ML17291A694
| ML17291A694 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 03/13/1995 |
| From: | Kirsch D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17291A692 | List: |
| References | |
| 50-397-94-33, NUDOCS 9503200046 | |
| Download: ML17291A694 (29) | |
See also: IR 05000397/1994033
Text
ENCLOSURE 2
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection
Report:
50-397/94-33
License:
Licensee:
Washington Public Power Supply System
3000 George
Way
P.O.
Box 968,
MD 1023
Richland,
Facility Name:
Nuclear Project-2
(WNP-2)
Inspection At:
WNP-2 site near Richland,
Inspection
Conducted:
December
11,
1994,
through January
21,
1995
Inspectors:
R.
C. Barr, Senior Resident
Inspector
D. L. Proulx, Resident
Inspector
D.
E. Corporandy,
Project Inspector
Approved:
Ins ection
Summar
ir
,
'e
,
eactor
ProJect
rane
D te
Areas
Ins ected:
Routine,
announced
inspection
by resident
and Region-based
inspectors
of control
room operations,
licensee
action
on previous inspection
findings, operational
safety verification, surveillance
program,
maintenance
program,
licensee
event reports,
special
inspection topics,
and procedural
adherence.
During this inspection,
Inspection
Procedures
37551,
61726,
62703,
71707,
71750,
92700,
92901,
92902,
92903,
92904,
and 93702 and'TI 2515/126
were used.
Results:
~oerations
~
Operators
did not adequately
evaluate
the impact to safety
and the
Technical Specification
(TS) requirements
of the degraded
position
indication of a postaccident
sampling valve.
Weak shift turnovers
and
control
board walkdowns contributed to the excessive
duration of this
situation.
The operator's
apparent failure to consult with operations
management
and
system engineering,
in addition to the licensing manager,
contributed to an inappropriate operability determination.
9503200046
950314
ADOCK 05000397
Q
~
Several
operators
exercised insufficient attention to detail in failing
to either perform or document the first or second verifications that
and full-out indication checks
had
been performed.
Licensee corrective actions for previous operator inattention to detail
associated
with verification of control rod manipulation
have not been
fully effective.
This indicates that the process
of verifying control
rod manipulations requires additional attention.
~
Operations
followup of a half-scram event
was timely and effectively
identified weaknesses
in work coordination,
communications,
and
procedure
adherence
for which appropriate corrective actions
were taken.
~
An out-of-specification diesel
generator
(D6) governor setting indicated
that equipment operator tours
(as well as
system engineer
walkdowns)
require additional attention to detail.
Maintenance
~
Surveillances
observed
were performed properly.
~
Work control personnel
did not perform an adequate
review of work
associated
with indication
on
a containment isolation valve,
contributing to
a violation of the TS.
Licensee
craftsmen
performed
a design
change to
a safety-related
level
switch without
a proper evaluation. being performed
and without an
approved
work package.
The licensee
thoroughly considers
the safety (risk) aspects
of
conducting online maintenance,
Engineering
~
Licensee
procurement
and receipt inspection of a safety-related
level
switch were inadequate
to determine
whether
a like-for-like replacement
had
been provided.
Engineering
personnel
failed to maintain the operability assessment
log
to
a current status
by removing superseded
Plant
Su
ort
Radiation protection performance
was good regarding the compliance with
radiation work permits,
wearing of protective
equipment
and monitoring
devices,
and personnel
frisking practices.
~
Housekeeping
was good in all plant areas
containing safety equipment.
Security performance
was
good in all areas
observed.
Summar
of 1ns ection Findin s:
~
Violation 397/9433-01
(Section 3.2. 1) was identified.
~
Violation 397/9433-02
(Section 3.2.2)
was identified.
~
Honcited Violation 397/9433-03
(Section
9. 1) was identified.
~
Licensee
Event Report 397/94-18
was reviewed
and closed.
Attachment:
~
Persons
Contacted
and Exit Heeting
0
DETAILS
I
PLANT STATUS
At the start of this inspection period,
the reactor
was operating at
100 percent
power.
The reactor'continued
to operate
at
100 percent
power
(except for momentary
power reductions to support control rod exercises,
bypass
valve testing,
and
steam leak repairs) until the
end of the inspection
period.
2
ONSITE
FOLLOWUP TO EVENTS
(93702)
2.1
Half-Scram Durin
Surveillance Testin
On January
17,
1995,
at 5:45 p.m., while performing Surveillance
Test 7.4.3.6.25;
"Control
Rod Drive Rod Block Recirculation
Flow Test Upscale,
and Comparator
Channel
D Channel
Check,"
WNP-2 experienced
a
half-scram.
The shift manager initiated Problem Evaluation
Request
(PER)
295-
0035 to document
and assess
the event.
The licensee
determined that the half-scram resulted
from a craftsman
moving
Switch Sl out of the zero position to the operate position without waiting
30 seconds,
as prescribed
in the procedure.
The licensee
concluded that the
root cause of this event
was that the operating
crew did not adhere to Plant
Procedures
Manual
(PPM) 1.2.3,
"Use of Controlled Procedures,"
in that the
sequence
for exiting the procedure
was not determined prior to exiting the
procedure.
The licensee
also noted that contributing factors were:
(1) poor
communication
between
the control
room supervisor
and the shift manager;
and
(2) starting
a surveillance with the'ntent of not completing the surveillance
without interruption.
As corrective actions,
the licensee
reviewed the event with all instrument
and
control technicians
and operations
personnel,
added the discussion of this
event in industry events training, counselled
the individuals who participated
in the event,
and is considering modifying the surveillance
procedure
to
caution the craftsmen
on the operation of Switch Sl.
The inspector
concluded that the evaluation
was thorough
and that the
corrective actions
were appropriate.
3
PLANT OPERATIONS
(71707,
92901)
3.1
Plant Tours
The inspector
toured the following plant areas:
Reactor
Building
Control
Room
T
0
Diesel
Generator Building
Radwaste
Building
Service
Water Buil,dings
Technical
Support Center
Turbine Generator Building
Yard Area
and Perimeter
3.2
Observations
The inspector
observed
the following items during the tours.
3.2.
1
Operating
Logs
and Records
The inspector
reviewed operating
logs
and records
against
TS and
administrative control procedure
requirements.
On January
11,
1995,
the inspector
reviewed the control
rod pull sheets
For
the past
2 months to ascertain if recent
rod movements
had
been
performed in
accordance
with licensee
procedures,and
the TS.
The inspector identified that
the control
rod coupling
and rod full-out light checks
had not been
signed off
as having
been
performed.
PPH 9.3.9,
"Control
Rod Development
Sequence
Withdrawal
and Control" (the licensee's
procedure that implements
TS
surveillances
4. 1.3.6.b
and 4. 1.3.7.c),
requires
the operator
and
a second
individual to verify these
checks
have
been
performed.
For the following rods
on the listed dates,
the initial and
second verifications were not performed,
indicating that the control rod coupling
and full-out light checks
may not
have
been
accomplished:
~
On October
23,
1994,
was pulled from Position
00 to
48.
~
On October
29,
1994,
was pulled from Position
00 to
48.
~
On December
21,
1994,
was pulled from Position
00 to
48.
~
On January
5,
1995,
Rod 02-19 was pulled from position
46 to 48.
The inspector notified the shift manager of these discrepancies.
The shift
manager initiated
PER 295-0026 to document
the occurrence.
The licensee
interviewed both the operator
and the second verifier involved
with the rod manipulations
and found that the individuals could not recall
performing the checks.
The individuals noted that,
as operators,
they have
a
routine for withdrawing control rods that included performing the control rod
and full-out indication checks.
The inspector
noted that part of
this routine was to log that the checks
had
been performed.
Although the
inspector could not substantiate
that the checks
had
been performed,
the
and full-out indication checks
were subsequently
performed with satisfactory results.
The licensee
reviewed earlier records that the inspector
had not reviewed
and
identified additional
instances
of not logging the performance of.control rod
and control
rod full-out light checks.
To prevent recurrence
of this problem,
the licensee
proposed
the following
corrective actions:
(I) the shift managers will provide coaching for the
control
room staff on expectations
for documentation;
(2)
an observation
form
for supervisory oversight will be created for auditing operator
programs
in
place, e.g.,
clearance
orders,
component status
change orders,
TS action
statement
(TSAS) entries,
and control rod withdrawal sheets;
and
(3) the
reactivity manager will be expected
to review and initial control rod
withdrawal sheets
upon completion of control rod movements
which occurred
on
his shift.
The inspector discussed
this issue with the operations division manager,
who
acknowledged that operator attention to detail with control rod manipulations
and other aspects
of plant operation requires
strengthening.
He stated that,
in addition to the corrective actions for the failures to document the
coupling checks,
more generic corrective actions for the overall operator
error rate will be considered.
The inspector determined that the safety significance of this error was low.
The missed
checks
were required to lower the probability of a rod drop
accident,
which is reasonably
low.
Nevertheless,
the inspector
was concerned
because:
(I) management's
expectations
for second
and independent verification were not
consistently
implemented;
(2) management's
expectations
for self-checking
have
not been consistently
implemented;
(3) multiple operating
crews were involved
with these oversights;
and
(4) there is
a history of inattention to detail
with respect
to control
rod manipulation at WNP-2.
NRC Inspection
Report 50-397/93-24
documented
an event where communication
between
the shift nuclear engineer
(SNE)
and the reactor operator
(RO)
resulted
in confusion over the sequence
with which control rods
had
been
withdrawn.
As corrective actions for this event,
the licensee
required the
SNE and the
RO to initial each control rod movement to assure
the planned
rod
movement
sequence
was
im'plemented.
NRC Inspection
Report 50-397/94-27
documented
a licensee
identified violation of TS where two control rods
had
been withdrawn with their hydraulic accumulators
A contributing
cause of this event
was the apparent
lack of communications
and attention to
detail
by the shift manager,
the
SNE,
and the
RO.
The prerequisites
for
pulling the control rods
had not been established.
NRC Inspection
Report 50-
397/94-32
documented
an event where
two control rods were pulled out of
sequence.
The licensee
concluded that poor communications
between
the
SNE and
the
RO caused
the event.
As corrective actions,
the licensee
discussed
the
event with all licensed
operators
and clarified the expectations
for
independent
and
second verifications.
The inspectors
discussed
the corrective
actions with the operations
manager
and expressed
their reservation with the
corrective actions
since additional formality to the process
had not been
implemented.
It appeared
that the attention to detail, self-checking,
and
commitment to independent
or second verification has not been
adequately
implemented
by the operating
crews.
With respect
to the corrective actions for not documenting or verifying that
the overtravel
and full-out checks
had
been performed,
the
NRC questions
the
usefulness
of a third review, given the disregard for the prior existence of
requirements
to conduct
second
reviews.
The root of this problem appears
to
be inadequate
implementation of management's
expectations
with respect to
self-checking
and
second verifications.
The proposed corrective actions
do
not address
correcting those
issues.
TS 6.8. l.a invokes Regulatory
Guide 1.33,
Appendix A, which states
"implementing procedures
are required for each surveillance listed in the TS."
TS Surveillance
Requirement
4. 1.3.6.b states,
"Each affected control rod shall
be demonstrated
coupled to its drive mechanism
by observing
any indicated
response
of the nuclear instrumentation while withdrawing the control rod to
the fully withdrawn position
and then verifying that the control rod does not
go to the over travel position
.
.
.
Anytime the control rod is withdrawn to
the 'Full out'osition
.
. ."
TS Surv'eillance
Requirement
4. 1.3.7.c states,
"The control rod position indication system shall
be determined
by
verifying
.
.
. that the control rod position indicator corresponds
to the
control rod position indicated
by the 'full out'osition indicator when
performing surveillance
4. 1.3.6.b."
The licensee
implements
these
surveillance
requirements
by
PPM Procedure'.3.9,
which specifies
the use of
rod pull sheets
that require signatures
documenting
the completion of these
surveillances.
The failure to document
the performance of the control rod
and full-out verification checks for the
above listed control rods is
a violation of TS 6.8. l.a (Violation 397/9433-01).
3.2.2
Monitoring Instrumentation
The inspector
observed
process
instruments
to verify correlation
between
channels
and conformance with TS requirements.
On January
18,
1995,
the inspector
noted that
a deficiency tag
was affixed to
the control
room containment isolation valve position indication (VPI).
This
deficiency tag was dated
January
6,
1995,
and stated that the VPI for
Valve PSR-V-X77A1 had incorrect indication when cycling the valve.
Valve PSR-
V-X77A1 is an inboard containment isolation valve for the postaccident
sampling
system
(PASS).
The VPI indicated that the valve was closed.
The
inspector
was concerned
that this valve did not provide "closed,
not-closed"
indication for accident monitoring as required
by TS 3.3.7.5.
The inspector questioned
the shift manager
on the status of the deficiency
tag.
The shift manager
stated that
he 'believed that the tag
was invalid,
because
the problem was corrected shortly after it was identified.
The shift
manager
noted that Work Order 95000285
was referenced
by the deficiency tag.
0
The shift manager
accessed
on "Passport"
(the licensee's
work management
database)
and noted that this work order
had
been cancelled.
The shift manager
then removed the deficiency tag.
In further researching
this issue,
the inspector
noted that the control
room
operator log of January
6,
1995,
stated that Valve PSR-V-X77A1 indicated
closed
when it was
opened
and,
when closed,
indicated
open briefly, then
indicated closed.
The inspector
found that over the
2 subsequent
weeks
no
control
room log entries
had
been
documented
concerning
Valve PSR-V-X77A1.
This indicated to the inspector that the problem
may not have
been
adequately
resolved.
The inspector discussed
this issue with the work control senior reactor
operator
(SRO).
The work control
SRO used the Passport
system to find that
was cancelled for administrative
reasons
and that it had
been
superseded
The work control
SRO further stated
that the position indication for Valve PSR-V-X77AI had not been repaired
because
the repair required entry into primary containment,
which was
inaccessible.
He noted that the local position indication at the
PASS panel
on the
487 foot level of the radwaste
building was available
and considered
that the local indication fulfilled the requirement of the TS.
The inspector
reviewed the TS, the
TS bases,
the Final Safety Analysis Report,
and Regulatory
Guide
1.97 to verify that local indication was
an acceptable
substitute for control
room indication.
From this review, the inspector
concluded that VPI must
be available in the control
room for the accident
monitoring channel
to be operable
per
Regulatory
Guide 1.97, to
which the licensee
is committed,
recommends
Category
1 closed/not
closed
indication
on all primary containment isolation valves,
excluding check
valves.
Regulatory
Guide 1.97 states
that accident monitoring instrumentation
is necessary
in the control
room to meet the criteria discussed
in General
Design Criterion 19.
Final Safety Analysis Report Section 7.5.2.2.3,
"NRC
Regulatory
Guide Conformance,"
states
that VPI for each applicable
containment
isolation valve is provided in the control
room.
The inspector notified the
shift manager that it appeared
that the local
PASS indication was not an
acceptable
substitute for control
room indication for accident monitoring.
On January
18, the operators
cycled the
PASS valves
and noted that
Valve PSR-V-X77A1 indicated
shut
when open,
then briefly indicated
open
when
shut,
and then indicated
shut again.
Because
the shift manager
was
aware of
the past practice of taking credit for remote valve indication in meeting the
TS, the shift manager
contacted
.the licensing manager to notify him of the
inspector's
concern
and the problems with the indication of Valve PSR-V-X77A1
and obtain clarification of the acceptability of the past practice.
Based
on
input from the licensing manager,
the shift manager
declared
the VPI
The shift engineer initiated
PER 295-0037 to document the
deficiency
and to propose corrective actions.
The following day, the licensee
deenergized
and danger-tagged
shut the outboard valve for the line associated
with Valve PSR-V-X77A1
and exited the
TSAS.
The licensee's
PER included the inspector's
observation that the valve was
potentially inoperable
since January
6,
1995.
The licensee's
investigation
found that
on January
6,
1995,
the shift manager
had contacted
the licensing
manager
at
home to discuss
the operability of the VPI for Valve PSR-V-X77A1.
Based
on informal communications with the licensing manager,
the shift manager
incorrectly determined that the
VPI was operable
on January
6,
1995.
The
shift manager did not document this assessment
of operability in a
PER.
The
inspector
was concerned
that
on one occasion
the shift manager
had consulted
with the licensing
manager
but had not involved operations
management
or
system engineering
or followed the administrative
processes
to make
an
operability decision.
This event
was potentially safety-significant
because,
during
an accident,
deficient indication for Valve PSR-V-X77AI could lead
an operator to believe
that the valve was shut,
when actually it was open, giving false indication of
containment integrity.
Table
1,
Item 27, Action 80, requires with less
than the minimum
number of accident monitoring channels
restore
the channel
to
in
7 days,
or be in hot shutdown within the next
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Because
the
YPI for Valve PSR-V-X77A1 was inoperable for 12 days,
the inspector
concluded that the licensee violated
TS 3.3.7.5 (Violation 397/9433-02).
The inspector discussed
this issue with the plant manager.
The inspector
concluded that the operators
did not exhibit a questioning attitude in daily
panel
walkdowns to determine
the status
and operability of Valve PSR-V-X77A1.
In addition, operations
personnel
did not follow procedures
for initiating
PERs
and conducting operability assessments,
The inspector also concluded
that the work control personnel
did not perform an adequate
review of the work
to properly prioritize the work as required to be done within 7 days to adhere
to the
TS.
The plant manager
acknowledged
the inspector's
comments
and
added
that,
in the past,
operators
had taken credit for local indications for
accident monitoring
and depended
on this past
assumption for operability in
this case.
The licensee
was preparing
a Licensee
Event Report
(LER), pursuant
to
at the
end of the inspection period,
3.2.3
Shift Manning
The inspector
observed
control
room and shift manning for conformance with
TS,
and administrative procedures.
The inspector also
observed
the attentiveness
of the operators
in the execution of their duties
and found acceptable
performance.
Shift manning
was in conformance with
applicable
requirements
and
a professional
control
room demeanor
and
atmosphere,
free of distractions,
existed.
3.2.4
Equipment
Lineups
The inspector verified valves
and electrical
breakers
to be in the position or
condition required
by TS and administrative
procedures
for the applicable
plant mode.
This verification included routine control
board indication
-10-
reviews
and conduct of partial
system lineups.
TS limiting conditions for
operation
were verified by direct observation.
3.2.5
Equipment Tagging
The inspector
observed
selected
equipment,
for which tagging requests
had
been
initiated, to verify that tags
were in place
and the equipment
was in the
condition specified.
The inspector did not identify any deficiencies
in
observing clearance
orders.
3.2,6
General
Plant
Equipment Conditions
The inspector
observed
plant equipment for indications of system leakage,
improper lubrication, or other conditions that would prevent the system
from
fulfillingits functional requirements.
were observed
to
ascertain their status
and operability.
3.2.7
Plant Chemistry
The inspector
reviewed chemical
analyses
and trend results for conformance
with TS and administrative control procedur'es.
3.3
'En ineered
Safet
Features
Walkdown
The inspector walked 'down selected
engineered
safety features
(and systems
important to safety) to confirm that the systems
were aligned in accordance
with plant procedures.
During the walkdown of the systems,
items
such
as
hangers,
supports,
electrical
power supplies,
cabinets,
and cables
were
inspected
to determine that they were operable
and in a condition to perform
their required functions.
Proper lubrication
and cooling of major components
were also observed for adequacy.
The inspector also verified that certain
system valves
were in the required position
by both local
and remote position
indication,
as applicable.
The, inspector walked
down accessible
portions of the following systems
on the
indicated dates:
~Sstem
DG Systems,
Divisions 1,
2,
and
3
Low Pressure
Coolant Injection
Trains
A,
B,
and
C
Low Pressure
High Pressure
Reactor
Core Isolation Cooling
(RCIC)
Dates
January
20,
1995
January
4 and
16,
1995
January
4 and
16,
1995
January
4 and
16,
1995
January
4 and
16,
1995
-11-
Residual
Heat
Removal Trains
A and
B
125V
DC Electrical Distribution,
Divisions
1
and
2
250-Vdc Electrical Distribution .
3.4
Results
January
4 and
16,
1995
January
5,
1995
January
5,
1995
The inspector determined that routine plant operations
appeared
to be adequate
during this inspection period.
In addition,
the inspector
determined that the
engineered
safety feature
systems
were in good order
and aligned in accordance
with plant procedures'.
However, the inspector
noted the following issue with
DG 1.
3.5
Uncertain
Governor Settin
On January
20,
1995,
the inspector walked
down the
DGs using licensee
procedures.
During this walkdown, the inspector verified lubrication levels,
starting air pressure,
and governor settings,
The inspector
noted that
PPH 2.7.2.A (the system operating
procedure for DG 1) required that the speed
setting of the governor
be set at 13.80 for Diesel
Engine
IA1.
PPH 2.7.2.A
also states
that the out-of-specification
high value
was "greater than 13.80"
and the out-of-specification
low value
was "less than 13.80."
The inspector
found that the
speed
setting for Diesel
Engine
lA1 indicated
13.79.
The
inspector
was concerned
that the setting
was not in accordance
with the
procedure
and that, if the
speed setting
was not adjusted
properly, the tandem
DG engines
would not load equally, potentially affecting the operability of
the
DG.
The inspector notified the shift manager,
who in turn notified the system
engineer
(SE).
The
SE noted that the adjustment
knob was loose
such that
there
was "play" in the position of the speed setting
adjustment
knob, that
'the
speed setting
was still proper,
and that
1 was operable.
The inspector
noted that, with no tolerance
band for the speed setting,
the
speed setting
knob must
be indicating correctly,
so that the indication,
and
thus proper operation of the
DGs, would not be in question.
The licensee
initiated
a work request
to correct the faulty knob.
The inspector
noted that licensee
procedures
require that the governor
speed
setting
must
be checked
by the equipment operators
during each startup of the
DGs,
and then hourly thereafter.
In addition, the
SEs frequently perform
system walkdowns.
Because
the
NRC identified this issue,
the inspector
questioned
whether
and equipment operators
have performed sufficiently
thorough walkdowns of the emergency diesels.
-12-
4
ONSITE ENGINEERING
(37551,
92903)
The inspector
performed reviews of the following engineering
related
activities during this inspection period.
4.1
Review of 0 en
0 erabilit
Assessments
On January
8,
1995,
the inspector
reviewed the "Prompt Operability
Assessment
(POA) Log," to determine if engineering
personnel
were adequately
reviewing
and dispositioning
degraded
conditions.
This log contains
POAs
and
formal "Followup Assessments
of Operability" (FAO).
During this review, the
inspector
noted three
issues
in which the
FAO gave the rationale for why the
equipment
was operable for Nodes
4 and 5, but included
no justification for
the current operational
Node
1.
These three
issues
were associated
with PER 294-0700
(Degraded
Agastat
Relays),
PER 294-0463
(Emergency
Core Cooling System
Room Flooding),
and
PER 294-0483
(Degraded Electrical Penetrations).
The licensee
noted that in
these
cases
the
FAOs should
have
been
removed
from the
POA log, because
either
the problems
had
been corrected or the
FAO had
been
updated.
As followup to the inspector's
concern,
the licensee
proposed five corrective
actions.
They also noted that there
was
no formal process
to review the
POA
log prior to plant startup to ensure it was
up to date,
and that
any FAO's
that were completed
were removed
from the book.
The licensee
stated that they
would evaluate
whether
a change to
PPH 3. 1. 1, "Haster Startup Checklist,"
was
necessary.
In addition,
the licensee
was evaluatin'g
changing
PPH
Procedure
1.3. 12A, "Problem Evaluation Requests,"
to more formally track the
status of FAO's
and to periodically perform reviews
and updates
to the
POA
log, to ensure
operators
have
a complete
and accurate listing of degraded
equipment.
The inspector
noted that the
POA log in the control
room is
a tool used
by the
operators
to assure
awareness
of degraded
conditions and/or work-arounds.
If
this is not kept
up to date,
operators
may not have
an accurate
depiction of
the status of degraded
safety
systems,
which is important for safe plant
operations.
5
PLANT SUPPORT ACTIVITIES
(71750)
The inspector evaluated
plant support activities based
on observation of work
activities, review of records,
and facility tours.
The inspector
noted the
following during this evaluation.
I
5, 1
Fire Protection
The inspector
observed firefighting equipment
and controls for conformance
with administrative
procedures,
Within the scope of this inspection, fire
protection controls
were adequate.
-13-
5.2
Radiation Protection Controls
The inspector periodically observed radiological protection practices to
determine whether the licensee's
program was being implemented
in conformance
with facility policies
and procedures
and in compliance with regulatory
requirements.
The inspector
also observed
compliance with radiation work per-
mits, proper wearing of protective equipment
and personnel
monitoring devices,
and personnel
frisking practices.
Radiation monitoring equipment
was
frequently monitored to verify operability and adherence
to calibration
frequency.
Licensee
personnel
followed radiation protection procedures
and
maintained their exposures
as low as reasonably
achievable.
5,3
Plant
Housekee
in
The inspector
observed
plant conditions
and material/equipment
storage to
determine
the general
state of cleanliness
and housekeeping.
Housekeeping
in
the radiologically controlled area
was evaluated with respect
to controlling
the spread of surface
and airborne contamination'lant
housekeeping
was
observed
to be good in all plant areas
containing equipment
important to
safety.
S. 4
~Securi t
The inspector periodically observed
security practices
to ascertain
that the
licensee's
implementation of the security plan was in accordance
with site
procedures,
that the search
equipment at the access
control points
was
operational,
that the vital area portals
were kept locked and'alarmed,
that
personnel
allowed access
to the protected
area
were
badged
and monitored,
and
that the monitoring equipment
was functional.
5.5
Emer enc
Plannin
The inspector toured the emergency
operations facility, the Operations
Support
Center,
and the Technical
Support Center
and ensured that these
emergency
facilities were in
a state of readiness.
Housekeeping
was noted to be good
and all necessary
equipment
appeared
to be functional.
5.6
Conclusions'lant
support
performance
was satisfactory
throughout this inspection period.
Performance
in the radiation protection
and security areas
was good.
6
SURVEILLANCE TESTING
(61726)
The inspector
reviewed surveillance tests
required to be performed
by the
TS
on
a sampling basis
to verify that:
(1)
a technically adequate
procedure
existed for performance of the surveillance tests;
(2) the surveillance tests
had
been
performed at the frequency specified in the
TS and in accordance
with
the
TS surveillance
requirements;
and (3) test results satisfied
acceptance
criteria or were properly dispositioned.
The inspector
observed
portions of the following surveillances
on the dates
shown:
Procedure
PPH 7.4.3,6.2.4
Descri tion
Control
Rod Block Recirculation
Flow Upscale
and
Comparator
Channel
C Channel
Check
Dates
Performed
January
11,
1995
PPH 7,4.3. 1. 1.20
Reactor Protection
System
and
End of Cycle Recirculation
Pump Trip
December
6,
1994
The inspector
concluded that these
surveillances
were performed
and documented
properly.
7
MAINTENANCE OBSERVATIONS
(62703)
During the inspection period,
the inspector
observed
and reviewed
documentation
associated
with maintenance
and problem investigation activities
to verify compliance with regulatory requirements
and with administrative
and
maintenance
procedures,
required quality assurance/quality
control
involvement,
proper
use of clearance
tags,
proper equipment
alignment
and
use
of jumpers,
personnel
qualifications,
and proper retesting.
The inspector
verified that reportability for these
maintenance activities was correct.
The inspector witnessed
portions of the following maintenance activities:
Descri tion
SH4601,
Change
Out Scram Accumulator for
RV 79, Drift Light Indication Repair for
46-47,
14-43
and 54-39
Dates
Performed
January
18,
1995
December
30,
1994
The inspector determined that these
maintenance activities were performed
and
documented
properly,
8
EVALUATION OF ONLINE MAINTENANCE
8. 1
Back round Information
During recent plant visits by several
NRC senior managers, it was noted that
some licensees
are increasing
both the amount
and frequency of maintenance
during power operation.
Expansion of online maintenance
without thoroughly
considering
the safety (risk) aspects
may raise significant concerns.
The
purpose of performing this temporary instruction
was to review and record the
-15-
licensee's
program for scheduling online maintenance activities
and to
determine if the licensee's
program considers
the appropriate risk factors.
8.2
Overview of the Current Plannin
and Schedulin
Pro ram at
WNP-2
The licensee
has
two procedures
which 'directly address
the subject of online
maintenance.
The two procedures
are
PPH Procedure
1. 16.6,
"Scheduling
and
Coordination of Plant Work," and
PPH 1, 16.6B, "Voluntary Entry into TS Action
Statements
(TSAS) to Perform Work Activities During Power Operations."
One of
the persons
with primary responsibility for the implementation of these
procedures
is the production scheduling shift manager
(PSSH)
who is required
by procedure
to be either certified or licensed
as
an
SRO.
Scheduling of work involves
a 12-week rolling matrix schedule.
Although
a
quantitative probabilistic risk assessment
(PRA) was not performed in
developing the rolling matrix, risk was considered
during the development of
the schedule
by licensee
personnel
with extensive
knowledge of plant
operations
and risk significance.
The licensee's
12-week rolling matrix shows
both safety-
and nonsafety-significant
systems
which can
be worked
concurrently.
The systems
for each
week are listed such that work on more
than
one train of safety equipment
at the
same time is not scheduled.
The
schedule
is designed
so that sufficient margin exists
between
scheduled
work
activities
on redundant trains to avoid any overlap of activities should work
on one train extend
a short period past its planned duration.
The underlying principle to performing on-line maintenance
of safety
components
at
WNP-2 is that the activity should
be performed only if the
safety of the plant is either enhanced
or maintained.
Accordingly,
PPH
1. 16.6B requires
(as
an expectation of WNP-2 management)
that
a safety
justification be provided
and that
a Probabilistic Safety Assessment
(PSA)
be
performed for all work activities requiring voluntary entry into TSAS.
In
addition, the
PSSH
may request
a
PSA for any tentative work activities that
he
feels could potentially impact plant safety.
Scheduling of emerging work at
WNP-2 always involves review by the
PSSH.
Although equipment availability requirements
may necessitate
the performance
of work on equipment prior to its appearance
on the
12-week rolling matrix,
concurrent
work on redundant trains would be generally excluded.
Also, the
licensee's
procedures
do not allow the scheduling of ".
.
. activities
concurrently
on divisional related
equipment
which have the potential for
resulting in unplanned initiations or actuation of Engineered
Safety Features,
Nuclear
Steam Supply System Shutoff, Reactor Protection
System
.
It should also
be noted that production schedules
are reviewed
on
a daily
basis
at scheduling
meetings
attended
by the maintenance
manager
and the
PSSH.
These
meetings
include
a review of the work .activities scheduled
to be worked
over the next
3 days.
-16-
8.3
Consideration of Risk in the Schedulin
of On-Line Maintenance 'Activities
The
12-week rolling matrix schedule
i.s one of the basic
components of the
licensee's
scheduling
process.
The rolling matrix was developed
considering
the licensee's
assessment
of risk based
on knowledge of plant operations'.
However, the licensee
did not perform
a formal
PRA analysis for the activities
listed in the matrix weekly windows.
The probability of an initiating event
can
many times
be attributed to failure of nonsafety
equipment.
Because
the
licensee
included nonsafety
as well as safety equipment
in its evaluation
and
development of the rolling matrix, it can
be concluded that the licensee did
quantitatively consider the probability of an initiating event in developing
its schedule for on-line maintenance activities.
Because
the licensee
considered
the effect of on-line maintenance
on the availability of the safety
systems
in the rolling matrix, it can
be concluded that the risk factors
associated
with core
damage
prevention
and containment integrity were also
considered.
At WNP-2,
a formal quantitative calculation of risk is required whenever
voluntary entry into
a
TSAS is considered.
For this calculation,
the group
performing the
PSA must depend
upon the
PSSH for accurate
data to be
considered
in the
PSA model.
In other words,
the licensee's
PSA group bases
their risk evaluation
on the systems
identified by the
PSSH in the memorandum
request for the
PSA;
hence,
the judgement of the
PSSM as to which scheduled
activities
may
be critical to safety
becomes
very important.
This is one
reason that the
PSSH is required to be licensed or certified as
an
SRO.
As an
additional level of checking,
the
PSA manager
has
been instructed
by the plant
manager to perform
a check of activities in the
WNP-2 Oaily Work Schedule to
identify any work activities which might significantly impact safety.
In addition to the
PSA evaluation,
work activities involving voluntary entry
into TSAS require approval of the
PSSH
and operations shift manager,
For TSAS
restoration
times less
than
7 days,
approval of the Operations
Hanager is
required.
For TSAS restoration
times that are less
than
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />,
approval of
the plant manager
is required.
The inspector also noted that the licensee
might potentially allow voluntary entry into a
TSAS when the system
outage
time is estimated
to exceed that
TSAS time limit,provided subsequent
actions
could
be performed
as required;
however, this type of on-line maintenance
activity would require approval
through the plant manager level.
8.4
Additional Notes
According to WNP-2 procedures,
on
a quarterly basis,
the licensee's
PSA group
reviews all of the voluntary limiting condition for operation entries for the
quarter
and compares
the outage
times to those
assumed
in the
PRA analysis.
This appears
to be
a useful tool in helping to identify problem areas.
For
example,
one of the quarterly reviews identified that the reactor core
isolation cooling had
been
removed
from service for various maintenance
activities for an excessive
amount of time.
Once the situation
was
identified, reactor core isolation cooling availability improved dramatically
the following quarter.
-17-
The licensee
has
recognized that the quarterly report
was not adequate
to be
taken
as
a comparison of actual
equipment
outage
time versus that
assumed
in
the
PRA, because
equipment
down time for routine maintenance
and surveillance
activities is not accounted
For in the quarterly review.
The licensee
was
planning to perform
a second revision to its WNP-2
PRA analysis,
which would
include all equipment
down time.
The inspector
observed
that the licensee's
guality Assur ance department
had
conducted
surveillances
of online maintenance
activities at WNP-2.
8.5
Future Plans
P
A number of aspects
of WNP-2's current on-line maintenance
scheduling
program
(e.g., detailed
PSA for TSAS activities)
were only recently implemented.
The
licensee
appeared
to'ecognize
that the
new WNP-2 scheduling
program relies
heavily on the insights of the
PSST to ensure that work activities which could
impact safety
are fully recognized
and considered.
Consequently,
within the
next few months,
the licensee
is planning to add
a system
dependency
matrix to
PPN 1.16.6B.
The system
dependency
matrix is expected
to aid the
PSSH in
identifying work activities which could significantly increase risk and in
establishing
a consistent
approach
to work planning.
If used properly, the
system
dependency
matrix should help to assure that the
PSA group is provided
with all of the important data to properly assess
risk.
9
ONSITE REVIEW OF
LERs
(92700,
92902,
92904)
The inspector
reviewed the following LER that was associated
with an operating
event.
9. 1
Closed
LER 50-397 94-18
Revision 0:
Failure to
Com l
with TS Action
Re uirement
When Ino erable
Control
Rod Block 'Instrumentation
Exceeded
the Allowed Outa
e Time
This
LER described
an event
on November 9,
1994, that involved Channel
A scram
discharge
volume
(SDV) level switch failing to calibrate.
In the
LER, the
licensee
described
that the switch had
been replaced
during the
1994 refueling
outage
(R9).
The licensee
noted that General Electric
(GE) supplied the
Hagnetrol
manufactured
switch to the Supply System
and that
GE is an approved
10 CFR Part 50, Appendix B, supplier.
GE procured the
75 series
switch from
Nagnetrol
as commercial
grade
and dedicated
the switch for safety applications
at WNP-2.
GE indicated to the licensee that the switch was
an "acceptable
replacement"
for the switch that
had
been previously installed.
The Supply
System's substitution evaluation
concluded that the switch was
a direct
replacement
for the original switch.
On June
30,
1994,
licensee
craftsmen installed the switch under work order
task
(WOT) CN23.
WOT CH23 directed the craftsmen to calibrate the switch
using
PPM 7.4.3 . 1. 1. 17, which was the procedure that was used in calibration
of the original switch.
The calibration resulted
in the lower switch assembly
being raised
approximately 3/4 of an inch above the base plate.
During the
~l
-18-
replacement
and calibration,
the craftsmen,
with the concurrence
of the
instrumentation
and control
(IEC) supervisor,
removed the upper switch
assembly
even
though the
WOT did not direct the upper switch to be removed.
The craftsmen
removed the upper switch assembly
because
the switches
in the
upper assembly
were not used in the control rod drive level switch
application.
During the calibration,
the craftsmen
had difficulty getting the
switch to calibrate;
however, after several
attempts,
which included the
repositioning of the lower switch, the control rod drive level switch was
calibrated within the required tolerances.
Based
on the difficulty
calibrating the switch, the
IKC supervisor
noted in the
WOT that the switch
was not operating properly in its current configuration
and the results
should
have
an engineering
review.
In documenting
the work in the
WOT, the craftsmen
noted that the upper switch assembly
had
been
removed.
Despite the comments
in the completed
WOT, the licensee's
review of the completed
work order did
not cause
an engineering
review to be performed.
On October ll, 1994,
the switch failed
a channel
check.
Craftsmen
recalibrated
the switch
and returned
the switch to service.
During this
failure, the craftsman struck the switch with a wrench.
The
NRC inspector
questioned
the practice of agitating the switch with a wrench
and the
operability of the switch.
The licensee
concluded
the switch was operable
because it passed
a subsequent
calibration.
The licensee
indicated that,
when
moving parts
are believed to be bound,
IEC technicians
routinely attempt to
free the
bound part
by mechanical
agitation.
The licensee
assumed
the switch
had failed calibration
due to entrainment of a foreign particle that
may have
been introduced
as
a result of SDV water lancing.
No debris
was found to
substantiate
this conclusion.
The licensee
increased
the frequency of channel
checks
due to the October ll,
1994, failure of the switch to pass its calibration check.
On October
27,
1994,
a calibration check of the switch found the switch to be within
calibration tolerances.
On November 9,
1994,
the switch again failed
calibration
and operators
declared
the switch inoperable.
The licensee
generated
PER 94-0975 to document the November 9,
1994, failure
to calibrate.
The licensee
documented
the following findings in the
PER:
the
replaced
switch had significantly different operating characteristics
than the
original switch; the replacement
switch consisted
of different switch types
than the original switch;
GE had not provided the Supply System with operating
and maintenance
instructions for the switches;
during licensee calibration,
craftsmen
had
removed
(modified) the upper
(unused)
switch without proper
concurrence
or documentation;
and the lower switch had
been set approximately
I/3 inch higher than the value designated
by Hagnetrol.
In the
PER the
licensee
concluded that the causes
of the switch failure were
a combination of
installation, application,
and adjustment errors.
For interim disposition,
the licensee identified the following actions to correct the deficiencies
identified in their assessment:
identify and correct
any substitution
evaluation
process
failures that contributed to the problem; determine if
proper reviews were obtained prior to r'emoving the
unused
upper switch
assembly.;
determine if seismic qualification of the switch was affected
by
-19-
removal of the upper switch assembly;
determine if the switch was installed at
the correct elevation;
and determine
why vendor information (vendor manual)
was not provided or placed in vendor files.
In closing this
LER the inspector
reviewed procurement
records,
receipt
inspection records,
drawings,
WOTs,
and vendor manuals
and discussed
the event
with Supply System craftsmen,
supervisors,
and engineers.
Initial NRC
followup of this event
was described
in
NRC Inspection
Reports
50-397/94-29
and 50-397/94-32.
The inspector
had the following observations:
~
The licensee's
procurement
specification
was not detailed
enough to
assure
that the correct level switch would be provided
by GE.
Additionally, the Supply System procurement
did not require that
provide
a vendor manual with the switch.
The initial procurement
document
requested
a like-for-like replacement.
When
GE notified the
Supply System that
a like-for-like replacement
was not available,
the
Supply System did not define all the pertinent characteristics
that
an
acceptable
replacement
should
have,
The Supply System
assumed
that
recogn'ized
that the replacement
switch should
be adjustable,
just like
the original switch.
However,
in GE's substitution evaluation,
they
assumed
that the Supply System did not use the adjustable
feature of the
switch
and provided the Supply System with a nonadjustable
switch.
The
Supply System review determined
the switch needed to be adjustable
'because
the piping that houses
the switch had
been installed at
a
slightly different elevation than design
documents
indicated.
The
switch had
been adjusted
to correct for the differences
in design
and
actual
piping elevations.
The licensee's
receipt inspection of the switch was not thorough.
documentation
indicated that the model
number of the switch was
different from the original switch and that the
new switch had four
double-pole,
single-throw switches
instead of the original switch's
two
double-pole,
double-throw switches.
These differences
should
have
initiated
a more thorough evaluation of the differences
between
the
switches.
In November, after receiving the vendor manual
and speaking
with representatives
of Magnetrol
and
GE, the licensee
recognized that
the switch had other configuration differences.
The most significant
difference
was that the replacement
level switch had two magnets
and two
switch assemblies
instead of the
one magnet
and
one switch assembly of
the original switch.
For the licensee's
receipt inspection to identify
these differences,
the switch would have to have
been disassembled
or
the vendor manual
referenced.
The licensee
did not disassemble
the
switch or have the vendor manual
during receipt inspection.
In
November,
the licensee
learned that the reset function of the
replacement
switch was impacted if the upper switch assembly
was
removed.
Based
on information provided
by the supplier
and vendor,
the
licensee
concluded that the replacement
switch could
be "used-as-is."
(without the upper switch assembly)
since the accuracy of the switch was
within the reset
tolerances
required
once the lower switch assembly
was
returned
to within the manufacturer's
specifications.
The licensee
J
-20-
plans to restore
the upper switch assembly
when plant conditions permit.
The licensee
has
changed
the receipt inspection criteria to require
a
vendor manual
or
a revised
vendor manual if there
has
been
a physical
change to any part of the component.
GE did not completely'understand
the differences
between
the original
and the replacement
switches.
GE's lack of understanding
contributed to
the Supply System's difficulty in resolving the channel
check failures.
In October,
Supply System engineers
discussed
the switch operation
and
switch troubleshooting with GE representatives.
GE indicated that the
original vendor
manual
could be used to troubleshoot
the switch, which
was subsequently
found not to be the case.
Supply System craftsmen
performed
a modification to the switch by
removing the upper switch assembly without an appropriate
engineering
safety evaluation or approved
work package.
The failure to control the
design of the switch is
a violation of 10 CFR Part 50, Appendix B,
Criterion III, "Design Control."
Because
the licensee's
corrective
actions
were thorough
and the issue of performing
an unauthorized
modification was self-identified, the above violation is not being cited
(397/9433-03).
The Supply System missed opportunities
to identify deficiencies with the
switch installation
upon review of the completed
work request
and during
the failures of the channel
check.
The licensee's
root cause
analysis
was weak in that it concluded
the
root cause of this event
was GE's failure to identify the nonadjustable
design of the switch in their substitution evaluation,
The Supply
System did not identify to
GE that the adjustable
feature
was critical
to the switch application at
WNP-2; therefore,
to GE's
knowledge the
switch would perform the
same function.
Additionally, the Supply System
receipt inspection did not use verification of adjustability
as
an
acceptance
criteria.
The Supply System's
assessment
of safety significance
was acceptable.
The switch in question
provides
a rod block if water level in the
SDV is
high.
Other switches
provide the safety function of a reactor
scram if
the water level in the
SDV exceeds
a higher level.
In summary,
the licensee's
activities regarding the procurement
and
installation of the
SDV level control rod block switch were not adequate
in
that:
(1) the procurement specification
was not sufficiently detailed to
assure
that the supplier provided the correct level switch;
(2)
GE did not
thoroughly understand
the differences
between the originally supplied switch
and the replacement
switch;
(3) the receipt inspection of the supplied switch
was not sufficiently thorough to determine that the component
was not
a like-
for-like replacement
and in conformance with the purchase
specification;
(4) craftsmen
performed
a modification to the switch without an appropriate
engineering
safety evaluation or approved
work package;
and (5) the Supply
System missed opportunities to identify deficiencies
in the switch
installation during the review of the completed
work request
and the failures
of the channel
check.
ATTACHMENT
1
PERSONS
CONTACTED
Washin ton Public Power
Su
l
S stem
- V. Par rish, Vice President,
Nuclear Operations
- J. Gearhart,.
equality Assurance
Director
J. Swailes,
Plant Manager
J.
Baker, Technical Training Manager
- R. Barbee,
System Engineering
Manager
S. Kirkendall, Plant Support Engineering
Manager
- P. Bemis,
Regulatory
Programs
Manager
- J, Albers, Radiation Protection
Manager
- G. Smith, Operations Division Manager
- M. Reddemann,
Technical
Services Division Manager
- C. Schwarz,
Operations
Manager
- D. Swank,
Licensing Manager
- J. Huth, Plant Assessments
Manager
- P. Taylor, Shift Manager
- H. Baird, Shift Manager
- A. Langdon, Assistant Operations
Manager
- W. Sawyer,
Operations
Support
Manager
- J
~ Pedro,
Licensing Engineer
- V. Harris,
Maintenance Specialist
- J, Bekhazi,
Principal
Engineer
- G. Weimer, Training Specialist
Bonneville Power Administration
- D. Williams, Nuclear
Engineer
Nuclear
Re ulator
Commission
- D. Kirsch, Chief, Projects
Branch
E
- R. Barr, Senior Resident
Inspector
- D. Proulx, Resident
Inspector
The inspector
also interviewed various control
room operators,
shift
supervisors,
and shift managers
and maintenance,
engineering,
quality
assur ance,
and
management
personnel.
- Denotes attendance
at the exit-meeting
on January
26,
1995.
2
EXIT MEETING
An exit meeting
was conducted
on January
26,
1995.
During this meeting,
the
inspector reviewed the scope
and findings of the report.
The licensee
acknowledged
the inspector'indings.
The licensee
did not identify as
proprietary
any of the information provided to, or reviewed by, the inspector.
c
0'