ML16342D261
| ML16342D261 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 04/09/1996 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D260 | List: |
| References | |
| 50-275-96-02, 50-275-96-2, 50-323-96-02, 50-323-96-2, NUDOCS 9604160043 | |
| Download: ML16342D261 (50) | |
See also: IR 05000275/1996002
Text
ENCLOSURE
2
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection
Report:
50-275/96-02
50-323/96-02
Licenses:
DPR-82
Licensee:
Pacific
Gas
and Electric Company
77 Beale Street,
Room
1451
P.O.
Box 770000
San Francisco,
Facility Name:
Diablo Canyon Nuclear
Power Plant,
Units
1
and
2
Inspection At:
Diablo Canyon ~ite,
San Luis Obispo County. California
Inspection
Conducted:
January
21 through March 2,
1996
Inspectors:
M. D. Tschiltz, Senior Resident
Inspector
S.
A. Boynton,
Resident
Inspector
D.
E. Corporandy,
Project
Inspector
C. J,
Paulk,
Reactor
Inspector
D.
G. Acker, Senior Project Inspector
Approved:
her"
H
Wong,
Re ctor ProJects
Branc
Date
Ins ection
Summar
Areas
Ins ected
Units
1
and
2
Routine,
announced
inspection of operational
safety verification, maintenance
observations,
surveillance observations,
onsite engineering,
plant support activities, followup.operations,
followup
engineering,
in office review of licensee
event reports
(LERs),
and review of
the Upd'ated
Final Safety Analjsis Report .gFSAR).
Results
Units
1
and
2
~Qeratinna:
~
The licensee's
procedure for performing monthly channel
checks of the
incore thermocouple
instruments
did not ensure
the Technical
Specification
(TS) surveillance
requirement
was met.
As
a result,
the
licensee
failed to identify an inoperable
incore thermocouple
instrument
on Unit 2.
A violation was identified (Section 2.1).
9604l60043 9604l0
ADOCK 05000275
6
-2-
Operations
responded
promptly and effectively in response
to
a steam
leak
on cold reheat drain piping that necessitated
an unanticipated
reduction of reactor
power to perform repair of a cracked
(Section 2.4).
Operators
failed to identify the potential for spread of contamination
during
a surveillance test of
a containment
spray
pump when leakage
from
the pump's
mechanical
seal
sprayed
outside of the posted
surface
contamination
area
(Section
4. 1).
An operator failed to properly perform
a system
alignment verification
for the performance of TS required surveillance testing.
A noncited
violation was identified (Section 4.2).
Maintenance:
Maintenance
personnel
failed to address
a potential seismically
induced
system interaction
when
a storage
cabinet
was allowed to be placed in
close proximity to safety-related
conduit associated
with the Unit 2
diesel
generators
(Section 2.2).
The licensee's
configuration control
program
and engineering
system
walkdowns failed to identify the installation of improperly sized motor
bearing oilers
on several
safety-related
pumps
(Section 2.3).
The replacement
of Safety Injection (SI)
Pump 2-2 was thoroughly planned
and well coordinated,
enabling
the work to be completed within the
allowed 72-hour action statement.
8riefings conducted
For the test were
informative and personnel
performing testing
were knowledgeable
of their
assigned
duties
(Section 4.3).
En ineerin
The thermography
program
implemented
by predictive maintenance
was
effective in identifying a problem with a containment
fan cooler motor
controller prior to actual failure (Section
3. 1).
The licensee
failed to take timely and appropriate
licensing actions to
pursue
extension of the
TS allowed outage
time for SI
Pump 2-2
replacement,
after noting
a decrease
in pump performance
during
surveillance
testing
and concluding that
LOKTITE had not been applied to
the shaft locknuts
(Section 4.3).
~
Engineering
investigative actions
taken
in response
to concerns
regarding centrifugal
charging
(CC)
pump operability failed to fully
consider
the
impact of closing the recirculation isolation valves
on
accident
analyses.
As
a result,
the failure to take
prompt
and
comprehensive
corrective actions,
a violation was identified
(Section
5. 1).
'
~
Periodic fire brigade proficiency training was not completed
as
required.
and resulted
in unqualified personnel
being assigned
as fire
brigade
members.
A violation was identified {Section 6.2).
~
A number of minor radiological controls deficiencies
were noted,
indicating
a decline in radiological
housekeeping
practices
and worker
awareness
of radiological
hazards
and controls
(Section 6.3).
Summar
of Ins ection Findin s:
~
Violation 323/9602-01
was
opened
(Section 2.1).
Violation 275/9602-02;
323/9602-02
was
opened
(Section
5. 1).
~
Violation 275/9602-03;
323/9602-03
was
opened
(Section 6.2).
~
A noncited violation was identified (Section 4.2).
~
Violation 275/95015-01
was closed
{Section 7.1).
Inspection
Followup Item 275/9334-01
was closed
(Section 8.1).
~
Unresolved
Item 50-275/95014-04
was closed
(Section 8.2).
LERs 275/95-009,
Revision 0; 275/95-012,
Revision 0;
and 275/95-017
Revision
0 were closed
(Section 9).
Attachments:
~
Persons
Contacted
and Exit Meeting
~
List of Acronyms
DETAILS
1
PLANT STATUS
Unit
1
At the beginning of this inspection period, Unit
1 was in Mode
1 at
100 percent
power.
On February
17 operators
reduced
power when
a moisture.
separator
reheater
stop valve failed to reopen during
a surveillance test.
The stop valve
was
reopened within an hour and the unit was returned
to
100 percent
power.
On February
21 power was
reduced
to approximately
10 percent
to allow for a weld repair of a cold reheat drain line.
The unit
returned
to
100 percent
power
on February
22
and remained
there
through the
end of the inspection period.
Unit
2
At the beginning of this inspection period, Unit
2 was
in Mode
1 at
100 percent
power.
The unit remained
at
100 percent
power throughout
the
inspection period.
Between
February
22-24,
the licensee
replaced
Pump 2-2
based
upon
pump performance
concerns
identified during the
pump's routine
surveillance test
(Section 4.3).
2
OPERATIONAL SAFETY VERIFICATION
(71707)
The inspectors
performed this inspection
to ensure
that the licensee
operated
the facility safely
and in conformance with license
and regulatory
requirements.
The methods
used to perform this inspection
included direct
observation of activities
and equipment,
observation of control
room
operations,
tours of the facility, interviews
and discussions
with licensee
personnel,
independent
verification of safety
system status
and
TS limiting
conditions for operation, verification of corrective actions,
and review of
facility records.
The Senior Resident
Inspector
conducted
a review of recent
INPO evaluations
during this inspection period.
2.,1
Incore Thermocou le Channel
Checks'n
February
13 the inspector identified
a discrepancy
between
the incore
thermocouple
readings
on postaccident
monitoring system
(PAMS) Train
A and
Train
8 on Unit 2.
Specifically.
the average
core temperature
on the
PAMS
Train
8 display
was approximately
20'F higher than that
on the Train
A
display.
The inspector discussed
the temperature
variation with the
engineering
supervisor
responsible
fo~
the incore temperature
monitoring
system
and requested
them to evaluate its impact
on the system's operability.
As
a result.
engineering
determined
that the
PAMS Train
B temperature
indications
were erroneous
and operations
declared
the
PAMS Train
B display
Train
A of the incore thermocouple
PANS continued
to provide
a
sufficient number of operable
thermocouples
to meet
TS requi.ements.
TS require that the incore thermocouples
be calibrated
on
a refueling
frequency
and that
a channel
check
be performed monthly when the unit is
operating
in Hodes
1,
2, or 3.
The inspector
reviewed
the work orders,
documenting
the latest calibrations
performed,
on Trains
A and
B to meet
TS
surveillance
requirements.
The work orders
were complete
and
no abnormal
results
were noted.
The inspector
also reviewed
Procedure
STP I-10,
Revision
25A, "Routine Monthly Checks
Required
By Licenses."
Procedure
STP I-10 is utilized by the licensee
to satisfy the
TS requirement
to perform monthly cha"-"el checks of the incore thermocouples.
Step
11.s. of
Attachment
11.
1 to Procedure
STP I-10 directs operators
to perform
a channel
check of the incore thermocouples
and verify at least four thermocouples
per core quadrant.
The procedure
stipulates
that the indications
may
be read locally (at the
PANS panel) or through
a graphical
interface
on the
plant process
computer
(PPC).
With no other specific guidance
provided for
determining
the acceptability of the thermocouple
indications,
the inspector
questioned
several
control operators
on
how they would evaluate
Step ll.s.
The inspector
determined that,
in general,
operators
would rely upon the
incore thermocouple
map provided
by the
and not visually observe
the local
indications.
The inspector considered
this to be
a contributing factor in the
operators'ailure
to identify the inoperable
PANS Train
B display.
Concerned with the acceptability of using the
PPC to fulfill the
TS required
channel
check of the incore thermocouples,
the inspector discussed
this
practice with the system engineer,
the operations director,
and the
surveillance
engineering
group.
The operations director
and the surveillance
engineering
group responsible
for the maintenance
and performance of
Procedure
1-10 agreed that
use of the
PPC alone would not adequately
verify operability of the incore thermocouple
accident monitoring instruments.
The operations director initiated
an action request
(AR) for engineering
to
evaluate this issue
and directed
the on-shift operators
to perform
a partial
STP I-ID to verify the operability of the local
PANS displays.
The results of
the partial surveillance
were satisfactory.
The inspector
noted that the incore thermocouple
accident monitoring
instruments
would be relied
upon
by operators
during
an accident
to evaluate
the core cooling critical safety function criteria.
A potential
consequence
of,inadequate
surveillances
of these
instruments
is erroneous
core temperatur%~
indication that could adversely
impact the operators'bility
to effectively
implement the emergency
operating
procedures.
The inspector
concluded that
Procedure
STP I-10,
as written, would not necessarily verify operability of
the incore thermocouples
in that it did not specifically require operators
to
observe
the local indications.
The failure of Procedure
1-10 to
adequately
evaluate
the operability of the
PANS incore thermocouples
is
a
violation of TS 6.8.
1 (Violation 323/9602-01).
2.2
Unit
2 Diesel
Generator Air Exhaust
Room Material Stora
e
On February
1. during
a plant tour of the Unit 2 turbine building, in the
diesel
generator
exhaust
room.
the inspector identified
a potential
seismically
induced
system interaction
(SISI) when
he noted that
a large,
unrestrained
storage
container
had
been
placed
in close proximity to safety-
related electrical
conduit.
The inspector raised
the concern of potential
seismic interactions
between
the container
and the conduit with the
responsible
maintenance
supervisor.
The supervisor
agreed
that the placement
of the container
was inappropriate
and the container
was
moved to
a new
location
and secured.
The inspector discussed
his concerns
with the system engineer
responsible
for
implementation of the SISI program. ~- system engineer, determined that the
conduit was
an SISI "target" in that it contained vital circuits for the
operation of Emergency
Diesel
Generator
(EDG) 2-3.
SISI "targets"
are defined
in Procedure
AD4. 103,
Rev.
1B, "SISI Review of Housekeeping Activities," as
those
components
required for safe
shutdown of the plant or for accident
mitigation.
The system engineer
evaluated
the potential
SISI
and determined
that it was unlikely the container could have
damaged
the conduit in
a seismic
event.
Conclusion:
The inspector
concluded that the maintenance
supervisor failed to
identify the potential
SISI created
by the placement of the storage
container
and,
thus,
the appropriate
evaluation
had not been
performed
by engineering
services.
Similar concerns
had previously
been identified by the inspector
and communicated
to the licensee
for ongoing work in this
same
area.
The
actions
taken to resolve
the issue
had not been effective.
The inspector
considered
these
problems
as
a weakness
in the implementation of the SISI
program during maintenance activities.
2.3
Com onent Coolin
Water
Pum
Motor Bearin
Oilers
On January
31, during
a plant tour in the Unit
1 auxiliary building, the
inspector
noted that the size of the motor bearing oilers installed
on
Pump
1-2 were smaller
than that
on the other
CCW pump motors for Unit 1.
The
inspector contacted
the
CCW system engineer
to ascertain
the reason
for the
difference
and to determine if the oiler's smaller capacity could affect the
operability of the
pump.
In response
to the inspector's
concerns,
the
system
engineer
performed
a prompt operability assessment
(POA) of
Pump
1-2
and
reviewed
the work order history for the
pump motor.
The system engineer
determined
thaWthe instalgod oilers did not meet'esign
requirements;
'however, their smaller'capYc'ity did not affect the operability of the
pump.
The licensee's
review of the maintenance
history on the
pump motor could not
identify a definitive cause for the installation of improperly sized bearing
oilers.
In addition to evaluating
the
impact of the smaller bearing oilers
on
Pump 1-2,
the licensee visually inspected
the other
CCW pumps
on Units
1
and
2.
The licensee
identified that
an improperly sized bearing oiler had
~iso been installed
o,i
Pump 2-1.
The inspector
followed up this finding
by visually inspecting all safety-related
pumps
and motors
in the auxiliary
building and identified another
improperly sized oiler on the outboard
motor
bearing of auxiliary feedwater
(AFW)
Pump 2-3.
The inspector
noted that
an
had
been initiated by the licensee
for improper sizing of the motor-bearing
oilers
on
AFW Pump,2-3
and containment
spray
(CS)
Pump 1-2.
The
AR for the
pump included
a
POA justifying the pump's operability.
Although
a formal
POA
was not performed for AFW Pump 2-3, the
AR provided technical justification
for the acceptability of the smaller sized oiler.
The licensee
determined
that the incorrect oiler was installed
due to an error in tne replacement
parts evaluation
(RPE) associated
with the
AFW pump motors.
The licensee
has
revised
the
RPE to reflect the proper oiler size required for the
AFW pump
motors.
The licensee
has also initiated actions
to replace
the incorrect
oilers
on all four pumps.
Conclusion:
The inspector
concluded that the installation of improperly sized
bearing oilers
on the
above
pumps did not impact the pumps'bility to perform
their safety function.
The inspector
noted that the
POAs for the
CCW pump
motors
and the
pump were technically sound.
However,
the inspector
considered
the, multiple examples
and failure of system engineers
to note these
problems during system
walkdowns to be indicative of a weakness
in the
licensee's
configuration controls during plant maintenance.
2.4
Control
Room Observations
On February
21 the inspector
observed
the conduct of operations
in the control
room during
a reduction
in power of Unit 1.
The reduction of reactor
power
was required to establish
conditions to perform
a weld repair of a cracked
weld on
a cold reheat
steam line drain connection.
Prior to reducing reactor
power,
a preevolution briefing was conducted.
The inspector
noted that the
appropriate
procedures
were referred to and followed, where applicable,
and
that the briefing covered
the important aspects
of the evolution
and the
applicable precautions.
During shift turnover,
the inspector
observed
the communications
and briefings
of the control
room operators
for the oncoming shift.
The inspector
noted
that the information pertinent
to the evolution was
communicated
during the
shift turnover.
As the reduction in power continued,
the inspector
observed
that the control operator
was attentive
and responsive
to plant parameters
and
conditions.
The inspector
noted that the axial flux diIference
(AFD) limits figure posted
on the control
panel
had expired three day&earlier.
The issued-for-use
interval of 30 days
had bee"
exceeded
without the figure having
been
rever'fied
as current.
The inspector
discussed
the deficiency with the
control operator,
who initiated actions
to obtain
a verified copy of the
figure.
The inspector later determined that the
AFD limits figure had not
been revised
since
the figure was previously issued
and that the
issued-for-use
figure was the latest revision.
Conclusion:
During the reduction of reactor
power levEl, operators
referred
to and followed applicable
procedures.
Crew briefings observed
by the
inspector
covered
the important aspects
of the evolution
and the applicable
precautions.
The failure of the control operators
to verify that control
panel
posted
are maintained current for a period of over
3 days is indicative
of inadequate
tracking of issued-for-use
procedures.
3
PLANT NAINTENANCE
(62703)
During the inspection
period the inspectors
observed
and reviewed selected
documentation
associated
with the maintenance
and problem investigation
activities, listed below, to verify compliance with regulatory requirements,
compliance with administrative
and maintenance
procedures,
required quality
assurance
department
involvement,
proper
use of safety tags,
proper equipment
alignment
and
use of jumpers,
personnel
qualifications,
and proper retesting.
Specifically,
the inspector
reviewed
the work documentation
or witnessed
portions of the following maintenance
activities:
Unit
1
~
Troubleshooting
and repair of containment
fan cooler Unit (CFCU)
1-4
motor controller
~
CCW System Backflush
Unit
2
~
Troubleshoot
and repair
(Pressure
Control Valve)
PCV-21 I/P controller
(10 percent
atmospheric
steam
dump)
~
Replace
PCV-106 regulator (air supply to
EDG 2-3 air start motors)
~
Sl
Pump 2-2 replacement
Selected
observations
from the activities witnessed
are discussed
below.
3. 1
Troubleshootin
and
Re air of Cablin
in CFCU Breaker Cubicle
On February
27
and
28 the inspector
observed
maintenance
personnel
perform
troubleshooting
and repair of cabling inside the breaker cubicle for CFCU 1-4.
This maintenance
was beirjq performed
based
upon periodic thermal
imaging data
collected
by predictive maintenance.
Thermographic
imaging of the breaker
cubicle
had identified
an elevated
temperature
on several
cables.
The inspector
reviewed the associated
work package
and referenced
procedures
and discussed
the
scope of troubleshooting with the maintenance
technicians.
The inspector
noted that the technicians
were knowledgeable
on the breaker
design
and function.
and their approach
to the troubleshooting
was methodical.
The troubleshooting
resulted
in the identification and replacement
of several
degraded
cables.
Postmaintenance
testing verified that the elevated
temperatures
had
been corrected.
Conclusion - The inspector
concluded
that the maintenance
on the
CFCU 1-4
breaker cubicle
was performed
in accordance
with applicable
procedures
and
was
effective in identifying the root cause of the elevated
temperatures
and
resolving the deficiency.
The inspector
also noted that the thermography
program
implemented
by predictive maintenance
was effective in identifying the
problem before
a failure occurred.
3.2
OEG-2-PCV-106
Re lacement
On February
15 the inspector
observed
portions of the work to replace
EDG 2-3
air start motor air supply pressure
reducing Valve DEG-2-PCV-106.
When the
inspector arrived at the work site,
the valve
had already
been
removed
from
the system
and the workers
had
taped foreign material
exclusion postings
over
the
open piping.
The inspector
reviewed
the work package
and noted that,
although the valve had
been
removed
from the system,
two of the prerequisites
for the work had not
been initialed as being completed
in the controlling work document.
The
specific prerequisites
that
had not been initialed as complete
were the
verification of the subclearance
and hanging of the red tag
and the
foreman
reporting
on the clearance.
Prior to leaving the work site the maintenance
mechanic
hung the red tag required
by the subclearance.
When questioned
by
the inspector,
the mechanic
indicated that the
foreman
had reported
on the
clearance
prior to the start of the work although
the step
had not been
initialed.
The inspector later verified that the foreman
had,
in fact,
reported
on the clearance prior to the removal of the valve.
The inspector
reviewed
the licensee's
work order procedures
and did not find
any specific requirement
to complete
work order prerequisites
prior to
commencing
work.
The inspector
discussed
the observations
with the director
of mechanical
maintenance
who indicated that
he did not believe the failure to
complete
work order prerequisites
was
a violation of procedures;
however, it
was management's
expectations
that, prior to commencing
work. prerequisites
would be completed.
Conclusion - The inspector
agreed with the licensee's
conclusion that, during
the replacement
of"'DEG-2-PCV-'106,
the ma5etenance
workers performing the work
failed to meet
management
expectations
for completion of work order
prerequisites.
4
SURVEILLANCE OBSERVATIONS
(61726)
Selected
surveillance
tests
required
to be performed
by the
TS were reviewed
on
a sampling basis
to verify that:
(1) the surveillance
tests
were correctly
included
on the facility schedule;
(2)
a technically adequate
procedure
existed for performance of the surveillance tests;
(3) the surveillance tests
had
been
performed at
a frequency specified
in the
TS:
and
(4) test results
satisfied
acceptance
criteria or were properly dispositioned.
-10-
Specifically, portions of the following surveillances
were observed
by the
inspector during this inspection period:
Unit
1
STP P-CSP-11,
Revision 0, Routine Surveillance
Test of Containment
Spray
Pump
1-1
STP P-1282,
Revision
6, Routine Surveillance
Test of Diesel
Fuel Oil
Transfer
Pump 0-2
STP P-3RV1,
Revision 9, Exercising
10 percent
Atmospheric
Dump Valves
PCV-19,
20,
21,
22
STP I-111A, Revision
5, Functional
Test of Steam Generator
Blowdown
Sample Effluent Liquid Monitor RM-19
Unit
2
~
STP P-SIP-22,
Revision
7, Routine Surveillance
Test of Safety Injection
Pump 2-2
~
STP M-16D, Revision
13A, Operation of Train
B Slave Relay K608 (Safety
Injection)
4.1
Containment
S ra
Pum
Performance
Test
On February
I the inspector
observed
portions of STP P-CSP-11,
Revision 0,
"Routine Surveillance
Test of Containment
Spray
Pump 1-1."
The test is
performed
on
a quarterly frequency to verify continued operability of the
pump.
The inspector
attended
the preevolution briefing and observed
operator
actions
in the containment
spray
pump room.
The inspector
noted that the
briefing appropriately
emphasized
the precautions
and limitations of the
surveillance
and that the procedure
was performed
in
a controlled,
formal
manner.
Duri.ng operation of the
pump,
the inspector
observed
leakage
from the outboard
mechanical
seal
of the
pump at approximately
150 drop's/min.
Noting that the
surveillance
acceptance
criteria for seal
leakage
was
no leakage
or minor
dripping,
the inspector questioned
the operators
on the acceptability of the
observed
leakage.
The operators
and the shift supervisor
agreed
that the
leakage
was greater
than anticipated;
however.
they considered
that the
leakage
would not affect the operability of the
pump
as it did not exceed
the
test's criteria for unacceptable
leakage (i.e.,
steady
stream or spraying).
The inspector discussed
the seal
leakage with the containment
spray
system
engineer.
The system engineer
explained that during previous surveillance
tests of CS
Pump
1-1 the outboard
seal
leakage
had
been
observed
at varying
levels
and that
he believed
the leakage
observed
on Fobruary
1 was not
indicative of a significant seal
degradation.
-11-
Following completion of the, test,
the inspector
observed
that water
had
sprayed
outside
the posted
surface
contamination
area
(SCA) around
the pump's
outboard
seal
area,
and informed the operators.
In response,
the operators
requested
a radiation protection technician
to survey the area.
The results
of the survey identified no spread of contamination
outside of the
SCA.
Conclusion - The inspector
concluded
that the surveillance test
was well
controlled
and that both operations
and engineering
appropriately evaluated
the impact of the observed
seal
leakage
on the operability of the
pump.
However, operators
failed to take action to address
th~ potential
spread of
contamination
from the seal
leakage until prompted
by the inspector.
4.2
Diesel
Fuel Oil Transfer
Pum
Surveillance
Test
On February
6 the inspector
observed
portions of STP P-1282,
Revision 5,
"Routine Surveillance
Test of Diesel
Fuel Oil Transfer
Pump 0-2."
The test is
performed
on
a quarterly frequency
to verify the operability of the
pump per
During the verification of the
system electrical
lineup, prior to starting
the
pump,
the inspector
noted that the operator failed to perform all of the
required actions of Step
12 '.2 prior to proceeding
to the next steps
Step
12.2.2 requires
that the transfer switch in loadcenter
IH is in the
"Unit 1" position with Breaker
52-1H-65 closed.
During the performance of
this step,
the operator failed to verify the position of Breaker 52-1H-65.
After checking that the step
had
been completed,
and prior to performing the
next step,
the inspector questioned
the operator whether
he
had verified the
breaker position.
The operator
indicated that
he
had not and returned
to the
switchboard
and verified that the breaker
was in the required position
as
required
by the step.
The inspector
observed
the remainder of the test
and noted that the
pump
operated within the limits specified
in the surveillance
procedure
and that
there
were
no leaks during
pump operation
on the portion of the system located
within in the vault.
Conclusion:
The failure to>>.perform the, required actions of a surveillance
test constitutes
a violation of minor significance.
This violation is being
treated
as
a noncited violation, consistent
with Section
IV of the
NRC
4.3
Sl
Pum
2-2 Surveillance
Test
4.3.1
Licensing Actions in Preparation
for SI
Pump Testing
Background:
Sl
Pump 2-2 was replaced
in March
1995 after the
pump failed to
develop required differential pressure
during surveillance testing.
Prior to
conducting
the test,
the licensee
submitted contingency
License
Amendment
and
Notice of Enforcement Discretion
(NOED) requests
to increase
the allowed
outage
time
(AOT) for the
pump from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to
7 days for pump replacement.
-12-
The
pump was replaced
in accordance
with 10 CFR 50.59,
tested,
and returned
to
an operable
status
in less
than
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Since
the
pump was returned
to an
status within the allowed outage
time there
was
no need for NRC
approval of the contingent
requests
and the licensee later formally withdrew
them.
In Hay
1995 the licensee
determined
that the replacement
Sl
pump did not have
documentation
that
LOKTITE had
been applied to the shaft locknuts during
assembly.
The licensee
determined
that the absence
of LOKTITE made
the
locknuts susceptible
to loosening.
This was the
same
mechanism for
degradation
that
was determined
to have
caused
the decrease
in pump
performance of the previously installed
pump.
The licensee
performed
an
operability evaluation
(OE) which provided the basis for concluding that the
pump was operable
and instituted
more restrictive performance criteria during
periodic
pump tests.
During the performance of the quarterly
pump test
in August
1995,
a slamming
noise
was noted
on the
pump start
as well as
a slight decrease
in differential
pressure.
At that point the cause of the noise
was indeterminate;
however, it
was believed
to have
been
caused
by
a water
hammer,
due to
a void in the
piping or check valve slam.
A week later the
pump
was tested
again with
a
slight decease
in performance,
although
no slamming noise
was noted.
The
pump
was tested
again
in November with a continued
decrease
in differential
pressure
and the slamming noise.
The
pump was placed
on
an "alert" status
in
accordance
with the compensatory
measures
established
by the
OE.
Placing
the
pump on "alert," required
pump performance
testing every
6 weeks
as
opposed
to
the normal quarterly frequency.
In January
1996 the
pump was tested with no
change
in differential pressure
and
no slamming noise.
On February
15,
1996,
6 days prior to the next scheduled
performance
of the
pump test,
the licensee
submitted
a license
amendment
request
(LAR) to the
NRC
requesting
an increase
in the allowed outage
time from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to
7 days for
pump replacement.
On February
22 the licensee
provided the
NRC
a draft
version of
a contingent
HOED request
to allow the continued operation of
Unit
2 with one train of SI system
inoperable for up to
7 days,
4 days longer
than allowed by TS.
Preliminary discussions
regarding
the basis for the
request
between
.the
NRC and the licensee
revealed
that the licensee
had
known
of the pump's
degraded
condition
and the potential
need for an extension of
the
AOT for pump replacement
since
Hay 1995.
Consequently,
sufficient time
nad
been available for the licensee
to process
and gain
NRC approval of an
to increase
the
pump
AOT.
Therefore.
the condition that resulted
in the
need
for an
NOED was considered
to have
been avoidable.
Following the discussion
with the
NRC the licensee
decided
not to pursue
formal submittal of the
request.
4.3.2
Pump Testing Resulting
in
Pump Replacement
On February
22 the inspector
observed
the performance of STP P-SIP-22,
Revision
7, "Routine Surveillance
Test of Safety Injection
oump 2-2."
-13-
In preparation
for the
pump test
the licensee
installed acoustic
emission
monitoring equipment
on several
locations
on the
pump
and adjacent piping.
A
temporary procedure
was
issued
to record investigative data concurrent with
the start of the
pump.
The
pump start
was initiated by energizing
the Train
B
slave relay at the solid state protection
system
safeguard
test cabinet.
Initiating the
pump start with the test signal
also started
the following
pumps:
Pump 2-2, Residual
Heat
Removal
(RHR)
Pump 2-1,
Pump 2-2.
The
inspector
was in the
pump
room for the test
and hea"d
a loud slamming noise
concurrent with the stuart of the
pump.
The licensee's
evaluation of the acoustic
emission
data
indicated that the
noise
emanated
from SI
Pump 2-2.
The
pump performance
data did not
show any
further degradation
in pump performance
since
the previous surveillance test;
however,
since
the
slamming noise
was determined
to have
come
from the
pump,
the licensee
declared
the
pump inoperable
and
commenced
replacement
of the
pump.
It should
be noted that the licensee
considered
that there
was
a
potential for the
slamming noise to have
been
caused
by
a water
hammer
from
the start of the
RHR pump;
however,
there
were insufficient accelerometers
installed
on the suction of SI
Pump 2-2 to provide the data
necessary
to
further investigate
the issue.
4.3.3
Postmaintenance
Testing Following SI
Pump Replacement
Following replacement
of the
pump,
the inspector
attended
the preevolution
briefing and observed
the test of the replacement
pump.
The replacement
pump
was instrumented
to monitor for any unusual
noises
during the test.
The
pump
was started
manually from the control
room and developed
a differential
pressure
greater
than the minimum required
by TS and within the acceptable
band of the surveillance.
There
was
no slamming noise
noted during the
pump
start or at any other time during
che testing.
4.3.4
Conclusion
The replacement
and testing of Sl
Pump 2-2 was well coordinated,
and,
as
a
result,
was accomplished
in
a timely manner within the allowed 72-hour action
statement.
Briefings conducted for the test
were thorough.
The testing
observed 4y the inspector
was well organized
and the personnel
involved were~
knowledgeable of their assigned
duties.
Following'he licensee's
conclusion
that
LOKTITE had not been
used during
pump assembly
and the decrease
in pump
performance,
the licensee failed to take appropriate
licensing actions
to
pursue
extension of the
TS allowed outage
time for pump replacement
as
opposed
to reliance
upon
an
NOED request.
The
LAR submitted
on February
15,
1996, did
not allow sufficient time for public comment
and
NRC review prior to the
scheduled
performance
of the surveillance test.
4.4
Exercisin
10 Percent
Atmos heric Steam
Dum
Valves
On February
6 the inspector
observed
portions of STP V-3R1, Exercising
10 percent
Atmospheric
Dump Valves
PCV 19,
20,
21,
22, which accomplished
the
quarterly inservice
atmospheric
steam
dump valve stroke timing pursuant
to the
S
-14-
requirements
of TS 4.0.5.
The measured
stroke testing of PCV-19 was within
the acceptance
limits of the procedure.
The inspector
noted that the first
stroke of the valve in the test direction
was recorded
as the official test
and that the appropriate
TS action statement
was entered
during the
performance of the test.
During the testing,
the inspector
noted that the cover to mechanical
panel,
PM-308, which contains
the solenoid valves
and control air lines that supply
the
PCV-19 actuator,
was not securelg&astened.
Closer inspection
revealed
that
a number of the clips that hold the panel
cover in place
had not been
tightened.
The inspector questioned
the operator
about
the condition of the
panel.
The operator
opened
the panel
and noted approximately
1/2 to
1 inch of
standing water in the bottom of the panel.
The operator
then
opened
Panel
PM-309 for PCV-20
and noted approximately
1/8 inch of water in the
bottom of the panel.
The inspector
noted that there
were drains installed in
each of the panels
but the installation did not allow all of the water to
drain from the panels.
The operator wrote
an
AR to document
the standing
water found in the panels'he
response
to the
AR concluded that the water
intrusion did not effect the safe operation of the solenoid
valves
and exposed
terminal
boards
mounted
in the panel.
Conclusion:
The inspector
noted that the test
was performed per the procedure
and that the valve operated within the acceptable
limits of the surveillance.
The water in the panels
did not appear to have
any current
impact
on valve
operability;
however, failing to secure
the panel
cover clips
on
safety-related
panels
exposed
to the weather
was judged to be
a poor work
practice.
5
ONSITE ENGINEERING
(37551)
5. 1
Investi ation of
Pum
Surveillance Testin
5. 1.1
Background
On September
15,
1994,
the licensee
discovered
that closing the
CC pumps
common recirculation flow path isolation valves
(CVCS-8105 or 8106) during
periodic
pump performance~tests
potentially impacted
the oPerability of both
'harging
pumps.
The concern identified that closing the recirculation valves,,
secured
the minimum flow re"uired for internal cooling of the
pump to prevent'
overheating.
5.1.2
Licensee
Investigation
and Corrective Actions
Following identification of the concern,
the licensee's
regulatory compliance
organization
was consulted
to determine
the reportability of the condition.
Since
the
impact of clos~no
the valves during testing
had not been fully
evaluated,
no reportability determination
was
made at that time; however,
a
nonconformance
report
(NCR) was initiated
on September
24,
1994.
-15-
The
NCR documented
that the closure of the
pump recirculation valves during
periodic
pump testing
was inconsistent with the licensee's
response
to
NRC
"maintenance
of Adequate
Minimum Flow Thru Centrifugal
Charging
Pumps
Following Secondary
Side High Energy Line Rupture."
The
NRC
bulletin identified the potential for CC
pump failure due to loss of
recirculation flow under accident conditions
where reactor coolant
system
pressure
remained
at or near the
pump shut-off head.
The licensee's
initial investigation of the issue
focused principally upon the
impact of the
loss of recirculation
on the cooling of the
pumps.
The licensee
responded
to
the concern
by revising the surveillance
procedure
to c'lose
a manual
isolation
valve that secured
the recirculation flow 'only for the
pump being tested.
After revision of the surveillance
the technical
review group
(TRG) did not
close
the
NCR and did not hold any meetings
to discuss
the issue for a period
of approximately
6 months.
Closing
pump recirculation isolation valves during testing
increases
the
charging injection flow rate.
The
TRG failed to evaluate
the
impact of the
increased
charging injection flow on the accident
analyses until January
19,
1996,
when concerns
were raised
to the
TRG by
a system engineer.
On February
1,
1996.
the licensee
determined
that closure of recirculation
flow path Valves 8105
and
8106 for testing placed
the emergency
core cooling
system
in an unanalyzed
condition.
Following the determination
the licensee
made
1-hour nonemergency
report to the
NRC that both units
had
been previously
placed
in an unanalyzed
condition during
pump surveillance testing.
From September
1994 to February
1996 the investigative actions
taken in
response
to concerns
regarding
pump operability failed to consider the
impact of closing the recirculation isolation valves
on the accident
analyses.
Significant conditions that are adverse
to quality are required to be
investigated
and corrected
in
a timely manner.
The actions initiated by the
licensee
following identification of concerns
with
pump surveillance
testing
were not considered
to have
been either prompt or comprehensive.
5. 1.3
Conclusion
10
CFR gart 50, Appendix B, Criterion XVI "Corrective Action,",requires that
measures
shall
be established
to assure
tkht conditions
adverse
'to quality.A
such
as failures, deficie",-ies,
and deviations
are promptly identified and
corrected.
The licensee's
failure to fully consider
the effect of closing the
pump recirculation valves
on accident
analyses
for over
1 year after the
initial concerns with the test
were identified is
a violation of
10 CFR Part 50, Appendix B. Criterion XVI, Corrective Action (Violation 275/9602-02,
323/9602-02).
-16-
6
PLANT SUPPORT
ACTIVITIES
(71750)
The inspectors
evaluated
plant support activities
based
on observation of work
activities,
review of records,
and facility tours.
The inspectors
noted the
following during these evaluations.
6. 1
Re air of Fire
Pum
0-1 Dischar
e Isolation Valve
On February
7 licensee
mechanical
maintenance
personnel
overhauled
the
discharge
isolation valve to fire Pump 0-1.
The clearance
associated
with the
maintenance
required that several fire water hose reel stations
be isolated
in
the Unit
1 Fuel Handling Building.
The inspector discussed
with the licensee
the compensatory
actions
implemented
to ensure
adequate
fire fighting
capability was maintained
in the fuel handling building.
The inspector also
toured the fuel handling building with a fire brigade
member to walk down the
temporary fire hoses
that
had 'been
staged for providing water to the isolated
hose reel stations.
The inspector
noted that the fire brigade
member
was
knowledgeable
on the actions
they would take in the event of
a fire in the
affected
areas.
The inspector
concluded that the licensee
had adequately
assessed
the
impact
of the maintenance
on the in-plant fire protection
system
and
had
implemented
appropriate
compensatory
measures.
Following completion of the work the
inspector
observed
portions of the surveillance
on firewater
Pump 0-1
performed in accordance
with STP P-13A,
Rev.
15
XPR, "Fire Pumps
Performance
Test."
6.2
Failure to Meet Fire Bri ade Trainin
Re uirements
6.2.1
Background
On January
19 the licensee
noted in AR A0391417 that there
were several
members of the fire brigade
whose qualifications
had lapsed
because
they had
not completed all of the requalification requirements.
Further investigation
by tne inspector
revealed
that
as of January
19, greater
'..')an
70 percent of
the personnel
listed
as qualified fire brigade
members
did not have current
qualifications.
In order
to,.be able to meet
minimum fire brigade
manning
requi'rements
Ne licensee
administered
challenge
exams
to personnel
whose
qualifications
had lapsed.
Prior to January
19,
1996,
the licensee
had utilized
a computer bulletin board
to list all qualified fire brigade
members;
however,
as fire brigade
member
training lapsed,
the bulletin board
had not been properly updated.
Since the
shift watchlists,
which designate fire brigade
members,
had
been written
utilizing the bulletin board.
personnel
whose training
had lapsed
had
been
assigned
to the fire brigade.
-17-
6.2.2
Review of Fire Brigade Training
The inspector
reviewed
the qualification matrix previously used
by the
licensee
to track fire brigade training
and noted that in January
1996,
the
fire brigade qualifications for 79 of the
97 personnel,
listed
as being
qualified fire brigade
members,
had lapsed.
The majority of the individuals
had not received
the required biennial portable fire extinguisher training
since July 1993.
In addition,
the inspector
noted that other fire brigade
members'raining
had lapsed
in other areas,
including techniques
for
suppression
of electrical
and radiological fires.
The inspector
reviewed
the shift watchlists for December
29,
1995, for the
7 p.m.
to
7 a.m.
watches.
The review found that none of. the personnel
listed
as fire brigade
members
had current fire brigade qualifications.
6.2.3
Fire Brigade Training and Manning Requirements
TS 6.8.1 requires that written procedures
shall
be established,
implemented,
and maintained that cover the implementation of the fire protection
program.
Fire Brigade training is
a part of the fire protection
program.
Diablo Canyon
Procedure
Tgl.DC12, Revision
1, "Fire Brigade Training," details
the training
requirements
for fire brigade
members.
Section 5.3.3.c.3
requires that fire
brigade continuing training include
a biennial
review of the subject matter
contained
in the initial fire brigade
member
and leader training courses
in
each of the subject
areas
specified
in UFSAR Appendix 9.5H.
The classroom
instruction program described
in the
UFSAR requires
instruction in the proper
use of fire fighting equipment
and the correct
method for fighting various
types of fires.
Fire brigade
manning requirements
are detailed
in OP1.DC12,
Revision
2,
"Conduct of Routine Operations."
OPI.DC12 Section
5.9 requires that
a site
fire brigade of at least five members
shall
be maintained onsite at all times.
6.2.4
Previous
NRC Findings in the Area of Fire Brigade Training
NRC Inspection
Report 50-275/95-09;
50-323/95-09,
issued
on July 7,
1995,
contained
a Notice of Violation (275/950)-02)
that cited
a Severity Level=,IV
violation regarding
the licensee's
failu're to ensure that all members of the
fire brigade participated
in required quarterly fire drills.
Following
receipt of the violation, the licensee initiated
an
NCR on the missed fire
drills.
The inspector discussed
the
scope of the
NCR with the individual
assigned
as the chairman of the
TRG responsible
for investigation of the
NCR.
The individual indicated that although
the
TRG had questioned
whether there
were problems
in other areas
of fire brigade training,
no in-depth review had
been
performed.
Although the initial problem with fire brigade
member qualification was
identified by the licensee,
the issue
is considered
to
be more than
a minor
violation for several
reasons.
0
-18-
Corrective actions initiated in response
to Violation 275/9509-02 failed
to identify fire brigade
member qualification deficiencies.
~
The errors resulted
in
a significant number of personnel
being routinely
assigned
to the fire brigade without having completed
the required
training.
~
The situation existed over
a period of several
months.
6.2.5
Conclusion
The failure to complete proficiency training required
by Tgl.DC12 and the
UFSAR for individuals assigned
to the fire brigade is
a violation of TS 6.8.1,
which requires
that written procedures
sha'll
be established,
implemented,
and
maintained that cover the implementation of the fire protection
program
(Violation 275/9602-03,323/9602-03).
6.3
Radiolo ical
Work Practices
within the Radiolo icall
Controlled
A~rea
6.3. I
Observations
and Findings
The inspector
performed
several
tours of the
RCA to assess
the effectiveness
of the licensee's
radiological controls.
As
a result,
several
deficiencies
in
radiological
work practices
were identified.
During
a to<<r of the
RCA on
February
5,
1996,
the inspector
noted
poor housekeeping
practices
associated
with ongoing work in the hot shop
SCAs located
in the fuel handling
building (FHB).
The inspector
noted the following deficiencies
which
increased
the potential for the spread of contamination
outside of the
SCAs:
Items were laid across
SCA boundaries.
Tools
and trash
were
on the floor of the
SCA.
Used protective clothing was laying on the floor.
A hose
crossed
the
SCA boundary without being taped
down.
The radiological posting at the entrance
to the
SCA was down.
.Based
upon:.these
observations,
the inspector questioned
whether it would be
prudent to perform
a survey of the area
to verify that there
was
no spread of
contamination.
Personnel
performed
a survey of the hot shop
and determined
that there
had
been
no spread of contamination
outside of the
SCAs.
After the
inspector
voiced concerns
over the condition of the
SCAs in the hot shop,
the
licensee
stopped all work in these
areas until conditions
were
improved.
The
actions initiated by the licensee
in response
to the
issues
were aggressive
and
have significantly improved the conditions
in the
FHB hot shop work area,
The inspector considered
these
actions
to be warranted
and prudent
based
upon
the conditions
noted.
0
JP 8
In addition,
the inspector
noted other conditions within the
RCA which raised
concerns
about the implementation of radiological controls.
Observations
included the following:
~
Dry boric acid crystals
in
a walkway which had accumulated
as
a result
of a dripping pipe cap.
This condition was estimated
to have existed
for several
days.
A contamination
survey performed
indicated
the
presence
of contamination
outside of a surface
contamination
area.
~
A radiation
area posting that
had fallen down
ana
was
no longer
effectively posting the area.
~
Hags of used potentially contaminated
protective clothing were setting
in
a puddle of rainwater that crossed
over
an
SCA boundary.
~
Welding lines that were coiled across
the
SCA boundary during the
SIP-2-2 replacement.
6.3.2
Conclusions
The inspector dete rmined that these
issues
were weaknesses
and did not
constitute
a violation.
The observations
have,
however,
furthered
a
continuing concern
about radiological
housekeeping
practices
and worker
awareness
of radiological
hazards
and controls.
It is also noteworthy that
routine supervisor
tours of the
RCA had not identified and corrected
the
problems
noted
by the inspector.
The inspector
concluded that the
observations
were indicative of a decline in performance
in the area of
radiological controls.
7
FOLLOWUP - OPERATIONS
(92901)
7.1
Closed
Violation 50-275 95015-01:
Failure to Ensure
Ade uate
Containment
Closure Durin
Refuelin
0 erations
~
Disconnected
instrument tubing to
RHR Pump 2-1 recirculation flow switch
was noted to be dripping onto the
RHR pump
room floor.
The subject violation occurred during Onit
1 refueling operations
(core"
offload) when the licensee
discovered that
two of the main steam isolation
valves
(NSIVs)
had failed to fully close.
This condition,
in conjunction with
the removal of the
secondary
manways,
provided
a direct
pathway
from the containment
atmosphere
to the environment.
The inspector
reviewed
the licensee's
response
to the Notice of Violation,
dated
December
21.
1995,
and
Revision 0, dated
November
10,
1995.
The inspector also verified the licensee's
installation of gag devices
on the HSIVs prior to the subsequent
core reload.
-20-
The main factor that contributed to the violation was the licensee's
failure
to implement
adequate
corrective actions
from
a similar event that occurred
in
1994.
The licensee
previously identified incomplete closure of the
during
a Unit
2 refueling outage
in October
1994.
As
a result of that event,
the licensee
planned
to revise its operating
procedures
to require
a visual
inspection of the actuator position of the MSIVs.
However, visual observation
of the HSIV actuator position during the subsequent
Unit
1 refueling outage
was not performed until after the core offload.
Licensee corrective actions
included replacement
of the HSIV actuator
pins to reduce frictional bin&~g of
the valves
and the revision of the library clearance
work instruction to
require
the installation of an HSIV gagging device
when the HSIVs are relied
upon to provide containment
closure.
As discussed
above,
the gagging devices
were installed
on Unit
1 prior to core reload.
In their response
to the
Notice of Violation, the licensee
has also committed to replacing
the actuator
pins
on the Unit
2 MSIVs during its next refueling outage,
scheduled
for April
1996.
The inspector verified that the actions described
in the licensee's
response letter of December
21,
1995,
to be reasonable
and
appeared
to address
correction of the circumstances
which contributed
to the violation.
8
FOLLOWUP ENGINEERING
(92903)
8.1
Closed
Ins ection Followu
Item 50-275 9334-01:
Unex lained Difference
Between Calculated
and Actual Estimated Critical Position of Control
Rods
During
a restart
on December
31,
1993, following a trip on December
26,
1993,
the actual critical position of the control
rods
was
79 steps
less
than the
calculated
estimated critical position.
While the difference
between
the
actual
and estimated critical positions
was the largest
experienced
by the
licensee
to that time, it was within TS limits.
The licensee
and Westinghouse
engineers
performed
an investigation of the
large difference
between
actual
and estimated critical posi:ions.
issued its report
on June
7,
1994.
The inspector
reviewed
the licensee's
and Westinghouse's
evaluations.
The
inspector
found that both concluded that the calculated
value provided
by the
APEX code
was in good agreement
with the
3D ANC model.
concluded that the effects of variations
in boron concentrations,
measured
boron-10 isotopics,
and rod positions, collectively, could have
4dused
the difference
between
the actual
and estimated critical positions.
The inspector
concluded that, while c'riticality occurred
sooner
than expected,
the estimated critical position
was appropriately calculated
and criticality
occurred within the allowable range..
The inspector
also
found that
a
conservative
approach
was taken
by licensee
engineers
to evaluate this issue
and reach
an appropriate
conclusion.
0
-21-
8.2
Closed
Unresolved
Item 50-275 95014-04:
Ade uac
of 230 kilovolt
kv
S stem Corrective Actions
and
0 en
Licensee
Event
Re ort 50-275
95007:
230 kv
S stem Outside
A
endix A. General
Desi
n
Criteria
17
in Some
Cases
The unresolved
item was
opened
to review the root cause(s)
of the degraded
230 kv source of offsite power to the Diablo site.
Violation 50-275/95014-03
documented initial failure of the licensee
to take corrective actions after
they
became
aware of the degraded
230 kv system.
The inspector
reviewed the
unresolved
item and determined
that it was
now duplicated
by
LER 50-275/95007,
as discussed
below.
Final
NRC review of the acceptability of the licensee's
root cause
and corrective actions for the degraded
230 kv system will be
by
further review of the
LER.
The inspector
reviewed
the operability of the
230 kv and
500 kv sources
of
offsite power during the storm of December
11,
1995.
The inspector determined
that the
500 kilovolt system
remained
throughout
the storm,
and that
the
230 kilovolt system
was properly declared
when
two of four
power lines supporting
the system
were lost.
The inspector
noted that the problems with the
230 kv system
were reported
in
LER 50-275/95007,
Revision 0.
This brief LER stated
that
a revision would be
issued
to provide
a root cause
and corrective actions.
The inspector
determined
that
an understanding
of the licensee's
position
on the cause(s)
of
the
LER and their planned corrective actions
would assist
in the review of the
LER.
The licensee
informed the inspector that they planned
to issue
the
revision in the near future.
The inspector deferred
review of the
LER pending
the licensee
planned revision.
9
IN-OFFICE REVIEW OF LICENSEE
EVENT REPORTS
(90712)
The inspectors
performed
a review of the following LERs associated
with
operating
events.
Based
on the information provided in the report,
review of
associated
documents,
and interviews with cognizant
licensee
personnel,
the
inspectors
concluded
that the. licensee
had
met the r porting requirements,
addressed
root causes,
and taken appropriate corrective actions.
The
followigg LERs were closed:
tl
9. 1
Closed
LER 275 95-09
Revision 0:
Turbine
and Reactor Trip Due to
Failure of Auto Stop Oil Pilot Valve Seat Material.
This event
was discussed
in Inspection
Report 50-275/95-14.
No new issues
were revealed
by the
LER.
9.2
Closed
LER 275 95-012.
Revision 0:
Technical Specification 3.9.4,
Requirement
for Containment
Closure During Refueling Not Met as
a Result of
Inadequate
Evaluation.
This event is discussed
in Section
7. 1.
9.3
~Closed
LER 275 95-17.
Revision 0:
Manual Reactor Trip Due to Heavy
Debris Loading to Traveling Screens.
This event
was discussed
in
NRC
Inspection
Report 50-275/95-18.
No new issues
were revealed
by the
LER.
-22-
9.4
Closed
LER 275 95-15
Revision 0:
Manual Reactor Trip Oue to Loss of
Oue to Design Deficiency.
This event
was discussed
in Inspection
Report 50-275/95-16.
No new issues
were revealed
by the
LER.
10
REVIEW OF
COMMITMENTS
A recent discovery of a licensee
operating their facility in
a manner contrary
to the
UFSAR description highlighted the
need for a special
focused
review
that compares
plant practices,
proces~res,
and/or parameters
to the
description.
During
a portion of the inspection period (February
1 through
March 2,
1996),
the inspectors
reviewed the applicable
sections of the
that related to the inspection
areas
discussed
in, this report.
-The following
inconsistency
was noted
between
the wording of the
UFSAR and the plant
practices,
procedures,
and/or parameters
observed
by the inspectors.
10. 1
UFSAR Radionuclide
Source
Term
During
a review of the licensee's
UFSAR, the inspector identified an apparent
discrepancy
in the assumptions
utilized to determine
the plant's radionuclide
source
term.
Specifically, the
UFSAR assumed
the plant would operate
on
a
12-month cycle at
a capacity factor of 80 percent.
Currently, Diablo Canyon
Units
1 and
2 are operating
on
an
18-month cycle
and
have historically
exceeded
an
80 percent capacity factor.
In response
to the inspector's
concerns,
the licensee
reviewed their source
term analyses
and determined
that calculations
had
been
performed for various
operating cycle lengths,
including
18 months,
and that the
12-month operating
cycle effectively bounds
the source
term.
Similarly, capacity factor
differences
did not affect the source
term calculation.
The inspector
reviewed the analyses
and
had discussions
with licensee
and
NRC personnel
to
confirm the licensee's
conclusion that the calculations
for the
12-month cycle
with an
80 percent capacity factor were bounding
and reasonable.
The licensee
has
issued
an
NCR to clarify the
FSAR.
I ~
ATTACHMENT 1
PERSONS
CONTACTED
Licensee
Personnel
G.
H. Rueger.
Senior Vice President
and General
Manager,
Nuclear
Power
Generation
Business
Unit
W.
H. Fujimoto, Vice President
and Plant Manager,
Diablo Canyon Operations
L.
F.
Womack,
Vice President,
Nuclear Technical
Services
- S.
D. Allen, Supervisor,
Balance of Plant Engineering
M. J.
Angus,
Manager,
Regulatory
and Design Services,
- T. R. Baldwin, Senior Engineer,
Nuclear
Steam
Supply System
(NSSS)
Engineering
J.
R. Becker, Director, Operations
D.
H. Behnke,
Senior Engineer,
Regulatory Services
E.
Chaloupka,
Engineer,
Surveillance
Engineering
- D. K. Cosgrove,
Supervisor,
Safety
and Fire Protection
- W. G. Crockett.
Manager,
equality Services
H.
E. Craig, Shift Foreman,
Operations
- R. N. Curb,
Hanager.
Outage
Services
J
~
S. Ellis, Instructor,
NPG Training
- T. F. Fetterman,
Director, Electrical
and Instrumentation
and Control
Systems
Engineering
J.
- N
- W.
- T
- C
- L
- C
- R
- J
H
C
R
- R
H.
A.
L.
R.
A.
D.
A.
A.
Galle,
Engineer,
NSSS Engineering
Gaudiuso,
Supervisor,
Procedure
Services
Team
Ginter,
Engineer,
NSSS Engineering
Grebel, Director, Regulatory
Support
Groff, Director,
Secondary
Systems
Engineering
Hagen, Director, Safety,
Health
and
Emergency
Services
Harbor,
Engineer,
Regulatory
Support
Harris. Director. Materials Services
Hays, Acting Manager,
Operations
Services
Hinds. Director. equality Control
Hug, Supervisor.
Emergency
Planning
Johnson,
Fire Marshall.
Emergency
Services
Johnson,
Supervisor.
Regulatory Services
Hagruder,
Shift Supervisor,
Operations
- D. B. Hiklush, Manager,
Engineering
Services
- J. E.:Holden,
Manager,
Maintenance
Services
- E: P. Nelson,
Supervisor,
Materials Services
p
- D
- L
- R
H
- H
- D
- D
R
- J
Nugent,
Senior
En..',neer,
Regulatory
Support
Oatley, Director, Hecnanical
Maintenance
Parker,
Engineer.
Nuclear Safety Engineering
Powers,
Acting Plant Manager,
Diablo Canyon Operations
Phillips. Director. Technical
Maintenance
Somerville.
Senior Engineer,
Radiation Protection
Taggart. Director. Nuclear Safety Engineering
dosburg.
Director.
NSSS Engineering
Waltos, Director, Balance of Plant Engineering
Young. Director, equality Assurance
1.2
NRC Personnel
- M. Tschiltz, Senior Resident
Inspector
- J. Sloan,
Senior Resident
Inspector,
San Onofre Nuclear Generating
Station
- Oenotes
those
attending
the exit meeting
on March 6,
1996.
2
EXIT MEETING
An exit meeting
was conducted
on March 6,
1996.
Ouring this meeting,
the
inspectors
reviewed the scope
and findings of the report.
The licensee
acknowledged
the inspection findings documented
in this report.
The licensee
did not identify as proprietary
any information provided to, or reviewed
by
the inspectors.
0
ATTACHMENT 2
ACRONYHS
AFO
CFCU
FHB
LER
HSIV
PANS
POA
RPE
SCA
SISI
TS
axial flux difference
allowed outage
time
action request
component cooling water
containment
fan cooler
containment
spray
emergency
diesel
generator
fuel handling building
license
amendment
request
licensee
event report
nonconformance
report
notice of enforcement discretion
nuclear
steam
supply system
operability evaluation
post accident monitoring system
pressure
control valve
public document
room
prompt operability assessment
plant process
computer
residual
heat
removal
repair parts evaluation
surface
contamination
area
safety injection
seismically
induced
system interaction
surveillance test
procedure
technical
review group
Technical
Specification
Updated
Final Safety Analysis Report
O.