ML17333A406
| ML17333A406 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/28/1996 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17333A404 | List: |
| References | |
| 50-315-96-02, 50-315-96-2, 50-316-96-02, 50-316-96-2, NUDOCS 9604090050 | |
| Download: ML17333A406 (35) | |
See also: IR 05000315/1996002
Text
U.S.
NUCLEAR REGULATORY CONHISSION
REGION III
REPORT
NO.
50-315
96002
50-316
96002
FACILITY
Donald
C.
Cook Nuclear Generating
Plant
LICENSEE
Company
Donald
C.
Cook Nuclear
Generating
Plant
1 Riverside
Plaza
Columbus,
OH 43216
DATES
January
17,
1995 through February
26,
1996
INSPECTORS
B.
LE Bartlett, Senior Resident
Inspector
D. J.
Har tland, Resident
Inspector
C.
N. Orsini, Resident
Inspector
C. Osterholtz,
Operating
License
Examiner
APPROVED
BY
W. J.
K
pp
Chi f
Reactor Projects
Br anch
3
Da
AREAS INSPECTED
A routine,
unannounced
inspection of operations,
maintenance,
engineering,
preparation for refueling, plant support,
and review of UFSAR commitments
was
performed.
Safety assessment
and quality verification activities were
routinely evaluated.
Follow-up inspection
was also performed for non-routine
events.
9'604090050
960402
ADOCK 050003i5
8
Executive
Summar
OPERATIONS
Human performance
issues,
which were discussed
in previous inspection reports,
were again
observed
during this inspection period
as evidenced
by:
~
Auxiliary equipment operator tours met the minimum requirements
defined
in the licensee's
procedure.
However, there
appears
to be insufficient
time being spent to perform the
recommended
inspections
defined in the
procedures.
(Section l.I)
NRC IDENTIFIED
~
His-communication
among reactor operators
contributed to the overload
trip of a safety-related
valve.
Although no damage to the valve was
discovered,
the event resulted
in the licensee
being in a
TS
LCO for a
greater period of time.
(Section 2.5)
SELF-REVEALING
~
Licensed operators
did not adhere to procedural
requirements
with
regards
to auxiliary building integrity controls.
(Section 4.2)
NRC
IDENTIFIED NCV
MAINTENANCE AND SURVEILLANCE
The licensee's
root cause investigation
and operability determination of the
missing residual
heat
removal
system valve gasket
were good.
(Section 2.4)
SELF-REVEALING
The evolution involving the airline replacement of valve
2-HARV-301 was well-
planned
and coordinated.
(Section 2.6)
SELF-REVEALING
The licensee
continued to have problems with secondary
plant material
condition which resulted in two plant transients
during the inspection period.
(Section 1.2)
SELF-REVEALING
Two examples of TS surveillance activities were identified where safety-
related
equipment
was not tested
under suitably controlled conditions.
A
violation regarding similar these
was issued in a previous inspection report.
(Section 2.3)
NRC IDENTIFIED
~
The surveillance test for the turbine-driven auxiliary pumps required
the operability of steam traps to be checked prior to starting the
pumps.
The procedure did not require that
an operability evaluation of
the as-found condition
be performed if a malfunctioning steam trap was
discovered
and bypassed.
~
The licensee
occasionally lubricated
and exercised
fuel rack linkages
prior to performing
TS monthly emergency diesel
generator
surveillances.
Failure of electrical
maintenance
personnel
to comply with procedural
requirements
resulted
in the overload trip of a safety-related
valve.
Although no damage to'he valve was discovered,
the event resulted in the
licensee
being in a
TS
LCO for a greater period of time.
Concerns
regarding
adherence
to plant procedures
have
been discussed
in previous inspection
reports.
(Section 2.5)
SELF-REVEALING
ENGINEERING
The licensee installed
a tarp over
a portion of the Unit 2 refueling cavity
which was not in accordance
with a previously approved safety evaluation.
Concerns
regarding
weaknesses
in licensee
safety evaluations
have
been
discussed
in previous inspection reports.
(Section 3.1)
NRC IDENTIFIED NOV
The licensee
did not properly install the
new fuel vault criticality monitor
system to meet
requirements.
(Section 4.1)
NRC IDENTIFIED NOV
Concerns
were identified regarding foreign material exclusion control of new
and spent fuel.
Similar concerns
have
been discussed
in previous inspection
reports.
(Section 4.3)
NRC IDENTIFIED
PLANT SUPPORT
There
was excellent
dose performance
during the fall 1995 refueling outage
and
good planning for the spring
1996 refueling outage.
Collective dose during
1995 was low. (Section 5.0)
SAFETY ASSESSMENT
AND EQUALITY VERIFICATION
Licensee
personnel
exited
a Technical Specification
(TS) action statement for
intermediate
deck ice condenser
doors while plant conditions did not meet the
limiting condition for operation
(LCO).
A similar concern regarding
non-
conservative
interpretation of TSs was discussed
in a previous inspection
report.
(Section 2.2)
LICENSEE IDENTIFIED
The licensee
took appropriate
action to address
a
NRC concern regarding the
resetting of time in the
LCO action statement
on
a daily basis for performance
of an ice condenser
surveillance.
(Section 2.2)
NRC/LICENSEE IDENTIFIED
Some minor discrepancies
in the
UFSAR were identified. (Section 6.0)
NRC
IDENTIFIED
Summary of Open
Items
Violations:identified in Section 3.1
and 4. 1
Unresolved Items:identified in Section
4. 1
Ins ector Follow-u
Items:
identified in Section 6.0
Non-cited Violations: identified in Section 2.5 and 4.2
INSPECTION DETAILS
1.0,
OPERATIONS
NRC Inspection
Procedure
71707
was used in ongoing inspection of plant
operations.
The
NRC continue's
to have concerns with the quality of auxiliary
operator rounds,
human performance,
and procedural
adherence.
l. 1
Auxiliar
E ui ment
0 erator
AEO
Tours
Both Units
While the
AEO tours
met all licensee
and regulatory requirements,
the tours
were determined
by the
NRC to meet the minimum requirements
of the tour
procedure.
However, there appears
to be insufficient time being spent to
perform the recommended
inspections
defined in the procedures.
Previous information concerning
AEO tour completeness
and quality were
documented
in NRC Inspection
Reports
50-315/316-93019,
93024,
94002,
and
94014.
As documented
in report 315/316-94002
a licensee
internal audit had
identified that,
based
on the time the
AEOs spent performing tours in certain
rooms,
a complete
and thorough tour was generally not being performed.
As
part of the corrective action to a previous concern regarding
the quality of
AEO tours,
the licensee
issued
procedural
requirements
governing tour
performance.
This guidance required that
AEOs carry log sheets
to document
certain readings
and also that shift management
periodically accompany
the
AEOs during plant tours.
The
NRC accompanied
AEOs on tours
and determined that the required
rooms were
being entered
and the required information was being recorded.
However, the
operators
were not spending
a significant amount of time observing the
recommended activities provided in the tour procedure.
These
recommended
activities included,
checking valve alignments,
V-belt condition, shear pins
not broken,
basin drains free of debris, differential pressure
not excessive,
etc.
In addition, the
NRC reviewed several
licensee tour verification sheets.
These
reviews also determined the tours were generally of such
a duration that
the
AEOs were performing only the minimum required
by procedure.
These
sheets
were used
by shift management
to verify, on
a sample basis,
that the operators
were entering the required
rooms
and sufficient time was being spent in the
toured areas.
The licensee
agreed to evaluate
the
NRC observations
to ensure that management
expectations
were being met by the AEOs.
1.2
Secondar
Side Transients
Unit 2
As discussed
in
NRC Inspection
Report 50-315/316-95012
the licensee
had
experienced
a number of secondary
side transients
due to the poor material
condition of some secondary
side components.
The material condition of the
secondary
side
has not improved
and continued to result in secondary
side
During this assessment
period the licensee
experienced
two secondary
side
Both of the transients
involved the Unit 2 heater drain pumps.
4
During
a January
27,
1996 scheduled
level test
on the
5B feedwater
heater,
the normal level controller appeared
to stick causing
a loss of
heater level
and the tripping of the South
and Middle heater drain
pumps.
The Middle condensate
booster
pump and the fast turbine
auxiliary cooling water
(TACW) pump automatically started
and the
operators
manually started
the South hotwell
pump to re-establish
heater
levels.
The auto start of the standby
pumps
combined with operator
action limited the scope of the resulting main feedwater
pump suction
pressure
~
On February
2,
1996, while the Unit 2 South heater drain
pump
(HDP) was
being restored to service following maintenance,
controller problems
resulted in the minimum flow valve not fully closing automatically after
the
pump was started.
The extra flow caused
heater drain tank levels to
drop to the low setpoint
and caused
the South
and the Middle HDPs to
trip.
The North hotwell
pump, the Middle condensate
booster
pump,
and
the West
TACW pump automatically started
as designed.
The auto. start of
the standby
pumps combined with operator action limited the scope of the
resulting main feedwater
pump suction pressure
1.3
0 er tor
'censi
In'tia
aminat'o
During the week of January
8,
1996,
one initial operator licensing examination
was administered
to an
SRO instant candidate.
The candidate
demonstrated
overall
weak performance,
particularly on the written examination.
The
licensee,
in general,
demonstrated difficulty in developing examination
materials for the pilot program, particularly in written test question
development,
job performance
measure verification,
and operating test
validation.
2.0
NAINTENANCE AND SURVEILLANCE
NRC Inspection
Procedures
62703,
61726,
and 92902 were used to perform an
inspection of maintenance
and testing activities.
Although the
NRC had
concerns with the licensee's
performance of ice condenser
surveillances,
the
licensee's
concurrent identification of these
concerns
and the resulting
actions
were viewed .as very positive.
In addition, the licensee's
root cause
investigation
and operability determination of the residual
heat removal
system valve gasket failure was also good.
However, the
NRC identified
examples
where safety-related
components
were not being tested
under suitably
controlled conditions.
In addition, the
NRC continued to have concerns
regarding non-conservative
interpretations of TS requirements,
procedural
adherence,
and secondary plant material condition.
)c
2. 1
Maintenance
and Surveillance Testin
Activities
The
NRC observed
routine preventive
and corrective maintenance
and
surveillance activities to ascertain
that these
were conducted
in accordance
with approved
procedures,
regulatory guides,
industry codes or standards,
and
in conformance with Technical Specifications
(TS).
The specific items
observed/reviewed
are listed below:
aintenance Activit
Descri tion
C0034641
C0033468
C0033923
R0054374
R0040929
R0053727
C0033810
Surveillance Activit
Containment polat
crane
clean
and inspect
drum gears
Clean
and paint polar crane trolley rails
Containment polar crane
inspect
main hoist
mechanical
load break
1-CD-EDG, Lubricate
and exercise
the fuel racks.
l-AB-EDG, Lubricate
and exercise
the fuel racks.
I-AB-EDG, Lubricate
and exercise
the fuel racks.
Repair 1-IRV-311
Descri tion
EHP.4030.STP.211
THP.4030.STP.245
EHP.4030.STP.250
OHP 4030STP.017T
IHP 5021.EHP.004
OHP 4030.STP.041
Ice Condenser
Surveillance
Inspection of Ice Condenser
Intermediate
Deck Doors
Inspection of Ice Condenser
Flow Passages
Turbine Driven Auxiliary Feedwater
System Test
Limitorque Limit And Torque Switch Setting
Refueling Integrity Verification
2.2
ce Condenser
Technical
S ec'fications
TS
Action Statement Error
Unit 2
On February
22,
1996, with Unit 2 at
100 percent
power
(Mode 1), the licensee
began
performance of the
TS 18-month surveillances
(4.6.5.3. 1(b))
on the Unit
2 ice condenser
doors in preparation for the upcoming refueling outage.
This
required entry into the action statement for TS 3.6.5.3
due to one or more
intermediate
deck doors
(IDDs) being inoperable.
The ac'tion statement
allowed
this condition to exist for up to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> with no action, or 14 days provided
that ice bed temperatures
were monitored every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
and maintained
under
27'F.
The licensee's
intent was to exit the action statement
at the end of
each
day as work was only being performed
on the day shift.
Therefore,
the
time out of service
and in the
LCO would have
been reset
each
day.
At the end of day shift (4:30
pm)
on February
22,
1996, surveillance
activities were stopped
and the lead engineer reported to the control
room
that all
IDDs were returned to service except door A in bay 9.
This door
failed the required load test.
The engineer
also discussed
a
memo from
corporate
engineering
which stated that the ice condenser
was capable of
performing the required safety function with up to
19
IDDs inoperable.
Based
on the engineering
memo, the unit supervisor declared
the ice condenser
and exited
The shift technical
advisor
(STA) and
assistant shift supervisor
reviewed the condition report documenting
the
IDD and concurred that entry into an action statement for one
IDD was not required.
Since
one
IDD was inoperable,
should not have
been exited.
While
reviewing the condition report generated
for the inoperable
IDD, the oncoming
night shift STA identified that the unit should still have
been in TS 3.6.5.3,
and the action statement
was re-entered
at 7:30
pm.
No TS action statement
time limitations were exceeded
due to this- error.
The
NRC had the following concerns with this evolution:
Neither the operators
nor the engineers verified that the licensing
bases for the ice condenser
were met.
Both organizations
allowed
guidance
contained
in an engineering
memo to supersede
TS requirements.
A similat event concerning diesel
generator
TS requirements
was
discussed
in
NRC Inspection
Report 50-315/316-95013.
~
The intended practice of resetting
the time in the action statement
by
entering
and exiting the
LCO on
a daily basis
was considered
a non-
conservative
approach
as cumulative out-of-service time would not have
been considered.
~
The licensee
did not utilize the plant's probablistic risk assessment
(PRA) to provide insight into the impact of performing ice condenser
surveillances
while at power.
The
NRC review determined that these
activities did not present
an increase
in risk because
the ability of
the ice condenser
to perform the required safety function was not
impacted
The
NRC viewed the licensee's
response
to this occurrence
as positive.
The
oncoming shift identified the erroneous
TS interpretation,
and further
performance of the surveillances
was stopped until the appropriate
course of
action was determined.
Also, licensee
management
recognized
the significance
of this event in light of a similar event involving a missed diesel
generator
surveillance.
Both instances
involved using information other than that
contained
in the licensing basis to determine
the applicability of TS
requirements.
Licensee senior
management
had similar concerns
regarding
the management
of
LCO time and
had
been reviewing this matter prior to this event.
Prior to
resuming performance of the surveillances,
the licensee
established
a limit of
200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of cumulative time in the action statement
was set to ensure
compliance with the intent of TS.
Additional licensee
actions
included; issuing
a
memo to all operations shifts
describing the details of the incident,
and the Operations
Superintendent
expressing
his expectation to all shifts emphasizing that licensed
operators
must
be responsible
for ensuring
compliance with licensing requirements.
2.3
Pre-Conditionin
of
E ui ment Prior to Surveillance
Tests
Hoth Units
As documented
in
NRC Inspection
Report 50-315/316-95013(DRP),
the
NRC
previously identified examples of TS surveillance activities where safety-
related
equipment
was not tested
under suitably controlled conditions
and in
accordance
with design
and licensing bases.
During the latest inspection
period,
the
NRC identified two additional
examples of pre-conditioning.
~
During routine review of surveillance
procedure
OHP 4030STP.017T,
"Turbine Driven Auxiliary Feedwater
System Test,"
the
NRC noted that
the licensee verified the operability of steam traps associated
with the
steam supply to the
pump turbine prior to starting the
pump.
The
licensee
performed the test
by placing
a listening device
on each trap
discharge
pipe and checking for proper operation.
If no flow was heard,
the trap was determined to be malfunctioning,
and the procedure required
the trap bypass
valve be opened to provide
a continuous flow path.
The
procedure
also required that
an action request
be issued to repair the
trap.
The
NRC concluded that the licensee's
actions
were prudent to verify the
steam traps were operable to prevent condensate
from damaging the
turbine.
However, the
NRC were concerned that the procedure did not
require that
a condition report
be initiated to address
the operability
of the
pump in the "as found" condition if a malfunctioning trap was
identified.
The
NRC noted that the traps that were tested
were required
to be operable or bypassed
to support
TDAFW pump operability.
The
NRC did not have
any immediate operability concerns,
due to the
reliability of the traps
and the few failures that have
been
experienced.
The
NRC reviewed surveillance
records
and discovered
only
one recent
example of a malfunctioning trap.
Action Request
(AR)
A0085828,
dated
December
8,
1994,
documented that
no flow was detected
at the outlet of drain
26 for the Unit 2 TDAFW pump and the bypass
valve
was throttled open
as required
by procedure.
However,
no operability
evaluation
was performed.
~
The
NRC identified that
an emergency diesel
generator
(EDG) preventive
maintenance
(PM) activity, to lubricate
and manually exercised
the
linkage of each fuel injection
pump to ensure
there
was
no binding or
sticking,
was performed every 30 days.
The
NRC noted that licensee
management
was
unaware of the purpose
and the frequency of the
PM on the
linkage.
The
NRC was concerned
that controls
had not been established
to prevent performance of the
PM prior to running the
EDGs during the
monthly TS surveillance test.
The pre-conditioning of the fuel
injection
pump linkages prior to surveillance testing could mask
a
problem that would prevent the
EDG from performing
as designed.
The
NRC reviewed licensee
records
and identified three
examples
where
the licensee
exercised
the fuel linkages within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of running the
EDG:
1-CD-EDG on January
23,
1996
(R0054374)
1-AB-EDG on February 7/8,
1995
(R0040929)
1-AB-EDG on January
9/10,
1996
(R0053727)
The
NRC reviewed the job orders
and verified that
no abnormalities
wer e
documented
that would have prevented
the
EDGs from starting
as designed.
However, the
NRC were concerned
that the licensee
had not established
procedures
to evaluate
the as-found operability of the
EDGs if non-
conforming or degraded
conditions
were identified during the
PH
activities.
These
examples of failure to test
equipment
under suitably controlled
conditions represent
a violation of NRC requirements.
However,
a notice of
violation will not be issued
since these
are further examples of a previously
identified violation (documented
in NRC Inspection
Report 50-315/316-95013)
for which the licensee
has not had the opportunity to fully implement
corrective actions.
2.4
Residual
Heat
Removal
Valve Gasket
Leak
Unit
1
On January
31,
1996, while disassembling
the
RHR heat exchanger
bypass control
valve,
1-IRV-311, to repair
a flange leak, the licensee
discovered that
approximately
50 percent of the flexitallic gasket material
was missing.
As discussed
in
NRC Inspection
Report 50-315/316-95010,
the licensee
replaced
the gasket
in August
1995 after discovering pieces of gasket material
from a
previous gasket failure during the last refueling outage.
At that time, the
licensee
performed full flow flushes of the emergency
core cooling system
(ECCS) pumps'ischarge
piping to remove
any material
remaining in those
lines.
In addition,
due to
a concern that material in the suction piping
could potentially damage
the safety injection and centrifugal charging
pumps,
the licensee installed
a cleanout connection
and removed gasket material
found
in the suction header.
The licensee
determined that the root cause of the
first failure was the installation of an undersized
gasket during maintenance
on the valve in 1994.
In response
to the latest identified failure, the licensee
performed
a prompt
operability 'determination,
as documented
in Condition Report
No. 0127, to
address
the potential
damage to the
ECCS pumps.
The licensee
concluded that
the gasket probably failed during the flushes
performed during the previous
refueling outage.
The basis for the conclusion
was that, unlike the previous
cycle,
no indication of fuel
damage
has
been detected
since the beginning of
the present
cycle
and that this portion of the line did not normally receive
flow.
The licensee
had determined that the first gasket failure caused
the
fuel failures during the previous cycle.
The licensee's
backup operability determination,
dated
February
2,
1996,
concluded that,
in the unlikely event gasket material
migrated to the
suction header,
the
pumps would not be damaged.
This was
based
on
a review of
the piping configuration
and operating experience
provided by the
pump vendor
of similar pumps in fossil plants.
The licensee
determined that the root cause of the latest failure was the
misalignment of the gasket
and the valve discharge
flange during installation.
The valve was maintained in place
between
two pipe flanges
and centering of
the gasket
was critical due to the tight tolerances
between
the outside
diameters of the valve discharge
and the gasket filler element.
The
problem was
compounded
because
the pipe flanges
were not concentric with each
other.
As immediate corrective action,
the licensee
replaced
the flexitallic
with a compressed
fiber gasket,
custom sized to ensure
proper
alignment.
On
a long-term basis,
the licensee will determine other
alternative
designs.
The licensee
also intended to inspect the 2-IRV-
311 valve gasket prior to the upcoming Unit 2 refueling outage.
The
NRC
concluded that the licensee's
root cause investigation
and operability
determination
were good.
2.5
Valve Overload Tri - Unit 2
On February
21,
1996, while restoring the out-of service clearance
on the
charging
pump suction cross-tie valve (2-IH0-361), the valve traveled in the
direction opposite
than what was expected
and the feeder breaker tripped on
overload.
Following motor operator replacement,
electrical
maintenance
had
signed off on the out-of-service clearance
but verbally requested
operations
shift management
to contact
them prior to operating
the valve.
The purpose
for the request
was to verify the correct rotation of the motor.
However, the unit supervisor
(US) did not effectively communicate
the request
to the reactor operator
(RO) during
a general
announcement
to the operating
crew.
The
RO was busy
and did not respond positively to the
command but later
took the valve control switch to the closed position,
as required
by the
clearance
restoration,
without notifying the electricians.
Following the
event,
the licensee
performed
an internal inspection of the valve and
no
damage
was noted,
however,
the event resulted in the licensee
being in a
TS
LCO for a greater period of time.
During review of the Condition Report
(CR), the
NRC noted that paragraph
7.4. 1
of procedure
12 IHP5021.EHP.004,
"Limitorque Limit And Torque Switch Setting,"
required that
a deadman
switch or equivalent
be installed prior to releasing
the clearance
permit.
The deadman
would have prevented
operation of the valve
from the control
room.
The failure to comply with the procedure constituted
a
violation of minor significance
and is being treated
as
a Non-Cited Violation
(50-316/96002-04),
consistent with Section
IV of the
As immediate corrective action,
the licensee
enhanced
the applicable
procedures
and briefed personnel
on the importance of adhering to procedures.
2.6
Re lacement of Airline to Valve
RV-301
Unit 2
The
NRC observed
the evolution involving the airline replacement
of the
letdown backpressure
regulating valve (2-(RV-301),
and concluded that the
evolution was well-planned
and implemented.
The evolution required that the
valve be isolated,
while maintaining letdown pressure
using
a manually
10
k
t
I,
'li
II
~
~
~
operated
bypass valve.
The evolution required coordination
between the
reactor operator
and the auxiliary operator
who was operating
the manual
valve
locally.
The
NRC observed that the prebrief and communications
among the
involved parties
was good.
3. 0
ENGINEERING
NRC Inspection
Procedures
37550
and 37551 were used to perform
an onsite
inspection of the engineering functions.
The
NRC identified
a failure to
perform
a 50.59 evaluation
and weaknesses
with other 50.59 evaluations.
In
addition,
as noted in paragraph
4.0, there
was
a weakness of reactor
engineering
not taking "ownership" in the receipt
and storage of new fuel,
and
concerns with foreign material exclusion.
3. 1
Work In Containment
While At Power
Unit
In an effort to reduce the refueling outage
scope,
the licensee
was performing
more maintenance
and modifications while on line.
The
NRC determined that
while the wor k was being performed in a safe
manner it was not always fully or
properly evaluated prior to the work being started.
The
NRC identified
concerns with potential debris
and with a tarp installed inside containment
without a safety evaluation.
The
NRC observed that in an effort to keep debris out of the containment
refuel
pool
a debris/cargo
net
had
been installed over the pool.
The
NRC
verified that
a safety evaluation
had
been
performed
and that the nets
were
installed in accordance
with the evaluations.
However the
NRC identified
weaknesses
with the evaluations.
A safety evaluation
had
been
performed for the installation of a jib
crane in Unit 2.
In order to allow the installation of the nets,
the
evaluation
incorporated
by reference
an evaluation for previously
performed Unit I work.
The licensee
spent considerable effort to verify
that the Unit I evaluation
could be utilized for the Unit 2 work.
This
method met the regulatory requirements
but was cumbersome.
This
increased
the opportunities for errors.
4
In response
to
NRC questions,
the licensee
located design
documents
showing that the ice condenser
top deck doors would not be affected
by
movement of the polar crane
and that the crane
met seismic requirements
even
when moved from its parked position.
Discussion of these
issues
was not included in the safety evaluations.
While inside the containment
the
NRC noted that workers properly secured all
bags of material
as required
by procedures
and the safety evaluations.
However, during movement,
about
a dozen
bags
became
unsecured.
While the bags
were attended
at all times, during
a Loss of Coolant Accident
(LOCA) the
workers could have left the bags in place during the containment
evacuation.
In response
to this concern
the licensee
instructed the radiation protection
technicians
to limit large numbers of unsecured
bags during containment tours.
lj,t
I
i
Ill
Ijj
I
During
a subsequent
tour of containment,
the
NRC noted
a 8 ft by 8 ft yellow
tarp secured
over the refuel
pool which was not in accordance
with the
approved safety evaluation.
The licensee
responded
by removing the tarp
and
performing
an analysis of the
as found configuration.
The licensee
determined
that the containment
lower drains
and the recirculation
were still
However, the licensee's
analysis initially failed to consider the
effects of post
LOCA pH on the tarp
and its supporting
rope until questioned
by the
NRC.
The failure to perform a safety evaluation
as required
by 10 CFR 50.59 prior to installing the tarp is
a violation 316/96002-02(DRP).
In response
to the identification of the tarp the plant manager
issued
a stop
work order for all work in the Unit 2 containment.
Prior to restarting
the
work, all workers were retrained
on the potential
consequences
of loose debris
in the containment.
In addition to the
above corrective action,
the
containment
system engineer
was tasked with the responsibility of maintaining
cognizance of all work being performed inside containment while the unit was
on line.
4.0
PREPARATION FOR REFUELING Unit 2
NRC Inspection
Procedure
60705
was
used to perform an inspection of the
licensee's
preparation for the planned Unit 2 refueling outage.
This
inspection primarily focused
on the control of and movement of new fuel during
the receipt inspection.
The
NRC determined that while the receipt,
storage
and handling of the
new fuel was safe,
there were failures to meet regulatory
requirements
and
a lack of ownership over new fuel.
4. 1
0 erabilit
of The
New Fuel Vault Criticalit
Monitor Unit 2
10 CFR Part 70.24 required,
in part, that the licensee
maintain
a monitoring
system capable of detecting
a criticality in the
new fuel storage vault (NFV).
The monitoring capability was required
even though licensee calculations
show
that
a criticality event in the
new fuel vault was not credible.
Following a
routine tour of the
new fuel storage vault, the
NRC questioned
the ability of
the installed monitoring system to comply with 70.24.
Subsequent
licensee
calculations
and monitor setpoint determinations
showed that the installed
monitoring system would not meet the requirements
of either 70.24(a)(l)
or
70.24(a)(2).
During a routine inspection of new fuel receipt
and of the
new fuel vault, the
NRC questioned
the ability of the one installed radiation monitor to meet the
requirements
The monitor was located outside the vault
and was separated
from the closest fuel assembly
in the
new fuel vault by a
distance of approximately
30 feet which included
one
18" thick reinforced
concrete wall. Subpart (a)(2) of 70.24 required the monitor be capable of
detecting
a 300 R/hr field that was
one foot from the fuel.
In addition,
(a)(2) required that the monitoring devices
have
a set point of not less
than
5 mr/Hr nor more than
20 mR/hr.
Subpart
(a)(1) of 70.24 required,
in part,
two radiation monitors for the
new fuel.
The
NRC was concerned
that the distance
to the monitor combined with the thick
wall would defeat
the purpose of the one installed monitor.
Interviews with
licensee
personnel
and the review of licensee
documents
determined:
12
~
~
~
~
The licensee
was not knowledgeable of the need to meet the requirements
of 70.24.
The licensee
had information regarding
an exemption to 70.24(a)(2) that
had
been granted
in the mid 1970s,
but the information indicated the
exemption
had lapsed.
~
The monitor had not been installed in accordance
with an approved design
change
package
but was instead
a temporary monitor that
had
been in
place since
December
2,
1993.
Prior to that time, another
temporary
monitor had been installed in a different location.
~
The calculation which supported installation of the monitor in 1993,
contained
assumptions
as to locations
and distances
which were not met.
Specifically the monitor
was
assumed
to be located outside of the
new
fuel vault some
9 feet above the fuel.
Instead
the monitor was located
outside the
new fuel vault some
30 feet horizontally from the fuel.
The
increased
distance
caused
the radiation field to be seen
by the monitor
to drop below that required
by 70.24(a)(2).
The
NRC determined that
no
licensee
procedures
governed the placement of the criticality monitor.
In response
to an
NRC request,
the licensee
checked
the actual setpoint
of the monitor.
The monitor was determined to be set to alarm at 1,000
mr/hr.
70.24(a)(2)
required the monitor to be set
between
5 and
20
mr/hr.
The
NRC determined that
no plant procedures
governed the
setpoint of the criticality monitor.
A review of the licensee's
USAR identified that the
NFV criticality
monitor was not addressed
in any section.
Area radiation
monitors/criticality monitoring devices
were
a part of the licensee's
design
and licensing basis that should
be in the
USAR.
~
The licensee
had initially assumed
they were required to meet
70.24(a)(2) for Unit 2.
Subsequently,
the licensee
and the
NRC
questioned
whether (a)(2) or (a)(1)
was the appropriate
requirement.
This issue will be
a part of the unresolved
item discussed
below.
The licensee's
failure to have
a radiation monitor that met the requirements
of 10 CFR Part 70.24 is considered
a violation (50-316/96002-01(DRP)).
The
NRC also
had questions
concerning the licensee's
emergency
procedures
for
a criticality event,
the need for drills, and the need for either constant
monitoring or a detector which would send signals to
a remotely monitored
location.
NRC resolution of these
questions
and whether the licensee
must
comply with 70.24(a)(1)
or (a)(2) is an Unresolved
Item (50-316/96002-
03(DRP)).
The licensee's initial response
to this issue
was slow and not focused.
Initially there
were
no attempts
to expand the questions
concerning detector
. operability beyond those raised
by the
NRC.
This occurred
even though
new
fuel
was continuing to be stored
and loaded into the
new fuel vault.
13
Following the initial inoperability determination
the licensee
made
a one hour
phone call to the
NRC.
To restore
the detector to operable
the licensee
repositioned
one
new fuel assembly
so that the detector
would have
a direct
line of sight.
At that point the licensee
believed the detector
had been
restored
to operable.
No further questions
were asked
by the licensee
concerning detector operability until the
NRC questioned
the setpoint of the
detector.
At that point the licensee
determined that the detector
was
due to the wrong setpoint
and another
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> report
was
made to the
NRC.
4.2
Poorl
Im lemented Auxiliar Buildin
Inte rit
Controls
Unit 2
On February
27,
1996,
the
NRC identified that restoration of auxiliary
building integrity (ABI) had not been verified prior to performing fuel
movement in the spent fuel pool
(SFP).
Following the off load of the
new fuel transportation
canisters
in the
auxiliary building, the senior reactor operator-core
alterations
(SRO-CA)
attempted
to close the crane-bay
door but, the door remained
approximately
1-2
feet open.
The
SRO-CA left the area
and
made
a mental
note that the door
would be closed prior to moving fuel in the
SFP.
During
a routine plant tour, the
NRC noted the unattended,
partially open door
while new fuel was being unloaded
from transportation
canisters
and inspection
activities were about to begin.
The
NRC notified the licensee
and the bay
door was immediately closed.
Operations
procedure
01-0HP-4030.STP.041,
"Refueling Integrity," Revision 4,
provided the controls necessary
to ensure that ABI was maintained while fuel
movement
was in progress.
A note in the procedure
stated that
"when
a piece
of equipment is out of position, not to include normal
passage,
this fact must
be logged
on Data Sheet
No. 4,
Loss of Refueling Integrity Log."
Step 4.9
further states,
"before refueling or spent fuel pit operations
commence,
verify restoration of all items
on Data Sheet
No. 4."
Due to the NRC's questions,
the appropriate
Data Sheet entries
were
made for
the door being out of position.
The failure to document the partially open
door on data sheet
4 and failure to verify restoration of all items
on the
data sheet is considered
a violation of procedure
STP.041.
However, since
no
fuel movement occurred with the door partially open, this failure constitutes
a violation of minor significance
and is being treated
as
a Non-Cited
violation, consistent with Section
IV of the
316/96002-05.
4.3
Forei
n Material Exclusion
For New Fuel
and the
S ent Fuel
ool-
Unit 2
The licensee
and the
NRC identified examples
where foreign material
was
allowed to be in contact with new and spent fuel.
Problems with FHE were
identified in
NRC inspection report 50-315/316-95010(DRP)
and
was the subject
of inspection follow-up item (IFI) (50-315/316-94024-02(DRP)).
As was noted
14
in the 315/316-95010 report,
FHE controls were improving but more attention in
this area
was needed.
During the receipt
and inspection of the
new fuel, the licensee identified two
examples
where foreign material
inadvertently reached
some assemblies.
Those
examples
were:
~
On February
9,
1996, oil leaked onto two assemblies
when the seal
on
a
scale failed.
The assemblies
were not damaged
but did have to be
returned to the factory for cleaning.
~
On February
26,
1996,
a safety clip on
a chain hook being used to lift
the fuel into the vertical position broke.
Several
small pieces of
metal
landed
on top of the fuel
and
on the floor around the fuel.
Fuel
movement
was immediately halted.
Licensee
personnel
performed
a
detailed evaluation of the clip and determined that the head of one
small
screw was missing.
A maintenance
mechanic
found the screw head
on
the upper most grid support inside
one of the assemblies.
The screw
head
was
removed
and reverification made that no other parts were
missing.
In addition, during routine observations
of the spent fuel pool
on January
27,
1996, the
NRC identified some material
on top of old fuel
and
some material
on
the bottom of the pool.
The material
on the bottom of the pool consisted of
resin,
a washer,
and
a piece of stainless
steel.
The resin
was left over from
an old occurrence
where resin
was inadvertently backflushed
from the spent
fuel pool clean
up system.
The pieces of metal
and the material
on top of the
used
assembly
were relatively recent.
A regular inspection of the spent fuel
pool performed
on January
18,
1996 by reactor engineering
revealed that
no
material
was in the pool.
The licensee initiated action requests
to have the
material
removed
from the top of the fuel
and the bottom of the pool
and
initiated
a condition report (96-0293).
The licensee
intended to vacuum up
the resin;
however, it. could not be removed from the unaccessible
areas of the
storage
racks
and additional material would gradually migrate back out.
5.0 'LANT SUPPORT
NRC Inspection
Procedure
84750 was used to perform an inspection of plant
support activities.
As noted in paragraph
4.0 above,
the licensee failed to
ensure that
a radiation monitor was installed
and operated
in accordance
with
In addition,
NRC review of licensee
performance
regarding
dose
for the upcoming unit 2 refueling outage
and for the previous unit
1 refueling
outage
showed:
~
The
1995 collective dose
was low (202 person-rem).
~
There
was excellent
dose
performance
during the fall 1995 refueling
outage
and good planning for the spring
1996 refueling outage.
15
6.0
Review of UFSAR Commitments
A recent discovery of a licensee
operating
a facility in
a manner contrary to
the Updated Final Safety Analysis Report
(UFSAR) description highlighted the
need for a special
focused
review that compared plant practices,
procedures
and/or parameters
to the
UFSAR description.
While performing the inspections
discussed
in this report, the
NRC reviewed the applicable portions of the
UFSAR that related to the areas
inspected.
The following inconsistencies
were
noted
between
the wording of the
UFSAR and the plant practices,
procedures,
and/or parameters
observed
by the
NRC.
~
The placement of a tarp inside the Unit 2 containment
was performed
without a review of the
UFSAR commitments
(paragraph
3. 1).
~
Section 6.10 of the
UFSAR stated that "alarms
and redundant level
indicators
are provided in the containment recirculation sump...."
In
addition, section 7.5, stated that "the lower range
channels
indicate
the water level in the containment
sump."
The containment
sump water
level
was also stated in'table 7.8-2
as reading out in the control
room.
The
NRC determined
the licensee
removed the recirculation
sump level
indicators
and moved them to the adjacent
sump which is connected.
The
licensee failed to properly update all pertinent sections of the
at the time of the modification.
(50-315/316-96002-06)
7.0
eetin
s and Other Act'vities
a.
Hang ement Heetin
s
On January
11,
1996, there
was management
meeting
between
NRC and the licensee
to discuss
the personnel
performance
issues
during the Unit
1 refueling outage
and during subsequent
Unit
1 and Unit 2 reactor operations.
In addition, the
poor material condition of certain secondary
side components
and the causes
were also discussed.
A copy of the material
used
by the licensee to discuss
these matters is attached.
b.
~ill
The
NRC contacted
various licensee
operations,
maintenance,
engineering,
and
plant support personnel
throughout the inspection period.
Senior personnel
are listed below.
At the conclusion of the inspection
on Harch 7,
1996, the
NRC met with
licensee
representatives
(denoted
by *) and summarized
the scope
and findings
of the inspection activities.
The licensee
did not identify any of the
documents
or processes
reviewed
by the
NRC as proprietary.
- A. Blind, Site Vice President
- J. Sampson,
Plant Hanager
- K. Baker, Assistant
Plant Hanager
0. Noble, Radiation Protection Superintendent
- T. Postlewait,
Site Engineering
Support Hanager
16
- J. Wiebe, Superintendent,
Plant Performance
Assurance
- H. Barfelz, Superintendent,
Nuclear Safety
& Analysis
- J. Allard, Haintenance
Superintendent
- L. Gibson,
Hanager of Business
Performance
- S. Colvis, Licensing Engineer
- D. Horey, Chemistry Superintendent
- P. Schoepf,
Plant Engineering Superintendent
- T. Beilman,
Scheduling Superintendent
- S. Hover, Licensing Engineer
- B. Burgess,
Information Communications
Services
- R. Leonard,
Plant Engineering - System Engineer
- R. Smith, Plant Engineering
System
Engineer
- L. Smart,
Licensing Engineer
- S. Brewer,
Hanager
Regulatory Affairs
"A. Verteramo,
Reactor Engineering Supervisor,
Plant Engineering
- P. Russell,
Fire Protection Supervisor
- H. Ackerman,
Licensing Engineer
- J. Cassidy,
Radiation Protection
- L. VanGinhoven, Haterial
Hanagement
Superintendent
- H. Depuydt,
Licensing Coordinator
- R. West, Licensing Coordinator
- R. Gillespie, Operations
Superintendent
Attachment:
American Electric Power Agenda
17
e
ANERICANI
ELECTRlC
~
POMfER
Agenda
January
11, 1996
Opening Remarks
AlBlind - Plant Manager/Site Vice President
introduction
John Sampson - Assistant Plant Manager
Operations
BillNichols - Acting Operations Superintendent
Scheduling
Terry Beilman - Scheduling Superintendent
Maintenance
John Allard - Maintenance Superintendent
Plant Engineering
Paul Schoepf - Plant Engineering Superintendent
Closing Remarks
Gene Fitzpatrick - Senior Vice President
AEPNO/Cook Nuclear Plant - Pcrformancc Overview
Page
1
ANERlCAN
EI.ECTRlC
POMfER
January
11, 1996
Maintenance Costs
(Millions
$45
$40
$35
$30
$25
$20
$<5
$<0
$5
$0
t 4>>t>>>>Ikl44~>>
g>>
Balance Of Plant
Safety Related
AEPNO/Cook Nuclear Plant - Performance Overview
Al Blind - Site Vice President/Plant
Manager
Page 2
AMERlCAN
ELECTRlC
POWER
January
11, 1996
Capital Costs
(Millions)
$20
$18
$ 16
$14
$ 12
$10
$8
$6
$4
$2
$0
'i994
1995
Balance Of Plant
W
Safety Related
- 1995 Capital represents
only 11 months (data lag)
AEPNO/Cook Nuclear Plant - Performance Overview
Al Blind - Site Vice President/Plant
Manager
Page
3
AMERICAN
ELECTRlC
POWER
January
11, 1996
Business Model
Competitive Challenge
Other
Production ~
Operafing Cost ($)
People
Generafion (Mi/Yhj
Outages
Other
Pillars
m
65
~~
L
N~e
+ CJ
U Q)
ego
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t- O g
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1
O~ a.
O
Foundation
Human Performance
Teamwork
AEPNO/Cook Nuclear Plant - Pcrfomtancc Ovcrvicw
Al Blind - Site Vice President/Plant
Manager
Page 4
AMERICAN
EI.ECYRIC
POWER
January
11, 1996
FUNDAMENTALISSUES
Human Performance
Operational Focus
Material Condition
.Work Control
"Improvement Culture"
AEPNO/Cook Nuclear Plant - Performance Overview
John Sampson - Assistant Plant Manager
Page
5
I
<<
AMERICAN
ELECTRIC
~
POWER
OPeratiOnS
January
11, 1996
Shifts - Generated Procedure Change Sheets
50
40
30
20
10
0
No. Change Sheets
Avg-6.5
May
Jun
Jul
Aug
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'<<!
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~
Supervisory Oversite
~
Procedures
~
Briefings/Communication
AEPNO/Cook Nuclear Plant - Pcrformancc Overview
Bill Nichols - Acting Operations Superintendent
Page 6
AMERICAN
EI.ECYRIC
a
~
POMfER
Scheduling
January
11, 1996
2500
2000
1500
Corrective Maintenance inventory
1992-95
k1kk~t ~~kl ~kg1$ 44:~<~5
1600
1200
1000
600
600
400
200
Corrective Maintenance inventory
1995
'
i l ! '
>
1 f ', t
2 l l f j
5'
( I
6 i
tl f
~
History OfWork Control Process
~
Analysis of Current Status
Irnprovernent Measures
AEPNO/Cook Nuclear Plant - Performance Overview
Terry Beilman - Scheduling Superintendent
Page 7
1
AMERICAN
EI.ECYRIC
POWER
January
11, 1996
Maintenance
Rework CR's
Average Age (days)
~SCg~SBSCSS~BR8$
S
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St,ÃS~~
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aa
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~
Recent Observations
~
Quality
Corrective Actions
- Worlananship
AEPNO/Cook Nuclear Plant - Performance Overview
John Allard - Maintenance Superintendent
Page 8
c'
AMERICAN
EI.ECYRIC
POWER
January
11, 1996
Plant Engineering
1.8
1.6
1.4
C
g
0.8
C
0.6
o
0.4
0.2
Safety System Performance - Auxiliary
Feedwater System
Unit 1 (1995 YTD avg.)
95 Goal (<1.0%)
~
Observations and Assessment
~
Engineering Support ofProduction
~
Corrective Actions and Self Assessment
AEPNO/Cook Nuclear Plant - Performance Overview
Paul Schocpf - Plant Engineering Supcrintcndcnt
Page 9
AMERICAN
ELECTRIC
~
POWER
January
11, 1996
Notes
AEPNO/Cook Nuclear Plant - Performance Overview
Page
10