ML16341F730
| ML16341F730 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/24/1990 |
| From: | Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F728 | List: |
| References | |
| 50-275-90-08, 50-275-90-8, 50-323-90-08, 50-323-90-8, NUDOCS 9006120015 | |
| Download: ML16341F730 (48) | |
See also: IR 05000275/1990008
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report
Nos:
50-275/90-08
and 50-323/90-08
Docket Nos:
50-275
and 50-323
License
Nos:
DPR-80 and
Licensee;
Pacific
Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Diablo Canyon Units 1 and
2
Inspection at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
March ll through April 21,
1990
Inspectors:
P.
P. Narbut,
Senior
Resident Inspector
K.
E. Johnston,
Resident
Inspector
Approved by:
en onca,
>e
,
eac or
roJec
s
ec
Ton
a
e
1gne
Summary:
Ins ection from March 11 throu
h
A ril 21
1990
Re ort Nos. 50-275/90-08
and
Areas Ins ected:
The inspection
included routine inspections of plant
opera
sons,
maintenance
and surveillance activities, follow-up of onsite
events,
open items,
and licensee
event reports
(LERs), as well as selected
independent
inspection activities.
Inspection
Procedures
30702,
30703,
35702,
37702,
37828,
40500,
42700,
61726,
62703,
71707,
71710,
92701,
92702,
92720,
and 93702 were
used
as guidance during this inspection.
Safet
Issues
Mana ement
S stem
SINS) Items:
None
Results:
General
Conclusions
on Stren th and Weaknesses:
.Areas of Stren th:
The maintenance
area
was strengthened
by the addition of a new manager.
Specifically the former position of Maintenance
Hanager
was split into two new
-full-time positions consisting of Mechanical Maintenance'anager
and
Electrical Maintenance
Manager.
qgr 6120;
+<,C,>>
)g, oOOSZ<
PgiP
ADOCf' -')(
9
The licensee's
methods for event investigation were demonstrated
to be
effective in rapidly determining .causes
and corrective actions.
This was
demonstrated
by the investigation
done for a reactor vessel
head lift mishap
in which thermocouples
were
damaged
due to protective covers not being
installed properly.
As will be discussed
in the weaknesses
section which
follows, when the event investigation
methods
were not used,
understanding
and
resolving problems
sometimes
languished.
Certain elements of the licensee's
staff identified and elevated
problems
which were not immediately obvious problems
and the identification of those
problems
speaks
well for the quality of the licensee staff.
Examples of this.
include the identification of motor operated
valve spring pack relaxation
by
maintenance,
the recognition of the design basis
seismic problem when water
was discovered
in containment
spray piping by plant engineering,
and the
recognition
and questioning of test configuration versus operational
configuration differences for the centrifugal charging
pumps
by plant
engineering.
Areas of Meakness
Mechanical
maintenance
engineers
demonstrated
a lack of recognizing
and
expeditiously dealing with already identified problems.
The most notable
example
was the untimely action surrounding
blowdown settings
on Crosby relief
valves.
The potential for inaccurate
settings
was noted by the
NRC residents
in July 1989.
The Unit 1 outage in October
1989 sampled three valves
and
found them inaccurately set.
Nothing was done to finalize Unit 1 corrective
action during that outage opportunity.
NRC follow-up in-February
1990 led to
increased
sampling during the Unit 2 outage
and the knowledge of broader
blowdown setting problems.
A justification for continued operation
and
a
nonconformance
report were not prepared until suggested
by the
NRC on March
20,
1990.
Other examples of mechanical
maintenance
engineers failing to
recognize
problems included:
o
check valve which would not fully shut both in the
second
and third refueling outage.
o
RHR valves which had failed operator-to-valve shaft keys, which were
repaired,
but the applicability of the problem to Unit l and to other
similar valves
was not addressed
until brought to the assistant
plant
manager's
attention by the
NRC.
Electrical Maintenance 'Engineers
have not always pursued potentially broader
problems.
This concern
was evident when
a component cooling water pump
circuit breaker failed to close
due to a part failure.
The initial reaction
was to repair the breaker
and treat the case
as isolated.
The electrical
maintenance
manager.
however had the case
pursued
and demonstrated
potentially
generic failures.
Likewise diesel
generator
1-1 tripped in April which was
a
repeat of a 1989 event.
In both cases
the cause
was
a broken wire lug.
The
cause of the broken lug was wire tension which could have
been determined in
1989, but was not,
based
on the belief that .it was isolated.
Si nificant Safet
Matters:
None.
Summar
of Violations and Deviations:
One violation was identified regarding
e opera
s
s y o
e
ue
an
sng Building Ventilation System during the
movement of spent fuel (paragraph
S.a).
0 en Items
Summar
Two items were closed
(one follow-up item and
one
unreso
ve
s
em
and two items were
opened
(one enforcement
item and
one
follow-up item).
Persons
Contacted
DETAILS
"J.
D. Townsend,
Vice President,
Diablo Canyon Operations
8 Pl
"D.
B. Miklush, Assistant Plant Manager,
Operations
Services
.
M. J.
Angus, Assistant Plant Manager, Technical, Services
"B.
W. Giffin, Assistant Plant Manager,
Maintenance
Services
W.
G. Crockett, Assistant Plant Manager,
Support Services
W.
D. Barkhuff, Acting equality Control Manager
T.
A. Bennett,
Mechanical
Maintenance
Manager
D.
A. Taggert, Director equality Support
T.
L. Grebel,
Regulatory Compliance Supervisor
"H. J. Phillips, Electrical Maintenance
Manager
D.
P. Brooks, Acting Work Planning Manager
- R.
C. Washington,
Acting Instrumentation
and Controls Manager
"J.
A. Shoulders,
Onsite Project Engineering
Group Manager
H.
G. Burgess,
System Engineering
Manager
S.
R. Fridley, Operations
Manager
"R. Gray, Radiation Protection
Manager
E.
C. Connell, Assistant Project Engineer
"L. Cossette,
Plant Engineer
"M. Hug, Regulatory Compliance Supervisor
"R.
D. Cramens,
equality Control
Lead Engineer
"R. Nanniga,
Mechanical
Maintenance
Eng)neer
ant Manager
The inspe'tors
interviewed several
other licensee
employees
including
shift foremen
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
"Denotes those attending the exit interview on Hay 1, 1990.
0 erational
Status of Diablo Can
on Units 1 and
2
Also during this reporting period,
an enforcement
conference
regarding
security matters
was held on March 16,
1990 and a management
meeting to
review the licensee's
SALP (Systematic Appraisal of Licensee
Performance)
report was held on March 22,
1990.
These meetings
are documented
in
separate
NRC reports.
Diablo Canyon Unit 1 started
the reporting period at full power and
continued at power during the reporting period.
Unit 2 was in its third
refueling outage for the entire period.
During this reporting period the licensee
made organizational
and
personnel
changes.
The maintenance
department
was changed in that
separate
positions for a mechanical
maintenance
manager
and electrical
maintenance
manager
were created.
Therefore,
the assistant
plant manager
for maintenance
now has separate
managers for electrical,
mechanical,
and
I8C maintenance,
in addition to a work planning manager
and
a manager of
materials services.
3.
0 erational
Safet
Verification
71707)
~
~
lj
a.
General
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations of those activities
were conducted
on a daily, weekly or monthly basis.
On a daily basis,
the inspectors
observed control
room activities to
verify compliance with selected
Limiting Conditions for Operations
(LCOs) as prescribed
in the facility Technical Specifications
(TS).
Logs, instrumentation,
recorder traces,
and other operational
records
were examined to obtain information on plant conditions,
and
trends
were reviewed for compliance with regulatory requirements.
Shift turnovers
were observed
on a sample basis to verify that all
pertinent information of plant status
was relayed.
During each
week, the inspectors
toured the accessible
areas
of the facility'o
observe
the following:
(a)
General plant and equipment conditions.
(b)
Fire hazards
and fire fighting equipment.
(c)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(d)
Interiors of ei~ctrical
and control panels.
(e)
Plant housekeeping
and cleanliness.
(f)
Engineered safety feature
equipment alignment
and conditions.
(g)
Storage of pressurized
gas bottles.
The inspectors
talked with operators
in the control
room,
and other
plant personnel.
The discussions
centered
on pertinent topics of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
b.
Radiolo ical Protection
The inspectors 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 inspectors verified
that health physics supervisors
and professionals
conducted frequent
plant tours to observe activities in progress
and were generally
aware of significant plant activities, particularly those related to
radiological conditions and/or challenges.
ALARA consideration
was
found to be an integral part of each
RWP (Radiation Work Permit).
c.
Ph sical Securit
Security activities were observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative
procedures
including vehicle and personnel
access
screening,'ersonnel
badging, site security force manning,
compensatory
measures,
and protected
and vital area integrity.
Exterior lighting was checked during backshift inspections.
No violations or deviations
were identified.
4.
Onsite Event Follow-u
(93702)
During the report period, there were
a number of events involving
,.
equipment important to safety,
where the equipment
was found in a
degraded
condition or had failed either during testing or in the course
of operation.
For the items discussed
below, the inspectors
confirmed
that the licensee
had initiated its problem identification and corrective
action programs in accordance
with 10 CFR Part 50, Appendix B, Criterion
16, "Corrective Actions" and the licensee's
procedure
NPAP C-12.
The
program is initiated with an Action Request
(AR).
equality Evaluations
(gE) and Nonconformance
Reports
(NCR) are
used to document
cause
and
corrective action, with NCRs used to address
the more significant
problems.
When appropriate,
the licensee initiated a Justification for
Continued Operation
(JCO).
In each
case the inspector confirmed that the
licensee
had addressed
the cause
and safety significance of the event
and
had taken corrective actions to prevent recurrence,
addressing,
as
appropriate,
the generic applicability to Diablo Canyon
and the industry.
a.
Unit 2 Motor 0 crated Valve Fails to 0 en
On March 12, 1990, during periodic surveillance testing, Unit 2
valve SI 8805B (refueling water storage
tank to charging
pump
suction) failed to open.
The licensee
performed follow-up
investigations,
but these investigations
did not appear to be
completely thought out prior to commencing action.
Consequently
some information was lost (such
as the torque switch condition and
the thermal overload condition).
The licensee
actions
were examined
by an
NRC motor operated
valve specialist
and will be reported in
detail in a separate
report.
The licensee did not develop
an
absolute
cause for the motor operated valve's failure to open, but
did perform extensive
maintenance
and testing to verify valve
operability for restart.
The need to perform preplanned
and
prescribed trouble troubleshooting
was discussed
with the licensee
management
at the exit interview.
Licensee
management
stated that
they recognized
the faHure to obtain valuable information and would
evaluate
program changes.
b.
S ill of Water in Containment
On March 12, 1990, during pump
down of the Unit 2 recirculation
for the refueling outage water was
pumped to the reactor
coolant
drain tank (RCDT).
The
RCDT was not intended to be the terminus for
the
sump water.
An overfill and spill occurred.
The event
had
no
safety significance,
but did indicate confusion between
maintenance
and operations
personnel.
Personnel
had apparently
moved hoses
without notifying operations.
The assistant
plant manager for
maintenance
stated
he was unable to determine
who moved the hoses
or
why.
He had questioned
the outage control center personnel
and
maintenance
personnel.
Licensee
management
personnel
took no further actions to determine
the cause of the spH
1 due to the lack of safety significance.
The
inspectors
understood
the licensee's
position but noted that this
was
a second
apparent
example
where maintenance
personnel
were not
apparently
meeting management's
expectations.
Auxiliar
(AFW
Terr
Turbine Steam
Su
1
oun
uc
en
Reference:
NCR DC2-90-MM-N023
On March 14,
1990, following the removal for a design
change of the
AFW terry turbine steam supply check valves,
one of the check
valves,
FW-2-5166 was found stuck open.
It was subsequently
determined that the valve disc was not bound to the extent that it
would not have performed its design function to isolate the
steam supply from a faulted steam generator.
Upon disassembly,
maintenance
engineering
found that the bushings
for the hinge p";n had rotated
and had bound the hinge assembly.
In
a history search,
the licensee
found that in 1984 the bushings for
FW-2-5166
had been
machined for an unspecified
reason.
As a result,
an excessive
gap in the arm/hinge block/bushing assembly
allowed
enough clearance for the bushing shoulders to rotate out of
position.
Although bushing rotation was noted during the Unit 2 second
refueling outage,
no corrective actions
were taken at that time.
The problem almost did not come to light during this outage.
The
Assistant Plant Manager for operations
recognized
the problem and
brought it to light after discussions
with maintenance
engineers.
The licensee
performed
a history search
and confirmed that
no other
check valves of similar design
had been previously machined.
The
licensee
also will revise check valve inspection procedures
to
measure
the gap in the hinge arm assembly.
The missed opportunity
to discover this problem during the previous refueling was noted at
the exit interview.
The importance of instilling the proper safety
perspective
in maintenance
personnel
was discussed.
Check Valve Missin
Pin
Reference:
gE f0007385
On March 15, 1990; during a planned inspection of Unit 2 important
the pivot pin and retaining pin were found missing
from one ear of the disc/seat
assembly of main feedwater
pump
discharge
check valve FW-2-506.
Both pins were subsequently
found
downstream in the feedwater piping.
The cause
was attributed to the
previous post maintenance
placement of the pivot pin anti-rotation
tack welds (essentially,
the tack welds,
as they were placed,
did
not prevent the pin from rotation).
The corrective actions
included
revisions to inspection
and maintenance
procedures.
The licensee
determined that this problem was limited to the two main feedwater
pump discharge
Auxiliar Saltwater
(ASW) Seismic
Su
ort Bolt Crackin
Reference:
NCR DCO-90-EN-NOOS
On March 22, 1990, during the disassembly for maintenance
of
auxiliary saltwater
(ASW) pump 2-2, the
pump casing brace ring bolts
were found to be badly corroded.
It was subsequently
determined
that the installed
Grade
630 stainless
steel bolts are not
appropriate for service in a saltwater
submerged
environment.
The
licensee's
review also determined that the bolts had been replaced
in the previous
outage.
The original bolts were
304 stainless
steel
bolts and were replaced with Grade
630 bolts.
The licensee
determined that all other
ASW pumps
had also
had bolts replaced with
Grade
630 material.
The licensee identified and replaced all other Grade
630 bolts in
submerged
service in the
ASW sy'htems for both units.
An analysi
performed of the
as found conditions of the bolts determined that
the
ASW systems
would have performed their design functions during a
seismic event.
An NCR was initiated to investiqate
why Grade
630
bolts were allowed to be used in submerged
service
and to determine
appropriate corrective 'actions.
The inspector will review the
licensee's
NCR during the course of routine inspection activities.
Limitor ue Valve 0 erator
S rin
Pack Relaxation
On March 23, 1990, the inspectors
became
aware of a potentially
generic problem dealing with relaxed spring packs
on limitorque
valve operators.
The licensee
discovered
the condition on a valve
being disassembled
and inspected
during a routine maintenance.
The
condition observed
was,a physically loose spring pack which was
astutely
noted to be wrong by the mechanics
performing the work.
Discussions
were held with the licensee,
the residents,
regional
supervision
and
NRC headquarters
personnel.
An NRC specialist
was
sent to the site to perform
a special
inspection for the potentially
qeneric issue of spring pack relaxation.
The results of that
inspection will be reported separately.
The resident inspectors
examined the licensee's
rationale for
continued operation of Unit 1 and the justification for restart of
Unit 2 and found the licensee's
positions acceptable.
Protective'"Bullet Noses"
Se grated
From Core Exit Thermocou le
ea
s
ur>n
reac or vesse
ea
Reference:
gE f0007448
On March 26,
1990, during a,Unit 2 reactor vessel
head lift,
temporary protective "bullet noses"
separated
from the core exit
thermocouple
The "bullet noses 'ere installed to protect
the thermocouple
leads during the
head
movement.
The bullet noses
had been incorrectly installed.
The licensee
determined that the
installation problems resulted
from inadequate
installation
instructions
aggravated
by the conditions which existed
when the
bullet noses
were installed;
the installers
were required to use
respirators
and the position of the scaffolding placed the
installers in an awkward position.
Corrective actions
included
procedure
revisions
and training enhancements.
Three thermocouples
were identified as potentially damaged.
However the licensee
evaluation
concluded that operation with three inoperable
thermocouples
was acceptable.
Pum
(RCP) Motor Rotor Delamination
References:
NCR DC2-90-EM-N017
JCO 90-07
On March 26,
1990, during the inspection of tPg Unit 2 RCPs,
motors
2-1, 2-2 and 2-4 were .found to have loose structural
and electrical
parts called finger plates
and motor laminations.
The condition was
found to a limited extent
on the 2-3 motor,
and the motor required
minor repair.
The Unit 1 and Unit 2 loop three motors
had been
swapped prior to the initial startup of Unit 1 in 1985.
Therefore
it was suspected
that since limited problems
were found on the 2-3
motor, the 1-3 motor would be likely to have
more severe rotor
defects similar to the other Unit 2 motors.
Likewise, it was
suspected
that the other Unit 1 motors would not have substantial
defects.
The vendor performed
an analysis to determined the
probable failure mode of a motor with defects
as described
above
and
concluded it to be an electrical fault without lockinq the rotor.
Since the design basis
assumes
one locked rotor, continued Unit 1
operation
was determined to be acceptable,
since
a locked rotor or
the concurrent failure of more than one
pump was determined to be
improbable.
.'The licensee
committed to inspect the Unit 1 motors
during the Unit 1 fourth refueling outage in February 1991.
Trojan
was the only other plant with this specific motor design
and they
were supplied with information on how to detect
and correct the
rotor defects.
Although it was suspected
that the cause of the
defects
was related to the manufacturing process,
the specific cause
had not been determined
and the licensee
was continuing to pursue
the issue with the vendor.
y ~
Com onent Coolin
Water
Pum
Circuit Breaker
On March 31, 1990, following planned preventative
maintenance
in the
breaker cubicle, the 4kv circuit breaker for component cooling water
pump 2-3 failed to close
when actuated
from the control
room.
The breaker
was declared
and
an action request
(AR) was
written.
Investigative actions
showed the cause to be
a fai lure of
a gear in the charging motor.
The licensee's first reaction
was
that such fai lures are infrequent
and would be self-revealing
when
breakers
are racked in.
Consequently
no further action, other than
this breaker's
repair,
would be required.
Licensee
maintenance
.'ersonnel
in reviewing past history identified another breaker in a
non-safety application which underwent
a similar failure.
Consequently
licensee
maintenance
management
was considering
elevating the problem to a quality evaluation level at the end of
the reporting period.
The inspectors will follow-up licensee
action
in the course of future inspection activity.
Chromated
Water
S ills
On April 3, 1990,
a chromated water spill was
announced
over the
plant public address
system.
An inspector examination of the spill
was initiated.
The spill was from the service coolinq water system;
a non-safety
system.
The spill was the second spill sn as
many
weeks involving the
same modification and startup testing personnel.
The inspector discussed
the event with the lead startup enneer
and
the general
construction
manager
and confirmed that a quality
evaluation
had been written (gED7440)
and root cause
determined.
Action to prevent recurrence
had not yet been determined but the
startup
engineer
confirmed that the interface
between operations
and
startup personnel
would be re-examined.
Diesel Generator
(D/G
1-1 Tri
ed While Runnin
in Test
References:
gE f0007424
ACR DCI"90-EM"N026
On April 3, 1990,
D/G 1-1 tripped during a post maintenance
run when
its generator differential current relay actuated.
The cause
was
determined to be
a broken wire lug for the secondary
side of the
current transformer.
The licensee's
inspection
found evidence that
the wire had been taut and that cabinet vibration caused
the lug to
break (the cabinet is mounted
on the D/G).
All other D/G current
transformers
were inspected
and wiring adjustments
were
made to
ensure
no similar, conditions existed.
The
DG 1-1 problem was
determined to have also occurred in 1989 and as
a result,
a
non-conformance
report was issued to address
the lack of a root
cause investigation following the first event.
Vital Batter
Char er 232 Overloaded
Reference:
NCR DC2-90-EM-N028
On April 3, 1990, while placinq Unit 2 battery charger
232 in
service
on battery 2-3, following- its battery discharge test,
four
of the six battery charger
fuses failed.
The output current
was
noted to be above
500 amps.
The battery charger
was rated for a
maximum of 440
amps
DC. It was subsequently
determined that the
battery charger's
current control module,
which had been replaced
on
November
12, 1988,
had not been correctly calibrated to limit
current output.
The battery charger overloaded in its attempt to recharge
the
depleted battery.
The lic'ensee
determined that the current control module for battery
charger
232 had been the only one which had been replaced
and
therefore
had confidence that the other nine safety related battery
chargers
would charge correctly.
Additional confidence
was provided
by the fact that
no other chargers
achieved
an overload condition
when recharging depleted batteries:
The licensee
also determined that battery charger
232 could have
failed following a loss of all
AC power event,
when it would have
been required to supply both the depleted batteries
and emergency
loads,
depending
on the length of the loss of AC power.
However,
the redundant battery charger
231 could have been
used to supply the
loads.
Additionally, the licensee
determined that for other
analyzed
events,
battery charger
232 would have
been able to perform
its design functions.
The licensee initiated a non-conformance
report to investigate
the
cause
and corrective actions.
The inspector will followup the.NCR
during the course of routine inspection.
Pum
(RCP) Thrust Runner
On April 3, 1990, during the
RCP motor inspections,
the licensee
noted marring of the
RCP motor thrust shoes.
The licensee
and the
vendor determined that the indications were limited to the thrust
shoe babbit and not in the shoe itself.
The licensee
had
a second
vendor resurface
the thrust shoes
and was informed by that vendor
that the as found condition of the shoes
was acceptable
and not
unusual.
The licensee postulated
from the evidence
and discussions
with the vendor that cavitation at the leading edge of the thrust
shoe
was causinq'he
indications.
Further, the licensee
performed
motor modifications in the previous
outage which they feel
terminated the progression of the problem.
This was supported
by a
comparison of pictures of the thrust
shoes
from the Unit 2 second
refueling outage
and the current condition of the thrust shoes
during this outage.
Ventilation Lineu
Shift Due to an Inverter Volta e
S ike
Reference:
NCR DC2-90-OP-N020
On April 4, 1990, the Unit 2 Control
Room Ventilation System
(CRVS)
unexpectedly transferred
from its normal ventilation lineup to the.
pressurization
lineup and the Fuel Handling Building Ventilation
System
(FHBVS) transferred
from its normal ventilation lineup to the
iodine removal lineup.
Other control
room alarm annunciations
indicated that vital instruments
powered
by AC panels
PY-21 and
PY-21A had undergone
a current transient.
At the time of the event,
Unit 2 was in a refueling outage with a high level of maintenance
activity.
The licensee
was unable to determine
the cause of the
current transient.
A non-conformance
report
(NCR DC2-90-OP-N020)
was initiated to
address
the cause,
safety significance,
and corrective actions.
The
licensee
determined
the event to be an engineered
safety features
actuation
and will submit a Licensee
Event Report (LER).
The
inspector will review the cause
and corrective actions following the
submittal of the
LER.
RHR valves
HCV-670
637
and 638
roblems
Reference:
gE f0007456
On April 3, 1990, during the performance of containment
spray
testing, Unit 2 residual
heat
removal
(RHR) valves
HCV-670, HCV-637,
and HCV-638 were observed to be leaking excessively.
HCVs 637 and
638 are the throttle valves for RHR trains
1 and
2 respectively.
HCV-670 is the
RHR heat exchanger
bypass
valve.
The combined
leakage past the seats
of the three valves, which were in their
closed position,
was measured to be 1800
gpm, with HCV-670 leaking
the greatest.
All three valves are the
same
model butterfly valve with an air
actuator.
Hechanical
maintenance
(NM) found that for HCV-670, the
key .which interlocks the valve shaft to the actuator lever had
sheared.
HCVs 637 and 638 were found with identical problems;
the
key was found outside its lever slot and had allowed the shaft to
rotate in relation to the actuator lever.
For all three valves the
cause
was attributed to fatigue of the key and wear of the lever
slot.
The .inspector discussed
the valve problems with HN on April 26. It
was evident from the discussion that although the immediate cause
was understood
to some extent,
the licensee
had not yet adequately
addressed
the root cause,
the safety significance,
the generic
applicability, and the corrective actions.
Specifically, the review
had not addressed
the following;
The installed
key material
was not the material specified in
the most recent plant drawings.
Mhether the safety function of the valves
had been
compromised.
If other plant valves
may be subject to the
same failures.
10
o
The operability of the Unit 1 valves
and any inspections
or
testing
needed to confirm their operability,
The inspector discussed
the adequacy
of HM's review of these
problems with the Assistant Plant Manager
(APH) for Maintenance
Services.
As
a result of this discuss>on
and the APM's further
investigation,
an
NCR was initiated to address
the issue.
The
inspector will followup the licensee's
review during the course of a
future inspection.
Containment
Fan Cooler Unit
CFCU 2-2
Breaker Control Transformer
ause
a
>re
>n
s uice
Reference:
On April 6, 1990,
a small fire was discovered in the breaker cubicle
for Unit 2
CFCU 2-2.
The fire resulted
from a ground in the primary
side of the breaker control transformer.
The fire was extinguished
when the breaker
was racked out.
Electrical maintenance
was in the
process
of trouble shooting the breaker following spurious
breaker
trips.
Electrical maintenance
concluded that the spurious trips had
resulted
from the degraded
control transformer.
The licensee
also concluded that the control transformer failure was
an isolated event,
arguing that there are
many transformers of this
type operating without recurring failures.
Based
on the above,
broader corrective action was considered
unnecessary.
Containment
Leak Rate Test
On April 10, 1990, Unit 2 completed its integrated
leak rate test.
Licensee
engineers
reviewed the data
and concluded the results
were
satisfactory.
Inadvertent Ventilation Lineu
Shift
On April 17, 1990, the licensee
made
a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency
report
due to an automatic ventilation lineup change
from normal to
safeguards
mode in,both the control
room and fuel handling building
ventilation
systems.
The ventilation lineup change
was caused
by
I8C technicians
inadvertently shorting leads to radiation monitor
RH-51.
The short caused
a voltage disturbance
on the vital
instrument panel'hich initiated the lineup changes.
The'icensee's
immediate actions
were appropriate
and the licensee's
follow-up actions will be examined in response
to their event report
and
Non Conformance
Report
DC 2-90-TI-N025.
Wirin
Se aration Not Sufficient
On April 20,
1990, the licensee
made
a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency
report
for Unit 2,
The report was based
on finding the wiring for relays
for low temperature
over-pressure
protection
(LTOP) not properly
separated
per
IEEE standards.
The licensee
had also found and reported the problem in Unit 2
earlier in the day.
The Unit 2 condition was repaired.
The Unit 1
condition has
been included on a forced outage
work list and will be
corrected at the next opportunity.
The inspectors will follow-up the licensee's
root cause evaluation
through the licensee
event report and
non conformance
report.
5.
Haintenance
62703)
The inspectors
observed portions of, and reviewed records
on, selected
maintenance activities to assure
compliance with approved procedures;
technical specifications,
and appropriate
industry codes
and. standards.
Furthermore,
the inspectors verified maintenance activities were
~
~
~
~
~
erformed by qualified personnel,
in accordance
with fire protection
and
ousekeeping
controls,
and replacement parts were appropriately
certified.
The inspectors
examined maintenance activities in conjunction with the
plant events
reported in paragraph
4.
In particular,
those examinations
included the maintenance .aspects
of motor operated
valve problems (4a),
RCDT overfill (4b), stuck check valves (4c), missing check valve parts
(4d), auxiliary saltwater
pump restraint bolting repair (4e), limitorque
valve spring pack relaxation (4f), reactor vessel
disassembly
work (4q),
reactor
coolant
pump rotor repair {4h), 4kv circuit breaker repair (4>),
diesel
generator repair (4k), vital battery charger repairs (41), reactor
coolant
pump thrust bearing repair (4m), butterfly valve repair (4o), fan
cooler transformer
replacemeh't
(4p), and wiring separation
repair for
protection relays (4r).
In addition detailed maintenance
observations
were
made for motor
operated
valve testing
and repair by an
NRC specialist.
That activity
will be reported separately.
a.
Relief Valve Blowdown Settin
s
During the reporting period, the inspector
examined
licensee
progress
in resolving Crosby relief valve blowdown settings.
The problem was first identified in Inspection Report 50-275/89-16
in July 1989.
The inspector questioned
the setting of the Unit 2
letdown relief valve due to an event in which the valve would not
reseat at normal. system pressure.
The licensee
commenced
an
examination of the subject at that time.
Three Crosby relief valves were examined during the Unit 1 refueling
outage in October to December
1989.
The as-found
blowdown settings
were not in accordance
with licensee
procedures
and were set high
such that the relief valves would have chattered
had they lifted.
No further examination
was
done during the Unit 1 outage.
The
maintenance
engineers
logic for not examining additional valves
was
that the valves would liftat the proper setpoint
and the improper
blowdown would only cause chatter.
12
During the Unit 2 refueling outage in March 1990, the licensee
examined all Crosby relief valves with adjustable
blowdown settings
in Unit 2.
The reason for the expansion of the sample
was the discovery that
the licensee's
procedure for setting Crosby relief valves
was in
error and did not recognize that each individual valve had
a unique
blowdown ring setting.
The Unit 2 valves
had been set to Unit 1
values.
The events to this point raised two concerns.
First, it took from
July 1989 to March 1990 to discover that the licensee's
procedures
were wrong and the valves were improperly set for blowdown.
Secondly,
the Unit 1 outage
had
come
and gone
and left valves with
improper blowdown settings in Unit 1.
On March 20,
1990, in response
to a request for an operability
evaluation
by the resident inspector,
the licensee
issued
a
justification for continued operation,
JCO 90-04RO, for Unit 1
operations with potential
blowdown setting problems
on Crosby relief
valves.
The
JCO was reviewed by the resident inspectors
and judged
to be acceptable.
Copies of the
JCO were provided to regional
and
headquarters
technical
personnel
and the subject
was discussed
with
regional supervision.
The licensee
subsequently
issued
a
Nonconformance
Report,
NCR DC2-90 MM-N013, on the subject of the
Crosby relief valve blowdown settings.
The licensee
had not yet
determined final root cause or final permanent corrective action.
Subsequent
licensee
actions regarding
Crosby relief valves appear to
be acceptable.
All Unit 1 valves will be properly set by the fourth
refueling outage in 1991,
and
a new maintenance
procedure will be
prepared
and training conducted
by the
same date.
Licensee
nonconformance
analysis did not appear to address
two
management
issues:
o
En ineerin
Res onsibilit
Engineering
involvement in the problem is not addressed
in the
nonconformance.
Engineering culpability should
be examined
since they were the organization which specifically provided
the wrong information for Unit 2 in the Diablo Canyon vendor
manual for Crosby relief valves
(DC663 219-601,
Revision 2,
dated
June
15, 1987).
o
Untimel
Maintenance Action
The licensee action in resolving the apparent
blowdown problem
appeared
to be untimely.
The problem revealed itself in July
1989 and was not addressed
comprehensively
during the Unit 1
outage
even through all three valves
sampled
had improper
blowdown settings.
13
The two management
issues
above were discussed
at the exit
interview.
The licensee
committed to .include the management
issues
in the nonconformance
report.
The inspector also discussed
the
opinion that the facts surrounding the development of the blowdown
setting problem
show the
need for improved management
oversight of
mechanical
maintenance
activities to recognize,
raise
and deal with
issues.
No violations or deviations
were identified.
6.
Survei1
1 ance
(61726)
By direct observation
and record review of selected
surveillance
testing,
the inspectors
assured
compliance with TS requirements
and plant
procedures.
The inspectors verified that test equipment
was calibrated,
and acceptance
criteria were met or appropriately dispositioned.
Surveillance testing observed
during this period included the performance
of the Unit 2 Integrated
Leak Rate Testing
and the integrated test of
engineered
safeguards
and diesel
generators
(STP M-15).
Both tests
involved major coordination efforts during the refueling outage.
Both
tests
were successfully
performed.
No findings were identified.
In addition surveillance testing aspects
of the events
discussed
in
paragraphs
4 and 8 were examined.
The surveillance
aspects
included
visual examination of check valves - paragraph 4d., diesel
generator
1-1
testing - paragraph 4k., 'battery testing - paragraph 41., safety valve
testing - paragraph
8b., containment
spray surveillance testing-
paragraph
8d.,
and charging
pump testing - paragraph
8.e.
No violations or deviations
were identified.
7.
0 en Item Follow-u
(92703
92702
a.
Core Reload Confi uration
Unresolved
Item 50-275/89-26-01
Closed
On November 17, 1989, during the Unit 1 core reloading operation,
the senior power production engineer
(SPPE)
and the refueling- senior
reactor
operator
(SRO) placed
a fuel element in a position
prohibited by the core loading procedure
(OP B-8D Sl).
With only
six vacancies left in the core,
a fuel assembly
(one cycle used)
was
placed temporarily next to the core baffle.
Although OP B-SD Sl
allows the temporary placement of fuel elements to facilitate the
placement of a bowed element,
the procedure
requires that two
vacancies
exist on either side of the temporary storage position.
With only six vacancies
open, this was not possible.
This procedure violation was identified by the
SPPE during a
subsequent
core reload evaluation.
An evaluation
was performed
by
the fuel vendor and determined that the move essentially .lowered
reactivity (as
had been judged by the
SPPE during the move)
and was
therefore
not safety significant.
A gE (f0006994)
was written which
'nitiated corrective action to clarify OP B-8D S1 reqarding the
placement of fuel elements at the end of fuel load w)th limited core
b.
vacancies.
After the procedure
was revised, prior to the Unit 2
outage,
training was provided for individuals involved in the fuel
load.
Although the
SPPE
and
SRO failed to follow procedure,
the event
was
identified by'he licensee,
there
was
no safety significance,
and
the licensee
took appropriate corrective action in a timely manner.
Therefore, this item is closed.
II
Main Annunciator
T
ewriter Testin
(0 en Item 50-323/89-21-01
ose
Following the August 21,
1989 manual trip of Unit 2, the main
typewriter did not record alarms during the critical
portion of the event.
An electronic
memory card,
designed to
maintain alarm information until the alarm typewriter caught
up,
had
failed and approximately
40 seconds
worth of alarm information was
lost.
As a result of the event,
the licensee
implemented
a periodic test
to assure
the availability of the memory cards.
As permanent
corrective action, the licensee
replaced
both the Unit 1 and
2 main
annunciator typewriter systems with state of the art equipment.
The
system,
which has redundant processors,
is not subject to the
same
fai lure mode
and the testing
was discontinued.
Thss item is closed.
No violations or deviations
were identified.
8.
En ineerin
and Desi
n Control
37700
37702)
a.
Fuel Handlin
Bui ldin
Ventilation
S stem Ino erable Durin
Fuel
ovemen
On March 14, 1990, during a walkdown of the Unit 2 Auxiliary
Building, the inspector
noted that hoses
used for the Unit 2 steam
generator fill and drain evolution passed
from the 100 foot
elevation containment penetration
area,
through
a door, to the motor
driven auxiliary feedwater
(AFW) pump room.
The inspector also
observed that the
AFW pump rooms appeared
to be within the fuel
handling building and the door, propped
open by the hoses,
appeared
to be
a barrier between the fuel handling building and the auxiliary
building.
At the time of the the inspection,
fuel was being handled
in the spent fuel pool and the fuel handling building ventilation
system
(FHBVS) was required to be operable.
The inspector
asked the Assistant Plant Manager for Technical
Services to confirm that the door between the 100 foot penetration
area
and the
AFW pump room served
as
a
FHBVS boundary
and to,
determine
whether the open door affected
FHBVS operability.
Subsequent
to the inspector's
questions,
the licensee
determined
that the door in question
was indeed
a
FHBVS barrier.
Additionally,
the licensee identified a second
open
FHBVS barrier door and
determined that the open doors
made indeterminate
the ability of the
15
FHBVS to maintain
an 1/8 inch differential pressure,
as required
by
the Technical Specification.
The licensee
took immediate action to
shutdown the
FHBVS supply fans,
leaving the exhaust
fans on, to
ensure that
a greater
than 1/8 inch differential pressure
was
established.
The safety function of the supply fans is specifically
to cool the
AFW pump rooms.
Since the plant was in Mode 6,
refueling,
the
AFW system
was not required to be operable.
The
supply fans are not taken credit for in the ventilation design basis
for the spent fuel pool.
Technical Specification
3. 9. 12, "Fuel Handling Building Ventilation
System,"-allows fuel movement within the spent fuel pool provided
the
FHBVS is operable.
To demonstrate
operability, every eighteen
months
TS 4.9. 12.d.3 requires that the licensee verify that the
FHBVS maintains the spent fuel storage
pool area at a negative
pressure
of greater
than or equal to I/8 inch water gauge relative
to the outside
atmosphere
during system operation.
FSAR Section
15.4. 5. 2. 2, "Fuel Handling Area Accident, 'tates
that,
"Doors in
the fuel handlinq area
are closed to maintain controlled leakage
characteristics
sn the spent fuel pit region during refueling
operations
involving irradiated fuel."
In response
to the inspector's
questions,
a test
was performed to
establish
what effect having the doors
open
had on the ability of
the
FHBVS to maintain
a 1/8 inch negative pressure
with the supply
and exhaust
fans operating.
The test determined
+hat under these
conditions,
the
FHBVS could maintain only a 1/16 inch negative
pressure.
This indicates that while fuel was being handled in the
spent fuel pool, from March 12 to March 15,, 1990, the
FHBVS was not
able to maintain the
TS required 1/8 inch negative pressure.
This
is an apparent violation (Enforcement Item 50-323/90-08-01).
Subsequent
to the inspector
s findings, the licensee initiated a
non-conformance
report and prepared
a licensee
event report (Dated
April 16, 1990).
As a result of these
events,
the inspector questioned
the adequacy
of the review the licensee
performed in April 1989 of the final
safety analysis report
(FSAR) for commitments which may not have
been incorporated into procedures.
The review was performed in
response
to an enforcement action which also involved the failure to
implement
an.'FSAR commitment, which was associated
with the
Auxiliary Saltwater
System.
During the
FSAR review, the licensee
recognized
the commitment in FSAR section 15.4.5.2.2.
regarding the
control of FHBVS doors.
However, plant engineering limited their
attention to control of large roll-up doors
and did not address
other
FHB doors.
The inspector
reviewed the non-conformance
(NCR) report which
implemented the licensee's
commitment to review the
(DCO-89-TN-N015) and the
NCR which addressed
the design
discrepancies
identified during that review (DCO-89-TN-N081). It
was not apparent to the inspector that all of the discrepancies
found (154)
had received the appropriate
review for safety
16
significance
and reportability.
NCR DCO-89-TN-N081 stated that it
addressed
only the
'design related discrepancies",
a total of 72,
and that
NCR DCO-89-TN-N015 addressed
the remainder.
However, while
DCO-89-TN-N015 appears
to have addressed
the cause
and corrective
actions for the implementation of commitments
made in the
FSAR, it
did not address
the safety significance
and reportability of the
commitments
not implemented.
In the specific case of the
FHB
roll-up doors, there
was
no consideration of the possibility that
because
the roll-up doors
had not been procedurally controlled
through the first two refueling outages for both units, that they
may have
been
open,
rendering the
FHBVS inoperable.
In the exit meeting,
the licensee
was requested
to address
in
response
to the notice of violation contained in this report, the
control of the
FHB roll-up doors during the first two refueling
outages
and the adequacy of the safety analysis for all
discrepancies
identified.
Additionally, the licensee
was requested,
to address
the adequacy
of the
FSAR review and the design
memo
review conducted in 1989.
b.
Pressurizer
Code Safet
Valve Testin
Through discussions
with the licensee
and examination of the
periodic testing performed
on pressurizer code'afety
valves,
the
inspector
became
aware of a change in the licensee's
method of
testing pressurizer
code safety valves.
4
The change
has to'o with the definition of when the valve is
considered
to have "lifted".
The licensee previously considered
the
"lift"point the pressure
at which "popping'f the relief occurred.
The valves ordinarily have
a water loop seal
and .the initial lifting
of the stem
and the passing of the loop seal water occurs first and
does
not involve "popping" the valve which occurs later.
Dependent
on which definition is used,
"popping" or "stem movement," there is
about
an 80 psi difference in the apparent liftpressure.
The- licensee
has
chosen to use the definition of first stem
movement.
In effect, therefore,
pressurizer
valves will be set 80
psi higher than in previous outages.
The licensee
engineers
concluded that thiC will help prevent the simmering of relief valves
experienced
in previous fuel cycles.
The licensee
performed
an
evaluation
and
had
a safety evaluation performed by Westinghouse.
The evaluations
concluded that the change in liftpoint definition
was acceptable for existing safety analysis
and was in accordance
with ASME Code definitions.
The licensee's
position is described in PG&E Womack to Giffin letter
dated
March 21, 1990,
(147497),
and Westinghouse
McHugh to Womack
letter dated
March 23,
2990 (PGE-90-580).
The information and the licensee's
position appeared
reasonable.
The information was forwarded to regional specialists
for
information.
17
Fuel Handlin
Buildin
Brid e Crane
Problems
Overview
During the fuel loading operation for Unit 2, the spent fuel pool
building bridge crane control system locked
up while attempting to
lower a fuel element into the fuel transfer
upender.
To recover,
the licensee
installed
a controlled electrical
jumper and performed
a safety evaluation to allow the fuel element to be lowered.
The
inspector
reviewed the fuel movement operations
conducted in the
spent fuel pool with the Assistant Plant Man'ager
(APH) for Technical
'ervices,
the spent fuel pool system engineer,
and equality Assurance
personnel,
and
a number of problems
were indicated.
Although the lowering of the fuel element
appears
to have
been
performed in acceptable
manner,
the inspector's
review of the events
leading
up to the locked
up crane control event indicates there were
a number of precursor
problems.
Discussed
below are apparent
~
~
~
~
~
~
~
~
~
roblem areas
which indicate that operation of the spent fuel pool
ridge crane
was not performed in a fully controlled manner.
The
discussion is based
on interviews with the APH, the system engineer,
and gA.
In some instances
the information received
was
contradictory.
Due to the limited time of the"inspection
and the
complexity of the issues,
these findings are therefore characterized
as preliminary.
Ade uac
of Startu
Testin
Extensive modifications were
made to
e
ue
an
ing sys
em, )ncluding the spent fuel pool bridge crane
control system,
at the end of the Unit 2 second refueling outage
(December
1988).
However, testing of the systems
was not completed
during the second refueling outage
and was scheduled for the start
of the third refueling outage, prior to its use.
Two apparent
hardware
problems
(discussed
below) were not discovered
during
startup testing.
These
problems
may have
been caught
and corrected
if a complete dry run had been performed using the bridge crane to
move the
dummy fuel element into the upender.
This was apparently
not done.
Hardware
Problems:
During fuel movement, it was noted that when
ggH ti f t
p d,th
1d
tf
3
to 6 inches
beyond the stopping point.
The system engineer
indicated that the crane
brake was designed to stop the element in
1.5 inches.
Additionally, the digital limit controller for the
bridge crane,
as set
up by the startup engineer,
did not allow the
fuel element to clear the upender
when the element
was lifted in
slow speed.
To correct this problem, the system engineer raised the bridge crane
control
system
upper limit to allow a fuel element to clear the
upender in slow speed.
It was subsequently
discovered that if the
crane
was raised in fast speed,
the coast past the upper stop would
put the crane in a position where the electronic controller did not
know what position it was in.
As a result, the controller would not
allow the crane to be moved.
This is the condition reported
as
18
"lockup".
As corrective action, prior to core reload, the fuel
movement
crew was given verbal instructions to assure
fuel elements
were raised in slow speed.
However,
midway through the reload this
was not successfully
accomplished
and crane control locked
up with
an element in the elevated position.
Desi
n Chan
e Turnover:
After the core offload, but prior to the
core re oa
,
ectncal
Maintenance
(EM) was asked to investigate
the bridge crane.
No problems
were found.
System engineering
indicated that the turnover from startup engineering to
EM regarding
the design of the spent fuel pool bridge crane
may have
been
inadequate.
Procedural
Com liance:
The system engineer indicated that after the
core
o
oa
,
o
ow>ng the departure of the fuel movement
crew
(supplied
by a service vendor),
he became
aware that the contractor
had not been following the fuel handling procedure.
During the core
offload, the contractor
had discovered that the upper control limit
would not allow a fuel element to clear the upender if the element
was raised in slow speed
as required by the procedure.
To
compensate,
the fuel movement
crew raised fuel elements
in fast
speed,
relying on the crane's
coast past the upper limit to allow
the fuel element to clear the upender.
When the system engineer
became
aware of the problem,
he reprogrammed
the controller to set
a
higher liftpoint.
This was performed without a change to a
procedure
which specifies
the limit settings.
Upon the return of the fuel movement
crew for the core reload,
a
problem was found with the crane's
underload
bypass
feature.
The
startup
group was asked to investigate
the problem.
The system
engineer
noted that when the crane
was returned to service following
investigation
by the startup group, the limit settings
were
different than those set by the system engineer
and were also not
those specified by the procedure.
Inade
uate
Communications:
During the fuel movement,
there were
examp
es
o
apparen
dna equate
communications.
The first example
was the apparent
lack of communication of the difficulty experienced
by the fuel movement
crew in raising the fuel element
above the
upender.
There
was also evidence of inadequate
communications
between
the startup group,
EM, and the system engineer.
ualit
Assurance
Involvement:
The equality Assurance
department
per orme
our surveys
ance
coverage of spent fuel handling
operations.
The gA department did not have any outstanding
issues
related to the problems discussed
above.
The lead
gA auditor was
unaware of some of the problems
and questioned
the accuracy of
information supplied to the system engineer.
The inspector concurred with the
APM for Technical
Services that
a
review of these
events
was not immediately necessary
given the
impending restart of Unit 2 and that fuel movement would not
commence
on Unit 1 until 1991.
However, the inspector
observed that
efforts should
be made in a timely way to prevent the loss of
19
impetus for corrective actions.
In the exit meeting,
the
committed to initiate an
NCR to address
the issues
discussed
above.
This item will remain
open pending the completion of the licensee's
review (Unresolved Item 50-323/90-08-02).
Containment
S ra
Header in an Unanal
zed Condition
Overview
During Local
Leak Rate Testing of the Unit 2 Containment
Spray
(CS)
system containment penetration isolation valves,
engineers
discovered water downstream of the
CS isolation valves.
Upon
further inquiry by plant engineering, it was realized that based
on
Hosgri design considerations,
the
CS piping inside containment
was
not qualified to withstand the design basis
seismic event with water
in the pipe.
Details
On April 3, 1990, the licensee
drained the inside containment
portion of the Unit 1
CS piping and discovered
approximately
30
gallons of water in one train and 160 gallons in the other.
In
accordance
with 10 CFR Part 50.72, the licensee
made
a 1-hour
non-emergencey
report on Unit 1 and
a 4-hour
non-emergency
report on
Unit 2, after determining that the condition was
an "unanalyzed
condition that significantly compromised plant safety."
Subsequently,
an engineering analysis
was performed,
taking into
consideration"the
amount of water found.
The analysis
concluded
that while the
CS piping would have
been stressed
beyond the design
allowables, it would not have been stressed
to the point of yield.
Although the licensee
could not make
a positive determination of how
the water managed to get beyond the outside containment isolation
valves, it was concluded that isolation and check valve surveillance
tests
were the most probable
cause.
Supporting this was that the
water level discovered in the Unit 1 piping was calculated to reach
the 150'evel, 10'elow the minimum level of the
RMST.
This
suggested
that the head of the
RMST and not a
CS pump had pushed the
water downstream of the isolation valve.
Supporting the conclusion
that this had occurred during valve testing and not as
a result of
isolation valve leakage
was that
a week following the discovery of
water in Unit 1
CS piping,
no additional water was discovered.
To address
cause
and corrective action, the licensee initiated an
NCR (DCO-90-TN-N-019).
Additionally, the event was determined to
require
an
LER.
A February 10,
1982
memo from the plant manager to the corporate
office documented portions of the
CS design basis including the need
to maintain the
CS piping inside containment dry.
However, the
requirement to maintain the
CS piping dry was never implemented into
plant procedures.
On March 24, 1989, in response
to an
NRC
inspection finding regarding the design basis of the auxiliary
saltwater
system,
the licensee
committed to and performed
a review
20
of engineering
correspondence
and communications specific to
constraints
on plant operations.
This was
done to verify that
no
other operational
requirements
identified by design
memorandum
were
missed.
The February 10, 1982,
memo was not included in this
review.
Section
Ba. of this report describes
a similar issue.
The
FSP'eview
performed
as
a result of the
same set of corrective ac'ns
did not identify the
need to control all
FHB doors.
At the xit
meeting for this report, the licensee
was requested to include in
their response
to the notice of violation contained in section
8a.
an evaluation of the adequacy of the
memo and
FSAR review performed
in 1989.
Char in
Pum
Recirculation
Lines
While performing functional testing of the emergency
core cooling
system
(ECCS) during the Unit 2 refueling outage it was noted
bP the
plant engineering staff that the tested
ECCS configuration did riot
match the configuration that would result from a safety injection
signal.
Specifically the centrifugal charging
pump (CCP) minimum
flow recirculation isolation valves
do not receive
an automatic
close signal
and are normally open during plant operations,
whereas
the tested configuration was with the
CCP recirculation valves
closed.
The licensee
then questioned
the ability of the charging
system to perform its design function as explained below.
In the original plant design;:the
CCP recirculation valves were
automatically closed
on a safety injection signal.
In 1981, in
response
to
NRC I8E Bulletin 80-18,
where it was recognized that the
CCPs could be dead
headed
against
'ressure,
the licensee
removed the recirculation safety injection
isolation signal to the recirculation isolation valves.
An analysis
was performed that determined that the
ECCS could perform its design
function with this configuration.
During the third refueling outages for both Units,
new higher
enrichment fuel was added to the core.
The revised safety analysis
for the
new fuel assumed that the recirculation valves would close
on a safety injection signal.
As a result, the analysis
took credit
for more high head injection than would have
been available.
The licensee
requested
the
NSSS vendor provide
a supplemental
analysis of the
FSAR accident analysis,
taking into consideration
the. open recirculation line.
The analysis
concluded that the design
basis
had been met.
An NCR was initiated to identify why an
accurate
ECCS configuration
had not been provided for the
new fuel
analysis
and to determine appropriate corrective actions.
The
inspector will review the
NCR during the course of routine
inspection.
g ~
21
f.
Block Mall Ins ection
The Office of Nuclear Reactor Regulation
(NRR) reviewer and the
Region
V Projects
Section I Chief inspected
masonry block walls with
ductility ratios greater
than three.
This review did not find any
apparent situations
where large safety components
would be
significantly affected
by the collapse of the masonry walls.
The
inspection identified concerns
on the length of restrainina
angles
at the bottom of walls A06A and
B and the connection detaH of the
ventilation duct at the top of these walls.
The walls between the
cable spreading
rooms are also
an
NRC concern.
These
concerns
we'll
be reviewed under
NRR's evaluation of this issue.
No violations or deviations
were identified.
11.
Exit (30703)
On Hay 1, 1990,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.