ML16342C896
| ML16342C896 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 04/05/1995 |
| From: | Kirsch D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342C895 | List: |
| References | |
| 50-275-95-02, 50-275-95-2, 50-323-95-02, 50-323-95-2, NUDOCS 9504210280 | |
| Download: ML16342C896 (48) | |
See also: IR 05000108/2002018
Text
ENCLOSURE 2
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-275/95-02
50-323/95-02
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 Site.
San Luis Obispn County, California
'Inspection
Conducted:
January
8 through February
18,
1995
Inspectors:
H. Hiller, Senior Resident
Inspector
H. Tschiltz. Resident
Inspector
J.
Sloan.
Senior Resident
Inspector
G. Johnston,
Senior Project
Inspector
R. Azua.
Resident
Inspector
Approved:
ate
Ins ection
Summar
Areas
Ins ected
Units
I and
2
Routine,
announced
inspection of operational
safety verification. plant maintenance,
surveillance
observations,
onsite
engineering.
plant support. activities,
followup maintenance,
followup plant
operations,
and in-office review of licensee
event reports
(LERs),
Results
Units
1
and
2
~0erations:
The Notice of Enforcement Discretion request
regarding solid state
protection
system
(SSPS) circuit vulnerability was strong
and well
coordinated
and
showed excellent
safety awareness.
Unit
2 was maintained
at
50 percent
power during
a period of heavy
Pacific
Ocean
swelIs following condenser
cleaning to minimize further
sea growth fooling of the condenser
and intake traveling screens.
This
95042i02BO 950417
ADOCK 05000275
Q
-2-
Vr,
~ 4
~
Cg
conservative
operational
decision demonstrated
an exceptional
safety
sensitivity during
a period ~here repeated
condenser
fouling was
probable.
Operator simulator training performed
as
a result of the weaknesses
noted during the response
to the dual unit trip was challenging for the
crew and utilized an inr ~vative approach
to training by accounting for a
reduced
crew presence
in the control
room.
~
Reactor trip bypass
breaker operations
in support of Technical
Maintenance
(TM) activities were not performed
in accordance
with
licensee 'procedures.
Certain steps
which required concurrent
verification by two individuals were initialed as performed
when,
in
fact.
they were not performed
as specified
by the procedure
and resulted
in
a violation.
Licensee
procedures
lacked
the necessary
specificity to assure
proper
alignment of alternate
power supplies for safety related
components
having alternate
power supplies.
This problem manifested itself in
three different systems.
one
found by the
NRC and
two others
found
during your evaluations.
~
Maintenance:
~
Training of
a maintenance
crew on
SSPS training equipment
beFore
performing
a sensitive
design
change
in the field demonstrated
excellent
safety awareness.
~
A proactive
review of periodic surveillance
test
data for a component
cooling water
{CCW) heat
exchanger
(HX) inlet auxiliary saltwater valve
detected
an increasing
trend
in the valve stroke time.
Investigation
and additiona'1
testing of the valve was performed promptly and revealed
further degradation
of valve performance.
Initial identification and prompt resolution of
a generic design
vulnerability in t'
SSPS
was noteworthy.
Response
in the
implementation of the design
change,
requiring the timely integration of
multiple disciplines,
was strong.
The existing design of the
SSPS did not incorporate
adequate electrical.
isolation of nonsafety-related
inputs from the engineered
safety
feature
(ESF) actuation logic power supplies.
An unresolved
item was
identified for this problem pending further
NRC review.
System engineer
involvement
in the investigation
and corrective actions
for flow control valve
(FCV) 603 stroke time were considered
proactive,
p'C
~9 ~
-3-
and quality control
(0C)
involvement in troubleshooting
and technical
evaluation
was considered
very strong.
~P1
!
~
Site access
authorization for several
former
NRC employees
had not been
terminated
following NRC notification of the licensee
that the personnel
were
no longer authorized site access.
Sugar
of Ins ection Findin s:
~
Violation 323/9502-01
was identified (Section
3. I).
~
Unresolved
Items 275/9502-01
and 323/9502-01
were identfffed
(Section 5.1)
~
Violation 323/9429-01
was closed
(Section 9.1).
Violation 323/9429-02
was c1osed
(Section 9.2).
Violation 323/9429-03
was closed
(Section 9.3).
Followup Item 323/9324-01
was closed
(Sectfon 9.4).
~
Violation 323/9418-01
was closed
(Section 9.5).
~
Followup Item 275/9430-05
was closed
(Section 10.1).'
LERs 275/92- 18. Revision 0: 275/94-020,
Revision 0: 323/94-010,
Revi:ion 0; 275/93-12,
Revision
2:
and 323/94-012,
Revision 0, were
closed
(Section Il).
Attachments:
~
Attachment
1 - Persons
Contacted
and Exit Meeting
~
, Attachment
2 - Acronyms
-4-
DETAILS
r
llama a
1
PLANT STATUS
(71707)
i.i
Unit i
Unit
1 began
the report period at
100 percent
power.
On January ll, 1995,
power was reduced
to 60 percent
due to sea
growth fouling of the condenser.
Following condenser
cleaning,
power was increased
to
100 percent
on
January
12,
19~3.
Unit
1 operated
at
100 percent for the remainder of the
report period.
1.2
Unit
2
Unit
2 began
the report period at 50,percent
power.
Unit 2 power had
been
decreased
on January
7,
1995,
due to heavy pacific Ocean swells which caused
sea growth fouling of the condenser.
On January
10,
1995, Unit
2 power was
further reduced
and the unit was separated
from the grid for main turbine
control
system troubleshooting
and repair.
Later that
same
day the unit was
paralleled with the grid and power was
increased
to 50 percent.
Unit 2
returned
to
100 percent
power
on January
12.
1995.
Unit 2 reduced
power on two subsequent
occasions
due to sea
growth fouling of
.
the condenser
on January
16 and
23,
1995.
On both occasions
the unit returned
to
100 percent
power the next day after condenser
cleaning.
Unit
2 operated
at
100 percent for the remainder of the report period.
1.3
Re uest to Exercise
Due to Vulnerabilit
of a
Train of ESF Automatic Actuation to Electrical Faults
on
Some
SSPS
In uts
e
a
'l
~
~Back round
Some of the input signals
to the
SSPS
system
are nonsafety related
and were electrically connected
to safety-related
120-Vac circuits.
These
circuits also
feed the
SSPS
power supplies
for reactor trip and
ESF master
relay actuation logic functions,
Descri tion of Concern
On February
1,
1995,
as
a result of a walkdown to
resolve
a design basis
reconstruction
concern
on input circuitry, the licensee
identified that the
SSPS
input circuits, which provided indication of main
turbine stop valve positions,
were vulnerable to the effects of a main
steamline
break
(HSLB) jet impingement.
The licensee
determined that,
as
a
result of jet impingement, circuits from two channels
could be electrically
grounded
and could, therefore,
remove
power from a train of reactor trip logic
(causing
a reactor trip) and the
ESF logic for that train.
Removal of power
from the
ESF logic would result
in failure of that train's automatic
initiations of ESF functions.
A single failure, which must
be
assumed
during
a design basis
event,
could occur
on the other train.
The licensee
determined
that,
in this particular
HSLB event,
automatic
ESF initiation would be
although
manual
actuation of individual
ESF components
would
remain operable
and available
to operators.
-5-
Further evaluation
by
NRC insp'ectors
identified that
none of the remaining
17 nonsafety-related
inputs to the
SSPS
were properly isolated,
allowing
a
similar vulnerability to
ESF logic in the event of electrical
grounding of
multiple channels
and that this
was
a generic
Mestinghouse
design which may be
a concern'for other plants.
Licensee Action
The licensee
requested
enforcement discretion to not enforce
the Technical Specification
(TS) requirements
for automatic
ESF actuation
during the length of time required to install
a design
change
to correct
the
vulnerability for all nonsafety-related
input circuits
(4 days).
This request
and
the associated
safety evaluations,
risk assessme~ts,
and
compensatory
actions
were documented
in PGlE Letter OCL-95-025,
dated
February
2,
1995.
After receiving enforcement discretion
from the
NRC, the
licensee
selected
one crew of technicians
to install
the design
change.
The
crew then performed
the design
change
on similar equipment,
used for training
the maintenance
crews,
before performing the work in the plant.
No problems
were encountered,
and the design
changes
were completed
ahead of schedule,
on
February
3,
1995,
at approximately
] p.m.
Safet
Si nificance
The licensee
conservatively
assumed
the risk of any
HSLB
outside containment
during the time required to complete
the design
change
and
added
to that the risk during the design
change while one train of and
one
reactor trip breaker
was
removed
from service
in order to accomplish
the
design
change.
This total
increase
in risk, the
sum of the risk of being in
the degraded
plant condition
and of the risk of implementing
the design
change
while at power,
was estimated
to be 0.3 percent of the annual
internal
events
core
damage
frequency,
or
a 2E-7 increase
in core
damage
frequency.
Since
changes
of less
than
]E-6 are considered
to be nonrisk significant,
the
licensee
concluded
that
the risk associated
with extending
the out-of-service
time of the two trains of SSPS
was acceptable.
Generic
Concerns
The licensee
and resident
inspectors
informed Mestinghouse
and the
NRC that other plants
may
be vulnerable to this concern.
NRC
[nformation Notice 95-10
was
issued
February
3,
1995,
to describe this concern
to the industry.
NRC Conclusion
The
NRC concluded
that both the oral
and written licensee
evaluations
and compensatory
actions appropriately
addressed
applicable
concerns.
The
was granted orally and
was
documented
in an
NRC letter dated
February 6,
1995.
The training of the crews
by performing the design
change
on training equipment
was considered
a
noteworthy strength.
1.4
~ Notice ot Unusual
Event
Oue to
an Earth
uake
On February
13,
1995,
at 2:~.'.m.
(PST),
an earthquake
occurred with an
epicenter
approximately
2 kilometers
southwest
of the site.
A peak ground
acceleration
of 0.0075g registered
on the licensee's
supplemental
strong
seismic motion instrument
system
{Terra lech) which is the licensee's
most
sensitive
seismic monitoring equipment.
The licensee's
seismic monitoring
system associated
with the reactor protection
system
(Kinemetrics) did not
detect
the earthquake
since
the peak ground acceleration
was below its
threshold sensitivity.
At 2:10 a.m.
(PST),
the licensee
declared
an unusual
event since
the earthquake
was felt. in the power block.
Postearthquake
assessments
of Units
1
and
2 revealed
no abnormal
conditions
as
a result of the earthquake.
At 2:53
a.m.
(PST),
the unusual
event
was
terminated.
The licensee's
geoscience
department
determined
that the
magnitude of the earthquake
was 2.7
on the Richter scale
and that it occurred
at
a depth of appro:imately 6.9 kilometers.
The earthquake
location
was
northwest of the Hosgri fault, in
a transition
zone
bet,ween
the Hosgri fault
and the coastline
where other earthquakes
of small magnitude
have occurred
in
the past.
2
OPERATIONAL SAFETY VERIFICATION
(71707)
2.1
Diesel
Fuel Oil
DFO
Transfer
Pum
0-1
480 Volt Power
Su
I
Ali nment,
During
a walkdown of 480 volt load centers,
the inspector
noted
t.hat both
the
alternate
and normal
power source circuit breakers
for DFO transfer
Pump
0 '
were closed.
The inspector
questioned
the alignment
and notified the Unit
l
shift foreman.
The proper alignment required
the normal
power supply circuit
breaker
to be closed
and the alternate
power supply circuit breaker
tu be
open.
The Unit I shift foreman initiated action to open
the alternate
power
supply breaker
to restore
the
DFO transfer
pump power supplies
to the proper
alignment.
Review of the most recently performed
alignment procedure.
OP J-6C: 11,
Revision
11,
"DFO System
- Alignment Verification for Plant Startup," revealed
that both of the
OFO transfer Pumps'-
1
and 0-2 normal
and alternate
power
supply circuit breakers
had
been closed during the alignment.
Subsequent
to
the alignment.
the alternate
power supply circuit breaker for OFO transfer
Pump 0-2 had
been
opened'he
opening of the circuit breaker
was likely to have occurred during
a
realignment of power to
OFO transfer
Pump 0-2 in accordance
with Operating
Procedure
(OP)
13. Revision
5, "Transferring Equipment to Alternate
Power
Source
(480 Volts AC)."
OP 13 required
both power supply circuit breakers
to
be open prior to the repositioning of the transfer switch.
Following
repositioning of the transfer
switch only the circuit breaker
which was
aligned to power the
pump was closed.
During review of the most recent
completed
alignment verification checklist,
Attachment 9.2 of OP J-6: II, it
was noted that
the checklist .did not specify the required circuit breaker
positions.
Since
the procedure
was not specific,
the operators
who performed
the alignment closed all four DFO transfer
pump power supply circuit breakers
and annotated
the alignment checklist
to indicate
the breaker positions.
Licensee
Procedure
Reviews
The licensee
changed
the
OFO alignment procedure,
OP J-6C:I I, to clarify the required breaker positions.
Additionally, the
-7-
licensee initiated
a review of other procedures
which aligned
systems with
both normal
and alternate
power supplies,
Two additional
procedures
were
discovered
which did not adequately
specify the alignment of the alternate
power source circuit breakers.
The procedures
which were
Found during the
review that required
changes
included:
OP H-5:II, Revision 9, "Control
Room
Ventilation System - Alignment Verification," and
OP A-3: I, Revision 8,
"Control
Rod System
- Hake Available."
Safet
Si nificance
Proper breaker coordination at the loadcenters
reduced
the significance of thi; alignment.
The concernfor
loss of redundant
power
divisions
was origin~<ly raised
in Oiablo Canyon Safety Evaluation Report,
Supplement
18, Appendix C, Section 4.2.2.2,
"Control
Room Ventilation and
Pressurization
System."
In order to address
this concern,
in the past,
the licensee
had
issued
an
operating order to document their standard
practice for keeping circuit
breakers
open which supply power from an alternate
power source.
Based
upon
the licensee's
standard
practice,
the
NRC concluded
in Safety Evaluation
Report,
Supplement
18, Appendix C, that
the licensee's
actions
were acceptable
and that plant modifications or additional verifications were not required at
that time.
Conclusion
Licensee, procedures
which were written to perform alignment of
systems with alternate
power supplies
did not properly
implement
the standara
practice of the licensee's
commitment.
Additionally, while resolving this
problem,
three
separate
system alignment procedures
were identified by the
licensee,
which did not ensure
proper alternate
power source
alignment.
The
licensee
has
issued
"on the spot"
changes
to these
procedures
and properly
aligned the alternate
power sources.
The licensee
is
c >ntinuing investigation
into the alignment of the
}20-Vac systems
with alternate
power supplies.
The'icensee's
actions
to correct this problem
as well as the ongoi: g
investigation of the
120-Vac
system
appear
to properly address
his issue.
The safety significance
is very low since
a knife switch separates
the power
sources,
and breaker coordination
appears
to have
been maintained.
2.2
Unit 2 Vital Instrument
S stem Malkdown
The inspectors
performed
a detailed
walkdown of a representative
sample of the
Unit
2 Instrument
AC System.
To perform these efforts,
the inspectors
used
tne Operations
Procedure J-10:II, Revision
7, "Instrument
AC System-
Alignment Verification."
The equipment
appeared
to be operating within
specified
parametei
s
and
no discrepancies
were noted with regard to breaker
positions.
Material condition oF the equipment
was
found to be good.
All
equipment
inspected
was
found to be appropriately labeled.
Housekeeping
around
the associated
equipment
and inside electrical
cabinets
was noted to be
very good.
-8-
3
PLANT HALNTENANCE
(62703)
Ouring the inspection period,
the inspector'bserved
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
'ssurance/quality
control department
involvement,
proper
use
y
g
,
proper ~quipment
alignment
and
use of jumpers,
personnel
qu
1
ualifications.
and
proper 2etesting,
Specifically,
the inspector witnessed
portions of the
following maintenance
activities:
Unit i
Inspect
and Clean the Seawater
Side of
2
Flush
and Refill the Bearing Oil Reservoirs
For Unit I: Auxiliary
(AFW)
Pump
2 to Remove Identifi( .'aint Chips
Replace
Failed Test
Sequence
Processor
Power Supply
in Rack
7 of the
Eagle
21 Process
Protection
System
Replacement
of Actuator for Valve SW-I-FCV-603
t
Routine Preventive
Maintenance
for Unit l Turbine-Driven
AFW Pump
Unit 2
~
Train
A Jumper Installation Design
Change
~
Troubleshooting of Reactor Trip Bypass
Breaker
52BYB
Routine Preventative
Maintenance
on Unit
2 Turbine Driven
AFW Pump
3.1
Train
A Jum er Insta~lat~on
Desi
n
Cha~n
e
3. I.l
Design
Change Installation
The
SSPS design
change
was
implemented
to provide electrical
separation
between
the Class
I power supplies
and Class II circuits.
The portion of the
modification observed
involved the installation of
a jumper
and the
replacement
of
a
15
amp fuse with an
8
amp fuse for both channels
in Train A.
The inspector
observed
portions of the design
change.
postmodification
testing,
and reactor trip bypass
breaker operations.
The inspector
noted that
the
TH technicians
appeared
to be knowledgeable
of
the design
change
requirements
as well
as
the
sequence
of work specified
in
the work order,
The inspecto.
also noted significant supervisory
involvement
by both the cognizant
TH foreman
and maintenance
engineer.
The operations
tailboard
was conducted
by the
TH foreman.
The tailboard
appeared
to be
~h'" ~
~
~
L~~*,'
'
'Iy
1
~
~ P
-9-
thorough
and address
the
impact
on operations
as well as
focus
on specific
points during the design
change
where s'.gnificant operations
personnel
involvement
was required.
Before implementing
the design
change
in the plant,
the
TN crew performed
the
change
on
SSPS training equipment
in the training facility.
Conclusion
TH technicians
were well trained
and very knowledgeable
concerning
implementing
a sensitive
and urgent design
change.
Training on
SSPS training
equipment
was
a noteworthy strengths
3. 1.2
Reactor Trip Bypass
Breaker Operation
The inspector
observed
portions of the operations
required
to establish
the
conditions for performance
of the
SSPS
design
change
and
the restoration.
During the performance
of the design
change. it was necessary
to remove
the
SSPS train from service.
During this evolution the inspector
observed
operations
personnel
rack Reactor Trip Bypass
Breakers
A and
B (52/BYA'and
52/BYB) into the test position
and test breaker operation.
rack in and clo~e
Breaker
52/BYA. and then
open
the reactor trip breaker
for SSPS
Train
A
(52RTA).
Following the modification for Train
A Channels
I
and 2.
the inspector
observed
operations
personnel
close
Breaker
52RTA,
open Breaker
52/BYA and
rack out both Breakers
52/BYA and
52/BYB.
When repos,itioning
Breaker
52/BYA
from the racked
in position to the racked out position,
and Breaker
52/BYB
from the test pos,ition to the racked out position,
the inspector
noted that
the operators
failed to comply with the procedure.
The operation of the reactor trip bypass
breakers
was controlled
by the
licensee's
OP A-3: IV, Revision
12, "Control
Rod System - Hanual Operation of
the Reactor Trip and
Bypass
Breakers."
Section 6.4 pertains
to repositioning
a reactor trip bypass
breaker
from the racked
in position to the racked out
position.
Performance
of the steps
in Section 6.4 require concurrent
verification.
Concurrent verification requires that the step
be performed
by
an operator while being concurrently verified by
a second operator.
Section 6.4.3 directs
the operator
to install the breaker racking bar
and lift
up on the bar to release
the spring tension
on the locking device.
The inspector
noted that this step
was performed without installation of the
racking bar.
In addition,
the operators
failed to properly perform the
concurrent verification during portions of this section
in that they affirmed
by initials that the procedure
step
had
been
performed properly.
The
operators
also did not use
the rackinq bar for performance
oF Section 6.6 when
repositioning
Breaker
52/BYB from the test position to the racked out
position.
Safet
Si nificance
The evolution of racking out reactor trip bypass
breakers
from both the racked
in and test positions
was satisfactorily accomplished
from the standpoint
that the breakers
were restored
to the racked out position
'
-10-
without damage
to the breaker or cubicle.
The proper
use of the racking bar
is not critical when repositioning
the reactor trip bypass
breakers
to the
racked out or test positions.
However,
use of the racking bar is important
when repositioning
the reactor trip bypass
breakers
into the racked
in
position to ensure
the required
force is applied for proper breaker
engagement
during rack in,
The evolution of racking in Reactor
Trip Bypass
Breaker
A was
observed
to have
been properly performed.
Therefore,
the safety significance
associated
with noncompliance with the procedure
for racking out the reactor
trip bypass
breakers
was very low.
However,
there
is
a high level of
significance to the failure to perform the procedure
steps
as required
and
an
even higher significance
to the failure to properly perform the required
concurrent verifications.
Conclusion
The operators
failed to comply with the procedural
requirements
for racking out Reactor Trip Bypass
Breakers
A ~nd
8 in that the racking bar
was not used
as required
by Sections
6.4,and
6.6 of OP A-3:IV, Revision
12,
"Control
Rod System
- Manual Operation of the Reactor
Trip and
Bypass
Breakers,"
The failure to comply with OP A-3:IV is
a violation of TS 6.8.1,
which states,
in part.
that written procedures
shall
be established.
implemented,
and maintained
covering applicable
procedures
recommended
in
Appendix
A of Regulatory
Guide
1.33,
Revision
2, dated
February
1978.
Appendix
A of Regulatory
Guide
1.33, Revision
2,
recommends
procedures
for the
operation of the control
rod drive system.
Contrary to these
requirements,
on
February
3,
1995,
the inspector
observed
operators fail to perform the
required actions of OP A-3:IV {323/9502-01),
3.2
Ins ect
and Clean
the Seawater
The inspector
observed
inspection
and cleaning of a
Maintenance
work
orders
{WOs), and associated
procedures,
were observed
as having
been
reviewed
and approved,
as
noted
by the appropriate
signatures.
The maintenance
were also noted to have
been 'prepared
in accordance
with the licensee's
Interdepartmental
Administrative Procedure
AD7.1D1,
"Use of Pooled
Inventory
Management
System
WO Module."
No discrepancies
were noted.
In addition,
the
inspector verified that
the licensee
entered
the appropriate
TS limiting
condition
For operation,
during the performance of these activities.
During the performance of the maintenance
the inspector
reviewed licensee
Administrative Procedures
NR BL-1.10, "Collection and Analysis of Macrofouling
Samples
from the
NR BL- 1.8, "Micr'ofouling Sample Collection in
and Other Single-Pass
Tubed HX."
The procedures
were found to
be prescriptive
and provided sufficient detail for performing this activity.
The licensee
personnel
were
found to be very knowledgeable of their
responsibilities,
and it was determined
that this effort was within the skill
of the craft.
Procedural
compliance
was observed
throughout this effort.
Conclusion
Maintenance
personnel 'involved in the inspection effort of the
HX were
found to be very knowledgeable
of their responsibilities.
"
3.3
Re lacement of
CCW HX 1-2 Saltwater Inlet Valve
SW-I-FCV-603
Actuator
On February
2,
1995,
the licensee
determined
that Valve SW-1-FCV-603 would not
smoothly stroke
open
and that its stroke
time had
increased significantly.
Even though the stroke time (58 seconds)
was less
than the administrative
limit (90 seconds),
the licensee
decided
to replace
the actuator
and scheduled
the work for February
9.
The licensee
performed valve diagnostics
during
stroking
on February
8, during which the stroke time to open
exceeded
the
administrative limit, and
immediately decl'ared
the valve inoperable
and
commenced
the actuator
replacement
activity.
The inspector
reviewed
WOs C0134169
and C0134183,
Action Request
(AR)
A0363821, Surveillance
Test
Procedures
(STP)-V-2F,
"CCW Valves," Revision 4,
and STP-V-3F5,
"Exercising Valve FCV-603
2 Saltwater Inlet,"
Revision
7,
and the valve vendor manual.
The inspector
found the work and
testing instructions
to be clear.
The inspector
observed
the removal
of the actuator.
The maintenance
engineer
was present
and directed
the act'ivities.
The maintenance
personnel
followed
the
WO instructions during the removal
process.
The activity was wel)
coordinated
and smoothly executed.
Following the reinstallation,
the
inspector
reviewed
the work package
and postmaintenance
testing documentation
and concluded that
the testing
was adequate.
After the actuator
was
removed,
the licensee
noted that the 3/4-inch mounting
bolts
had been overtorqued
and
had bottomed out in the valve body, allowing
the actuator to rotate approximately
5 degrees
during valve stroking.
The
licensee
checked
Valve
SW- I-FCV-.602 and the counterpart
valves
in Unit 2 and
did not find evidence of actuator rotation,
but noted that the bolts for all
the valves
had
been
changed
to slightly longer fasteners
of a different
material
by the vendor
when the actuators
were repl'aced
in
1991
and
had also
been overtorqued.
The licensee initiated
AR A0364202 to further inspect
and evaluate all the
affected mounting bolts.
The licensee
replaced
the bolts in Valve SW-1-FCV-
603 with slightly shorter bolts
and performed
an operability evaluation
For
the valves,
concluding that the valves were operable.
The inspector
reviewed
the operability evaluation
and concluded that it was acceptable.
g
I
1
tl
systematic
investigation of the problem had not been
performed
and that the
root cause of the problem
had not
been identified before
the actuator
had
been
removed
in an attempt
to correct
the problem.
The
tIC inspector
reviewed
these
observations
with various individuals
in the engineering
and maintenance
organizations,
including managers
and supervisors.
in order to poin'ut
the
need for improvement
in systematic
troubleshooting.
When the
removed actuator
was
found to be
in good condition. with no
discernable
problems.
the
QC inspector's
observations
regarding
weak
troubleshooting
were verified
a~
va >>d,
and hi
documentation
of possible
-12-
sources
of the prob)em
and
recommended
additional
investigations
were used
as
a basis for future troubleshooting.
Safet
Si nificance
The valve is designed
to fail open
upon loss of air.
The
stroke
time degradation
was
in the open direction.
Therefore,
the safety
significance
was
low.
Conclusion
The inspector
concluded that the maintenance
and engineering
communication
and understanding
of administration
process
requirements
were
excellent
and that the corrective actions initiated by the licensee
were
prompt, a)thou".i rot completely systematic.
The involvement of gC in
'ecommending
more systematic
troub)eshooting,
in providing constructive
criticism and in communicating negative
observations
with several
levels of
the maintenance
and engineering
organization
was considered
a noteworthy
strength.
3.4
Troubleshootin
of Reactor Tri
B
ass
Breaker
52BYB
On February
3,
1995, during
implementation of the
SSPS design
change,
a
general
trouble alarm for Unit 2 Reactor
Trip Bypass
Breaker
52BYB occurred.
The )icensee
planned
troubleshooting of the breaker
to determine
the cause.
The inspector
attended
the contro)
room tai)board for the troubleshooting
and
noted that the plan was thorough
and clearly communicated.
The inspector
then
observed
the troubleshooting activities,
per
WO C0134204.
and determined
that
the plan was careful)y implemented.
The licensee
identified that
some
contacts
on the breaker auxi)iary switch exhibited higher
than expected
resistance
(approximately
29 ohms).
After manipiilating the )inkage,
resistance
decreased
to approximately
8 milliohms;
a black substance,
apparently
a lubricant,
was observed
on the contact
surfaces.
A similar
substance
was
found on the contacts
of
a
new replacement
switch. which
exhibited low resistance
{approximate)y
5 milliohms).
The licensee
determined
that the switches
were supp)ied
by the vendor with the lubricant in place.
The licensee
stated its intention of performing
an evaluation
to determine
why
the contacts
in the installed breaker exhibited high resistance.
The licensee
also determined
that the high resistance
was responsible
for the general
alarm
on the breaker.
The inspector
observed
portions of the switch replacement
work, specifically
the labeling
and verification of wire connections prior to disconnecting
the
from the old switch.
Conclusion
The inspector
concluded
that the work was meticulously executed.
The inspector also reviewed
the licensee's
documentation
and concluded that
the maintenance
and engineering activities observed
were well performed
and
documented.
3.5
Vnnecessar
Outa
e
Times for Turbine-Driven
AFW Pum
s Durin
Maintenance
The inspector
observed
that. during simultaneous,
routine preventive
maintenance
on both Units
1
and
2 turbine-driven
AFW pumps,
a single crew had
~
~ ~
u
-13-
been
assigned
to work both pumps'he
inspector
observed
one
pump out of
service with no work in process
for over
an hour
and communicated
the
implication that greater
than desirable
pump outage
times
may be occurring to
licensee
maintenance
management.
The licensee
promptly concluded that,
i~t
this case,
the
pump outage
times could have
been
reduced.
The licensee
included
in
a recent initiative reviews to determine if safety
equipment
should
be cleared
and worked in seri~s or parallel
to reduce overall safety
equipment
outage
times.
Conclusion
The licensee's
response
was prompt
and appropriate
to minimize
equipment
outage
times.
3.6
Flush
and Refi'll of Unit
1
AFW Pum
Bearin
Oil Reservoir
The licensee
observ~d
'ma'1 paint chips at the bottom of an
AFW pump oil
reservoir,
performed investigation
to determine
the source,
and performed
a
flush of the reservoir.
The work was
done
in accordance
with procedures,
the
chips were removed,
and
a source
was not identified.
A safety evaluation
concluded that the chips would not have
become entrained
in the oil stream
and, therefore,
would not damage
equipment.
The licensee's
evalu~tion of the
chips
was ongoing.
Conclusion
The work was performed well,
and the safety evaluation
appeared
valid.
4
SURVEILLANCE OBSERVATIONS
(61726)
Selected
surveillance tests
required to he performed
by .he
TS were reviewed
on
a sampling basis
to verify that:
{I) the surveillance tests
were correctly
included
on the facility schedule,
(2)
a technically adequate
procedure
exi'sted for per 'ormance 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.
Specifically, portions of the following surveillances
were observed
by the
inspector during this inspection period:
Vntt
1
~
STP I-4-L529,
(SG)
2 Narrow Range
Level Channel
LT-529
Calibration
i
~
STP I-4-L539.
3 Narrow Range
Level Channel
LT-539 Calibration
"~
5JP V-3F5,
Exerc i s ing Valve FCV-603
2 Sal twater Inlet
T'.onclusfon
Throughout
these activities.
orocedura'I
cntaofiance
was observed.
Procedures
were
found to br of the latest
revision.
as verified through
the
licensee's
document control
program.
ln addition.
the procedures
were found
-14-
to have
been
reviewed
and approved
as noted
by the appropriate
signatures.
Finally, it was verified that
these
surveillances
satisfied
the requirements
of TS and were performed within the appropriate
time period.
5
ONSITE ENGINEERING
(37551)
5.1
Vulnerabilit
to HSLB
An electrical vulnerahilit,y in the
SSPS
power supply. discussed
in
Paragraph
1.3 of this report,
was identified by the licensee's
engineering
staff during resolut>on
of
a design
basis reconstruction
concern.
The
licensee's
revie~ found that
the
SSPS
input circuitry could
be electrically
grounded during
an
HSLB,
and the resulting
blown fuses
would remove
power from
ESF actuation
logic circuitry.
A reactor trip would occur upon loss of power,
but one train of automatic
ESF actuation
would be inoperable.
In the event of
a single failure on the other
ESF train,
no automatic
ESF functions would be
available.
although operator actuation of individual equipment
items would
remain operable.
Oesign engineers
promptly communicated
these
concerns
to licensee
management,
who discussed
them with the
NRC.
Ih~ resulting conrlusions
and corrective
actions
were discussed
in Paragraph
l.3 above.
Conclusion
Ouring design basis
reconstruction
followup efforts,
the licensee
engineering staff performed excellent
technical
work in identifying a design
basis vulnerability.
The licensee
aggressively
evaluated
this potentially
significant issue,
communicated with the industry in a timely manner,
and
aggressiviely
implemented corrective actions.
The issue of SSPS vulnerability
to an
HSLB will remain unresolved
pending further
NRC review (275/9502-01;
50-323/9502-01).
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.
The inspectors
have noted minor improvement
in cleanliness
and appearance
in
certain areas.
't e licensee's
management
recently established
expectations
and accountability for housekeeping
for specific areas
by assigning
area
owners.
Since
thyrse
plans
were established
on February l.
1995,
there
has
been
no notable
improvement
in housekeeping
and material condition
attributable
to the change.
Conclusion
Efforts are
in process
l,o improve housekeeping.
but changes
have
been
too recent
to he conclusive.
> a ~
g,
~
p ~
A '%
~i
-15-
6.2
Site Access Authorization for NRC Personnel
During
a review of the licensee's
listing of NRC personnel
having unescorted
security
access
authorization,
the inspector
noted that five personnel
who
were
no longer employed
by the
NRC continued
to have site security
access
authorization.
Comparison of the list of NRC employees
provided in
a letter
from NRC Region
IV, dated
November
10,
1994, with the licensee's
unescorted
security
access
database,
indicated that the licensee
had not removed
the
former
NRC employees
from unescorted
security
access
to the licensee's
facility.
The licensee's
procedure
for the site access
Program,
ONII.ID1, Revision
2,
"Diablo Canyon
Power Plant
(DCPP) Site Access
Process,"
specified that it is
vitally important to terminate
access
for person~el
who no longer require
access.
In response
to this finding, the licensee
performed
a verification o
'on of
unescorted
security
access
records for all listed
NRC personnel
and,
in doing
so,
found three additional
people
who should
have previously had their
unescorted
security
access
authorization
terminated.
The
DCPP Access Control Coordinator wrote
a security incident report
documenting this occurrence.
As
a result of the problems noted,
the
licensee's
quality assurance
organization
performed
a surveillance
to
determine if non-NRC personnel
access
was being controlled properly'he
results of the surveillance
indicated that the Access
Department
was properly
terminating or controlling the unescorted
access
of terminated
employees
and
contractors,
Conclusion
The failure to terminate
unescorted
security
access
for'ersonnel
who are
no longer certified
as
NRC employees
was
a weakness
in the
DCPP site
access
control program.
The scope of the problem appeared
to be limited to
NRC employees
only.
The licensee
has established
a single point of contact
within the Access
Department
to cross
check
t.he periodic certification letters
provided
by the
NRC with the Security Access Authorization log.
The
licensee's
actions
to prevent
recurrence
of this problem appeared
timely and
appropriate.
7
DIABLO CANYON INDEPENDENT SAFETY COHNITTEE NEET ING
(71707)
The inspectors
observed
a routine meeting,
open to the public. of the Diablo
Canyon
Independent
Safety Committee
on February
2.
1995.
The committee
reviewed sever<'icensee
technical
presentations.
including
a
summary
and
lessons
learned
concerning
plant events
which had occurred
since
the last
meeting,
a
summary of the Nuclear Safety Oversight
Committee'NSOC)
meeting.
and evaluations
of plar t performance
since
the last meeting.
NRC Conclusion
The
NRC attended
the meeting
to be aware of issues
discussed
by the Independent
Safety Committee.
The
NRC was already
aware of a11
issues
discussed.
-16-
8
NUCLEAR SAFETY OVERSITE CONHITTEE MEETING
On February
1,
1995,
the inspectors
attended
portions of an
NSOC meeting.
This meeting is
a top level quality meeting attended
by
TS specified
members
to evaluate
safety significant issues.
The members
attending
included
the
TS specified
number of participants
and
properly included
the nonlicensee
members
of NSOC.
Discussions
focused
on programs
assuring
safety.
The
NSOC developed
management
issues
and questions
based
on lessons
learned
associated
with NRC
violations
as well as
concerns
identified by plant staff.
Several
concern~
identified in previous meetings
were followed up.
Hany action
items were
completed.
Self-critical evaluatinn
was encouraged
by the
NSOC members.
The inspector
noted that,
in the area of procedural
compliance,
licensee
members of NSOC acknowledged
that this was
a difficult problem to correct
anu
that
improvements
had
been
steady
over the years.
However.
nonlicensee
members of NSOC
recommended
prompt action to re-emphasize
management
expectations.
Conclusion
The
NSOC meeting
addr
ssed
appropriate
management
level safety
concerns.
The nonlicensee
members of
NSOC provided valuable insight to root
causes
and corrective actions for management
issues.
9
HAIHTEHAKCE FOLLOWUP
(92902)
9.1
Closed
Violation 323 9429-01:
Entr
1nto 0 erational
Mode
When
Limitin Condition for 0 erations
is Not Met
i
The licensee's
response
letter of January
17,
1995,
stated their agreement
that the events re.ulted
f) om:
(1>
improper implementation of equipment
clearances,
(2) inadequate
verification of equipment
clearances,
and
(3)
inadequate
procedures
for surveillance testing.
The licensee
identified four corrective action steps
to address
the violation.
First,
a summary of the event
is planned for the quarterly training seminar
for the instrument
and control technicians.
The inspector
reviewed the lesson
,plan, which included
a discussion of the input impedance characteristics
of
the alarm modules.
Second,
a policy statement
for TH personnel
was
issued
that provides guidance
to assure
timely review of excessive
out-of-tolerance
conditions.
The inspector
reviewed
the policy statement
and concluded that it
effectively addressed
the issue.
However, it used
three
times the acceptance
criteria for a measu
ed parameter
as
the basis for figuring out
an excessive
out-of-tolerance condition.
The inspector discussed
this basis with the
TN
Director, pointing out that conditions other than three times the acceptance
criteria may warrant consideration
as excessive
out-of-tolerance conditions.
The Director agreed with the inspector's
position
and said that
he would
consider revising the policy statement
as
more experience
is gained.
The
inspector
noted that
the current
procedure
governing
ARs would not preclude
'
-17-
personnel
from initiating an
AR when
an instrument
is questionable.
The
Director acknowledged
that the current
AR procedure
does
not preclude
initiation of an
AR for other causes.
He further said that the policy was
intended
to provide guidance
and reflects
a consensus
of his staff.
The third corrective action
was
a revision of administrative
procedures
governing the review of excessive
out-of-tolerance
conditions
to provide
assurance
of a more timely review before
Node transitions.
The inspector
reviewed the current
nonconformance
report
{NCR), N00018S9,
which recommended
a change
to Procedure
OH7.101,
"Problem Identification and Resolution
- ARs."
The recommended
change
requires
a review of all pending quality evaluations
before plant startup
to assure operability of plant equipment.
Supporting
procedures
for process
measuring
equipment
and measurement
and test equipment
also
had
recommended
changes
to require
reviews before
a unit startup.
The
inspector
concluded
that the
recommended
changes
address
the concerns
expressed
by NRC.
The fourth corrective action stated
that outage policies,
procedures,
and
practices
would be reviewed
to assure
that shorter
outage durations
would not
adversely affect control of plant
systems
and equipment.
NCR N0001859
indicated that
the review was still ongoing.
The inspector
noted that the
would remain
open to track the reviews.
The inspector
concluded
that the
licensee
is pursuing
the review diligently.
A discussion
with the Director of NRC Regulatory Support
indicated that the
licensee
intends to close
the
NCR before
the
commencement
of Unit
1 Refueling
Outage
1R7 this fall.
The inspector
concluded
that the corrective actions
not
completed at the time of the inspection
were
on schedule
and will be completed
as indicated
in the licensee's
response
letter.
9.2
Closed
Violation 323 9429-02:
Failure
to Follow Procedures
Governin
Clearances
and
Inde endent Verification
The licensee
acknowledged
that
"he clearance
in question
was not
implemented
as the instructions
in the clearance
document
indicated,
and the persons
who
had installed
the clearance
had modified the clearance
point without prior
approval.
Further,
the persnn
performing the
independent verification
incorrectly assumed
the clearance
point was the equivalent of the instruction
in the clearance
document.
The licensee
identified two corrective actions
For this violation.
A detailed
incident
summary
had
been prepared
for training of both plant maintenance
and
operations
personnel.
The inspector
examined
the
summary,
noting that it
emphasized
the procedural
requirement
to obtain prior shift foreman review and
approval if a clearance
cannot
be
implemented
as written.
The
summary also
re-emphasized
the management
expectations
regarding
procedural
adherence.
Secondly,
OP 1.0C2, "Verification of Operating Activities." was
changed
to
include precautions
to further emphasize
the
need to obtain additional
review
and approval if a plant activity cannot
be
implemented
spec i fica1 ly a~
written.
-le-
The inspector
concluded that the corrective actions
had
been completed
and
that they appeared
adequate
to address
the issues
described
in
NRC inspection
Report 50-275/94-29;
50-323/94-29.
9.3
Closed
Violation 323 9429-03:
fnade uate
Procedures
Relatin
to ARs
and
The licensee
acknowledged
the procedural
inadequacies
for Procedure
ON7.101,
"Problem Identification
and Resolution
- ARs," and
STP l-9-P960.8 through
l-g-P9607.8.
for the calibration of the accumulator
pressure
instruments.
The
licensee
also stated
that the root cause
was personnel
error by utility
personnel
involved with the accumulator
pressure
transmitter calibrations
in
that they did not have cognizance
of the change
in the alarm module
impedance
caused
by removal of the input electrical
power.
Two correctivo actions
were identified by the licensee;
a policy statement
{described in the response
to Violation 323/9429-01);
and procedural
guidance
that will be revised
to assure
a review of out-of-'olerance
conditions
is
performed prior to Node transition {also discussed
in the response
to
Violation 323/9429-01).
The inspector
concluded that the proposed
change
in
procedure
guidance
would address
the issue of personnel
error
and procedural
inadequacies
which may occur with the complex schedule
of surveillance testing
at the end of outages.
Removal
RKR
Pum
Seal
Cooler
During
a routine walkdown,
a system engineer identified reduced
flow through
an
Rl(R pumn seal cooler.
Subsequent
investiqation identified small particles
of a valve liner lodged
in the cooler piping.
Licensee
followup of testing,
operating history,
and installation of a
diagnostic strainer
determined
that
no additional particles
were entrained
in
the system.
The service life of the valve liner was determined
by the vendor
to be at 'least
2 years,
with periodic durometer
checks
to determine additional
service life.
The licensee
plans
to include durometer
checks
in future valve
inspections,
9.5
Closed
Violation 323 9418-01:
Lack of Ade uate
Surveillance
Testin
{N
The licensee
identified that testing of four
RHR system
was not
properly performed
in that only partial stroke testing
was verified.
The licensee
evaluated
other check valve flow tests
and did not identify
similar problems.
The valves
have since
been
tested
and
found capable of full
stroke performance.
Several
human performance
and root cause
evaluations
of
this concern
were performed
and d>scussions
held with engineers.
\\
~
~
~ ~'
10
FOLLOWUP PLANT OPERATIONS (92901)
-19-
10. 1
Closed
Followu
Item
275 9430-05
0 erator
Res
onse to December
14
1994
Dual Unit Tri
and Cooldown of Unit I
10. 1. 1
Training and Operator
Performance
Issues
From Event Review
As reported
in NRC Inspection
Report 50-275/94-30,
following the reactor trip
of December r 14,
1994, Unit
I plant parameters
revealed
that pressurizer
level
decreased
to
5 percent
following the reactor trip.
The decrease
in
pressurizer le".l was attributed
to the effect of reactor coo~;nt
system
(RCS)
contraction
due to the
RCS temperature
decrease
to 520'F.
The major
contribution to the cooldown was
the addition of AFW to the
SGs at the maximum
flow rate.
Further,
RCS pressure
dropped 'to
1868 psig,'ue
to the cooldown
and contraction,
This threatened
the safety injection actuation setpoint of
1850 psig.
The positive displacement
(PD)
pump was
in service at the time of
the reactor trip, with both centrifugal
pumps off.
Normal operating practice.
at the time of the reactor trips,
was to maintain only the
PO
pump in
operation.
The lower flow rate of the
PD pump,
combined with the overfeedin9
AFW, led to the low pressurizer
level
and pressure.
The
5 percent
level
was
also below the pressurizer
heater cutoff of
17 percent.
which further
contributed
to the pressure
decrease.
The postevent
review identified two important operator
performance
issues.
First, the operators
did not throttle
AFW from the turbine-driven
AFW pump
until Step
2 of E-0. I, "Reactor Trip Recovery."
This is the first point in
the procedures
where
the operators
are specifically told to thrott'le flow from
the
AFW system.
However,
the inspector determined
from interviews with
licensed operator requalification training personnel
that the operators
are
routinely instructed during simulator training to be
aware of the effects of
excessive
AFW addition to cooldown of the
RCS.
Secondly,
the instructors
indicated ti,at the operators
should
be aware of the configuration of the
charging
system
and, therefore,
the necessity
of starting
a centrifugal
charging
(CC)
pump to recover pressurizer
level prior to reaching
17 percent.
The inspector concluded.
from the event review and interviews of training
staff, that the operator's
performance
was not specifically due to
a weakness
in the training program.
The inspector
reviewed selected
scenarios,
task
analysis,
and learr ing objectives
to determine
whether
the operators
had
received training, on cooldown events.
The training material
indicates
that
the operators
have
been trained
on cooldown events
involving various sized
secondary
breaks
and overfeeding
events.
The operators
are expected
to
monitor
RCS pressure
and
AFW flow rates
to ensure
cooldowns
remain
within'xpected
posttrip parameters.
Operators
are also expected
to be cognizant of
pressurizer
level
and pressure
control following transitions
to optimal
recovery procedures.
The inspector
concluded that operator
performance
rather
than training was the primary factor
in the cooldown.
C$.S
~
i
~ s +
i.
-20-
10. 1.2
Training Conducted
to Address Operator
Performance
Training Improvement
Proposal
6405 was initiated by Operations
to request
specific training related
to the
Oecember
14,
1994,
dual unit trips.
The
proposal
requested
training on the cooldown of Unit
1
and the transfer
to
startup
power.
The inspector
reviewed
the changes
made
to the
p
Training Scenario
LR946S2
in response
to the Training
Improvement
Proposal.
Scenario
LR946S2 involved,
as
the main event,
an
HSLB outside
containment
upstream of
a main
steam isolation valve
on Steam Line 4.
The scenario results
i
s'gnificant
cooldown
and depressurization
of an
SG and requires
the use
n
a
i
of Procedures
E-O, "Reactor Trip or Safety Injection,
E-1,
Loss
o
or Secondary
Coolant,"
and E-2, "Faulted
SG Isolation."
Each of these
P rocedures
would require monitoring of
RCS pressure,
pressurizer'r level
and
level; all of which are parameters
related to the cooldown event
on Uni't 1.
The actions required of the operators
included throttling of AFW and close
monitoring .of pressurizer
'evel.
However, starting of
a
pump was moot
because
the scenario
resulted
in
a safety injection,
The lesson
plan for Scenario
LR946S2
included
a discussion
of the Unit
1
cooldown event.
Included
in the discussion
was
a review of what occurred,
utilizing event strip chart records
and the event
sequence
record.
The
instructor pointed out the need
to throttle the turbine-driven
AF'H pump soon
after it was determined
that is was not needed.
The operators
were also
instructed to closely monitor pressurizer
level
and pressure
and to consider
the need to start
a
CC pump if it was apparent
the
PO pump could not keep
up
with RCS contraction.
The instructor also reviewed procedure
changes
generated
as
a result of the event.
The scenario
had several
unique aspects
present
during the Oecember
14,
1994,
event to enhance
realism.
The scenario utilized
a reduced
crew complement
with several
members
dispatched
to perform various activities outside the
control
room.
Further,
the scenario
also utilized
a videotape of another
event occurring simultaneously
on Unit 2.
The Shift Foreman,
because
the
Shift Supervisor
had
been
one of the dispatched
persons,
had to assume
the
control
room co+sand
function.
This meant
he had to monitor the status of the
event
on the simulator,
and remain cognizant of the Unit 2 event.
The Senior
Control Operator
being the procedure
reader could not approa'ch
the boards;
this left the Control Operator
as the only operator
on the boards,
because
the
other operator
had
been dispatched
to the remote
shutdown panel.
The
inspector
viewed this scenario
as being very challenging for the crew and
a
particularly innovative approach
to training for reduced
crew complement.
The inspector
concluded
the training conducted during the current
requalification cycle addressed
the Oecember
14,
1995, Unit
1 cooldown event.
The observed training represented
excellent practice with regard to
a systems
approach
to training program.
The training was sufficient to reemphasize
good
operator
practice
and addressed
needed
training within the
scope of the
gran>>.g~d.typal(~N
~ ~
. &v>> -~ g'f ~'
'
>>r
l
Pi.
-21-
11 ensed
operator training program.
Based
upon the training performed
in
response
to the weaknesses
noted during the response
to the dual un',
c
l unit tri
the inspector
concluded
that the follnwup item was closed.
ll
IN OFFICE REVIEW OF LERs
(90712)
The inspectors
performed
a review of the following LERs associated
with
ope rating events.
Base)1
on the information provided in the report.
review o
associated
docum) nts,
and interviews with cognizant
licens
e
p
inspectors
conc l))ded that
the
licensee
had met the reporting requirements,
addressed
root. causes.
and
taken appropriate
corrective action
.
following LERs are closed:
~
275/92-018.
Rev,is.ion 0.
Han))al Reactor
Trip to Prevent
Inadvertent
Criticality From Inadvt rt) nt 4)oldown
Oue to Exces~ive
Steam
Leakage
275/93-012.
R) vision 2. Auxiliary Saltwater Outside of Design )lasis
Due
to fouling
~
323/94-010.
R) vis)r)n 0.
TS 3.04 Not Met
When
Three of Four Accumulators
Were Inoperable
Oue to Personnel
Error
1
323/94-012.
R) vis)on 0,
Manual Reactor Trip Due to Circulating Water
Pump Cavitation
as
a Result of Intake
Screen
Fouling
~
275/94-020.
Revision 0, Reactor Trip Oue to Reactor Coolant
Pump
Bus
Undervo)tagn
That Resulted
from an Electrical
System Disturbance
External
tn th)
PG)F.
System
I
'
'
l
PERSONS
CONTACTED
ATTACHNENT I
Licensee
Personnel
G.
G
L.
- H
- J
D.
J.
- K.
S.
- P.
<<W.
- RE
V.
- T.
- C
J.
S.
- J
- K.
R.
R.
<<D
- T.
E.
D.
D.
- H
- R.
- W.
<<J
- D
<<H
'K.
R.
- D
J,
<<J
H. Rueger,
Senior Vice President
and General
Manager,
Nuclear
Power
eneration
Business
Unit
H. Fujimoto, Vice President
and Plant Hanager,
Diablo Canyon Operations
F.
Womack, Vice President,
Nuclear Technical
Services
R. Arnold, Acting Director. Mechanical
Maintenance
R. Seeker,
Director, Operations
H. Behnke,
Senior Engineer,
Regulatory
Compliance
E, Bonkosky,
Ins'rument
Haintenance
Foreman,
Technical
Maintenance
H. Bych, Senior Engineer,
Nuclear Safety Engineering
G. Chestnut,
Senior Reactor
Engineer,
Plant Engineering
R. Co)bert,
Supervisor,
Engineering
Services
G. Crockett.
Manager,
Engineering
Services
N. Curb,
Manager,
Outage Services
R. Foster,
Senior Engineer,
Systems
Engineering
L. Grebel,
Supervisor,
NRC Regulatory Support
R. Groff, Director. Engineering
Services
J. Griffin, Director, Learning Services
A. Hiett, Shift Foreman,
Operations
R. Hinds, Director, Nuclear Safety Engineering
A. Hubbard,
Engineer,
Regulatory
Compliance
L. Jett,
Training Supervisor,
Simulator/Operator Initial Training
G. Johansen,
ILC Engineer,
Technical
Maintenance
B. Hiklush, Manager,
Operations
Services
E. Molden, Hanager,
Maintenance
Services
A. Houlia, Assistant
to the Vice President
and Plant
Manager
P. Nelson,
Systems
Engineer,
Systems
Engineering
H. Oatley. Director, Mechanical
Maintenance
B. Petersen.
Operations
Engineer,
Operations
J. Phillips, Director.
Technical
Haintenance
P.
Powers,
Manager,
Nuclear Quality Serv>ces
F.
Ryan, Supervisor.
Access Control
and Fitness for Duty
A. Shoulders,
Director, Engineering
Services
A. Taggart,
Director, Nuclear Safety Engineering
J. Thailer,
Technical Spe:ialists,
Regulation
and Design Services
F. Trengove,
Coordinator,
Budget
and Performance
Management
G. Todaro, Director, Security.
A. Vosburg, Director,
Systems
Engineering
'.
Welsch,
Supervisor,
Operator Requalification Training
L. Young, Director, Nuclear Quality Services,
General
Office Quality
1.2
Other Attendees
(
- G
- R.
Gibson,
Southern (.al~fornia Edison
Company
Gireux,
Southern California Edison
Company
e
r
0
,
I.3
NRC Personnel
"H. H. Hiller, Senior Resident
Inspector
- H. D. Tschiltz, Resident
Inspector
G. K. Johnston,
Project
Inspector
J.
A. Sloan,
Senior Resident
Inspector,
San Onofre Nuclear Generating
Station
R. V. Azua, Resident
Inspector,
Fort Calhoun Station
- Denotes those attending
the exit meeting
on February
23.
1995.
In addition to the pe.".onnel
listed above,
the inspectors
contacted
other
personnel
during this inspection period.
2
EXIT MEETING
An exit meeting
was conducted'n
February
23,
1995.
During this meeting.
the
resident
inspector
reviewed
the
scope
and findings of the report.
e
The
licensee
acknowledged
the inspection
findings documented
in th)s report.
ihe
licensee
did not identify as proprietary
any information provided to, or
reviewed by, the inspectors.
~ g
ATTACKHEMT 2
ACRONYHS
~
~
AFM
CCM
OCPP
DFO
KSF
LER
NSOC
OP
gC
SSPS
p
(
TN
action request
centrifugal charging
component cooling water
Diablo Canyon
Power Plant
diesel
fuel oil
engineered
safety feature
flow control valve
heat
exchanger
licensee
event report
main steamline
break
nonconformance
report
Nuclear Safety Oversight
Committee
operations
procedure
positive displacement
quality control
system
residual
heat
removal
solid state protection
system
surveillance test procedure
technical
maintenance
Technical Specification
work order
I
t
e