ML17285A106
| ML17285A106 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/15/1988 |
| From: | Dangelo A, Fiorelli G, Paul Prescott, Richards S, Samworth R, Tatum J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A104 | List: |
| References | |
| 50-397-88-24, NUDOCS 8812120003 | |
| Download: ML17285A106 (40) | |
See also: IR 05000397/1988024
Text
4
U. S.
NUCLEAR REGULATORY COMMISSION
REGION
V
Report No.
Docket No.
50-397/88-24
50-397
License
No.
Licensee:
Facility Name:
Inspection at:
Washington Public Power Supply System
P. 0.
Box 968
Richland,
99352
Washington Nuclear Project No.
2 (WNP-2)
WNP-2 Site,
Benton County, Washington
Inspection conducted:
August
2 - September
2,
1988
Inspectors:
.
D
nge o,
n>or
es> ent
nspector
Team Leader
il rs
E/'e
gne
Approved By:
J.
atum,
ess
ent Inspector
lore
s,
e
s
t
nspector
NP7
rescott,
R
amwort
,
Other Accompanying Personnel:
B. L. Collins,
NRC Contractor,
INEL
sc
ar s,
)e
,
ngsneersng
ection
i> - is -88
ate
sgne
ll- 8'-88
ate
Soigne
l/ / ~ f'J
a
e
sgne
d'P
te
sgne
ate
sgne
Ins ection
Summar
Ins ection
on Au ust
22 - Se tember
2
1988
Re or t No. 50-397 88-24
~AI
I:
A I 11,
I
I I
I
I I
maintenance,
engineering
and
QA activities
as they relate primarily to the
system
and the Nuclear Steam Supply Shutoff System.
SSi2120003
88i123
Anger.v n~nnnzev
Results:
General
Conclusions
and
5 ecific Findin s:
1.
Control of work activities and operations is weak resulting in activities
being conducted
and documented in an informal manner.
2.
Plant problems
are not being adequately identified at the working level.
3.
The followup of identified plant problems is not aggressive..
Additionally, see Appendix B, Areas Inspected
and Results
Summar
of Violations Identified:
1.
Failure to follow procedures
when revising a surveillance procedure.
2.
Failure to report to the
NRC two Reactor Protective
System actuations.
3.
Failure to follow procedures
in reterminating electrical
connections
during maintenance.
~
~
~
~
~
~
~
~
~
4.
Failure to promptly determine the affect of the out of calibration status
of testing equipment.
0 en Items
Summar
Four new items open,
none closed.
4
>>
DETAILS
1.
Persons
Contacted
a.
Washin ton Public Power
Su
1
S stem
"C.
M. Powers,
Plant Manager
"R.
L. Webring, Manager, Assistant Maintenance
"A. L. Oxsen, Assistant
Managing Director, Operations
"J.
W. Baker, Assistant
Manager,
Nuclear Plant
"M. R. Wuestefeld,
Supervisor,
Plant Engineering
"G.
D. Bouchey, Director, Licensing and guality Assurance
"A. G. Hosier, Manager,
Project Licensing
WNP2
"L. T. Harrold, Manager,
Generation
Engineering
"W. D. Shaeffer,
Assistant
Manager,
Operations
Nuclear Plant
"S.
L. McKay, Manager,
Operation Nuclear Plant
D.
S.
Feldman,
Supervisor,
Mechanical
Maintenance
E.
R.
Ray, Supervisor,
Instrument Maintenance
T.
W. Albert, Engineer,
Instrument Maintenance
J.
0.
Cooper,
Engineer,
Mechanical
Maintenance
S.
L. Gupta,
Engineer,
Principal guality Control
B. Pesek,
Engineer,
Systems
b.
"B. F. Faulkenberry,
Deputy Regional Administrator,
RV
"S.
A. Richards,
Chief, Engineering Section,
RV
Denotes
those attending the final exit meeting
on September
2, 1988.
The inspectors
also contacted
licensee
operators,
engineers,
technicians,
and other personnel
during the course of the inspection.
2.
Sco
e and Pur ose of the Ins ection
This team inspection evaluated
the material condition, performance,
maintenance,
design modifications
and operating procedures
of WNP-2 as
they relate primarily to two selected
systems.
The Emergency Diesel
4
Generator
(EDG) system
and the Nuclear Steam Supply Shutoff System
(NS )
were selected
by the team for review.
Generic precursor data associated
with the systems
under review was evaluated
by the team to determine if
the lessons
learned 'regarding potential
system degraded
performance
had
been addressed
by the licensee.
Observations
of operator performance
both inside and outside of the
control
room were conducted
by the team.
Maintenance
and surveillance
activities were observed for compliance with written instructions
and
procedures,
and for documentation of work which was actually performed.
The material condition of the plant was assessed
by comparing the as
found equipment status with documented
procedures,
drawings,
specifications,
vendor data
and past documented
industry experience.
3.
Performance
of the 0 eratin
Crews
The team performed several
plant tours
and verified the operability of
the emergency
diesel
generator
system,
reviewed the tag out log,
operators'ogs
and verified proper return to service of components.
Particular attention
was given to housekeeping,
examination for potential
fire hazards,
and fluid leaks.
The team observed that operational activities were conducted in a
professional
manner,
and the operations staff appeared
to be dedicated
and displayed
a good attitude towards the performance of their duties.
Although the licensed operators
appeared
to be very experienced,
the team
observed
'a number of weaknesses
in the execution of the licensee's
programs.
Additional definition of this concern is included in
paragraphs
3.a through 3.d below:
The team reviewed the Control Operator
and Shift Manager log entries
and verified that logs were being kept in accordance
with
Administrative Procedure 1.3.4, titled "Operating Data and Logs"
(Revision
9 dated April 17, 1987),
and verified that Technical
Specification action requirements
and mode restraints
were complied
with for selected
safety related
components.
Although no
discrepancies
were identified, the team noted the following
weaknesses:
Entries in the Control Operator's
log were often abbreviated
and did not provide much detail, making subsequent
log reviews
cumbersome
and time consuming.
Significant plant problems
and inoperable
equipment which could
have
some impact on Technical Specification requirements
were
not highlighted and carried forward, such that this information
was not readily available.
A formal system did not exist for tracking inoperable
equipment
to assure
compliance with Technical Specification action
statements
and mode restraints.
The team discussed
these observations
with the Operations
Manager,
who acknowledged the team's
comments
and stated that programmatic
improvements in these
areas
were currently being considered.
During review of the control
room logs, the team observed that the
following actuations of the reactor protection system
(RPS) occur red
and were not reported to the
NRC:
At 0844 on May 29, 1988, during Mode 5 operation,
an
actuation
occurred during initial testing of the alternate
rod
insertion (ARI) system.
The
RPS actuation occurred
when air
pressure
bled off the scram valves after the ARI system
was
placed in the test
mode
was isolated.
Although the Shift Manager's
log stated that this action is
normal with supply air off during the initial testing of ARI,
it appeared
that this conclusion
was reached after the
actuation occurred.
The team reviewed the procedure
which was
used for testing the ARI system
(TP 8.3.94)
and discussed
the
actuation with the cognizant engineer.
The team concluded that
the
RPS actuation
was not anticipated in the test procedure,
and control rod drive air system
leakage
was
an abnormal
condition which resulted
from undocumented air system leaks.
At 1553 on August 26, 1988, during Mode
5 operation,
an
actuation occurred
when Division II RPS power was transferred
from alternate to normal.
The Shift Manager's
log made
reference to nonconformance
report
(NCR) 288-379,
and the
Control Operator's
log stated that the actuation
was
due to
switch over-travel.
NCR 288-379 stated that this event was not
reportable
because it occurred during equipment testing.
The
Operations
Manager stated that a similar event was reported to
the
NRC which had occurred
on August 25 when Division I RPS
power was transferred
from alternate to normal.
The
actuation that occurred
on August 26 was
due to subsequent
testing
and was not felt to be reportable.
The team observed
that the control
room logs did not indicate that testing
was
in'rogress
at the time of the
RPS actuation,
and the licensee
could not produce
a maintenance
work order or other
documentation to demonstrate
that testing
was in progress
during the August 26 event.
10
CFR 50.72 requires the licensee to report
RPS actuations
which
are not part of a preplanned
sequence within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of actuation.
The licensee's
assessment
of the reportability of these
events
was
incorrect,
and the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> reports
were not made to the
NRC.
Failure to report these
events is an apparent violation
(50-397/88-24-01).
Housekee in /Material Plant Condition
While making rounds with equipment operators
and during general
plant tours, the team
made the following observations
relative to
housekeeping
and material plant condition:
The team toured the drywell during the inspection.
The drywell
was accessible
because
the unit was shutdown for an unscheduled
outage.
Equipment in the drywe11 did not appear to be well
preserved
in that there appeared to be excessive
rust on piping
and other
components.
Following the last scheduled
outage,
miscellaneous
debris
such
as fire retardant
covers,
a plastic
bag fashioned into a seat cushion,
and a pair of goggles,
had
not been identified and removed from the drywell.
The team
also observed that a grounding cable
had been left attached to
one of the reactor vessel
instrument nozzles.
It was
apparently
a remnant from startup testing.
The cap was noted
to be missing from an electrical
connector for temperature
element
CMS-TE"52 used to measure
upper return ring header air
temperature
in the drywell at the 575 foot elevation.
With the
exception of the rust and the grounding cable,
the licensee
stated that these conditions would be corrected prior to
startup
from the current outage.
Felt tip pen was
used extensively for component identification.
In addition, graffiti was prevalent throughout the plant.
Licensee
management
acknowledged
the teams
concern
and stated
that a program was being developed to address
plant labeling.
In addition, painting of the facility was in process
during the
inspection.
Electrolyte levels for many of the batteries
used for emergency
lighting were not properly maintained.
For example, batteries
441/2
~ 441/7 ) 441/8 j 441/9 )
SWA7 1X )
SWA7 2X )
SWA5 6
SWA6 4
and
SWS3-3 were all low on electrolyte level.
The team noted
that Electrical Maintenance
Procedure
10.25.63, titled
Emergency Lighting Inspection
(Rev.
3 dated
June 17, 1988)
identified batteries
SWA7-1X and
SWA7-2X as 8-hour units
required to satisfy the requirements
The licensee
stated that Electrical Maintenance
Procedure
10.25.63 would be changed to include verification of proper
battery electrolyte level.
Housekeeping
deficiencies
outside the drywell included several
instances
where ladders
were not properly stowed,
one instance
where a liquid nitrogen bottle was left on a dolly unsecured
and unattended,
a large accumulation of trash
on the 467'evel
of the radwaste building, and many observations
where tools
were not properly stored.
Transformer TR-7A-A (DIV 1) circuit lM-7AA-150-1 was missing
a
condulet cover,
and a grounding cable
near
MCC-8C-A was not
secured.
Handwheels
were not secured
on valves
RHR-PI-VX-74A,
RHR-PI-VX-74B and HPCS-V-69.
Breaker indicating lights were not working for high pressure
(HPCS) diesel
generator
(DG) room fan DMA-FN-31 and
DG oil transfer
pump DO-P-2.
The licensee
stated that the
indicating lights were burned out and that the bulbs were
subsequently
replaced to resolve the problem.
The team discussed
these observations with station management,
noting that a program for maintaining adequate
plant material
condition did not appear to have been established.
Although the
licensee
had undertaken
maintenance efforts to repair
known
deficient conditions
and
had begun to paint the power block,
no
comprehensive
program exists to establish
minimum requirements for
maintaining of material plant conditions.
d.
Formalit
and Attention to Detail
In addition to the housekeeping
and material plant condition
observations
discussed
in paragraph
2.c above,
the team identified
the following examples of informality and inattention to detail:
The shift brief that was conducted
by the Control
Room
Supervisor
on August 27, 1988, included mention of a
waterhammer that occurred in the residual
heat
removal
(RHR)
system.
The team observed that the cognizant engineer
was
present in the control
room evaluating this event.
While making
rounds with the equipment operator later during the shift, the
team observed that a waterhammer
occurred
when
RHR pump
B was
started.
The team also observed that
RHR pump
B was rotating
backwards for a pe} iod of time when the system
was being
aligned initially for operation.
Although the cognizant
engineer
was
made
aware of the
RHR waterhammer
problem, the
team observed that a log entry was not made regarding this
problem and resolution of the problem was not being pursued in
a formal manner.
In addition,
upper station
management
was not
made
aware of the waterhammer
events in a timely fashion.
In response
to the team's
concern over the pump shaft rotating
backwards
and the apparent water hammer,
the licensee
began
an
'nvestigation
which included the disassembly
and inspection of
the
RHR pump discharge
The licensee
discovered
during the internal valve inspection that the disk of the check
valve was in the open position and did not close.
The
RHR pump discharge
check valves are tilting disk Anchor
Darling valves.
The disk of these
valves rotates
about
a pin,
such that the disk remains in the flow stream.
However,
upon
rotation the cross sectional
area of disk which obstructs
flow
is reduced to a minimum.
When fluid flow is reduced or
stopped,
the buoyant force which had been acting on the disk is
reduced or removed.
This would cause the disk to rotate or
tilt back into the closed position.
The check valve disk, when opened
by fluid flow, is pressed
against
a stop which was designed to ensure
the disk's center
of mass is always
ahead of the disk pin.
Therefore the disk
would tend to close
based
on the disk's
own deadweight.
During
the valve inspection,
the licensee
discovered that the disk
stop did not interrupt the disk travel until the disk's center
of mass
was apparently directly over the disk pin.
This
apparently
caused the disk to become balanced
on the disk pin
and when fluid flow stopped,
the disk did not close.
In
addition, the disk remained
open against reverse flow which
apparently occurred
when the
RHR pump's shaft was observed to
be rotating backwards.
When clearance
order 88-8-106 was being implemented,
the
equipment operator could not locate
a fuse that was called out
as part of the clearance.
The inspector observed that drawing
24E005
(Rev 7) indicated that the fuse was located in
instrument rack 67, but the fuse was subsequently
found in a
terminal
box associated
with instrument rack 67.
The inspector
also observed that approximately
12 circuits were left
abandoned
in instrument rack 67,
and the circuits were not
labeled
as to their current status.
Actions were not taken
by
operations
personnel
to formally document
and resolve these
discrepancies.
During emergency diesel
generator
(DG) ¹1 surveillance testing
that was conducted
on August 26, 1988, the inspector
observed
that
a yellow oil-like substance
was floating in the cooling
water of the
DG cooling water expansion
tank sight glass.
The
inspector also observed that after the diesel
was started,
the
governor oil levels did not drop to the sight glass midpoint
scribe mark which was the nominal level specified by the
surveillance
procedure
(a tolerance
band was not specified).
These conditions were not questioned
and were not documented
by
the equipment operator.
The team discussed
the above observations
with the licensee.'t
appeared
that the licensee
recognizes
the
need for more aggressive
program
development
and implementation.
Recent
changes
in station
management
have
been
made in an effort to improve performance,
and programmatic
improvements
are currently being considered.
One violation was identified as discussed
in paragraph
3.b above.
4.
Surveillance Activities
The team observed
in"process surveillances
on the diesel
generator
and
the drywell sump flow monitor for attention to detail in following the
written instructions provided and in recording the data obtained
from the
surveillance.
There appeared
to be a rigorousness
by the control room
personnel
in following surveillance procedures.
However,
a surveillance
and in-process trouble shooting was observed
by the team for the drywell
sump monitor where such rigor was not apparent.
a 0
Diesel Generator ¹I Monthl
Surveillance
On August 26, 1988, the team observed the monthly operational
surveillance of the ¹1 emergency diesel
generator
(DG).
The
surveillance
was conducted in accordance
with Surveillance
Procedure
7.4.8. 1. 1.2.1, titled "Diesel Generator ¹1 - Monthly Operability
Test"
(Rev. ll dated August 25, 1988).
Although the surveillance
was performed satisfactorily, the team observed that a yellow
oil-like substance
was floating in the
DG cooling water expansion
tank sight glass.
The team also observed that after the diesel
was
started,
the governor oil levels did not drop to the sight glass
midpoint scribe
mar k which was the nominal level specified by the
surveillance
procedure
(a tolerance
band was not specified).
These
conditions were not questioned
and were not documented
by the
equipment operator (also discussed
in paragraph
3.d of this report).
In order to resolve the teams'oncerns,
maintenance
work request
I
b.
(MWR) AT6682 was initiated to remove any foreign substance
from the
DG cooling water system
and the
DG was started
so that adjustments
could be made to the governor oil levels.
The licensee
stated that
the surveillance
procedure
would be changed to provide more
definitive guidance with regard to the governor oil levels.
Dr well
Sum
Flow Monitor Calibration
On August 24, 1988, the team observed that instrument
and control
(I8C) technicians
were making adjustments
to the drywell sump flow
monitor calibration.
Procedure 7.4.4.3.1.4, titled "Drywell Sump
Flow Monitors - CC" (Rev. 3, including Deviation 88-538 dated
June.
ll, 1988),
was being used to perform this activity.
The licensee
had determined that the flow indicated by the monitor was
inaccurate.
The actual flow rate from the drywell sump
was being
measured periodically by liquid collection techniques.
The team
observed that the procedure
was being marked
up as the calibration
was being performed.
There did not appear to be any administrative
control of the revisions
made to the procedure.
The maintenance
supervisor stated that there were
some problems with the procedure
such that the flow totalizer did not give accurate
indication when
the calibration was completed
and that the procedure
was being
troubleshot
and corrected
as part of the calibration activity that
was currently being performed.
When questioned,
the Shift Manager
stated that he was not advised of the changes that were being
made
to the calibration procedure.
The licensee's
Administrative Procedure 1.2.3, titled "Use of
Procedures"
(Rev.
12 dated
September
18, 1987), requires
procedures
to be followed in the performance of plant activities.
When
procedures
cannot
be followed, a revision to the procedure or a
procedure deviation must be completed.
In the case of a procedure
deviation,
documentation prior to its implementation is not required
providing the deviation
has
been approved
by two members of plant
management/supervisory
staff, and the Shift Manager is of the
opinion that the work must continue.
During calibration of the
drywell
sump flow monitor, these administrative controls were not
complied with. The maintenance
supervisor initiated nonconformance
report
(NCR) 288-373 to address
the team's
concern.
This is an
apparent violation (50-397/88-24-02).
One violation was noted in this area during the inspection.
5.
Maintenance
Pro
ram Im lementation
a 0
Or anization/Pro
ram
The Maintenance organization consists of a staff of approximately
210 and is directed
by a maintenance
manager
who reports directly to
the plant manager.
In addition to the normal
complement of
craftsmen
and supervisors,
the organization includes groups of
maintenance
engineers
who provide both technical
and work
coordination support to the individual craft groups.
The
maintenance
engineers
are the principal developers
of the work
instructions
and work package
planning sheets
which identify the
critical elements of a maintenance effort.
In an effort to provide
stronger direction and improve the quality of the maintenance
work
at the plant,
reassignments
were recently
made in the positions of
maintenance
manager,
assistant
maintenance
manager
and mechanical
maintenance
supervisor.
The systems for identifying, controlling, documenting
and
determining work requirements
are established
in plant procedure
1.3.7,
"Maintenance
Work Request"
(NWR).
During the review of this
procedure,
the team noted that a maintenance
work procedure is not
required
when tightening the packing
on pumps or changing
a fuse
when it has blown for the first time.
Apparently this is considered
"mundane" work and the procedure
has
been written to allow this work
to be completed
by various organizations.
The team discussed this
with the licensee
and pointed out that the referenced
items,
when
associated
with safety related
equipment,
could represent
a
significant problem with the system (in the case of a blown fuse) or
require the discipline of an operating
check (tightening of pump
packing)
and should require the use of a maintenance
request.
The
licensee
representative
acknowledged
the comment
and stated that
this matter was already under review and subject to a program
change.
The
NWR procedure
describes
the following 3 types of maintenance
work requests;
a normal
MWR which is intended to control
a
"one-of-a-kind" equipment failure,
a standing
NWR whichis intended
to control repetitive maintenance
tasks,
and
a vital
NWR which is
intended to control maintenance activities
on equipment which, if
left unrepaired,
could result in a potential Technical Specification
violation, a reportable
occurrence,
a safety hazard,
or could affect
plant reliability.
The quality of instructions
and records
associated
with the later
NWR type was considered to be poor and is
addressed
in paragraph
5.b.
Additionally it was noted that the use
of the vital work request
exceeded
the intent of the maintenance
work request
procedure
and was routinely used
even when
no imminent
safety problem existed.
Document Review
After reviewing approximately
20 work packages
which were related to
the emergency diesel
generators
and the containment isolation system
and which were completed during the past
1 1/2 years,
the team
made
the following observations:
1.
An inconsistency in the work packages
was noted in the
identification of components
associated
with Technical
Specification requirements.
The
NWR form contains
a check box
to identify the equipment
on the
NWR as technical specification
equipment.
There appeared
to be a lack of formality in
checking the box correctly for equipment
on which work was
being performed.
~
A
I
The team noted Maintenance
Work Requests
where work
instructions
to craftsmen
were considered to be minimal.
One
case involved the troubleshooting of safety related isolation
valve RCIC-V66, which is a check valve with position indication
in the control
room.
The valve is the closest isolation valve
to the reactor vessel for RCIC injection water.
The valve had been discovered with an open indication in the
control
room, contrary to its required closed position.
An
activity had been
undertaken
by the licensee to establish
a
valve lineup which would cause
a lower pressure
region upstream
of the check valve and thereby tend to reseat
the valve.
The record after troubleshooting
the problem did not indicate
the reason
why the valve was open,
when it should
have
been
closed.
Also, there
was
no indication that retesting
was
required.
The inspector later confirmed that the valve had
been retested
as part of a generic surveillance test involving
other isolation valves.
Another case
involved the repacking of
RCIC-V63.
The instruction stated,
"Valve Leaking -, Repack".
No
detail, procedure
reference,
vendor manual, or torquing
requirements
were listed.
In one case,
a vital
MWR involved the reassembly of the
4
cylinder valve bridge and rocker arm assembly
as well as the
installation of the oil lines onto the rocker arms of emergency
diesel
1A.
Three torquing operations
were to be performed.
Due to informal communications
between Quality Control
(QC) and
Maintenance,
QC did not inspect the torquing operation in
accordance
with its internal guidance.
The vital
MWR did
permit the torquing step to be bypassed if QC was not available
at the time of the call to witness.
However, the inspector
noted that the torquing step
was not performed until the next
day, at which time
QC was not called again to witness the step.
Two cases
were noted where the maintenance
records
associated
with maintenance
work on the main steam isolation valve
solenoid pilot valves
and the
RHR-V53B valve indicated that
a
cable involved in each of the jobs had not been reterminated.
The retermination control sheet in the
MWR had not been
completed.
The changes
in the instructions
had not been
authorized
by the Plant Manage
as required by administrative
procedure 1.3.9, "Control of Electrical
and Mechanical
Jumpers
and Lifted Leads".
This is considered
a violation of
regulatory requirements
(50-397/88-24-03).
Three instances
were noted where the evaluation
and disposition
of out-of-calibration measuring
and test equipment
(t4kTE)
associated
with two torque wrenches
and a piece of leak rate
testing equipment were not completed in a timely manner.
In
the case of the two torque wrenches,
the out-of-calibration
notices
had been issued in August 1987 and were still open.
The out-of-calibration notice for the leak rate detection
instrument also was still open
and had been issued in
c
10
March 1987.
The failure to complete in a timely manner the
evaluation of the impact on performance of the equipment
on
which testing
was performed using out of calibration NTE is
considered
a violation of regulatory requirements
(50-397/88-24-04).
6.
On June 14, 1988,
RHR-V-9 would not close
when operated
remotely from the control
room.
The Shift Manager initiated
vital maintenance
work request
(MWR) AV1733 to address this
problem.
During subsequent
troubleshooting of the valve,
pump RHR-P-2A tripped and nonconformance
report
(NCR) 288-258
was issued to address this problem.
The
NCR concluded that the
probable
cause for the
RHR-P-2A failure was the initiation of a
pump trip signal during RHR"V-9 troubleshooting activities.
A
less than full open indication from RHR-V-9 sends
a trip signal
to RHR-P-2A for loss of suction protection.
The team reviewed
vital
MWR AV1733 and
NCR 288-258 and
made the following
observations:
The work instructions provided
on the
MWR appeared
to be
very qualitative (i.e. troubleshoot problem),
and no
caution
was provided regarding the potential to trip the
operating
RHR pump.
A continuation sheet
was
added to the work instruction
after the work instruction was initially prepared,
and
there did not appear to be any administrative controls
governing this type of change to a
MWR.
The work
performed section of the
MWR did not include documentation
of the date
and time when the work was started.
RHR-P-2A tripped on June 15, 1988, at 1253.
Work
associated
with MWR AV1733 was completed
on June
14 at
1605.
The licensee's
conclusion
documented
on
288-258, which indicates that RHR-P-2A tripped while
maintenance
was being performed
on RHR-V-9, does not
appear to be well founded.
No further root cause
determination
had been attempted to reconcile the apparent
mismatch of dates
between the
MWR being completed the day
before the
pump trip.
Observation of Work
The team observed portions of work in progress
associated
with the
following maintenance activities:
o
Pressure
decay test of the main steam re'Iief valve tail pipe
associated
with valve MS-RV-28 (MWR¹ AT 6632).
o
Replacement of a pressure
switch on one of the recirculation
valve controls
(MWR¹ AT 6053).
o
Repacking of the RCIC-63 valve
(MWR¹ AV 1810).
l
~
0
o
Modification of the moisture separator
level transmitter
on the
containment
atmosphere
control system
(HWR8 AT 6245).
The team noted during the observation of work that maintenance
work
requests
had been written for the work in progress.
Where
measurements
were being taken,
instrumentation calibrations
were
current.
gC was noted to be present
when the work activity required
gC presence.
Radiation precautions
were considered
adequate
for the
work in progress
and procedures
appeared
to be followed.
During the
performance of one maintenance, job involving the repacking of
RCIC-V63, the team observed that maintenance
personnel
were having
difficulty installing the
new packing into the valve stuffing box.
The team also noted that the maintenance
personnel
determined that
the packing was the wrong size
and stopped
the work.
The problem
with the packing was found to be associated
with the dye used to cut
the inner diameter.
The dye was
stamped with the wrong size.
Proper sized packing was produced
and the work completed.
An ASME
Section XI test
had been identified as
a retest
requirement
following maintenance.
Two violations were identified in this area of inspection.
6.
Emer enc
Diesel Generators
DG-1 and
DG-2
During the inspection the team performed
a field walkdown of the
and associated
support systems.
These
systems
included, in part,
the
EDG air start system,
EDG jacket water cooling system,
governor
control system,
EDG pre-heat
lube oil modification and service water
cooling system.
Verifying such items
as support locations, orientation,
and correct piping configurations,
the team performed
a limited as-built
configuration inspection of the subject
systems utilizing the applicable
design configuration drawings.
An operational test in which the team
was
able to observe
the various operating parameters
of the
EDG system
such
as temperatures,
pressures,
and fluid levels, (i.e. exhaust
gas outlet
temperature,
jacket water and lube oil pressure
and levels)
was also
performed for
EDG engine 81Al.
The following is a description of the
system material condition,
any observations
or deficiencies
noted,
and
the potential
impact the deficiencies
could have
on the safe
and reliable
operation of the system.
Also included is a description of the
licensee's
corrective actions for the deficiencies identified during the
team's
walkdown of the
EDG systems.
EDG Startin
Air and Servomotor
Pneumatic
Tubin
Lines
During the inspection the team performed
a limited as-built
configuration inspection of the
EDG pneumatic tubing lines which
supply air to the starting air motors, the servomotor,
and
associated
starting air piping and components.
During an emergency
start actuation,
a solenoid valve is energized,
allowing air from
the starting air tanks to pass
through the solenoid valve to the
pinion gear
end of the starting motors.
The entry of air through
the pneumatic tubing lines moves the pinion gear forward to engage
with the engine ring gear.
In addition to maintaining gear
engagement,
the air opens the air start valve, releasing
the main
1
~
~~,, l\\.
12
starting air supply.
Starting air passes
through the air start
valve and into the flexible hose
assembly
attached to each air
starting motor.
The multivane starting motors drive the pinion
gears,
rotate the ring gear,
and crank the engine.
During the starting sequence,
at the
same time that starting air is
applied to the starting motors, air is also applied to the bottom of
the governor booster.
This drives the booster piston up, forcing
oil under pressure
into the governor.
The governor power piston is
moved in the "increase fuel" direction and fuel is supplied to the
injectors for starting the engine.
The
EDGs are supplied with two
redundant
banks of air start motors
and servomotor shuttle valves.
During the field walkdown, the team identified approximately
20 feet
of the pneumatic starting air line on
EDG engine
01A1 to be
unsupported
and noted that additional
spans of tubing appeared
to be
unsupported
on the other
EDGs as well.
The team identified this
condition to the licensee's
design engineering staff and to the
system engineer to determine if there were any analyses
or
documentation indicating that the existing condition was acceptable.
The licensee
personnel
were unable to present
the team with an
analysis that the existing condition met the design criteria for
allowable tubing stress.
Licensee
personnel
were also unable to
identify any design control documentation
specifying the location
of'he
required vibration/seismic
supports for the pneumatic tubing
lines.
A postulated failure of these lines (if left unsupported)
could potentially result in a loss of starting air to the
EDG or a
loss of air to the servomotor during normal vibration or during a
seismic event.
The licensee
performed the following corrective actions.
The
licensee
issued plant deficiency report No. 288-380 which documented
the as-found condition of the starting air pneumatic tubing.
The
immediate disposition of the plant deficiency report recommended,
in
patt, performing an analysis to demonstrate
the ability of the
pneumatic tubing to withstand
a seismic event, evaluating the need
to add additional supports,
and requesting
design engineering staff
to provide design direction for the installation of the supports.
As a result, the design engineering staff issued basic design
change
(BDC) No. 88-0299-04.
This
BDC included the installation and
qualifying stress
calculations with references
to the analyses
assessing
the as-found condition of the starting air pneumatic
tubing.
The analyses
affirmed that no seismic
induced failure would
have occurred for the worst case
as-found condition.
However, prior
to the conclusion of the inspection,
design engineering did provide
design direction for the installation of additional supports to
improve seismic capability.
13
EDG Coolin
Water Pi
e Cou lin
During the field walkdown of the external
EDG cooling piping on
EDG-2, engine
181, the team identified that safety-related
flex
coupling No.
DLW FLX-llB1, located
on the cooling water line between
the engine
and thermostat
valve on the auxiliary skid, was
misaligned approximately 5.5
.
The team identified this condition
to the licensee to determine if there
had been
any analyses
performed or documentation reflecting that the existing condition
was
an acceptable
installation.
The licensee
personnel
stated that
this condition may have resulted
from the R-1 outage in July of
1986,
when it was noted that
EDG engines lA and
1B were not doweled
(aligned) in accordance
with the
EDG manufacturer's
recommendations.
The licensee
also stated that the original
EDG alignment problem had
been corrected
and documented
per plant modification record
No. 02-86-0329-0.
However, licensee
personnel
were unable to
demonstrate
that the present
excessive
angularity of the cooling
water flex coupling was acceptable.
Because
a postulated failure of the flex coupling during a seismic
event could result in the loss of EDG cooling water and potentially
render the
the licensee
performed the following
actions.
The licensee first performed angularity field measurements
on the flex coupling and determined the maximum angularity to be
~
5. 5
.
The licensee
also measured
the length of pipe insertion into
the flex coupling to assure that the minimum insertion criteria of
1.86 inches
had not been affected
due to the excessive
angularity.
Upon review of the manufacturer's
(Airoquip) catalog,
the licensee
determined that the coupling's as-found condition was outside the
manufacturer's
maximum angularity criteria of 4 .
Upon disassembly of the coupling in the field, the licensee
discovered that the actual
minimum insertion was 1.66 inches or .2
inch less than the manufacturer's
stated
minimum.
This situation
was discussed
with the licensee
and the manufacturer,
and was
determined to not render the
EDG inoperable for the following
reasons:
1.
The 1.66 inch penetration into the coupling is sufficient to
provide
a good contact surface
between the gasket
on the end of
the coupling and the pipe.
The end of the pipe is far enough
beyond the gasket not to interfere with the seal.
2.
The application normally involves
no pipe movement or very
small, infrequent
movement of the piping.
Consequently,
even
if contact
had been
made between the end of the pipe and the
coupling wall, the movement would not have been expected to
wear the coupling wall to an extent that the coupling would
have failed.
3.
The coupling is designed for 150 psig internal pressure
but
operates
at approximately
10 psig.
The licensee reinstalled the flex coupling to meet the required
angularity and insertion criteria as specified in the manufacturer's
catalog
and documented
the as-found condition per plant deficiency
report
(PDR) No. 288-382.
Bent Coolin
Water Vent Line Nozzle
While performing a limited as-built configuration inspection of the
external
EDG cooling water piping for EDG lA1 and 181, the team
identified two bent nozzles
(1/2 inch x 4 inches long) on diesel
cooling water
(DCW) tanks
181 and 2Bl. It appeared
that the nozzles
were bent 1/4 inch off center (worst case)
as
a result of being
stepped
on while personnel
were performing various work activities
in the
EDG rooms.
This condition had not been previously identified
in the licensee's
problem identification tracking system.
The
nozzles
were associated
with the
EDG cooling water vent lines,
and
failure of the nozzles
could result in a loss of EDG cooling water,
potentially rendering the
The licensee
performed
the following corrective actions.
The licensee
performed
a field
walkdown of all associated
cooling water vent lines and performed
field measurements
to determine which
DCW tank nozzle was most
affected.
The licensee
also issued plant deficiency report
(PDR)
No. 288-392 to document the deficiency and performed
a calculation
to assess
the (worst case) existing condition. It was determined in.
the calculation that the bend was
on the 4 inch vertical lead of
pipe (tank nozzle)
because this section of piping consisted of sch.
40 pipe while the rest of the associated
piping is sch.
160. It was
also determined that there
was
no deformation
near
the
DCW tank weld
and since the weld is a full penetration
weld, non-destructive
examination of the weld was not required.
The disposition of the
PDR and calculation was that the slight bend in the
DCW tank nozzle
had
no effect on the serviceability of the pipe.
Service Water Valve No.
SW-V-4A
During a field walkdown of DG room DG-1, the
NRC inspectors
identified an incomplete thread
engagement
condition on the packing
gland nuts for safety-related,
8-inch line, motor-operated
service
water valve No.
SW-V-4A.
The team identified this condition to the
licensee to determine if there
was any documentation reflecting the
existing condition.
The licensee
was unable to present
any
documentation
which reflected the existing condition.
However,
because
of the potential for a loss of service water which is used
as secondary cooling for the
EDG jacket water and lube oil systems,
the licensee
performed the following corrective actions.
The
licensee
issued
maintenance
work request
(HWR) No.
AT 6667.
The
MWR
work instructions stated in part to (1) obtain clearance for work,
(2) remove all necessary
packing to obtain proper thread
engagement,
(3) repack
SW-V-4A per maintenance
procedure
No. 10.2.7,
and (4)
ensure
SW-V-4A stokes
manually with proper thread
engagement.
The
NRC inspectors
were notified that the work was performed prior to
the conclusion of the inspection.
15
Deformation of EDG Su
ort Footin
s
During the field walkdown of EDG skids
and associated
components,
the team identified a deformed support footing on the east side of
engine
1B2.
The team identified this condition to the licensee
personnel
to determine if there
was any documentation reflecting the
existing condition.
The licensee
stated that the deformed support
foot had been
documented
upon receipt inspection (material
damage
report
No. B-022 dated
December
13, 1978)
and was dispositioned
accept-as-is,
touch
up with paint as required.
However, after
a
secondary
visual inspection of the subject support foot and the
discovery of an additional
deformed foot on the west side of engine
1B2 by the team, the licensee
performed the following additional
corrective actions:
The licensee
issued plant deficiency report
(PDR) No. 288-393,
which
stated
in part that the condition was caused
by an excessive
load
being placed
on the jacking screws which were used to obtain the
proper alignment for the
EDGs.
The
PDR further stated that the
operations
and maintenance
manual
would be modified to warn
personnel
performing
EDG alignments to exercise
care in using the
jacking bolts,
such
as not to deform the support footings.
The
licensee
also performed mechanical
evaluation
(M.E.) No. 02-88-58
for the west support foot which was determined to have the worst
case deformity.
The evaluation stated in part that based
on the
engine alignment, bolting arrangement,
visual weld examinations,
the
use of gusset plates
on either side of the support footings,
and
previous main bearing examinations
which showed
no perceptible
wear,
it was concluded that the support footing deformations
appeared
to
be localized,
and would have
no effect on the serviceability of the
engine.
Missin
Su
ort on Lube Oil Circulatin
Pum
Suction Line
The team performed
a limited as-built configuration inspection of a
vendor
recommended
modification (MI 9644), which the licensee
had
implemented
on the high pressure
core spray diesel
engine
and all
four EDG engines.
The purpose of the modification is to provide
an
improved immersion heater
lube oil circulating system that will
consistently
supply lube oil to the engine's
and
crankshaft in anticipation of an emergency start.
During a walkdown of the emergency diesel
engine lA1 modification,
the team identified a missing seismic support bracket
on the lube
oil circulating pump suction line.
The team identified this
condition to the licensee to determine if there
was any
documentation reflecting this condition.
The licensee
presented
the
team with as-built configuration drawing No. 02-332-002 which
identified the support
as part of the modification (item 90).
However,
because
the support
was missing
on engine
1A1, potentially
affecting the seismic capability of the lube oil piping, the
licensee
issued
PDR No. 288-393 to document the condition.
The
immediate disposition of the
PDR stated that,
based
on a span chart
criteria (ANSI B31.1) the missing seismic support would not affect
~
~
16
the seismic qualification of the suction line.
The licensee
also
performed
a physical inspection of the subject line and installed
the support per maintenance
work request
(MWR) No.
AT 6629 prior to
the conclusion of the inspection.
EDG Governor
Lube Oil Level
During a walkdown of the
1A1, the team noted
that the lube oil level in the external sight glass for the
governor
was out of sight high with the
EDG in the standby
mode of
operation.
The team also reviewed the station
EDG surveillance
procedure
No. 2.7.3-7 (Step 15) and was unable to determine the
required governor oil levels during standby or normal operation of
the
EDG.
The team identified this concern to the licensee to
determine what criteria the equipment operators
were utilizing for
the governor lube oil levels, while performing their surveillance
inspections
of the
EDGs and high pressure
core spray engines.
The
failure to identify a high oil level in the governor during
operation could potentially result in foaming of the lube oil
causing erratic operation of the engines.
On August 25,
1988 the licensee
contacted
the
EDG governor
manufacturer
(Woodward Governor) via telephone for guidance
on
determining the optimum governor oil level for standby
and normal
~
operation of the engines.
The
EDG governor manufacturer
recommended
that the governor oil level be monitored,
and if needed,
be adjusted
after the engine
has
been operating for such
a time span that the
engine is warm.
The governor manufacturer further stated that the
the intended
normal governor oil level
be determined (via the
external sight glass) with the engine running.
As a result, the licensee
performed
an operational test of EDG 1Al
to assure that the governor oil level dropped within tolerance
during operation.
Excess oil was drained
so that a level could be
observed
in the external sight glass during normal operation of the
engine.
The licensee
also revised the station surveillance
procedures
prior to the conclusion of the inspection.
Vendor Manual
Review
The licensee's
emergency diesel
engines
were manufactured
by General
Motors, Electromotive Division (EMD).
The diesels
are 20 cylinder
turbocharged
engines.
There are two diesel
engines driving each
emergency
generator.
The inspector reviewed the vendor manual
recommendations
applicable to the diesel
engines,
and made the
following observations:
The vendor manual stated that the governor oil level should
be
checked
and adjusted to the midpoint scribe mark in the
sightglass
shortly after the diesel is started.
As discussed
above, the licensee's
surveillance procedure did not provide
specific instructions in this regard.
E
c
~
17
For the oil fog lubricators located
upstream of the air start
motors, the vendor manual
speci fies
an oi 1 dr ip rate whi ch is
dependent
on the nominal air velocity through the air start
piping.
The licensee's
procedures
did not address
this vendor
recommendation.
Based
on the team's
observations, it appears that the licensee
has
not established
a program to address
and implement (as appropriate)
vendor recommendations.
Licensee
personnel
could not identity where
the vendor recommendations
had been incorporated.
However, they
would evaluate
the recommendations
for possible insertion into the
appropriate
procedure.
Because
the above identified concerns
did not result in a direct safety
issue
and because it would be difficult to determine the cause of the
deficiencies in most cases (ie, construction activities versus
recent
operational activities), the team did not consider enforcement
appropriate.
However the number of discrepancies
noted does indicate
that licensee
personnel
need to be more aggressive
in identifying and
documenting discrepancies.
ASCO Solenoid Valves
Used Within Nuclear Steam
Su
1
Shutoff
S stem
NS
During the inspection,
the team reviewed the licensee's
evaluation of NRC
=
information notice No. 88-43, entitled "Solenoid Valve Problems."
The
information notice was issued to alert licensees
to a series of solenoid
valve failures that have occurred at several
nuclear
power plants.
The
notice discussed
in part various licensee
investigations
which isolated
the cause for two main steam isolation valve (MSIV) failures to Automatic
Switch Company
(ASCO) Model
NP 8323AZOE dual solenoid operated
valves
(SOVs).
The failure mechanism(s)
could not be positively identified.
However, the most likely cause of the two failures
was determined to be,
in part,
a degradation
of the ethylene propylene diene
monomer
(EPDM)
elastomer
seats,
due to exposure to high temperature
environments,
and
a
yellowish sticky film which acts like an adhesive
and prevents
the core
assembly
from shifting to the de-energized
position,
and which lies
between the core assembly
and plugnut assembly of the solenoid valve.
It
was later stated that the film substance
closely resembled
the
Dow 550
lubricant with which ASCO routinely lubricates the core and plugnut
assemblies
to reduce noise
and wear associated
with a 60 cycle
hum.
In discussions
with the licensee,
the team discovered that WNP-2 had
experienced
one failure of their MSIVs during testing and
had established
an extensive
program to determine the root cause of the problem.
The
licensee attributed the cause of the failure to be sticking of the "A" or
upper core assembly of a SOV.
Two analyses,
one in-house
by licensee
personnel
and another by an outside consulting firm, were performed.
The
analyses
were based
on
SOV internal scrapings
which were found to be
primarily si'licon in nature.
The licensee
concluded that the sticking of
the "A" core assembly
was associated
with the
Dow 550 lubricant.
The
licensee
then issued
a maintenance
work request to reinstall all new MSIV
solenoid control valves without the
Dow 550 lubricant and is presently
operating with the MSIV solenoid valves in this configuration.
When the
licensee notified the solenoid valve manufacturer of their conclusion,
. ~
18
the manufacturer
stated that they did not concur with that postulated
failure mechanism.
The licensee
stated that the manufacturer
indicated that there
was
a
possibility that the lower exhaust
core assembly
was sticking due to the
introduction of hydraulic fluid leaking back through the air lines from
the MSIV closure control mechanism.
The licensee's
engineering
opinion
is that due to the torturous path the hydraulic fluid had to follow to be
introduced into the lower exhaust
core assembly, this possibility
appeared
to be unlikely.
The licensee's
engineering analysis
appears
to
be adequate
and supported
by chemical analysis of valve internals
residue.
Trouble-shooting
was initially performed
on the solenoid valve,
however,
the licensee
had not required
a controlled disassembly
in the field.
This effort, had it been performed,
could have preserved
any evidence of
hydraulic fluid within the piping system.
8.
Desi
n Process
Review
The licensee's
design processes
were evaluated for technical
accuracy
and
attention to detail.
Three (3) Plant Modification Requests
(PHRs)
and
their associated
Design
Change
Packages
(DCPs), Field Change
Requests
(FCRs),
and Maintenance
Work Requests
(HWRs) were reviewed
fear plant
modifications to the Nuclear Steam Supply Shutoff System
(NS ) and the
In the design packages,
no discrepancies
which had not already
been
addressed
by the licensee
were identified.
However,
some activities associated
with the design
packages
exhibited
weaknesses
where designs
were being performed or documented
in an
informal manner.
a ~
PHR 02-85-0466-0
RWCU Surveillance Test Switch
Design package
DCP 85-0466-OA was generated
to install test switches
to enable the performance of surveillance testing of the reactor
water clean
up
(RWCU) delta flow function without the use of
temporary jumpers.
The design
package
contained
both drawing
changes
and wire termination lists.
These
two items did not agree
with each other, i.e., the drawings were correct but the wire
termination lists were incomplete
and inaccurate.
The wire
termination lists were corrected
by the technical staff with a
revision
(DCP 85-0466-0B).
The design engineer prepared
the revised
DCP with the wiring list corrections.
However, the package
was not
released
since engineering
procedures
do not require the wire
termination lists to be a part of the controlled design package.
The wire termination lists, however, are required in the
MWR and
therefore the lists corrected
by the technical staff were included
in the
MWR.
The maintenance
department
reviewed the wire
termination list and discovered that the termination lists were
still incomplete.
Maintenance
personnel
made further corrections to
the wire lists.
The team's
concern
was that the wire termination
list is required to be contained within the
MWR.
However, there is
apparently
no clear procedure
requirement for someone to generate
19
the document.
In addition, for this
DCP review, it was not clear
that revisions
made to the wire termination list were checked.
Licensee
management
acknowledged
the concern
and stated that the
wire termination list would be required
by the appropriate
procedure.
Although the test switches
have
been installed
and operate
as
intended,
the informal design
and documentation
process left areas
where mistakes
and errors could have
been
made.
Since engineering
and the technical staff only receive the cover sheet of the
MWRs,
they had
no indications that the scope of the corrections to the
wire termination lists
had changed
from the
DCP.
b.
PMR 02-85-0383-0 Diesel
En ine Governor
S stem
Design packages
DCP 85-0383-OA and
DCP 85-0383-0B were generated
to
replace the diesel
engine governor controls with an electronic
governor allowing the diesels to be operated at a slow idle.
The
design
was intended to be a vendor supplied "black box" replacement
for the old governor controls.
This apparently simple 'plant
modification required
2 DCPs
and 15
FCRs to complete.
Of the 15
FCRs, at least
9 could be attributed to errors,
omissions,
or
incompleteness
of the design.
Furthermore,
a licensee
gA audit
(Surveillance
Report 2-88-203) identified 6 deficiencies
and 14
observations
associated
with the design
and installation of this
work package.
These
examples
are indicative of a less than rigorous approach to the
controls
placed
on the development
and implementation of design
packages
for plant modifications.
The licensee
has recently committed to
improving their program for design
changes.
Since
no design activities
were reviewed which would have been developed
under the
new programs, it
can not,
as yet,
be determined if the weaknesses
observed
by the
inspector
have been addressed
or eliminated by the licensee.
9.
Plant Oversi ht Grou
s
The team examined the involvement of the licensee's
oversight groups in
formulating corrective actions in response
to internal
and external
events
having potential safety significance.
To determine the
effectiveness
of the oversight groups,
the review considered initiatives
of the groups
and ultimate corresponding
actions of the licensee.
The
team generally found the work of the review groups to be thorough.
Instances
were found where followup of review group findings was
incomplete.
a 0
Nuclear Safet
Assurance
Grou
The Nuclear Safety Assurance
Group
(NSAG) functions to examine unit
operating characteristics,
NRC issuances
such
as bulletins and
notices,
industry advisories,
Licensee
Event Reports,
and other
sources of unit design
and operating experience
information
(including units of similar design) which may indicate areas for
20
improving unit safety.
The
NSAG makes detailed
recommendations f'r
revised procedures,
equipment modifications,
maintenance activities,
operations activities, or other means of improving unit safety.
NSAG
reports to the Director of Licensing and Assurance.
Specific
requirements for the group are set forth in Technical Specification 6.2.3.
The licensee's
procedures
under which this group operates
are found in PPM 1.10.4.
The team looked at NSAG's reviews of events
on emergency )iesel
generators
and
on nuclear
steam supply shutoff system
(NS )
components.
The number of reports
on external
events
reviewed by
NSAG is large.
There were roughly 100 events
reviewed
on diesel
generators
and roughly 40 reviewed
on
NS
components.
The team examined
NSAG reports
on a representative
number of events.
The analyses
were found to be thorough
and the recommendations
for
action were clear and concise.
NSAG recommendations
are subject to
review,
and thus modification, by other organizational
units prior
to implementation.
However, the team found that the
NSAG
recommendations
were well respected
and any modifications appeared
to have rational
bases.
Although NSAG maintains
cognizance of their recommendations
through
ultimate disposition,
the team noted that a small percentage
of
items were lost from the tracking system without documentation of
closeout
and furthermore were apparently not implemented.
For
example, in a report dated
November 26, 1984,
NSAG recommended
increasing the air receiver capacity of the air start system for the
HPCS diesel
generator in order to improve reliability.
Subsequently,
engineering
recommended
an alternative for achieving
the improvement in reliability.
The recommendation
is no longer in
the
NSAG tracking system.
However,
no action was taken to improve
diesel
generator reliability.
The alternative action is on a
different plant tracking system
(as
PMR 02 85 0093-1) but is
dormant.
This appears
to be a defect in the tracking system rather
than an indication that
NSAG is not functioning. Nevertheless,
to be
fully effective at its function, followup of review group
recommendations
is essential.
Cor orate Nuclear Safet
Review Board
The Corporate Nuclear Safety Review Board
(CNSRB) is appointed
by
the Managing Director from his senior technical staff and from
personnel
outside the Supply System.
At the time of the inspection,
three outsiders
served
on the Board. This group serves to provide
independent
review and audit of activities designated
in Technical Specification section 6.5.2 and advises
the Managing Director of
their findings and recommendations
from these
reviews and audits.
The team reviewed the minutes from the last four regularly scheduled
quarterly meetings of the
CNSRB (meetings
87-11, 88-01, 88-07,
and
88-09).
CNSRB also'meets
intermittently as needed,
for example, to
review proposed
changes
to technical specifications.
The inspection
team reviewed the minutes from one recent special
meeting (meeting
~ ~
21
p, ~
kc
88-05) to gain understanding
of the
CNSRB input to this process.
These special
meetings often do not include the complete
CNSRB
membership.
The inspector also interviewed the
CNSRB Chairman
and
the former recording secretary.
The team found the minutes to be quite detailed
and therefore very
helpful in providing insight into the depth of discussion occurring
at the quarterly meetings.
Presumably
because
of the focus
on the
need for management
involvement,
CNSRB recommendations
were usually
directed toward longer range safety
improvements
involving policies,
programs
and procedures,
rather than toward resolution of technical
problems.
However,
recommendations
gener ally would result in
actions for operations.
The
CNSRB maintains its own tracking system.
The team looked at
followup to recommendations
made at earlier meetings.
A number of
the recommendations
had been closed out and it generally appeared
that
CNSRB was making
a significant contribution to safe operation
of WNP-2.
However, the minutes often include recommendations
or
commitments which are not entered into the
CNSRB tracki,ng system
and
do not appear
to be closed out methodically by CNSRB. It appears
that the effectiveness
of the
CNSRB could be enhanced
by expanding
their tracking system to capture all recommendations
and
commitments.
C.
Plant
0 erations
Committee
The Plant Operations
Committee
(POC) functions to advise the Plant
Manager
on all matters related to nuclear safety.
Specific
responsibilities
detailed in the technical specifications
(Section
6.5.1) essentially
include review of changes
to hardware or
procedures
having potential safety ramifications,
review of events
which may convey safety lessons,
and review of operations
to detect
potential safety hazards.
The technical specifications
require
monthly meetings to address
these matters.
However, the
POC has
found it necessary
to schedule regular weekly meetings
and
frequently holds additional
meetings to discharge its
responsibilities.
The team reviewed minutes from POC meetings for most of the past
year and attended
one
POC meeting.
The team also talked with POC
members
about
POC procedures.
POC maintains their independent
tracking system for followup of certain specified action items.
Review of the minutes,
as well as observations
at the one meeting
attended,
indicate that the
POC meeting
agendas
are dominated
by the
mandatory reviews of design
and procedural
changes,
of licensing
actions,
and of event reports.
In order to accommodate
the large
number of such actions to be acted
on by POC, coordination problems
and technical
and safety concerns
must be resolved before the
meeting.
Discussion of these
items is minima) at the meetings.
Meeting minutes often are limited to identification of the items.
acted
upon with indication of the action taken.
Nevertheless, it
22
would appear that the formality of the
POC process for approval of
these
items results in resolution of safety concerns.
Review of the
POC minutes also sought records of discussion of unit
operations
and of evolving operational
problems to identify and
determine the effectiveness
of the group in advising the Plant
Manager of pending safety concerns.
Specifically sought out, for
example,
were minutes of meetings
addressing
drywell leakage
and
drywell temperature
problems,
both before
and after the recent
refueling outage.
The minutes were brief, but gave the general
impression that the discussion at
POC centered
around solving the
immediate
complex technical
problems, rather than
on the safety
ramifications of the problems
and alternative solutions.
An unexpected plant shutdown early in the inspection period afforded
the team
an opportunity to enter the drywell.
The team noted that
some outage work areas
apparently
had not been cleaned
up prior to
restarting after the last refueling outage.
Because of the role of
the
POC in implementing the restart plan, the
POC minutes for
meetings
near the end of the outage
were reviewed.
Minutes for the
June
1988
POC meeting (888-22.2) which reviewed the containment
closeout inspection,
indicated that housekeeping efforts were still
in progress
but would be completed prior to restart.
This was not
an item for the
POC tracking system
and was not addressed
in
subsequent
minutes prior to startup.
Based
on the team's
review of POC documentation, it is not apparent
that the
PDC had addressed
the long term safety implications of the
drywell leakage
and temperature
problems
or the drywell cleanliness
prior to restart.
No documentation
which addressed
the long term
effects of the higher than normal temperature
of the drywell on
electrical
equipment environmental qualification was found.
Drywell cleanliness
problems
were reviewed by the
POC during the
committee's
review of startup requirements.
However,
no followup
action appeared
to have been taken by the committee to ensure
acceptable
drywell cleanliness
standards
were met.
The licensee
acknowledged
the team's
concern
and stated that the
appears
to become involved in problem solutions rather than review
and oversight functions.
ualit
Assurance Activities
The team examined quality assurance
activities in cogjunction with
modifications to the diesel
generators
and to the
NS
.
The team
also reviewed
a recent audit more broadly addressing
design
modifications
and associated
activities (Audit 88-434) prepared
by
the Corporate
Licensing and Assurance staff.
The inspection
considered
the scope of the gA review,
as well as actions taken in
response
to gA findings, to ascertain
the effectiveness
of this
review group
on plant safety.
23
Audit 88-434
made
a number of findings regarding design
modifications which demonstrate
the thoroughness
of their
examinations
as well as their willingness to be candid to their
management
regarding their results.
A number of their findings focus
on problems identified in previous
NRC inspection reports
(87-19 and
88-02).
In accordance
with licensee
procedures,
the organization
whose work areas
were audited
was to respond to the audit,
identifying actions to be taken to correct deficiencies
noted in the
audit.
The effectiveness
of the audit activities will not be determinable
until corrective actions
have been fully implemented.
Audit
responses
addressed
specific plant components
called into question
by the audit,
and corrective actions
were taken where appropriate.
Additionally, a number of procedural
changes
were identified in
responses
to the audit.
Procedural
improvements
should enhance
performance of future design modifications.
The team expressed
some concern with follow up to audit findings by
the audit group.
Licensee
procedures
resulted in an apdit being
closed out on the basis of responses
received.
Thus specific audit
findings are not tracked by Corporate
Licensing and Assurance.
For
example,
the inspector
noted that at least
one item appeared
to have
been
dropped without significant procedural
changes
being
considered.
guality Finding Report
No. 4 stated that failure of
design engineers
to visit a jobsite
may have contributed to design
deficiencies.
In response
to this finding, the existing policy for
walkdowns was restated.
Although subsequent
discussions
with the
licensee
have provided additional insight on the particularities of
the deficiencies
referenced
in the audit, it remains to be
demonstrated
that walkdowns are being utilized effectively to
produce quality design modifications.
Based
on a review of records the licensee
supplied, it is not apparent
that recommendations
of the oversite
groups are adequately
tracked
through implementation.
This may result in some recommendations
being
dropped or deferred without formal documentation.
In some instances,
discussion with plant management
identified additional resolution,
although little documentation
had been generated
by the plant to support
the closeout of the issue.
On September
2, 1988,
an exit meeting
was held with the licensee
representatives
identified in paragraph
1.
The team summarized the
inspection
scope
and findings as described
in this report.