ML17157C238
| ML17157C238 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 03/05/1993 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17157C236 | List: |
| References | |
| 50-387-93-01-01, 50-387-93-1, 50-387-93-1-1, 50-388-93-01, 50-388-93-1, NUDOCS 9303160054 | |
| Download: ML17157C238 (22) | |
See also: IR 05000387/1993001
Text
e
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
Inspection
Report Nos.
50-387/93-01; 50-388/93-01
License Nos.
Licensee;
Pennsylvania Power and Light Company
2.North Ninth Street
Allentown, Pennsylvania
18101
Facility Name:
Inspection At:
Susquehanna
Steam Electric Station
Salem Township, Pennsylvania
Inspection
Conducted:
January
1, 1993 - February 15, 1993
Inspectors:
G. S. Barber, Senior Resident Inspec
D. J. Mannai, Res't
tor,
Approved By:
J. Whi, Chief
Reac
r Projects Section No. 2A,
ate
Thi i
I '>>
d
i
d
i
i
p
(during day and backshift hours) of station activities, including: plant operations; radiation
protection; surveillance and maintenance;
and safety assessment/quality
verification.
One
violation was identified regarding tracking out-of-service times during instrumentation
surveillances
(Section 4.4.1 pertains).
Findings and conclusions of this inspection effort are
summarized in the Executive Summary.
Details are provided in the inspection report.
9303ib0054
930308
ADOCK 05000387
Q
EXECUTIVESUMMARY
Susquehanna
Inspection Reports
50-387/93-01; 50-388/93-01
January
1, 1993 - February 15,
1993'perations
(30702, 71707, 71710)
During the period, Unit 2 was shutdown to effect repairs to the main generator exciter.
During the plant shutdown administrative cooldown rate limits, as monitored at the
recirculation loop suction lines, were exceeded.
Administratively, the cooldown rate is
limited to (90'F/hr by station procedures., About 103'P/hr was measured
at the
recirculation loop suction lines.
The licensee determined that the Technical Specification
Limitof 100'F/hr was not exceeded
since the correct indicator for plant conditions, i.e.,
saturated reactor steam dome temperature
(Tsat) indicated less than 60 F/hr.
The inspector
concluded weak communications and control by operators resulted in exceeding the
administrative limits. The inspector also noted that operators did not fully understand which
temperature indicators are used to determine Technical Specification compliance.
Section
2.2.1 pertains.
During the period radwaste transformer OX340 faulted.
The transformer failure resulted in
an undervoltage condition that propagated to both Susquehanna
Units.
The voltage transient
caused isolations of several primary containment isolation (PCIS) valves.
Operators
promptly responded
to the event and rapidly restored systems to normal.
Nuclear System
Engineering (NSE) reviewed plant response.
NSE found that systems operated per design
and no anomalies were detected.'he
licensee determined the cause of the transformed fault
was water intrusion into the transformer cabinet;
The inspector identified that this was a
third instance of an electrical fault on a balance of plant system having an effect on class
"1E" safety related systems since 1989,
The licensee agreed to evaluate system
enhancements
to minimize the possibility of these occurrences.
The licensee's investigation
and final resolution was still in progress at the conclusion of the inspection period.
The
inspector willassess
licensee corrective actions during inspector review of the Licensee
Event Report.
Section 2.2.2 pertains.
Maintenance/Surveillance
(61726, 62703)
During a routine control room walkdown, the inspector observed the performance of an
instrumentation surveillance on the low-low-lowlevel reactor water trip channels.
By
Technical Specifications (TS), each channel could be made inoperable for a period of two
hours without tripping the channel.
The inspector determined that the licensee was not
adequately tracking each channel's out-of-service time.
The actual out-of-service time for
each individual channel is not known, however, licensee past practice indicates that the time
was likely less than two hours.
This is an apparent violation.
Section 4.4.1 pertains.
Engineering/Technical Support (71707, 92720; 93702)
The licensee identified a small pinhole leak in a fuel assembly based on an increase in Unit 2
offgas pretreatment radioactivity.
The leak is extremely small and does not result in
approaching any offsite dose limits. The licensee has comprehensive
procedures in place to
address
any increases in radioactivity.
The fuel vendor willperform fuel sipping at the next
refueling outage to identify and repair the leaky fuel assembly.
The licensee's actions were
conservative and comprehensive.
Section 7.2.1 pertains;
The licensee identified an inconsistency in the piping analysis used to predict stresses
during
a high energy line, break on the Reactor Water Cleanup (RWCU) system.
A 45 degree angle
restraint was used in place of a vertical restraint for an elbow downstream of the RWCU
outboard containment isolation valve.
Bechtel was contacted and reran the analysis with
satisfactory results.
The inspector questioned
the licensee to ensure that the assumptions
used in the original analysis were also used for re-analyses.
Bechtel assured
the licensee that
all of the original assumptions were used, and the minor model changes did not invalidate the
results.
The inspector noted the licensee's identification of this discrepancy
as a positive
initiative. Section 7.2.2 pertains.
Safety Assessment/Assurance
of Quality (40500, 90712, 92700, 92701)
The inspector reviewed three Licensee Event Reports during the period.
Section 8.1
pertains.
TABLEOF CONTENTS
EXECUTIVE SUMMARY
SUMMARYOF OPERATIONS.......
1.1
Inspection Activities..........
1.2
Susquehanna
Unit 1 Summary....
1.3
Susquehanna
Unit 2 Summary....
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2.
PERATIONS
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2.1
Inspection Activities................................
2.2
Inspection Findings and Review of Events
2.2.1
Administrative Cooldown Rate Exceeded During Plant Shutdown
2.2.2
Engineered Safety Feature Actuation Due to Transformer Fault
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3.
RADIOLOGICALCONTROLS
3.1
Inspection Activities..... ~........ ~....
3.2
Inspection Findings
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4.
MAINTENANCE/SURVEILLANCE
4.1
Maintenance and Surveillance Inspection Activity .
4.2
Maintenance Observations
4.3
Surveillance Observations
4,4
Inspection Findings
4.4.1
Reactor Water Level Surveillance Concerns
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5.1
Inspection Activity......................
5.2
Inspection Findings
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6.
SECURITY
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Inspection Activity............
6.2
Inspection Findings
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8.
ENGINEERING/TECHNICALSUPPORT
7.1
Inspection Activity............ ~............
7.2
Inspection Findings
7.2.1
Long Term Fuel Performance Monitoring - Unit 2
7.2.2
Excessive Piping Stresses During High Energy Line
SAFETY ASSESSMENT/QUALITY VERIFICATION..
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Licensee Event Reports..................
8..2
Open Items
Breaks
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'ANAGEMENTAND EXIT MEETINGS ..........
9.1
Resident Exit and Periodic Meetings........
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Inspections Conducted-By Region Based Inspectors
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1.
SUMMARYOF OPERATIONS
1.1
Inspection Activities
The purpose of this inspection was to assess
licensee activities at Susquehanna
Steam Electric
Station (SSES) as they related to reactor safety and worker radiation protection.
Within,each
inspection area, the inspectors documented the specific purpose of the area under review, the
scope of-inspection activities and findings, along with appropriate conclusions.
This
assessment
is based on actual observation of licensee activities,'nterviews with licensee
personnel,
measurement of radiation levels, independent calculation, and selective review of
applicable documents.
Abbreviations are used throughout the text.
Attachment
1 provides a'listing of these
abbreviations.
1.2
Susquehanna
Unit 1 Summary
Unit 1 operated at or near full power for the duration of the inspection period.
Operators
conducted several routine power reductions during the period to facilitate control rod pattern'
adjustments,
surveillance testing, and maintenance.
One unplanned ESF actuation occurred
due to a volta'ge transient caused by a nonsafety related transformer failure,
Section 2.2.2
pertains.
1.3
Susquehanna
Unit 2 Surmnary
Unit 2 began the inspection period at 100% power.
On January 29, power was reduced to
60% to repair a condenser water box tube leak.
During the down power, a generator exciter
field ground alarm was received.
After investigation, the licensee identified the need for a
plant shutdown to determine and correct the cause of the ground.
The unit reached
Condition 4 at 10:20 a.m. on February
1. During the cooldown, operators
exceeded
administrative cooldown limits. Section 2.2.1 pertains.
On February 5, following the
generator exciter repair, the unit was started up.
The unit returned to 100% power operation
on February 8. Two unplanned ESF actuations occurred during the period.
One was caused
by the transformer failure, which resulted in primary containment isolations.
Section 2.2.2
pertains,
The other unplanned ESF actuation occurred during a momentary loss of 120 volt
AC instrument power.
Several primary containment isolations occurred as a result of the
voltage transient.
Section 8.1 pertains.
2.
OPERATIONS
2.1
Inspection Activities
The inspectors verified that the facility was operated safely and in conformance with
regulatory requirements.
Pennsylvania Power and Light {PP&L) Company management
control was evaluated by direct observation of activities, tours of the facility, interviews and
discussions with personnel,
independent verification of safety system status and Limiting
,Conditions for Operation, and review of facility records.
These inspection. activities were
conducted in accordance with NRC inspection procedure 71707.
The inspector determined
that Unit 1 operational and Unit 2 outage activities were conducted safely during this period.
I
The inspectors performed 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of deep backshift inspections during the period.
These
deep backshift inspections covered licensee activities during between
10:00 p.m. and 6:00
a.m. on weekdays,
and weekends and holidays.
2.2
Inspection Findings and Review of Events
2.2.1
Administrative Cooldown-Rate Exceeded During Plant Shutdown
On February
1, Unit 2 was shutdown to repair the main generator exciter.
During the
shutdown, the cooldown rate as measured
at the "A" recirculation loop suction line was
about 103'F per hour.
This, rate exceed the licensee's administrative limitof less that 90'F
per hour.
The administrative limitwas established
to assure that the Technical Specification
(TS) Limitof 100'F per hour cooldown is not exceeded.
Later analysis, revealed that the
saturated
steam dome temperature
(the approved indicator for the existing plant conditions
for assuring compliance with Technical Specification (TS) 3.4.6.1) indicated a cooldown rate
of about 60'F per hour.
Notwithstanding, the operators took appropriate action to reduce
the cooldown rate at the recirculation suction line to within the administrative limit. The
licensee documented
this occurrence in Significant Operating Occurrence Report (SOOR) 93-
024.
The plant was being taken to cold shutdown following GO-200-005, "Plant Shutdown to Cold
Shutdown."
The operators used SO-200-011, Reactor Vessel Temperature and Pressure
Recording, to record temperatures
and determine cooldown rate every fifteen minutes.
GO-
200-005 requires that the cooldown rate be limited to 90'F/hour.
SO-200-011 requires
action be taken to reduce the cooldown rate iftemperature
change is >25'F in a fifteen
minute period.
The temperatures
monitored are recirculation Loop "A" suction line,
recirculation Loop "B" suction line, reactor vessel bottom head drain and reactor steam
dome'emperatures.
After determining a fifteen minute cooldown rate of 33'F on the "A"
recirculation suction line, operators took action to reduce the cooldown rate.
However, the
cooldown rate exceeded
100'F in one hour on the "A" recirculation suction line.
SO-200-
011 requires that TS 3.4.6.1 be entered only ifreactor steam dome temperature delta-T's are
greater than 100'F in any one hour.
The inspector questioned why operations entered the
TS action statement when the procedure did not require it. The inspector determined that the
TS action statement was entered
as a prudency measure until Nuclear System Engineering
could complete their evaluation.
From earlier analysis of excessive cooldown rate events, the licensee, in concert with
General Electric, determined the 100'F limit specifically applies to the belt line region of the
reactor vessel relative to brittle fracture prevention.
The analysis showed that reactor belt
line temperature is best determined from reactor steam dome temperature
(Tsat) with coolant
temperature )212'F. Ifcoolant temperature is less than 212'F then reactor recirculation
suction line temperatures
are used.
The lowest coolant temperature at the time of the event
was 224'F.
The GE analysis also indicated that non-beltline regions have been analyzed for
the most severe applicable design basis thermal event and are not limiting. Therefore, they
do not require monitoring to ensure TS compliance.
The NRC accepted this method of
determining compliance with TS cooldown rate limits and documented
acceptance
in
Inspection Report 50-387/91-18.
Maximum change in Tsat during the event was less than
60'F in one hour.
The licensee decided that no TS limits were exceeded
and pressure
temperature curve limits were not challenged.
Nuclear System Engineering (NSE)
determined that the cooldown observed on the "A" recirculation loop was not detrimental to
the recirculation piping or reactor vessel.
The inspector agreed with the licensee determination that no TS limits were exceeded.
The
licensee conservatively performed an engineering evaluation though one was not required.
The inspector determined inadequate communications and control between the operator
controlling the cooldown and the operator recording the temperatures
resulted in exceeding
administrative cooldown limits. Aside from following the procedure, no prior specific
discussions took place between the unit supervisor (SRO) and the plant control operator (RO)
to outline what actions would be taken to ensure cooldown rates would not be exceeded.
The
inspector concluded that, even though the procedure was very specific, the temperature
indication that should be used to determine compliance with the TS cooldown rate limitwas
not well understood by operators.
Licensee actions to prevent recurrence willconsist of reviewing this event with all operations
shifts,
Additionally, the basis for the temperature indication to be used for determining TS
compliance willbe discussed.
The licensee willemphasize the need for a pre-evolution brief
(tailboard) for significant plant evolutions.
2.2.2
Engineered Safety Feature Actuation Due to Transformer Fault
On February
1, a non-safety related radwaste transformer, OX340, (normal feed to radwaste
load center 08340) faulted, resulting in an undervoltage condition that propagated to both
Susquehanna
units.. At the time, Unit 1 was at 100% power, Unit 2 was in Condition 4,
Cold Shutdown.
Failure of transformer OX340 tripped the 13.8kv feeder breaker that feeds
the radwaste load center and two Unit 2 turbine building heating load centers.
The licensee
restored all three 480 volt load center's on alternate power supplies.
4
The undervoltage condition was of sufficient magnitude and duration to cause isolation of
several primary containment isolation system (PCIS) valves.
Systems affected included
containment atmospheric control (CAC) valves and containment- instrument gas (CIG) valves.
This constituted an unplanned Engineered Safety Feature (ESF) actuation.
The licensee
found the ESF actuations to be invalid but reportable per 10 CFR 50.72.
The licensee made
the required four hour NRC notification.
Besides numerous alarms, annunciators
and loss of
Balance of Plant (BOP) equipment, Unit 2 Reactor Water Cleanup (RWCU) and fuel pool
cooling (FPC) pumps stopped due to the low voltage condition.
Operators promptly restored important systems to service.
Operations personnel documented
observations'nd
plant system'responses.
Nuclear System Engineering (NSE) began a review
of observations
and plant responses
to ensure all systems functioned per design.-
Until protective undervoltage relaying tripped the transformer feeder breaker, the
undervoltage transient propagated
to Startup Bus 20 which is fed from transformer T-20.
Startup Bus 20 is common to both units.
Division 2 4kv emergency
busses
are supplied from
Startup Bus 20 for both units.
The resultant transient effects were explainable.
The licensee
deteimined,
based on a review of the event and operator observations,
that no anomalies
existed in plant response.
The licensee determined the transformer failure was due to water intrusion into the load
center transformer cabinet.
NSE found water dripping from inside the exhaust'ucting from
radwaste tank vent filtered exhaust fan discharge, to the turbine building exhaust vent on the
top of the electrical cabinet.
The ductwork is located above the load center transformer
cabinet.
The licensee made immediate provisions to collect the leaking water to prevent
additional intrusion in the electrical cabinet. >NSE preliminarily determined condensation of
moisture entrained in the air inside the ductwork was the source of the water dripping from
inside the ductwork.
Licensee investigation, analysis and evaluation of water coming from
the d'uctwork was in progress at the conclusion~of the inspection period.
i
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The inspector concluded that the operators promptly and properly responded to the
transformer failure and resultant plant perturbations.
PP&L used experience gained from a
similar previous occurrence to quickly understand
the effects of the voltage transient and
rapidly restored plant systems to a normal configuration.
The inspector agreed with the-
utility'-s reportability determination.
Of particular strength was Nuclear System
- Engineering's approach to reviewing all operations personnel observations
and documenting
plant effects to ensure that systems operated
as designed.
NSE concluded all plant responses
were explainable and that no anomalies were detected.
The inspector noted that this.was a third occurrence since 1989 of an electrical fault on a
- Balance of.Plant (BOP) system that affected safety-related
class "1E" equipment.
The
previous occurrences
are documented in SOORs 1-89-341 and 1-89-043.
The licensee agreed
to review the need for system enhancements
to minimize BOP system faults from affecting
class "lE" safety related systems.
Licensee resolution of the event was still in progress at
0
'the conclusion of the inspection period.
The inspector willreview final licensee actions to
prevent recurrence
and cause determinations during review of the Licensee Event Report
(LER).
3.
RADIOLOGICALCONTROLS
3.1
Inspection Activities
PP&L's compliance with the radiological protection program was verified on a periodic
basis.
These inspection activities were conducted in accordance with NRC inspection
procedure 71707.
3.2
Inspection Findings
Observations of radiological controls during maintenance activities and plant tours indicated
that workers generally obeyed postings and Radiation Work Permit requirements.
4.
MAINTENANCE/SURVEILLANCE
4.1
Maintenance and Surveillance Inspection Activity
On a sampling basis, the inspector observed and/or reviewed selected surveillance and
maintenance activities to ensure that specific programmatic elements described below were
being met.
Details of this review are documented in the following sections.
4.2
Maintenance Observations
The inspector observed and/or reviewed selected maintenance activities to determine that the
work was conducted in accordance with approved procedures,
regulatory guides, Technical
Specifications, and industry codes or standards.
The following items were considered,
as
applicable, during this review: Limiting Conditions for Operation were met while
components or systems were removed from service; required administrative approvals were
obtained prior to initiating the work; activities were accomplished using approved procedures
and quality control hold points were established where required; functional testing was
performed prior to declaring the involved component(s) operable; activities were
accomplished by qualified personnel; radiological controls were implemented; fire protection
controls were implemented; and the equipment was verified to be properly returned to
service.
These observations and/or reviews included:
WA 15083, Test Equipment Installation for "D" Emergency Diesel Generator (EDG)
Emergency Service Water (ESW) Hydrostatic Test, dated January 25.
0
WA 24884, Core Spray Pump Minimum Flow Valve HV-152F013A Breaker
Maintenance,
dated January 27.
WA 23414, Install Sample Point and Sample Station for the "D" Emergency Diesel
Generator,
dated January 28.
WA 05401, HPCI Auxiliary Lube Oil Pump replacement,
dated February 4.
4.3
- Surveillance Observations
The inspector observed and/or reviewed the following surveillance test to determine that the
following criteria, ifapplicable to the specific test, were met:
the test conformed to
Technical Specification requirements;
administrative approvals and tagouts were obtained
before initiating the surveillance; testing was accomplished by qualified personnel in
accordance with an approved procedure;
test instrumentation was calibrated; Limiting
Conditions for Operations were met; test data was accurate and complete; removal and
restoration of the affected components
was properly accomplished;
test results met Technical
Specification and procedural requirements;
deficiencies noted were reviewed and
appropriately resolved; and the surveillance was completed at the required frequency.
SI-280-303,
18 Month Calibration of Reactor Vessel Water Level Channels LIS-B21-
2N031 A,B,C,D, dated February 9.
4.4
Inspection Findings
The inspector reviewed the listed surveillance activity. The review noted that work was
properly released before its commencement.
However, concerns arose on the licensee's
method of verifying compliance with Technical Specifications.
Section 4.4.1 pertains.
4.4.1
Reactor Water Level Surveillance Concerns
On February 8, during a routine control room walkdown, the inspector observed the
performance of 18 month calibration of the reactor water level-low-low-lowtrip channels
(Level 1) per surveillance procedure, SI-280-303.
The inspector noted that the Unit 2
Limiting Condition for Operation (LCO) log contained no entry for this surveillance activity.
Consequently,
the inspector questioned the unit supervisor (US).
The US indicated that a
Nuclear Department Administrative'rocedure (NDAP-QA-722, Step 6.7.1) allowed certain
safety-related instruments to be removed from service without being declared inoperable.
The inspector questioned the validity of this procedure step since SI-280-303 required
isolation of each trip channel in sequence.
The inspector noted that when the instrument is
isolated, it is no longer be capable of detecting an actual low reactor water level condition,
and would not perform its intended safety function.
-
Based on this discussion,
the US agreed that the instrument was inoperable and that the
procedure was poorly worded.
However, he stated it was the responsibility of the work
group to track the out-of-service times.
The inspector noted that the procedure suggested,
but did not require, the work group to monitor and control out-of-service times for the
individual channels;
and, did not recognize or address
the responsibility of licensed operators
to track the status of inoperable equipment in accordance with NDAP-QA-302, System Status
and Equipment Control.
NDAP-QA-302, Step 6.3.2 requires that shift supervision make
,LCO log entries whenever equipment is made or found to be inoperable.
The licensee did
not make the required LCO entries when the four Level
1 trip channels were intentionally
made inoperable per SI-280-303.
The inspector noted that this requirement could have been
accommodated
had the work group actually logged- and tracked the out-of-service times for
each channel.
On February
10, the inspector reviewed the completed surveillance on the Level
1 trip
switches (SI-280-303) and rioted that the work group did not track the times that the various
'instruments were taken out of and returned to service.
NDAP-QA-722, Step 6.7.4 only
suggests
that start and stop times be documented.
Technical Specification (TS) 3.3.3, Table
3.3.3-1, footnote (a) allows channels to be made inoperable for a period not exceeding two
hours without tripping the affected channel as long as the redundant channel in the same trip
system is operable.
For example, the "A" channel could be isolated and surveilled without
tripping Division 1 of the Reactor Protection System (RPS) as long as the "C" channel was
operable and capable of providing the necessary Division 1 safety functions on an actual low
level condition.
This would allow the surveillance to be completed without a half
scram'ignal
present,
thereby reducing the overall complexity of the surveillance,
However', such
action required the licensee to assure that the subject instr'uments were not out-of-service for
an excessive period without tripping the affected channel.
The inspector noted that the TS
action required initiating plant shutdown with less the minimum (2) channels operable.
The inspector noted that the tracking of out-of-service times, as practiced by the licensee,
was inadequate to assure compliance with the applicable Technical Specification.
Start and
stop times were not documented per NDAP-QA-722. The inspector noted that failure to
document specific start and stop times prevented monitoring and verification of the
acceptability of SI-280-303 relative to meeting the performance standard.
The inspector
determined that SI-280-303 commenced at 10:45 a.m., February 8, and ended at 8:50 a.m.,
February 9, a period of 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />.
The inspector determined that there was no other record
or system that provided assurance
that the out-of-service times were effectively monitored
and controlled.
Within the 22 hour2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> period, it is not known how long each individual channel
was actually out-of-service.
However, based on interviews with operators and Instrument
and Control personnel,
past practice indicates that individual channels are typically out-of-
service for no more than 30 minutes for this surveillance, and only one channel at a time is
actually affected.
Notwithstanding, the inability of the licensee to show compliance with TS 3.'3.3 is an
apparent violation of 10 CFR 50, Appendix B, Criterion V which requires that procedures
be
written to ensure that specific quantitative and qualitative information be provided to
demonstrate
satisfactory accomplishment.
In this case, the lack of a requirement to
specifically monitor and control out-of-service times for the reactor water level indicators
while in surveillance in accordance with TS 3.3.3, constitutes the bases for this apparent
violation. (VIO 50-388/93-01-01)
Upon identification by the inspector, the licensee took prompt actions to rectify this apparent
violation. The licensee immediately initiated action to track each individual instrument
channel's out-of-service time on the surveillance procedure cover sheet in the control room;
and required shift supervision approval prior to taking any instrumentation channel out-of-
service during the surveillance.
The licensee agreed
to=use this work practice for all future
surveillance that allowed making a channel inoperable without tripping.
5.
5.1
Inspection Activity
The inspector reviewed licensee event notifications and reporting requirements for events that
could have required entry into the emergency plan.
5.2
Inspection Findings
No events were identified that required emergency plan entry. No inadequacies
were
identified.
6.
SECURITY
6.1
Inspection Activity
PP&L's implementation of the physical security program was verified on'a periodic basis,
including the adequacy of staffing, entry control, alarm stations, and physical boundaries.
These inspection activities were conducted in accordance with NRC inspection procedure
71707.
6.2
Inspection Findings
The inspector reviewed access
and egress controls throughout the period.'o unacceptable
conditions were noted.
7.
ENGINEERING/TECHNICALSUPPORT
7.1
Inspection Activity
The inspector periodically reviewed engineering and technical support activities during this
inspection period.
The on-site Nuclear Systems Engineering (NSE) organization, along with
Nuclear Technology (NPE) in Allentown, provided engineering resolution for problems
during the inspection period.
NSE generally addressed
the short term resolution of
engineering problems; and interfaced with the Nuclear Modifications organization to schedule
modifications and design changes,
as appropriate, to provide long term corrective action.
The inspector verified that problem resolutions were thorough and directed at preventing
recurrences.
In addition, the inspector reviewed short term actions to ensure that they
provided reasonable
assurance
that safe operation could be maintained.
7.2
Inspection Findings
7.2.1
Long Term Fuel Performance Monitoring - Unit 2
The licensee monitors fuel performance on an ongoing basis for both units.
On December
15, the licensee detected
a slightly elevated sample in the Unit 2 offgas pretreatment
stream.
Pretreatment activity increased from approximately 100 uci/sec to approximately 170 uci/sec.
Normally, this type of change might have been within the bounds of expected activities.
However, Unit 2 activity had been trending downward since starting up from the fifth
refueling outage on November 24 before itjumped on December
15.
As a result, the
licensee intensified their fuel performance monitoring.
The licensee determined that the most likely cause for the increased pretreatment activity was
a pinhole leak in a once-burned fuel assembly.
They concluded this based on the existing
Cs-134 to Cs-137 ratios which also ruled out either new fuel or highly exposed reinserted
fuel (fuel used to support their exposure extension program).
On January 30, the licensee began shut down of Unit 2 and observed no unexpected
changes
in offgas pretreatment levels.
A sample taken on the subsequent
startup on February 7
confirmed the continued presence of the leak, and subsequent
pretreatment
samples indicated
the leak did not worsen.
The licensee willcontinue to monitor this minor leak and expects some continued degradation
due to secondary hydriding.
Detailed procedures exist that identify specific action levels
relative to any increase in offgas activity. These procedures provide a graded response
commensurate
with the actual activity level.
The inspector questioned the licensee in detail on their actions in response to this extremely
small fuel leak.
The inspector noted that the actual activity of approximately 170 uci/sec is a
small fraction of the 3000 uci/sec seen during a previous leak.
He also noted the licensee's
10
monitoring program was conservative and comprehensive.
In response to inspector
questioning, the licensee initiated a SOOR to track this activity until the leaky bundle is
identified during the next refueling outage.
The fuel vendor has been contacted and has
agreed to identify the leaker by using fuel sipping.
The inspector found the licensee's
response
to this issue to be effective and thorough.
ll
7.2.2
Excessive Hying Stresses During High Energy Line Breaks
The licensee identified the potential for excessive piping stresses
during a postulated High
Energy Line Break (HELB). 'As part of their Design Basis Documentation (DBD), the
licensee reviewed the ability of certain pipe supports to limitpipe stresses
to acceptable
valves during a HELB. They determined that the pipe break analysis model for the Reactor
Water Cleanup (RWCU) system may have been non-conservative;
Specifically, the RWCU
outboard containment isolation (F004) valve was assumed to have been confined by a vertical
restraint (PR 97Aa) when in actuality it was installed on a 45 degree angle.
The installed
angle introduced a new force component that was unaccounted for in the original analysis.
As a result, the licensee issued Engineering Discrepancy Report (EDR) G30007 to resolve
this concern.
The licensee contacted Bechtel on January 27 to rerun the original piping analysis with the
installed configuration.
Bechtel obtained the original computer model and a version of the
ANSYS program used for the original model on January 29.
The model was benchm'arked
on January 31.
The proper restraint configuration was installed in the model and study runs
were conducted.
The study runs were completed on February 6 and showed that the stress
levels on the piping were acceptable.
If
The inspector monitored the licensee's actions in this specific area throughout the inspection
period, and reviewed apparent changes relative to the original design assumptions.
Such
changes included the accommodation of the 45;degree pipe restraint, and the proper
-.
accounting of frictional forces that would be applied to the pipe elbow after impact with the
restraint during the postulated HELB. The inspector concluded that these minor adjustments
were appropriate and did not appear to exceed the regulatory bounds of the original analysis.
The inspector had no further questions on this issue.
8.
SAFETY ASSESSMFAT/QUALITYVEIUPICATION
8.1
Licensee Event Reports
The inspector reviewed LERs to verify that details of the event were clearly reported,
including the accuracy of the description of the'cause
and the adequacy of corrective action,
The inspector determined whether further information was required from the licensee,
whether generic implications were involved, and whether the event warranted onsite
followup. The following LERs were reviewed:
11
Unit 1
92-010-00
"Offgas Guard Bed "B" Experienced Elevated Temperatures"
On June 13, 1992 with Unit 1 in Condition 2 at 2% power, the "1B" guard bed experienced
a temperature excursion'fter purging the guard bed with heated air and during an air purge
of the Unit 1 offgas,recombiner.
The licensee determined that the condition was not
reportable, but submitted a voluntary LER to provide information to the NRC. The inspector
agreed with the licensee's reportability analysis.
NRC Inspection Report 50-387/92-16
reviewed this event.
The LER was acceptable,
92-014-00
Manufacturer's Installation and Operations Manual: Required Incorrect
'O'ing Lubricants for, Solenoid Valves
On September 9, 1992 during an evaluation of NRC Generic Letter 91-15, PP&L engineers
became aware that station circle seal solenoid valves (SOV's) could be susceptible to
deterioration of their '0'ings.
The concern was due to the incompatibility of hydrocarbons
(petroleum jelly) with ethylene propylene elastomers
(o-rings).
Circle Seal installation and
operations manual (IOM) recommend
use of petroleum jelly. Although the licensee
determined the event was not reportable,
a voluntary LER was submitted to provide
information to the NRC.
The inspector agreed with the licensee's reportability
determination,
NRC Inspection Report 50-387/92-22 reviewed this event,
The LER was
acceptable.
Unit 2
93-001-00
Momentary Loss of 120 VAC Instrument Power Resulted in Invalid ESF
Actuations
At 6:25 a.m. on January
14, 1993, with Unit 2 in Condition
1 at 100% power,.the alarm for
Instrument AC Panel 2Y226 Power Failure was received in the control room.
Invalid
Engineered Safety Feature (ESF) actuations occurred as containment isolations of the Reactor
Water Cleanup System, "B" Loop of Containment Atmosphere Control and Drywell Floor
Drain Sump lines.
The cause for the initial Instrument AC Panel 2Y226 Power Failure
alarm and the momentary voltage dip to the subject loads on Panel 2Y226 which resulted in
the invalid ESF actuations was attributed to failure of a rectifier on the Loss of Voltage
Relay located in Panel 2Y226.
The licensee considered the failure to be an isolated
occurrence.
System response to the momentary voltage dip of the 120 VAC power was per
design.
Per 10 CFR 50.73, invalid ESF actuations of the RWCU system are exempt from the ESF
reporting requirement.
However, invalid ESF actuations of the CAC and Reactor Building
Drain Sump isolation valves are not exempt from the ESF reporting criteria.
The LER was acceptable.
12
8.2
Open Items
(Update) VIO 50-387/92-23-01, Inadequate Inspection of Kaowool Fire Wrap
In Inspection Report 50-387/92-23, the inspector identified that the licensee did not inspect
Kaowool fire wrap as required by Technical Specification (TS) 3.7.7.
This conclusion was
reached after questioning mechanical maintenance personnel that performed the most recent
surveillance inspection.
They indicated that they only inspected Thermo-Lag and did not
inspect any Kaowool fire wrap.
This provided the basis for this apparent violation.
On January
19, during the fire protection enforcement conference,
the licensee disputed the
duration of this violation. They stated that Kaowool had been inspected per TS 3.7.7 from
initial licensing until December
1989 when a procedure change obscured the need for
continued Kaowool inspections.
The previous procedure methodology (pre-1990) identified
the fire wrap to be inspected by location (elevation and plant area) and by raceway number.
These raceways included both Thermo-Lag and Kaowool. The new methodology only
identified fire wrap locations and not raceways.
The briefings and training conducted by the
licensee were inadequate to cope with this new, limited procedural guidance.
Thus, only the
most recent inspections inadvertently omitted Kaowool.
On January 20 and 21, the inspector verified that the pre-1990'procedures
did include
Kaowool on the listings of fire wrap to be inspected.
In addition, the inspector sampled
certain in plant locations using the old procedure and verified that Kaowool did exist at these
locations.
A review of three pre-1990 inspections showed that licensee personnel inspected
raceways containing Kaowool.
Based on the above, the inspector concurred with the licensee
assertion on the violation duration.
The last valid Kaowool inspection preceded
the
procedure changes
made in December
1989, and it appeared
that removing the raceway
identifiers contributed to this apparent violation. The licensee is still in the process of
finalizing their corrective action.
This item is updated.
9.
MANAGEMENTAND EXITMEETINGS
9.1
Resident Exit and Periodic Meetings
The inspector discussed
the findings of this inspection with station management
throughout
and at the conclusion of the inspection period.
Based on NRC Region I review of this report
and discussions
held with licensee representatives,
it was determined that this report does not
contain information subject to 10 CFR 2.790 restrictions.
13
9.2
Inspections Conducted By Region Based Inspectors
1/12-1/13
Immhan
~Rp~~
93-02
~In p~r
H. Williams
14
ATI'ACHMENT 1
A rv>> nLi
ANSI
CFR
CIG
DX
ERT
IERP
Jlo
LCO
LER
NPE
NQA
NRC
NSE
- Administrative Procedure
- Automatic Depressurization
System
- American Nuclear Standards Institute
- American Society of Mechanical Engineers
- Containment Atmosphere Control
- Code of Federal Regulations
- Containment Instrument Gas
- Control Rod Drive Mechanism
- Control Room Emergency Outside Air Supply System
- Diesel Generator
- Direct Expansion
- Emergency Core Cooling System
- Engineering Discrepancy Report
- Electrical Protection Assembly
- Environmental Qualification
- Event Review Team
- Engineered Safety Features
- Emergency Service Water
- Engineering Work Request
- Fuel Oil
- Final Safety Analysis Report
- Heating, Ventilation, and Air Conditioning
- Industry Event Review Program
- Instrumentation and Control
- Justifications for Interim Operation
- Limiting Condition for Operation
- Licensee Event Report
- Local Leak Rate Test
- Loss of Coolant Accident
- Non Conformance Report
- Nuclear Department Instruction
- Nuclear Plant Engineering
- Nuclear Plant Operator
- Nuclear Quality Assurance
- Nuclear Regulatory Commission
- Nuclear Systems Engineering
15
PC
PMR
PSID
'RWCU
SOOR
SPING
TS
WA
Open Item
Out-of-Service
Protective Clothing
Primary Containment Isolation System
Plant Modification Request
Plant Operations Review Committee
Pounds Per Square Inch Differential
Quality Assurance
Reactor Building
Reactor Building Closed Cooling Water
Reactor Core Isolation Cooling
Regulatory Guide
Residual Heat Removal Service Water
Surveillance Procedure,
Instrumentation and Control
Surveillance Procedure,
Operations
Significant Operating Occurrence Report
Safety Parameter Display System
Sample Particulate, Iodine, and Noble Gas
Technical Specifications
Work Authorization