ML17158A870
| ML17158A870 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 08/29/1995 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17158A868 | List: |
| References | |
| 50-387-95-17, 50-388-95-17, NUDOCS 9509060251 | |
| Download: ML17158A870 (29) | |
See also: IR 05000387/1995017
Text
Inspection
Report Nos.
License
Nos.
Licensee:
Facility Name:
Inspection At:
Inspection
Conducted:
Inspectors:
UNITED STATES
NUCLEAR REGULATORY CONNISSION
REGION I
50-387/95-17;
50-388/95-17
Power
and Light Company
2 North Ninth Street
Allentown, Pennsylvania
18101
Susquehanna
Steam Electric Station
Salem Township,
July 5,
1995
August 5,
1995
N. Banerjee,
Senior Resident
Inspector,
B. NcDermott, Resident
Inspector,
N. Blumberg, Project Engineer,
Approved By:
C.
erson,
C >e
Reactor Projects
Section
2B
841 f~
ate
95090602Sl
950829
ADOCK 05000387
Q
EXECUTIVE SUMMARY
Operations
Susquehanna
Inspection
Reports
50-387/95-17;
50-388/95-17
July 5,
1995
August 5,
1995
Alert and cognizant control
room operators
operated
both units in a safe
manner with shift supervision
providing good oversight (Section
2. 1).
Maintenance/Surveil'lance
In preparation for the Unit 2 7'" refueling outage,
new fuel inspection
activities were conducted
in a safe
manner with good supervision
and
engineering oversight (Section 3.3).
Engineering/Technical
Support
PP&L's evaluation of the visqueen
sheet retrieved
from the suppression
pool
during the Unit
1 outage provided
a reasonable
assessment
of its potential
impact on the Reactor
Core Isolation Cooling (RCIC) suction strainers
and gave
appropriate consideration to the potential for its transport to other areas
of
the suppression
pool
under dynamic conditions.
The evaluation
concluded that
RCIC operability was not impacted during previous operating cycles with the
visqueen
sheet in the pool Section
(Section 4. 1).
Plant Support
An unannounced,
after hour emergency
plan call-out exercise
revealed
problems
with PP&L's call-.out procedure
and the tele-notification system.
Although the
licensee's ability to respond in case of an actual
emergency
was maintained,
PP&L took the necessary
corrective actions
and re-performed the call-out
exercise with much improved results
(Section 5.3).
Safety Assessment/equality
Verification
During the Unit
1 refueling outage,
Operations
management
s decision not to
enter the Technical Specification
(TS) action called out by an emergency
diesel
generator test procedure is
a violation.
The safety significance of
the incident was minimal, and this action reflected operations
management's
poor judgement,
and
was not willful.
However, this violation is being cited,
because
the decision not to enter the required
TS action
was
made
by a highet
level
management
personnel,
and
a previous
Licensee
Event Report in 1994
discussed
the need to enter the TS action during the subject testing.
Plant
management
has
counseled
operations
management
and reinforced the need to
comply with plant TS.
(Section
6. 1).
A total of nine
LERs and one unresolved
item were reviewed
and closed
based
on
the inspectors
assessment
of the licensee's
corrective actions.
EXECUTIVE SUNNARY .
TABLE OF CONTENTS
.
TABLE OF CONTENTS
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~ll
1.
SUNNARY OF FACILITY ACTIVITIES
2.
3.
PLANT OPERATIONS
2. 1
Plant Operations
Review ..
2.2
Use of Overtime
.
NAINTENANCE AND SURVEILLANCE
3. 1
Naintenance
Observations
3.2
Preventive
Naintenance of Core Spray
3.3
New Fuel Receipt Inspection
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Pump Notor
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4.
ENGINEERING
.
4.1
Evaluation Of Potential
RCIC Suction Stra incr
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Blocka
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5.
PLANT SUPPORT
.
5. 1
Radiological
and Chemistry Controls
.
5.2
Security
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5.3
Unannounced 'Off-Hour Exercise
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5
5
5
5
6.
SAFETY ASSESSNENT/EQUALITY VERIFICATION
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6. 1
Licensee
Event Report Review
6.2
Open Item Followup
6.3
10 CFR Part 21 Reports
7.
NANAGENENT AND EXIT NEETINGS
7. 1
Resident Exit and Periodic Neetings
.
7.2
Other
NRC Activities
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6
11
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DETAILS
1.
SUNNARY OF FACILITY ACTIVITIES
Susquehanna
Unit 1 Suamary
Unit
1 was operated
at or near full rated thermal
power throughout this
inspection period.
minor power reductions
were made to support main turbine
valve testing, control rod pattern adjustment,
and to reduce
condenser
backpressure
resulting from extreme hot and humid weather.
Susquehanna
Unit 2 Summary
Unit 2 remained at power throughout the inspection period, with routine power
reductions for turbine valve testing
and control rod pattern adjustments.
Also, minor power reductions
were required to reduce
condenser
backpressure
on
several
unusually hot days.
On Friday July 21,
power was reduced to 58% for
planned maintenance
on the 'B'eactor recirculation motor-generator
set'nd
cleaning of the 'B'ain condenser
water box.
As of Sunday July 23,
power was
returned to 100%.
2.
PLANT OPERATIONS (71707,
92901,
93702)'.1
Plant Operations
Review
The inspectors routinely observed
the conduct of plant operations to verify
independently that the licensee
operated
the plant safely
and according to
station procedures
and regulatory requirements.
Control
room indications
and plant systems
were observed
independently
by NRC
inspectors
to verify that plant conditions were in compliance with station
operating
procedures
and Technical Specifications
(TS).
Control
room alarms
and bypass indication system
(BIS) warnings were routinely reviewed
and
discussed
with operators;
Operators
were cognizant of control
board
indications
and plant conditions.
Control
room and shift manning were in
accordance
with TS requirements..
The inspectors
conducted regular tours of the various plant areas
and
periodically reviewed logs
and records to ensure
compliance with station
procedures,
to determine if entries
were correctly made,
and to verify correct
communication of equipment status.
These records
included various operating
logs, turnover sheets,
blocking permits,
and bypass
logs.
The inspector
observed
plant housekeeping
controls including control
and storage of
flammable material
and other potential safety hazards.
Posting
and control of
radiation,
high
r adiation,
and contamination
areas
were appropriate.
\\
The inspectors
performed backshift
and deep backshift inspections
during the
period.
The deep backshift inspections
covered licensee activities between
10:00 p.m.
and 6:00 a.m.
on weekdays,
weekends,
and holidays.
The
inspection
procedure
from
NRC
manual
Chapter
2515
that
the
inspector
used
as guidance is parenthetically listed for each report section.
Based
on routine observations
in the Unit
1 and
2 control
room, the inspectors
concluded that alert
and cognizant operating
crews
had operated
the plant in a
safe manner following plant procedures,
with shift supervision providing good
oversight.
Plant housekeeping
was found acceptable.
2.2
Use of Overtime
The inspector
reviewed the licensee's
use of overtime by the unit staff who
perform safety-related
functions during the recently completed Unit
1 8'"
refueling outage.
The inspector
noted that in one case,
a Nuclear Systems
Engineer
had worked in excess
of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> time period.
The plant
technical specification section 6.2.2 limits the overtime to 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48
hour period for unit staff who perform safety related function.
Upon
inspector's
questions,
the licensee clarified that this engineer's
use of
overtime did not involve jobs directly related to a nuclear safety function
(i.e., performing as
a test director for test of safety-related
equipment).
However, the licensee
prepared
a deviation form to document this overtime use.
Based
on
a sample review, the inspector
concluded the use of overtime during
the Unit
1 outage
was consistent with the requirements
of the plant Technical
Specification
(Section 6.2.2)
and licensee's
procedure
NDAP-00-650,
Conduct of
Site Support.
3.
MAINTENANCE AND SURVEILLANCE (62703,
61726,
92902)
3.1
Maintenance
Observations
The inspector
observed
and/or reviewed selected
maintenance activities to
evaluate
whether 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 imple-
mented;
and the equipment
was verified to be properly returned to service.
Maintenance
observations
and/or reviews included:
WA S15337,
Perform
5 Year
Pump Inspection,
August 3,
1995.
WA P45409; Unit 2 Core Spray
Pump 'B'ow Flow Check Valve Inspection,
August 1,
1995.
WA S50884,
Unit
1 'A'ain Transformer
Fan Cleaning, July 19,
1995.
WA P51032,
Negger
and Polarization Testing of the reactor
Pump 'D'otor, July 31,
1995.
Based
on sample inspection of the above maintenance,
the inspector
concluded
that the work was conducted
and completed appropriately,
with due concern for
plant safety
and procedures.
3.2
Preventive
Maintenance of Core Spray
Pump Motor
On July 31,
1995, the inspector
observed
WA P51032,
and Polarization
Testing of the reactor
Pump 'D'otor.
This test is an
18 month
periodic preventive maintenance
test performed for each core spray
pump.
The
inspector
observed
the test equipment readings
and noted that the test data
met acceptance criteria.
The test meter
was in calibration,
and
a quality
control
(gC) inspector witnessed
the test
as part of a
gC sampling'process
for
work on safety-related
equipment.
At the conclusion of the test, the
inspector
accompanied
the electrical
maintenance
supervisor in the clearing of
the tags,
the work authorization
(WA) documents,
and the equipment release
form (ERF).
The inspector
noted that the
WA and the tagging authorizations
are established
and cleared electronically.
The
ERF was cleared manually in
the control
room.
The overall maintenance activity was performed
satisfactorily.
3.3
New Fuel Receipt Inspection
On July 26,
1995, the inspector
observed
new fuel receipt inspection
activities
on the refueling floor in support of the upcoming Unit 2 refueling
outage.
The inspector
noted activities were performed following procedure
OP-
ORF-002,
New Fuel Receipt
and Inspection Activities, prerequisites
were
appropriately
checked,
good oversight of activities was performed
by the
Reactor
Engineer,
Maintenance
Supervisor
and the fuel vender representative.
The inspection
forms were duly completed,
and the operability of'ew fuel
vault criticality monitors were verified.
The inspector
concluded the
licensee
was performing the activity in an acceptable
manner with good
procedure
compliance
and supervision.
4.
ENGINEERING (71707,
37551,
92903)
4.1
Evaluation Of Potential
RCIC Suction Strainer Blockage
The Unit
1 suppression
pool inspection,
conducted during the Unit's 8'"
refueling outage,,
was to confirm the absence
of debris that could clog
emergency
core cooling system suction strainers.
During the inspection,
the
diver retrieved
a sheet of visqueen
(approximately 5'
5') found hanging from
the lower RCIC suction strainer bolts.
Condition Report
(CR)95-150 was
initiated to document this finding.
In the past,
visqueen
was
used to prevent
accidentally dropping debris into the suppression
pool,
and
has not been
used
after the 6th Unit
1 refueling outage.
Since
1989, the licensee
had
documented
debris that fell into the suppression
pool.
The licensee's
program
for foreign material
exclusion controls,
and suppression
pool inspection
were
reviewed in NRC combined inspection reports
50-387/94-22;
50-388/94-23
and 50-
387;388/95-08.
The
RCIC suppression
pool suction consists
of upper
and lower cone strainers
mounted vertically to
a "T" pipe, with each strainer
having
100% capacity.
Based
on the location of the visqueen, it was postulated that the
RCIC pump
suction could draw the visqueen'nto
the strainers
and block their flow.
At
the time of discovery,
the Technical Specifications
(TS) did not require
to be operable
and the
CR did not address
system operability.
The visqueen
was
removed
from the suppression
pool
and
an evaluation for CR 95-150 was
subsequently
performed
by Nuclear Systems
Engineering.
The safety assessment
concluded that "...RCIC would have probably been able to perform its design
function with suction from the pool."
After reviewing this
CR evaluation,
the
inspectors
noted that it did not provide any detailed evaluation of the
visqueen's
potential
impact and that it's conclusion
was not definitive.
The
issue
was left as
an unresolved
item (URI 95-08-02)
pending the licensee's
documentation
and approval of an operability evaluation which addressed
the
ability of RCIC to perform its specified function.
A supplemental
operability. evaluation for CR 95-150 was written to address
the
potential
impact of the visqueen
on the
RCIC suction flowpath during previous
plant operation
when the system
was required to be operable.
This evaluation
compared
the as-found
geometry of the visqueen
sheet to the physical
configuration of the suction strainers
and associated
piping.
The licensee
concluded that the visqueen, if it had remained at the as-found location,
could have blocked
one of the strainers,
but would not have
had sufficient
additional material to block the remaining
100% capacity strainer.
The
analysis
also addressed
postulated
dislodging of the visqueen
sheet during a
LOCA and the potential for its impacting the
ECCS suction strainers.
In these
scenarios,
multiple strainers for redundant
ECCS loops are available to assure
reliability of the suppression
pool cooling water source.
Adequate
capability would be maintained
assuming the visqueen
sheet
was transported to,
and blocked,
one
ECCS strainer.
The inspectors
reviewed the licensee's
documented
evaluation,
viewed
a video
tape of the diver's inspection,
and discussed
the issue with the responsible
system engineer.
The licensee's
evaluation provided
a reasonable
assessment
of the potential effects of the visqueen in the location it was found and gave
appropriate
consideration to the potential for transport to other areas of the
suppression
pool under dynamic conditions.
The inspectors
noted that the licensee's
addressed
whether
TS required
but it did not address
the
system's ability to perform its intended function.
The subsequent
evaluation
by Nuclear System Engineering
di.d address
the function of RCIC but failed to
include any detailed evaluation of the visqueen sheet's
potential
impact or
a
definitive conclusion regarding operability.
The inspector considered
these
problems
a weakness
in the implementation of the
CR process
and operability
determination
procedure.
However, the inspector
concluded that the
supplemental
operability evaluation for CR 95-150 adequately
addressed
the
impact of the visqueen
sheet
on the operability of RCIC and
ECCS systems
during previous operating cycles.
This review closes
URI 95-08-02
(see
Section 6.2).
5
5.
PLANT SUPPORT (71750,
71707,
92904)
5.1
Radiological
and Chemistry Controls
During routine tours of both units, the inspectors
observed
the implementation
of selected
portions of PP&L's radiological controls
program to ensure:
the
utilization and compliance with radiological work permits
(RWPs); detailed
descriptions of radiological conditions;
and personnel
adherence
to
requirements.
The inspectors
observed
adequate
controls of access
to various
radiologically controlled areas
and use of personnel
monitors
and frisking
methods
upon exit from these
areas.
Posting
and control of radiation
areas,
contaminated
areas
and hot spots,
and labelling and control of containers
holding radioactive materials
were verified to be in accordance
with PP&L
procedures.
Health Physics technician control
and monitoring of these
activities was satisfactory.
Overall, .the inspector
observed
an acceptable
level of performance
and implementation of the radiological controls program.
5.2
Security (71707)
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.
The inspector
reviewed
access
and egr ess
controls, throughout the period.'o deficiencies
were found.
5.3
Unannounced
Off-Hour Exercise
During an unannounced,
after hour,
emergency
plan call-out exercise
on July
20,
1995, completion of off-site notification,
and the simulated
manning of ,
the emergency
response facilities took longer than expected.
The problem
involved delays in activating the beeper s,
as well" as, difficulties
experienced
by the
r esponders
in their ability to call-back through the tele-
notification system that was overloaded.
This resulted in the on-call
Emergency Director
(ED),
among others,
not being able to respond to tele-
notification.
The drill required the responders
to call-back to the tele-
notification system
and confirm their fitness for duty and provide an
estimated arrival time.
The drill scope did not require the responders
to
physically respond to their assigned
duty stations.
It was also noted that
completion of'otification to Luzerne County, took longer than
15 minutes;
and
several
responders
stopped their attempted call-in, after
a few attempts,
when
they found the tele-notification system to be jammed.
The licensee
performed
a review to determine root causes
and needed corrective
actions.
The licensee
concluded that although substantial
delay occurr ed in
the tele-notification process,
in case of a real event, timely manning of the
facilities would have happened.
The on-call
ED could not respond
back to the
tele-notification system but
a back up
ED personnel
was available
and in
contact with the plant.
The tele-notification system call-out sequence
was
noted
as
a major root cause of its overloading problem.
A problem was also
identified with the Luzerne County telephone,
which was corrected.
To correct the tele-notification system weakness,
the licensee
implemented
several
changes.
To facilitate manning of the emergency
response facilities,
the control
room communicator flow chart
was revised to require notification
to security, for initiation of the tele-notification system, prior to the
notification of the off-site agencies.
To prevent overloading of the
tele-notification system,
the call-out sequence
was revised to activate first
the Technical
Support Center
(TSC)
and the Interim Emergency Operations
Facility (IEOF),
and then the
EOF as required.
Also, the call-out priority
setting
was revised to include clerical positions at the very end of the call-
out.
A memo from the
EP manager clarified the response
procedure in case
problems are experienced
by the responders
while calling into the system.
With the above
changes
in place,
the licensee
ran another off-hour
tele-notification system call-out on July 26,
1995.
The changes
were
effective,
and improved response
was noted.
,Further refinement of the call-
out process
is being considered.
As the call-out drills did not exercise
physical
manning of the emergency
response facilities, another off-hour
unannounced dril.l to demonstrate this ability is being considered.
The inspector
r eviewed the July 20,
1995 and July 26,
1995 drill call-out
time-lines, the revised control
room communicator flow chart,
and hot box
material
provided to the control
room operators that described
the changes
made to the call-out sequence.
The inspector
observed
a shift supervisor
instructing his shift about the hot box material.
The inspector also reviewed
the July 26,
1995 remedial drill critique,
and discussed
the issues with the
emergency
planning personnel.
The inspector
concluded the changes
made to the
,call-out process
were timely and effective.
Licensee
management
provided
appropriate
emphasis
on understanding
and correcting the problem.
6.
SAFETY ASSESSNENT/EQUALITY VERIFICATION (92700)
6.1
Licensee
Event Report Review
The inspector
reviewed Licensee
Event Reports
(LERs) submitted to the
NRC
office 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
considered
whether further information was required
from the licensee,
and whether generic implications were involved.
The following LERs were reviewed,
and the inspectors
concluded the licensee
met the reporting requirement,
LERs provided the needed
information,
and the
licensee's
corrective actions
were considered
adequate:
Unit 1
95-003-00
Unit 1 Shutdown
Due To Check Valve Surveillance Failure
On Narch 25,
1995, Unit
1 was shutdown from 100% power due to a failure of a
reactor
instrument line excess
flow check valve.
During the test,
the valve
failed to exhibit a significant decrease
in flow at the point of draining.
Excess
flow check valve testing is done just prior to unit shutdown for
refueling.
The
LCO was met since the unit was subsequently
shutdown for the
refueling outage.
During the outage, it was determined that the valve could
not be repaired;
and it was replaced.
The cause of'he failure has not yet
been determined;
however,
the valve has
been sent to the licensee's
laboratory
for analysis.
The licensee
determined that there were no generic
implications,
and the history of excess
flow check valves in the plant
indicates
a low probability for this type of failure.
95-005-00
Nissed Surveillance Test For 'D'mergency Diesel Generator
(EDG):
On Narch 29,
1995, during the Unit
1 Eighth Refueling Outage,
an engineering
review of past
emergency diesel
generator testing noted that
a hot restart
capability test of the 'D'DG had not been performed during the Unit 2 Fifth
refuelling outage
(September-November
1992).
The test
was subsequently
performed successfully
on January
2,
1994, during the Unit .1 Seventh
Refuelling Outage.
The apparent
cause
was that
a system test director
misunderstood
the test procedure requisite
and
assumed that
a hot restart test
performed
on the 'E'DG in Narch
1992 (during
a time period when the 'E'DG
was substituting for the 'D'DG) could be credited for the 'D'est.
Although the licensee
has
an automated surveillance authorization
(SA) system,
a procedural
misinterpretation still allowed the test to be overlooked.
18
month surveillance testing procedures
for the
EDGs have all been
changed to
clarify when the hot restart test must
be done.
This incident appears
to be
an isolated
occurrence
which was caused,
in part,
by the fact that the 'E'DG
can
be substituted for any of the other
EDGs.
The computer
generated
system would normally preclude missing
a scheduled
surveillance.
This
incident of technical specification non-compliance
met the criterion,of
Section VII.B.1 in 10 CFR Part 2, Appendix C,
and is not being cited.
95-006-00
Result of Local Leak Rate Test of a Nain Steam Line Penetration
Exceeds Limit
On April 1,
1995, during the Unit
1 Eighth Refuelling Outage,
line (NSL) penetration
local leak rate test through both the inboard
and
outboard main steam isolation valves
(NSIVs), indicated that the leakage of 53
standard
cubic feet per hour
(SCFH) exceeded
the required total
NSL
containment penetration
leakage of 46 SCFH.
The exact cause of the leakage of
,the valves
was not known; but the leakage
was apparently
caused
by some
corrosion
on the valve seats.
Stroking of the 'A', 'C'nd 'D'nboard
NSIVs
and the 'D'utboard
NSIV significantly reduced the leakage rate to 21
SCFH.
There have
been past incidents of NSIV leakage,
but the leakage did not affect
the integrated
containment
leak rate test.
The licensee
has submitted
a Technical Specification
change to raise the
leakage limits to 100
SCFH for any one NSIV and to 300
SCFH for all NSIVs
combined.
This request is currently undet
review by the
NRC.
Based
on the
licensee's
analysis
for offsite and control
room dose,
the leakage
was of low
safety significance.
If Technical Specification is approved,
the current
"as
found" leakage during tests
should normally be below the required limits.
(Post inspection note: the
NRC,
on August 18,
1995,
approved this technical
specification change).
e.
8
95-007-00
Unplanned
Due to Spurious Instrumentation
Upscale Signal
This
LER documents initiation of a scram signal during the recently completed
Unit I refueling outage,
while the
RPS was in the non-coincident trip mode,
due to spupious
intermediate
range neutron monitor (IRN) upscale signals.
During the time, control
room operators
were performing control rod stroke
'time and friction testing,
and in accordance
with the plant procedure shorting
links were removed to initiate a full scram signal
from the trip of any one of
the two RPS channels.
Spurious signal spiking of the
IRNs has
been
observed
on numerous
occasions
during refueling outages
when neutron flux levels are low and the
IRNs were at
their lower ranges.
At these
ranges
instrumentation is more susceptible
to
noise
due to high system gain.
The licensee
conducted
an investigation to
identify the source of the noise,
but a source
was not identified.
However,
one of the two IRNs associated
with the event
had
a lower than desirable
detector resistance
to ground,
and the licensee
believed that had contributed
to the event.
The licensee
plans to replace the degraded
detector during the
next refueling outage.
The licensee is also evaluating the requirement of
removing the shorting links to support control rod testing
and intends to
pursue it as
a part of their technical specification
improvement.
The inspector
concluded the safety significance of the event
was minimal.
95-008-00
Unplanned
ESF Actuation 'B'mergency Diesel Generator
Automatic
Start
On April 27,
1995,
an unplanned
automatic start of the 'B'mergency Diesel
Generator
(EDG) occurred
due to physical
bumping of a
125V DC circuit breaker.
The circuit breaker,
located, inside the diesel
generator
control
panel
was
found in the open position.
Due to the loss of the
125Y
DC control circuit,
, although it started,
the 'B'DG would not have properly loaded
had it been
called
upon to do so.
The other three
The breaker
was
subsequently
reclosed,
and the
EDG successfully tested.
The breaker
was
replaced with a breaker
from the
same manufacturer/model
number.
The licensee
plans to test the removed breaker at
a future date.
The licensee
indicated the breakers,
provided by Heineman,
are not used in any
other safety-related
applications in the plant.
The licensee
considered
the
incident isolated
and their review with the Cooper
Bessemer
Owners
Group did
not identify any generic concern with the breaker.
Regarding physical
bumping
of the breaker,
a task team at Susquehanna
is currently reviewing various
known incidents of human performance errors,
and developing
ways to improve
human performance.
Unit 2
95-001-00
Operation at Power with an Inoperable
Excore Neutron Flux Monitor
On January
30,
1995, while Unit 2 was at
100% power, the Excore Neutron Flux
Channel 'B'og power range indicator failed and
was reading upscale.
The
condition could not be corrected.
A notice of enforcement discretion
(NOED)
was obtained
from the
NRC on February 6,
1995, to allow continued plant
operation.
Operation in this condition was allowed until the next refueling
outage
scheduled to begin in September
1995.
Technical
issues
and licensee
actions
concerning this
LER were discussed
in NRC Inspection
Report 95-02.
95-002-00
Unplanned Engineering Safety Feature
(ESF) Actuation Due to
Operator Switching Error
On February 8,
1995, with Unit 2 at
100% power,
an unplanned
ESF actuation
occurred
when
a normally open primary containment isolation valve for the
Traversing Incore Probe
(TIP) Indexer automatically closed following the de-
energization of a
120 volt power supply circuit.
The cause of the problem was
operator error in that during
a routine work evolution
a blocking tag was
applied to a number
13 breaker
instead of the called for number
3 breaker
.
The error was discovered'bout
three
hours later by an electrician
who was
verifying electrical
blocking for a scheduled
maintenance activity.
Status indication of six pieces of equipment
was lost,
and
an
ESF actuation
occurred
when normally open primary containment isolation valve for TIP
Indexer automatically closed following de-energization
of the power supply.
There were no alarms in the Control
Room, but status indication for the valve,
which is located
on
a back panel,
was lost.
This loss of indication 'was not
noticed
by Control
Room operators
during
a shift turnover panel
walkdown.
Corrective action included retraining of nuclear plant operators
and control
room operators
on the weaknesses
that caused this event.
Regarding the
human
performance
aspect of the event,
a licensee task team is currently reviewing
the
human performance error events to develop comprehensive
corrective
actions.
95-006-00
Condition Prohibited by the Plant's Technical Specification
During the recently completed Unit
1 refueling outage,
the licensee
performed
an
18 month surveillance of the Emergency
Diesel
Generators
(EDG) and
Engineered
Safeguards
System
(ESS)
Buses
on Loss of Offsite Power with a
LOCA.
This test is performed
on each division of EDGs at
a time, thus affecting two
and two ESS buses.
During the testing, the auto-close
permissive relays
for the primary and feeder
breakers
to the subject
ESS buses
are de-energized,
and undervoltage start signals to the respective
EDGs are bypassed.
This
ensures verification of automatic start of the subject
EDGs upon
a
LOCA signal
and subsequent
sequential
loading of safety-related
equipment
on the
respective
ESS buses.
Since the
EDGs are shared
between the two units,
and
the Unit
1 buses
carry loads
common to both units, entry into a Unit 2
technical specification
(TS) limiting condition of operation
(LCO) is required
when any of these Unit
1
ESS buses
are not energized.
By virtue of removing
10
the main and alternate
feeder auto-closing features
from two of the Unit
1
ESS
buses,
these
buses
are considered
de-energized.
As the Unit 2 TS does not
address
de-energizing
two
ESS
buses
the test procedure specifies entry into
LCO 3.0.3 for Unit 2.
LCO 3.0.3 requires that within one hour actions
be
taken to enter hot shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
and cold shutdown in following 24
hours.
During Division I testing, the licensee
entered into
as it did
during the previous
performance of this
18 month surveillance.
But, during
Division II testing,
operations
management
made
a determination that such
an
entry was not required.
This decision
was contrary to the guidance
provided
in the licensee's
test procedure
and Technical Specification
(TS)
Interpretation
(TSI) document
No. 2-88-001.
Also, during the previous Unit
1
outage the licensee
determined that entry into
was necessary
during
performance of the subject test,
and
an
LER (94-001)
documented this entry.
The operations
management
was counseled
by plant management,
and is reviewing
the TSI 2-88-001 with the licensed
operators
regarding the need to enter
LCO 3.0.3 during performance of this test.
The licensee is currently preparing
a
TS change for submittal to the
NRC that will preclude
need for entry into
LCO 3.0.3 during the testing.
The
NRC inspector
was informed that,
pending
a TS
change, this
LCO will be entered
during future performance of the test.
The inspector
reviewed the
LER, the test procedure
steps
and
had discussions
with operations
management,
the test engineer
and the licensing engineers.
The inspector
concluded that the actual safety significance of not entering
was minimal,
as the respective
buses
were continually energized
during the test except for 10 seconds
from bus de-energization
to re-
energization
by the.EDGs.
As the main and al'ternate
feeder
breaker auto-
closure protective features
were
bypassed, if an
EDG failed to re-energize
the
bus,
manual
action would have
been necessary
to remove the bypasses
and
energize
the bus.
The test procedure
required positioning nuclear
plant
operators
at the breaker locations,
hence the needed
actions
can
be taken
promptly.
The inspector
concluded that the licensee's
decision not to enter
LCO 3.0.3 in this case
was
a violation of plant technical specifications.
This violation is being cited,
because
the decision
was
made
by a higher level
management
personnel,
and the need to enter the technical specification
required action during the subject testing
was previously identified by the
licensee,
as reflected in LER 94-001.
(VIO 50-388/95-17-01)
95-007-00
Local Leak Rate Testing Not Performed
on Two Electrical
Since Original Construction
On February 27,
1995, work planning reviews to support Unit 2 containment
(LLRT), identified that two electrical penetrations
used for the Excore Neutron Nonitoring System
had not been local leak rate
tested
since original construction in 1983.
The penetrations
had
been local
leak rate tested
during pre-operational
testing;
however,
through
an
oversight,
the need to leak rate test these penetrations
was not transferred
to licensee
documents.
0
11
As a corrective action, the licensee
reviewed all plans
and documents
and
performed
a walkdown of the containment penetrations
to ensure that
LLRTs have
been performed.
No further discrepancies
were found.
27 penetrations,
which
are located in inaccessible
or high radiation areas, will be visually verified
to be spare penetrations,
and
do not require
LLRT, during the upcoming Unit 2
Seventh Refuelling Outage starting, in September
1995.
In addition, the
licensee
performed
an
LLRT on the two penetrations
and both passed.
6.2
Open Item Followup
(Closed)
URI 50-387;388/95-08-02,
RCIC Suppression
Pool Suction Blockage
This unresolved
item is closed
based
on the inspector's
review documented
in
section 4. 1 of this report.
6.3.
10. CFR Part
21 Reports
Ethylene Glycol Fill Liquid in ITT Barton Differential Pressure
(D/P)
Indicators
and Differential Pressure
Indicating Switches
An ITT Barton Industry advisory dated
March 13,
1995, stated that for certain
Model
Gages filled with ethylene glycol, the ethylene glycol may disassociate
in radiation fields in excess of lE6 RADs.
The licensee
reviewed its environmental qualification (Eg) data
base for all
ITT Barton D/P switches regardless
of filling.
Only two D/P switches
were
found to have the potential for being exposed to fields in excess of lEG RADs.
These switches
are used for initial operation of the
HPCI system.
Based
on
a
review of the environmental profile of the areas
where these
switches
are
located,
the licensee
concluded. that the switches
would no longer
be needed
when the radiation fields ultimately exceeded
those in the advisory.
Based
on
this review, the licensee
determined that there is not
a problem at SSES.
The review by the licensee for this issue
was both prompt and comprehensive.
7.
MANAGEMENT AND EXIT MEETINGS (71707)
7.1
Resident Exit and Periodic Meetings
The inspector
discussed
the findings of this inspection with PPKL station
management
throughout the inspection period to ensure timely communication of
emerging concerns.
At the conclusion of the reporting period, the resident
inspection staff conducted
an exit meeting summarizing the preliminat y
findings of this inspection.
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'FR 2.790 restrictions.
7.2
Other
NRC Activities
The following region based
NRC inspection activities/management
visits took
place during this period:
Dates
12
~Re ort No.
Ins ection Procedure
Lead Ins ector
July 24 - 28
July 24 - 28
July
18 5 27
95-17
95-19
64704, Fire Protection
84750, Effluent
SALP Board Nembers Visit
Harrison
Jang
J'..
4