Curve Retest
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b.
Conclusions
Review of the performance of a variety of Emergency Core Cooling System
(ECCS) pump performance testing completed during the Unit 1
SGRP/ refueling outage indicated that the identified pump performance was
within limits.
System flow balancing was accomplished in accordance
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with the established procedures.
No problems were identified by the
inspectors.
M2
Maintenance and Material Condition of Facilities and
Equipment (61726, 62707)
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M2.1 Unit 1 Residual Heat Removal Pumo Uooer Motor Bearino Failure
a.
Insoection Scooe
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The inspectors reviewed the licensee's actions following indication of
motor t'aaring failure during surveillance testing of the Unit 1 B
Residual Heat Removal (ND) pump.
b.
Observations and Findinas
On April 22. 1997, with Unit 1 defueled, maintenance technicians
detected an unexpected noise at the 1B ND pump motor. The technicians
notified their supervisor of the unex3ected noise. As a result,
diagnostic testing was performed.
Vi3 ration data acquired during fuel
unloading when the pump was in service was compared to the current
levels.
Indication of a flaw on the inner race of the thrust side
bearing was identified. Although the vibration levels met ASME
acceptance criteria, the licensee decided to replace the bearing set
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since the failure rate was dependent upon operating conditions. The
bearing replacement was conducted prior to fuel reload to minimize any
potential loss of shutdown cooling risks.
No past operability concerns
existed since the equipment operated satisfactorily during fuel unload
and was repaired prior to core alterations.
The degraded upper motor bearing was sent to the licensee's metallurgy
laboratory for analysis to aid in the root cause evaluation. The
laboratory identified a spall on the inner race of one bearing which
appeared to be due to contact fatigue. The licensee also stated that
outside contractor support may be obtained to determine the actual
thrust bearing loads at various flows. The information would assist in
validating the adequacy of the bearing and lubricant for the application
and ensure that current predictive maintenance practices are
appropriate.
c.
Conclusions
The inspectors concluded that maintenance technicians demonstrated a
good cuestioning attitude. The station response to the potentially
degraced bearing was conservative and provided for improved equipment
reliability.
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Enclosure 2
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M2.2 Unit 2 Condensate Booster Pumo Motor Failure
a.
Insoection Scooe
The inspectors evaluated the unexpected Unit 2 A condensate booster pump
motor trip.
b.
Ohservations and Findinas
The condensate and feedwater system consists of three 50% capacity
condensate booster pumps and hotwell pumps.
Two of three condensate
booster and hotwell pumps are normally in operation. The third
condensate and hotwell pump remain in standay. The standby pumps
receive an autostart signal on low main feedwater pump suction.
Early in the inspection period, the 2A condensate pump tripped with the
unit at 100 percent power, The standby hotwell and condensate pump auto
started and main feedwater pump suction pressure returned to normal.
The licensee investigated and determined the 2A condensate pump trip was
attributed to motor stator insulating material breakdown.
The damaged
motor was immediately removed and shipped to a certified repair shop.
Although Unit 1 was in Mode 6 (refueling) of a scheduled shutdown for
steam generator replacement, the licensee decided against replacing the
damaged motor with a motor from Unit 1.
Loss of the standby condensate
booster pump increases the unit potential for a reactor trip due to
failure of a second booster pump.
The licensee received a refurbished motor from a certified repair shop.
The motor was installed and tested in accordance with station
procedures.
The licensee discovered during the testing that the
. -
indicated motor bearing temperatures exceeded expected values. The
repair facility was contacted for technical support.
Facility
representative arrived on site, reviewed motor performance data and
initially determined the cause to be a faulty rotor.
However, further
investigations revealed that the higher than expected motor bearing
temperatures were caused by incorrect gauge wire used in the measuring
,
thermocouple.
The wiring was replaced, the pump was operated, and motor
bearing temperature indication returned to acceptable values,
c.
Conclusions
The inspectors concluded that the licensee's diligence in correcting and
restoring the failed motor was good. The inspectors also noted this
l
motor failure as another example of the overall motor reliability
i
concerns that have been previously identified and recognized by the
licensee.
'
M2.3 Unit 1 Enaineered Safeauard Features (ESF) Testino
,
a.
Insoection Scooe
The inspectors witnessed portions of the Unit 1 Train A ESF testing
,
conducted May 1-2, 1997, following steam generator replacement
Enclosure 2
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10
activities.and prior to Unit 1 restart from the control room.
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b.
@servations and Findings
The inspectors witnessed the Train A test to confirm that the licensee
appropriately tested attributes of station equipment that may have been
affected by outage' maintenance activities.
The test was performed to:
(1) demonstrate the ability of the Emergency Diesel Generator (EDG).to
,
start and load in response to a manually initiated Safety Injection,
i
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Phase A Isolation. Phase B Isolation and Blackout: (2) demonstrate that
when the EDG is paralleled with offsite power, an SI returns the EDG to
standby status and the emergency loads are sequenced onto'.the offsite
,
l
power supply: (3) demonstrate EDG starting load shedding, and emergency
load sequencing in response to a Blackout: and (4)' ensure that'the.
-
!
correct movement of valves in response to an SI Phase A Isolation.
,
',
Phase B Isolation, and Blackout occur. The inspectors confirmed that
"
L
the A train test was performed with the equipment in its normal lineup.
i
l
Control room instrumentation response to changes in equipment status was
adequate. The inspectors also noted that few corrective work requests
Were generated following the test.
The inspectors reviewed the test procedure and noted that the procedure
-
had sufficient detail to provide adequate guidance to personnel
performing the test.
Coordination between Operations. Maintenance and
Engineering was good.
The inspectors observed a good pre-job briefing,
l
as well as routine briefs throughout the performance of the test.
Unit
2 operations staff prepared for the Unit 1 ESF testing by reviewing
app opriate abnormal and emergency procedures as a conservative measure
to ensure that the test realignment of. shared equipment would not
adversely affect Unit 2 operations.
Additional licensed operator
-
support was available to minimize the impact on the normal operating
crews during testing.
Routine maintenance and testing activities were
minimized on Unit 2 during Unit 1 ESF testing.
c.
Conclusions
The inspectors concluded that licensee preparation, planning, and
.
execution of the Unit 1 ESF testing was exceptional.
Equipment operated
as designed with mimmal necessary repairs.
Good equipment performance
during the test was determined to be indicative of good outage
maintenance
,
M2.4 Reoair of Leakina Unit 1 Conoseal Port
a.
Insoection Scooe
After reassembly of the reactor in MODE 5. the licensee identified that
conoseal port #2 was leaking. The inspector reviewed the licensee's
activities associated with the rework repair.
.
Enclosure 2
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11
b.
Observations and Findings
l
The leak was identified on one of the five core exit thermocouple
columns which exit the reactor head assembly sealed by conoseal
assemblies.
Work order 96064661-05 was being performed to inspect for.
leakage at low Reactor Coolant System (RCS) pressure (300 psig). Upon
identification. initial corrective actions attempted to retorque the
suspect area; however, minor leakage still existed.
Operations,
maintenance, and engineering personnel determined that a repair was
necessary and would involve an additional RCS drain down to
approximately 120 inches above the reactor flange.
The RCS drain down
was safely performed.
Inspection of the disassembled conoseal revealed.
,
that the upper gasket appeared to be deformed. The licensee postulated
'
that the gasket may have been installed inverted: however. personnel
performing the repair did not note the orientation of the gasket arior
to removal.
The subject conoceal was reassembled, all five assem)1y
housings retorcued and no leakage was identified at the 300 psig RCS
inspection wincow.
Based on the work performed engineering determined
that no additional conoseal work was required.
,
c.
Conclusion
The inspector concluded that the decision to cooldown and repair the
I
leaking conoseal connection was conservative, and the repair activities
were accomplished in a safe manner.
However, during disassembly of the
degraded component, root cause determination techniques could have been
better incorporated.
M3
Maintenance Procedures and Documentation
-
M3.1 Unit 1 Reactor Trio Durina MODE 3 Power Ranae Instrumentation
Calibration
t
a.
Insoection Scooe (61726)
The inspector reviewed the unit's response to the reactor trip and
evaluated the licensee's post trip review process to ensure all
potential problems were properly evaluated prior to restart.
b.
Observations and Findinas
On May 14. a Unit I reactor trip and feedwater isolation occurred. The
reactor trip occurred on 2 out of 4 logic for turbine trip / reactor tria
during power range instrumentation calibration.
Prior to the event t1e
reactor was in Mode 3 with shutdown banks A and B withdrawn. RCS boron
,
l
diluted, and a stable reactor temperature of ap3roximately 557 F.
Station personnel were areparing for an approac1 to criticality and
subsequent Zero Power P1ysics Testing (ZPPT). As part of the
preparations, the licensee entered TS 3/4.10.3 "Special Test Exception"
,
l
which requires, in part, that each power range channel shall be subject
to an Analog Channel Operational Test (ACOT) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> prior to
j
initiating startup and physics tests.
Enclosure 2
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In preparation for an approach to criticality, the reactor engineering
group requested an ACOT on power range channel N-42 be performed since
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> had elapsed since the last ACOT on N-42.
Power range channel
l-
N 41 was. connected to the reactivity computer for ZPPT. -In this
3
'
configuration. N-41 was inoperable and must be placed in the tripped
condition.
In order to save time, the licensee decided to bypass power
-
l
range channel N-41 in lieu (f disconnecting the com) uter and restoring
l-
N-41 to operable status.
Bypassing a power range clannel is permitted
'
by Technical Specifications and is how calibration of a single aower
range channel is normally performed with the reactor at power:
lowever,
use of channel bypassing with multiple channels affected was a new
evolution.
The licensee used procedure PT/1/A/4600/0140. NIS Power' Range Channel
N-41 Analog Channel Operational Test, to bypass the reactor protection-
!
U-
system functions for N-41.
However. Permissive P-8 (high reactor power--
low reactor coolant flow) is not tested by this procedure and as such
the permissive remained unblocked. The technicians and operators did
not recognize-that P-8 remained unblocked and'there was no guidance in
the ACOT procedure to check the-status of P-8.
Using a. simulated 120
percent power signal, technicians conducted the ACOT of N-42. With P-8
unblocked and the turbine tripped, 2 out of 4 reactor trip logic was
i
satisfied when simulated reactor power exceeded 48 percent of full power
(P-8).
A feedwater isolation also occurred due to low reactor coolant
system temperature (lo Tavg) bistables still active since they were not
clear until the reactor was at higher temperatures with the unit online.
i
P10 permissives, which automatically turns source range high voltage off
above 10 percent power, were also overlooked during the evolution.
This
resulted in both source range instrumentation trains being briefly (less
L
that one second) inoperable prior to the reactor trip. The licensee
-
plans to address all the associated impacts to the plant in an LER.
!
l
Following the event, the licensee discovered that procedure
l
IP/0/A/3207/09A Bypassing Power Range Channels In Tripped Condition,
L
should have been used to properly bypass N-41. This procedure provides
steps necessary for bypassing an inoperable power range channel and-
associated bistable outputs. The technicians were not cognizant that
this procedure should have been used to bypass N-41. The technicians
used the bypass steps provided in the governing ACOT procedure
PT/1/A/4600/014D. The inspector interviewed plant personnel on the
'
status of the root cause investigation.
Plant personnel indicated that
corrective actions for a 1994 PIP (0-M94-0331) led to the development of
L
IP/0/A/3207/09A. At the end of the inspection period, the licensee was
i
examining if an undue number of separate supporting procedures were
being used for ACOTs on power range channels whereby the likelihood of
errors may increase.
The ins)ector reviewed the governing ACOT procedures for testing )ower
range clannels N-41 and N-42. The ACOT procedure PT/1/A/4600/014) used
to bypass N-41 was determined to be inadequate since it failed to
'
reference and transition to the supporting procedure, even though the
ACOT governing procedure was written for use with the reactor in any
.'
Mode. The ACOT procedure Section 2.2 " References That May Be Needed to
Enclosure 2
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Perform Procedure" failed to reference IP/0/A/3207/09A. steps in the
body of the ACOT procedure did not transition to this supporting
procedure, and the ACOT procedure itself contained insufficient guidance
to properly bypass an inoperable power range channel to allow testing of
another channel, as evidenced by the event.
The licensee's work control
planning may have also contributed to the event with respect to not
identifying the supporting procedure in the job scope for plant
preparations for criticality and ZPPT.
This issue will be identified
as a Violation 369/97-08-02. Inadequate Procedure for performing ACOT
Testing.
c.
Conclusions
The inspector concluded that overall, the licensee's evaluation of the
reactor trip and restart assessments were adequately performed: however.
'
' '
a Violation was identified regarding inadequate ACOT procedures
bypassing the reactor protection function of power range channel N-41 to
permit testing of channel N-42.
M4
Maintenance staff Knowledge and Performance (62707)
, , -
Maintenance Staff Knowledge and Performance (62707)
M4.1 Unit 1 Material Condition /Housekeepina Insoections
a.
Inspection Scoce
The inspectors conducted walkdown inspections of the Unit 1 reactor
building.
The inspectors placed particular emphasis on identification
-
of fibrous material that may cause complications during the
recirculation phase of ECCS operation.
b.
Observations and Findinas
During MODE 5 restart 3 reparations, the licensee performed numerous
walkdowns to prepare t1e unit for containment closecut and began
restricted reactor building access.
Individuals and materials entering
containment for final restart preparations were logged in and out of the
building by the Shift Work Manager. The inspectors conducted detailed
walkdowns of portions of the lower reactor building and pipe chase areas
to asses the licensee's restart readiness. The inspectors performed
reviews on various system piping, focusing on system integrity,
potential systems adversely impacted by the outage, and support systems
to major components.
No adverse conditions which could affect the
safety function of safety-related equipment were identified.
Maintenance equipment used during the SGRP had been safely removed.
Protective covers used to minimize foreign material intrusion into the
containment sump during maintenance activities had been removed and the
sump was devoid of debris.
No visible indications of system leakage
were identified. Temporary shielding and scaffolding used during the
outage had been removed from the building.
Subsequent followup
inspections by the licensee using sensitive thermography equipment
Enclosure 2
[
!
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14
identified a small crossover leg loo) drain valve leak on the 'B' steam
generator.
The licensee tightened t1e valve to reduce the suspected
leakage.
The inspectors evaluated the newly installed blanket insulation used on
R
the replacement generators. The original mirror insulation was replaced
with fiberglass mass within a fiberglass cloth blanket insulation.
The
fiberglass blanket was covered by a stainless steel jacket to minimize
damage to the cloth.
The blanket insulation was supported by rings
i
mounted around the circumference of the steam generator shell. The
original insulation could not be reused due to the dimensional
differences between the old and new SGs.
The licensee also stated that
the new blanket insulation should provide for improved thermal
performance.
The inspectors evaluated insulation installation from the
main steam nozzle to primary system nozzles. The insulation was
,
adequately installed and no concerns were identified.
'
c.
Conclusions
The inspectors concluded that the Unit I reactor building had been
,
adequately returned to operational condition prior to power operation.
The inspectors noted significant improvements in reactor building
material condition and housekeeping that were implemented during the
,
outage.
M4.2 Outaae Plannina and Schedulina
a.
Insoection Scooe
1
The inspectors evaluated outage results to determine the effectiveness
-
of the licensee's outage planning and scheduling efforts.
b.
Observations and Findinas
The inspectors reviewed the scope of nutage activities identified for
1E0C11. The planned outage duration was 100 days. The insaectors
recognized that several significant maintenance activities
1ad been
planned for the outage.
The licensee performed steam generator
replacement, o)erator aid computer replacement, emergency diesel
generator overlauls, high pressure turbine and main generator
refurbishment.
Refueling activities, in general were well performed
with minimal interruptions from equipment problems. The inspectors
noted that the job scope for the significant activities did not change
appreciably. indicating good pre-outage work planning. These
activities, in conjunction with routine outage activities, were
.
conducted such that an optimum amount of work was accomplished with
appropriate emphasis on nuclear safety, personnel safety, quality
l
maintenance, and ALARA (As Low As Reasonably Achievable) exposure
l
considerations.
The licensee was also effective in incorporating
i
emergent corrective maintenance activities into the schedule.
i
Enclosure 2
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>
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c.
Conclusions
1
l
-The inspectors concluded that the outage management group was effective.
l
in planning. scheduling, and managing refueling outes sctivities.
The
R
i
outage was completed in 95 days.
Established station and SGRP
outageexposure goals were aggressive. The inspectors noted that ALARA
-l
initiatives were evident.
H7
Quality Assurance in Maintenance Activities (62707)
L
M7.1 Review of Critical On-line Maintenance Control
a.
Jnsoection Scop _q
.
The inspectors reviewed the licensee's process control of critical on-
'
' '
line maintenance.
'
l
b.
Observations and Findinas
The licensee's process' is defined in Work Process Manual (WPM) 601 and
Maintenance Directive 2.3.1.
The licensee had developed the current-
process through benchmarking other utilities * maintenance programs.
Within the licensee's process, work activities are categorized into four
classifications of maintenance--normal, complex, critical
and emergent-
l
critical.
Each ' category is defined by significance. TS Limiting
'
Condition for Operation (LCO) outage duration. . impact on the unit
operation (potential or actual), etc. All of the categories were
integrated into the licensee's established system work window rotation
process which _provides for additional structure for implementing the
process.
Some of the attributes of the critical on-line maintenance
'
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plans include:
specific. owners for every task: compensatory and
contingency measures pre-established; decision points clearly defined:
detailed schedule; pre-job briefing which included Generic Letter (GL)
>
91-01 guidance; and management presentations on the activities.
'
,
Checklists incorporate these and other attributes to assure orderly
completion for critical maintenance evolutions. To date.-the license
has qualified 14 individuals to be critical maintenance managers.
The category of complex maintenance was recently added to provide
additional oversight of activities which did not meet the criteria for
critical: however, it did warrant additional planning, coordination, and
preparation to ensure error-free execution. Work. activities considered
i
for complex maintenance include significant system shutdown (for example
EDG down days), multiple TS equipment impacts for maintenance.
rescheduled work due to ineffective initial plans, and complex work
L
activities which require continuous coverage.
Complex maintenance
activities are assigned a work sponsor who is responsible for designated
activities throughout the completion of the work.
r
i
c.
Conclusions
!
Based on the review of maintenance directives and observations of
l-
maintenance planning implementation, the inspector concluded that the
[
Enclosure 2
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licensee has developea a good process for evaluating and planning
maintenance evolutions according to their associated risk. Maintenance
'
management has been effectively implementing the process and increasing
l
the site overall awareness of risk associated maintenance evolutions.
L
This area was identified as a strength.
H7.2 Maintsnance Resoonse To Foreian Material Exclusion (FME) in Turbine
Generator
a.
Insoection Scooe and Observations
During Unit 1 main generator outage refurbishment, a large ratchet came
apart which allowed numerous metallic pieces to fall into the main
generator windings.
Maintenance personnel initiated a Problem
Investigation Problem (PIP) report and raised a concern for
',
identification of all the missing pieces prior to placing the generator
in service.
The licensee recognized the need to remove all of the
foreign material and took apart a similar rachet to identify each item.
Extensive searches were performed for several days, which included the
use of vacuum devices and mirror ins)ection.
Partial disassembly of the
generator was required.
All of the (nown pieces were eventually
recovered from the generator.
b.
f,_onclusions
The ins)ector concluded that the licensee placed appropriate emphasis on
FME witlin the main generator housing.
M8
Miscellaneous Maintenance Issues (92902)
..
M8.1 (CLOSED) URI 50-369/96-01-04:
Apaarent Failure to Follow Procedure
(Disassembly, repair and re-assem31y on Kerotest 'Y' type check valve
INV233)
During the McGuire Unit 1 refueling outage (1E0C10) in January 1996.
maintenance was being performed on valve 1NV233, a 2" diameter KER0 TEST
type check valve in the mini-flow path for the IB charging pump. The
seal weld on the valve was leaking and the maintenance work order was to
i
replace the existing valve with a new one.
On January 3. 1996, an Electrical Systems Support valve technician
initialed Step 11.4.5 of Procedure MP/0/A/7600/04. Kerotest "Y" Type
Check Valve Corrective Maintenance, which states: " Install !LEM body to
cover gasket in body."
On the evening of January 3.1996, the night shift noted that the valve
was assembled but not torqued. Although documentation was incomplete,
it indicated that final checks on the valve were satisfactory and the
valve a)peared ready to torque.
Due to incomplete documentation. the
night slift was concerned and confused. The supervisor directed the
i
technicians to disassemble the valve and begin the work task again.
When the valve was disassembled, the technicians identified that the
gasket was not new as it had been previously torqued. The licensee
Enclosure 2
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advised the'.NRC of a potential falsification of a Quality Assurance
'
Document.
.
'
!'
The NRC Office of Investigations initiated an investigation to determine'
if a Quality Assurance. Document had been intentionally falsified. The'-
investigation concluded that the technician had purposely decided to use
the old gasket and intentionally signed the procedure step claiming that
-
the gasket had been replaced. A copy of the synopsis of the-
'
investigation report is attached.
10 CFR 50.9(a) states, in part. that information required by the
Commission's. Regulations to be maintained by the licensee shall be
complete and. accurate in all material aspects. The failure to maintain
complete and accurate information required by the Commission's
.
t
Regulations is a violation.
This licensee-identified and corrected
'
,
. violation is being treated as a Non-Cited Violation (NCV). consistent
M
with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-369/97-08-03.
Failure to Maintain Complete and' Accurate Records).
.
Technical Specification 6.8.1.c requires that written procedures be
established implemented and maintained covering the activities
recommended in Regulatory Guide 1.33. Revision 2. February 1978.
Regulatory Guide 1.33 states in part that maintenance which can affect
performance of safety-related equipment should be performed in
,
accordance with written procedures.
Step 11.4.5 of Procedure
J
MP/0/A/7600/04 states " Install HS body to cover gasket body". The
l
failure to install a new gasket in accordance with the licensee's
procedure is'a violation.
This licensee-identified and corrected
.
violation is being treated as a Non Cited-Violation, consistent with
-
u-
.Section VII.B.1 of the NRC Enforcement Policy (NCV 50-369/97-08-05.
Failure to Follow Procedure).
Conclusions
Two Non-Cited Violations were identified concerning: . the failure to
maintain complete and accurate information; and the failure to follow
,
procedure. .Once identified, the licensee was proactive in assuring that
i
required quality assurance documents were complete and accurate in all
material aspects.
All other issues were corrected in a timely manner.
III. Enaineerina
El
Conduct of Engineering (37551)
q
E1.1 Potential Air Binding of Auxiliary Feedwater (CA) Pumos
a.
Insoection Scoce
During the inspection period, the licensee addressed potential
mechanisms for air entrainment into the CA system and subsequent air
binding of the CA pumps. The first issue involved CA pump vulnerability
.from air entrainment due to a vortex that could develop in the auxiliary
feedwater condensate storage tank (CACST) under certain design basis
Enclosure 2
4
.w
3
y
,
y
_ _ . - . . . - . , -
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18
events (DBEs).
Also under certain DBEs. a second issue was identified
involving air entrapment from other mechanisms (e.g. , tank depletion,
pipe. break, etc..) from interactions of the nonsafety-related CA water
sources and the safety-related CA water source.
L
The inspector reviewed the compensatory measures, attended PORC
meetings, reviewed the 10 CFR 50.59 evaluation, consulted the UFSAR and
facilities individual ]lant examination for Probabilistic Risk
Assessment (PRA) insig1ts, and verified that corrective actions were
I
implemented to minimize the potential for air binding CA pumps. The
inspector also performed an examination of the CA system nonsafety-
related suction sources, plant abnormal and emergency procedures.
previously identified issues related to CA air entrainment from tank
depletion, compliance with the licensing basis, and applicability of
regulatory requirements,
,
b.
Observations and Findinos
Background information on the CA water sources and subsystems, as well
as the inspector's observations and findings on the air entrapment
1ssues, are discussed in the following sections.
Auxiliary Feedwater System Water Sources Descriotion
Each unit's CA system may use several nonsafety-related water sources
which are, in order of preference, the CACST-. the unit's upper surge
tanks (USTs), and the unit's condenser hotwell. These sources are the
i
'
normal supplies for the unit's CA system. The assured safety-related
water source for the CA system is the nuclear service water system
(NSWS).
Auxiliary feedwater pump suction will automatically swapover to
-
NSWS when low CA pump suction pressure conditions (below approximately 3
psig) are present.
The CACST has a maximum capacity of 42,500 gallons of high quality water
and is the primary water source for the auxiliary feedwater system.
Normally, both units (total of six CA pumps) take suction from this
common, atmospheric tank.
Each unit also has two USTs that together
have a maximum capacity of 85.000 gallons and are normally used as water
sources for the CA systems upon depletion of the CACST. The USTs
normally operates under a vacuum.
Each unit's CA system may also use
its respective condenser hotwell water (170.000 gallon maximum capacity)
if available during a design basis event.
Each unit has a motor operated valve (1/2CA-6) to isolate the CACST.
Isolation of the CACST requires a manual operator action that may be
performed locally or from the control room if normal power is available.
>
The USTs may be isolated locally only with ICA-4 or ICS-18 and 2CA-4 or
l
2CS-18 for each unit. respectively.
The above valves are nonsafety-
l
related and do not receive emergency power in the event of a Loss-of-
l
Offsite Power (LOOP) and loss of normal station auxiliary power.
Also.
CACST level indication in the control room would be lost during a LOOP
,
event.
The CA system design as.sumes that once transferred to the
!
assured source, the nonsafety-related sources would not affect the
Enclosure 2
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19
safety-related portion of the system.
Hc,vever, it should be noted that
no automatic isolations occur to prevent interactions. The issues
~
concerning vortexing and other. air entrapment mechanisms identified are
discussed below.
CA Pumo Air Bindino from CACST Vortex
Under certain' DBEs. the licensee identified that a vort'ex could develo
L
in the CACST. draw air'into the CA suction piping, and damage or airbi d-
'
the-pumps.
The vortex would form prior to CA suction swapover_ to NSWS.
This potential condition was. reported under 10 CFR 50.72 on May 12,
1997.
The licensee identified the potential for CACST vortexing while
!
analyzing CA nonsafety-related suction source, reliability (see sub-
section below).' The most limiting case was a main steam line break
'
coincident with a dual unit LOOP where both units were drawing off the
CACST and the CA motor and turbine driven pumps were discharging at a.
high flow rate due to loss of instrument air.(nonsafety-related). This
l
scenario could result in a vortex within approximately 15 minutes of the
event initiation.
i
i
To provide immediate protection against this postulated event. plant-
engineers proposed compensatory measures to minimize the~ risk of air
i
binding the CA pumps from vortexing until plant design modifications
>
could be implemented. This issue and compensatory measures were
reviewed and approved by PORC prior to restart of Unit I which was
,
shutdown for refueling and replacement of steam generators. .An
NRC/ Licensee conference call was held on May 9 to discuss these issues.
The inspector verified the implementation of the following compensatory
measures:
-
. .-
Valve 2CA-6 (Unit 2 CA suction from CACST) was closed and power
e
was removed to reduce the rate of inventory draindown (reduce
likelihood of vortex formation in the CACST).
'
Unit 2 primary water source for CA was aligned to the USTs. This
action made Unit 2 more susceptible to a NSWS CA supply swapover.
)
Unit 2 was intentionally selected to protect the newly installed
Unit 1 SGs from raw water (NSWS).
The licensee developed special procedures to isolate the USTs
e
-(Units 1 & 2) with level below 5.5 ft and isolate the CACST from
Unit 1 CA with 35% level indication. The step to isolate the USTs
on low level was incorporated to eliminate the concern for air
entrapment from USTs operation (see sub-section below).
'
Use of two dedicated non-licensed operators (one for each unit).
L
e
L
with procedure in hand at all times, to implement each unit's
l'
special procedure upon certain plant conditions (e.g. LOOP,.
[
reactor trip. Safety Injection. etc.).
The procedures were time validated and the affected valves
e
,
accessibility was evaluated.
!
l
Enclosure 2
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- - -
.
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20
Maximum levels in the CACST and USTs were maintained.
Maximum pressure in the instrument air system (IAS) was
maintained.
The dedicated Non-Licensed Operators (NL0s) frequently monitored
e
the USTs and CACST levels and IAS pressures.
The compensatory measures augment steps in the Abnormal Procedures
(AP)/ Emergency Procedures (EP) that already instructed operators to
isolate the CACST and on low levels to prevent air entrainment (see sub-
section below) since these tanks are not automatically isolated on low
tank levels.
The licensee has proposed plant design modifications to
address vortexing concerns.
The licensee will convert an existing
filtered water tank (approximately 42,500 gallons) into an additional
'
CACST and install anti-vortexing devices in the suction inlet in both
'
the existing CACST and the new tank.
The licensee is also evaluating past operability of the condition.
CA Pumo Air Bindino From Other Air Entraoment Mechanisms
Currently the licensee has identified an additional potential concern
regarding CA operation using suction from the USTs after the tanks have
been drained into the CA suction piping and CA pump recirculation has
been initiated.
This problem may potentially occur before or after a
service water to CA suction swapover
Auxiliary feedwater pump
recirculation flow will continue to go to the USTs after the tanks
empty.
The possibility exists that CA pump air binding could occur in
this configuration if air is trapped in the suction piping and pushed to
.-
'
the CA pumps.
Based on interviews with plant engineers the inspector
was informed that an air slug greater than several cubic feet could
damage the pumps according to the pump vendor.
Validity of air
entrapment through USTs/CA operation is pending additional hydraulic
studies.
However, the licensee has factored this concern into the
compensatory measures noted in the previous sub-section.
In 1996, the licensee embarked on an extensive CA suction source
reliability study for issues related to CA air entrapment.
This effort
was taken because many PIPS have been written since 1992 on these
issues.
Under various DBE scenarios, these mechanisms involve
interactions among the CACST. USTs and condenser hotwell and between
these systems and the NSWS. The licensee has contracted Framatome
Technologies to perform analyses of pipe breaks in the nonsafety-related
CA piping, interactions between the CACST and USTs upon tank depletion,
use of the condenser hotwell, CA pump flow demand, and interaction with
the NSWS water supply.
l
The inspector reviewed several of the previous PIPS. corrective actions.
and other related station documents and discovered conflicting
characterizations of the safety importance of manual isolation actions.
The McGuire Operations Training manual and PIPS indicate that operator
action to isolate empty USTs are critical to prevent air entrapment in
Enclosure 2
,
. - ... .-
.
.
21
,
the CA suction piping. The inspector's preliminary review of the
I
McGuire PRA Jid not reveal extensive modeling of the CA system that
captures oir entrainment failure' modes and critical operator actions to
prevent CA pump air binding.
Between'1992 and 1994. some corrective actions were taken to addre's the
!
s
. concerns, most notably steps in the AP/EPs were added to isolate the-
CACST and USTs upon tank depletion to prevent air entrainment. -However.
'the inspector interviewed station engineers who stated that engineering
-judgement was used at that time to determine that there was a low-
probability of air entrapment in the CA suction piping, even though
!
there are several piping loop seals in the CA suction piping. Some -
estimates in 1994 indicated up to 20 linear feet of voided pipe could
exist .
The licensee did not consider single failure criterion
a)plicable to CACST isolation valves or tank level instrumentation since
I
'
t1e system was classified as nonsafety-related.
i
"
Pen'iing conclusion of the licensee's hydraulic studies, sufficient
information was not available.to the inspector to ascertain,
applicability of regulatory requirements to these important to safety CA
sources or the exact vulnerabilities that.may exist.
Pending further
review, this issue will be identified as Inspector Followup Item (IFI)
369.370/97-08-04, Potential Air Binding of CA Pumps,
c.
Conclusions
The inspector concluded that compensatory measures were prompt and
effective to deal with the CACST vortexing issue.
The aggressive
schedule to implement design modifications to eliminate the vortexing
concerns are also positive actions to maintain CA system reliability.
_ . -
Compensatory measures adequately capture steps necessary to minimize air
i
entrapment from USTs interaction with CA recirculation operation.
However, the inspector considered UFSAR document'ition on CA operation to
j
be non-detailed. Specifically, the UFSAR does not reflect that the
automatic swapover to NSWS also involves manual operator action to
isolate the nonsafety-related water source to prevent air entrainment.
Auxiliary feedwater air entrainment (other than vortexing) was
identified as early as 1992 and multiple PIPS have been written since
then related to the potential CA pump air binding.
Potential
significant weakness in the PRA exist if these critical operator actions
to prevent a common mode failure of CA are not properly reflected. The
air entrainment from emptying of the CACST or USTs. or use of the
condenser hotwell is stilI indeterminant until completion of hydraulic
,
studies. The ins)ector considers the licensee's engineering analyses as
a partial design ) asis reconstitution effort for the CA system.
!
!
,
Enclosure 2
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22
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E2
ENGINEERING SUPPORT OF. FACILITIES AND EQUIPMENT (37551)
p
E2.1 Missina Swivel Bracket Bolts in Ice Condenser Basket
'
a.
Insoection ScoDe
i
-The inspectors reviewed the licensee's followup to a degraded condition
l
identified on the Unit 1 ice condenser,
b.
Observations and Findinas
The' licensee's routine inspection of ice condenser baskets during the
Unit 1 EOC11 refueling outage, disclosed that an ice basket (5-6-9) was
missing both swivel bracket bolts. This basket had been vibrated empty
during this outage as part of the maintenance program, while executing
,
" ' '
ice condenser maintenance procedure SM/0/A/8510/007, under WO 96064989.
,
By review of the associated Problem Investigation Process (PIP) Report
!
1-M97-0907 and through discussions with the cognizant engineer, the
inspectors ascertained the following:
,
Swivel brackets were designed for attaching the ice basket to the
e
lower support steel. so that they would not eject from the ice
condenser during a Design Bases Loss of Coolant Accident (DBLOCA).
Each swivel bracket has two (2) stainless steel bolts which hold
the two symmetric halves of the swivel bracket to the bottom of
the basket and the swivel base.
The swivel base is pinned to a clevis on the lower support
-
e
structure.
The swivel bracket's bolted joint was designed to facilitate
e
weighing the baskets and vibrating the ice out for replenishment
i
. purposes.
)
i
By review of completed work orders, the inspectors ascertained that the
'
licensee's immediate corrective action was to assure that the bolt.s were
torqued to the requirements specified by procedure.
In addition, the
licensee checked the torcue on a sample of baskets whose ice had never
been replaced.or vibratec out since the installation of swivel brackets
and found them acceptable.
l
A followup investigation determined that the root cause of loose or
j
l
missing bolts was associated with vibrating the ice out of the baskets
'
for replenishment during maintenance. This determination was made as
part of an evaluation performed on the Unit 2 ice condenser, when a
.
similar condition was identified by maintenance during the 2E0C10
l.
refueling outage. That 3roblem, which was documented in PIP 2-M96-1025.
involved two swivel braccets; one had one of the two bolts missing and
'
the other had both bolts disengaged / backed out. Following an extensive
inspection of Unit 2 ice condenser baskets, an operability calculation
,
i
MCC-1201.17-00-0011 and an operability assessment by Westinghouse
L
Enclosure 2
1
I
_
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.
b
._
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23
determined that-a swivel bracket with one missing bolt was capable of-
performing its design function.
'In reference to the basket with two missing bolts, the Westinghouse
l
-evaluation analyzed the potential for and consequences of a small number
of ejected baskets.
Their determination was that with a 1% swivel
bracket failure rate, ap3roximately 0.26%-of all. baskets in the ice
l
'
condenser could conceivaaly pass through the intermediate deck. The
Westinghouse analysis also determined that the ejected baskets would
l
travel approximately 15 feet until striking the top deck structure and
l
. grating, which would prevent their exit from the ice condenser.
Westinghouse concluded that this limited number of ejectable basket
movement, even when combined with some non-ejectable basket movement.
would not effect the performance of the ice condenser system.
l
c. . Conclusions
The inspectors concluded that the licensee's identification and
corrective actions taken for the missing swivel bracket bolts in a Unit
~
1 ice condenser basket were adequate.
E2.2 Review of FN0 Fuse Reolacement Pro.iect
a.
Inspection Scoce (62707)
-
The inspector reviewed activities associated with the replacement of FNQ
type fuses during the Unit 1 EOC10 outage.
-
b.
Observations and Findinas
Bussman type FNA fuses equipped with spring loaded indicating pins were
used in the original design for both Class 1E and non-1E applications at
McGuire.
Over the years McGuire has experienced failures of these types
fuses where the fuses opened with no electrical problem in the circuit.
The FNA fuses were replaced with FNQ type fuses in all 1E applications
and replaced on an "as-fail" basis for the non-1E applications.
Subsequent to this replacement. McGuire experienced mechanical failure
of FNQ ty)e fuses similar to the FNA type failures.
FNQ type fuses
smaller tlan 3.2 amperes have an internal spring to assist fuse. opening
at low currents. After 10 confirmed mechanical failures resulting in
two reactor trips over a three-year period, a decision was made to
replace the FNQ type fuses.
.
NSM MG-12467/Pl. Replacement of Bussman FNQ Fuses with Non-detectable
Failure Modes, was accomplished in the outage 1E0C11. This modification
]
replaced FNQ type fuses that were identified as susceptible to the
established failure mode, with Little Fuse FLQ type fuses of the same
,
L
ampere rating.
Fuses identified for replacement were critical valve
'
'
circuits.
Critical valve circuits.were identified as circuits whose
failure of the fuse could trip the unit and challenge safety systems.
Enclosure 2
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E
.
.
24
The inspector reviewed the modification package and the fuses-identified'
for replacement.
The inspector concluded that a rigorous review to
determine fuse replacement needs had been performed, resulting in an
-adequate listing of fuses for inclusion in the modification.
Additionally, the scope of the modification included replacement of
fuses in IE applications whose failure would be non-detectable.
For
,
example. these included fuses such as control board indicator lights
whose failure would not cause loss of the indicator-light, or control-
board receiver gauges whose fuse failure would not result in the gauge
'
indicating offscale.
Also, fuses whose failure could result in a
significant transient were also incorporated into this_ modification.
The inspector discussed the scope of the modification with the
a3propriate personnel.
Electrical implementation procedures used for-
,
.' '
tie fuse replacement were also discussed and reviewed. The inspector
found the responsible personnel knowledgeable of the procedures and the
work in progress,
c.
Conclusions
The' inspector determined that the scope of the corrective actions for
FNQ type fuse failures were adequate.
Licensee personnel were cognizant
of the scope and' implementation of the associated modification.
,
E4
Engineering Staff Knowledge and Performance (37551)
E4.1 MNS Resoonse to the Oconee Heater Drain Pioe Ruoture Event.
-
u-
a.
Insoection Scooe
During the present SGRP outage. the licensee performed an inspection of
heater drain piping in Unit 1 to look for branch connections that lacked
adequate weld reinforcement.
,
b.
Observations and Findinas
a
The inspectors reviewed the licensee's fi:ndings as a result of the
inspections. The results indicated that weld reinforcement was lacking
in two dri) legs in heater drain line
'A' (HA), and two in heater drain
line 'B' (18).
Based on ANSI B31.1 Code requirements and design
pressures, the licensee determined that the two 18" x 4" drip legs in HA
were under-reinforced by 73% and the two 20" x 4". by 24%. To document
this problem, the licensee issued Problem Investigation Report No. 1-
.
M97-0879 and Minor Modifications 9149 and 9150 to perform the weld
L
reinforcement repairs. Through discussions, a field inspection and
[
document review, the inspectors determined the following:
MNS has six separate drain lines that expand across control valves
[
e
'
and proceed downhill to the heaters.
!
Walkdowns showed the second stage MSR drain line, had no low
e
points where a water slug could accumulate.
Enclosure 2
.
_
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.
25
Engineering's review of stress analysis. calculations determined
e
(
that all tees in the Moisture Separator Reheater Drain (HS) system
were manufactured fittings.
Other systems had fabricated tees and
'
laterals but most of these were manufactured by.Grinnell pipe
fabricators. Historically. branch connections-made by Grinnell
were found to meet ANSI.B31.1 Code requirements.
'
el
During construction, balance of plant piping and associated branch
connections were designed to ANSI B31.1 Code requirements, but
there were no requirements to retain these calculations'or,to
forward them to the site.
,
c.
Conclusions
,
The inspectors inspected the repaired branch connections and determined
'
that the additional weld buildup to the existing reinforcement was
-
sufficient to meet the applicable code requi_rement.
E8
Miscellaneous Engineering Isues (92903)
E8l1
(CLOSED) URI 369.370/96-10-04:
Evaluation'for Spent Fuel Poo1 ~(SFP)
I
Area Painting Project
j
This URI was identified to evaluate several projects performed under the
work order. process and to determine if adequate screenings for potential
50.59. issues were performed. The inspector determined through
interviews and review of available documentation, that reviews were
performed for this maintenance evolution which adecuately evaluated the
subject work for 50.59 impact criteria. Numerous ciscussions were
- '
-
conducted with engineering personnel and station management regarding
-
the threshold for completing 50.59 screening reviews for complex
maintenance activities. The licensee agreed that improvements.could be
made in this area as indicated by this and other examples identified by
the inspector.
One recent example involved the blocking.of a temporary
trailer over a safety-related pipe trench. While the piping could not
-
have been adversely impacted, more thorough review and documentation
could have been performed. As a result of the inspectors observations.
the licensee developed new guidance that was recently incorporated in
the 10 CFR 50.59 screening and evaluation process dated February 5.
'
1997. The guidance presented Duke wide clarification of expectations
'for performing and documenting adverse impact screenings for important
equipment and the importance of utilizing the appropriate administrative
process for evaluating maintenance and modification evolutions. Recent
inspections in the area of outage modifications reiterated that the
licensee's efforts in this area have been improving. This item is
L
closed.
l.
.
5
L
Enclosure 2
l.
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26
IV. Plant Supoort
R4
Staff Knowledge and Performance in Radiological Protection and Chemistry
R4.1 Steam Generator 2A Primary to Secondary leakaae (71750)
a.
Observations and Findinas
During the inspection period the licensee monitored a small primary to
secondary Steam Generator (SG) tube leak which was identified on the 2A
SG. At the end of the inspection period, the leakage was est-imated by
plant chemistry to be ap;roximately nine Gallons Per Day (GPD) and
exhibiting slow growth c w acteristics.
The licensee was actively
monitoring the identified leakare to identify any ste) changes and
keeping operations and management informed of the leac ]rogression.
The
,
licensee is maintaining an administrative allowable leacage limit of 100
t
GPD for continued operation. The current TS limit for this type of
leakage is 500 GPD for Unit 2 operation.
The Unit 2 SGs are scheduled
to be replaced during the upcoming Unit 2 cycle 11 refueling outage
scheduled to begin in September 1997.
b.
Conclusions
The inspectors concluded that the licensee was providing adequate
primary to secondary leakage monitoring of the degraded SG 2A condition
and had previously established conservative administrative leakage
limits as compared to TS allowable limits.
P2
Status of EP Facilities. Equipment, and Resources (71750)
-
P2.1 Emeraency Plannino Task Force Meetina
a.
insoection Scooe and Observations
On May 13. the inspector attended portions of a routine Emergency
Planning (EP) Task Force Meeting at the McGuire site.
Such meetings are
conducted on a frequent basis to facilit le good communications between
the licensee. State and local government personnel concerning a variety
of Emergency Preparedness topics.
b.
Conclusions
The inspectors concluded that the licensee's sponsoring of the routine
EP Task Force Meeting was indicative of good management support of the
EP area.
The meeting facilitated open discussions to improve existing
EP processes and the licensee's interaction with the local officials
during events.
l
l
!
(
I
Enclosure 2
- . . - - -~ . -
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,
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27
c
P8
Miscellaneous EP Issues (92904)
'
P8.1
(CLOSED) IFI- 50-369.370/96-04-05:
Verification of SSS Activation Time
,
During Emergency Plan Drill (capability to perform. time critical tasks
during SSS activation in conjunction with EP evolutions has not been
j
verified)
l
'
This item-identified a concern ~with the licensee's capability to assure
l
'the time critical ~ tasks of the Standby Shutdown System (SSS) activation
were accomplished during the altered operations command structure which
j
l
was implemented when.the Technical Support Center (TSC) was activated
1
l
during the Emergency Plan (EP) condition.
During an EP drill on May 29.
L
1996, the time critical SSS tasks were not met due to communications
l
problems inherent'in the TSC command structure. The licensee
~
,
' ~
subsequently-evaluated the SSS activation tasks and the TSC command
.,
!
structure communications and implemented changes to the communications.
-process during an EP activation.
Emergency Plan Drill 97-01 conducted
on February 18, 1997, adequately demonstrated the performance of time-
critical tasks for SSS activation during EP conditions. This itern is
!
closed.
F1-
Control of Fire Protection Activities (71750)
F1.1 Fire Prevention Activities Associated with Previous Turbine Oil Soill
a.
Insoection Scooe
i
i
The inspectors reviewed fire prevention activities in response to a
'
turbine oil spill which occurred during the Unit I refueling outage.
. . -
b.
Observations and Findinas
.
'
-The subject turbine oil spill was previously_ discussed in Inspection
Report 369.370/97-04.
During this inspection period, the inspector
reviewed the condition of the Unit 1 turbine building piping and
equipment affected by the oil. The inspector was specifically concerned
that residual oil may pose a fire threat to the affected area. The
specific oil has an auto-ignition between 750 and 850 degrees F:
however. oil soaked insulation sources have been reported to have much
lower ignition points.
This potential mechanism was determined to be an
l
oxygen exothermic reaction within the insulation. The licensee received
this information through researching their industry experience
iL
databases.
l
Licensee's corrective actions for the spill included replacement of a
!
large amount of potentially oil soaked piping insulation.
Prior to
i
restart of the unit, the inspectors
3erformed walkdowns of the areas
L
affected by the spill to evaluated t1e licensee's response.
In general,
j
the corrective actions for the spill were thorough. The as-left areas
were oil free and in good condition.
Normally inaccessible areas were
opened and cleaned to remove any residue. During initial heatup of the
!
system piping. the licensee posted fire watches around the affected
areas. Special fire fighting equipment was stationed in the area which
!
Enclosure 2
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28
I
would be most effective on an oil fire and the watches were focused on
the areas most vulnerable (i.e.. areas of hottest temperatures).
Part
of the monitoring included the use of laser temperature probes which
allowed the fire watch to search for changing piping hotspots during the
secondary side heatup.
Prior to heatup, the inspector did identify some
evidence of oil soaked insulation outside of the established boundary,
which was promptly addressed by the licensee. The inspector noted that
despite the licensee's best efforts in removing all the oil, residual
oil continued to seep from inaccessible areas onto piping and other
components.
The inspectors monitored the area during restart of the
unit and determined that the licensee's efforts were effective during
this period.
c.
Conclusions
The inspectors concluded that the licensee's fire prevention efforts
'
'
regarding a previous turbine oil spill event were effective in
preventing a potential fire threat to tha turbine building.
Contingency
measures were well established.
V. Management Meetinas
X1
Exit Meeting Summary
i
The inspectors 3 resented the inspection results to members of licensee
management at tie conclusion of the inspection on May 23, 1997. The licensee
acknowledged the findings presented.
No proprietary information was
identified.
_ . . .
l
!
Enclosure 2
.
.
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_.
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.
29
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Barron, B., Vice President McGuire Nuclear Station
Boyle, J., Civil / Electrical Systems Engineering
Byrum, W., Manager, Radiation Protection
Cline, T. , Senior Technical Specialist, General Office Support
Cross, R., Regulatory Compliance
Dolan, B., Manager Safety Assurance
Geddie. E., Manager, McGuire Nuclear Station
Herran, P., Manager, Engineering
Jones, R.. Superintendent, Operations
Michael, R., Chemistry Manager
Jamil, D., Superintendent, Maintenance
'
Cash, M., Manager, Regulatory Compliance
Thomas, K., Superintendent Work Control
Travis, B., Manager, Mechanical / Nuclear Systems Engineering
Tuckman, M., Senior Vice President Nuclear Duke Power Company
NRC
S. Shaeffer, Senior Resident Inspector, McGuire
M. Franovich, Resident Inspector. McGuire
M. Sykes, Resident Inspector, McGuire
.
N. Economos. Regional Inspector
S, Rudisail, Regional Inspector
'
R. Moore, Regional Inspector
.. -
.
l
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i
Enclosure 2
,
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'S
30
INSPECTION PROCEDURES USED
IP 71707:
Conduct of Operations
IP 71750:
Plant Support
IP 62707:
Maintenance Observations
IP 61726:
Surveillance Observations
IP 40500:
Self-Assessment
IP 37551:
Onsite Engineering
IP 92700:
Onsite LER Followup
IP 92902:
Followup - Maintenance
l
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support
ITEMS OPENED, CLOSED AND DISCUSSED
,
,
OPENED.
369/97-08-01
Root Cause of MSVV Level Actuation
(Section 02.2)
369/97-08-02
Inadequate Procedure for performing
ACOT Testing (Section M3.1)
369/97-08-03
Failure to Maintain Complete and
Accurate Records (Section M8.1)
369.370/97-08-04
IFI
Potential Air Binding of CA Pumps
(Section El.1)
369/97-08-05
Failure to Follow Procedure (Section
M8.1)
CLOSED
50-370/96-03
LER
Unit 2 Reactor Trip Occurred Due To
Reactor Coolant Pump Motor 2B
Failure (Section 08.1)
50-369/96-01-04
Apparent Failure to Follow Procedure
(Disassembly, repair and re-assembly
on Kerotest 'Y' type check valve
1NV233) (Section M8.1)
369,370/96-10-04
Evaluation for SFP Area Painting
,
Project (Section E8.1)
!
l
r
Enclosure 2
!
T
.
.
31
50-369.370/55-04-05
IFI
Verification of SSS Activation 23
Time During Emergency Plan Drill
(ca] ability to perform time critical
tascs during SSS activation in
conjunction with EP evolutions has
i
.
not been verified) (Section P8.1)
.
LIST OF ACRONYMS USED
ACOT -
Analog Channel Doerational Test
ALARA -
As Low As Reasonably Achievable
ASME -
American Society of Mechanical Engineers
CA
-
Auxiliary Feedwater System
CACST -
Auxiliary Feedwater Condensate Storage Tank
'
-
Main Feedwater System
'
CFR
-
Code of Federal Regulations
-
Design Basis Event
ECCS -
--
-
-
Engineered Safety Feature
-
Final Safety Analysis Report
-
FWST -
Refueling Water Storage Tank
Gallons Per Day
GPD
-
Moisture Separator Reheating Drain
HS
-
IAE
-
Instrument and Electrical
-
Instrument Air System
IFI
-
Inspector Followup Item
_ -
LER
-
Licensee Event Report
LCO
-
Limiting Condition for Operation
LOCA -
Loss of Coolant Accident
LOOP -
MS
-
MSSV -
Main Steam Line Safety Valve
MSVV -
Main Steam Valve Vault
-
Non-Cited Violation
'
-
NOUE -
Notice of Unusual Event
NRC
-
Nuclear Regulatory Commission
-
NRC Office of Nuclear Reactor Regulation
NSD
-
Nuclear Site Directive
j
Operations Shift Manager
-
-
Problem Investigation Process
,
!
PORC -
Plant Operations Review Committee
l
-
Probablistic Risk Assessment
GA
-
Quality Assurance
RCP_
-
Reactor Coolant Pump
-
-
Reactor Operator
-
Spent Fuel Pool
SGRP -
Steam Generator Replacement Project
Enclosure 2
r
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4
32
-
Safety Injection
-
Senior Reactor Operator
TS
-
Technical Specifications
UFSAR -
Updated Final Safety Analysis Report
-
Unresolved Item
USTs -
Upper Surge Tanks
-
Violation
-
Work Order
WPM
-
Work' Process Manual
ZPPT -
Zero Power Physics Testing
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Enclosure 2
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SYNOPSIS
This investigation was initiated by the U.S. Nuclear Regulatory Commission.
Office of Investigations. Region II, on March 22. 1995, to determine if an
individual at the Duke Power Company, McGuire Nuclear Station, intentionally
signed and falsified step 11.4.5 of a procedure (cuality assurance document)
claiming that he replaced a valve gasket when he cid not.
The evidence developed during this : investigation substantiated that this
individual purposely decided to reuse the old gasket and intentionally signec~
the procedure step claiming that he had replaced the valve gasket.
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Case No. 2-96-010
ATTACHMENT
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