ML17305B447
| ML17305B447 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 03/20/1991 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305B445 | List: |
| References | |
| 50-528-91-01, 50-528-91-1, 50-529-91-01, 50-529-91-1, 50-530-91-01, 50-530-91-1, NUDOCS 9104090135 | |
| Download: ML17305B447 (34) | |
See also: IR 05000528/1991001
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
or I
)los
Docket Nos.
License
Nos.
Licensee:
Facilit
Name:
50-528/91-01,
50-529/91-01
and 50-530/91-01
50-528,
50-529,
50-530
Arizona Public Service
Company
P.
0.
Box 53999, Station
9012
Phoenix,
AZ
85072-3999
Palo Verde Nuclear Generating Station
Units 1, 28
3
Ins ection Conducted:
January
6 through February
16,
1991
Inspectors:
Approved By:
a
e
sgne
D.
Coe,
Senior
Resident
Inspector
F.
Ringwald,
Resident
Inspector
J.
Sloan,
Resident
Inspector
D. Kirsch,
Chief, Reactor Safety Branch
W. Ang,
Project Inspector
3
ong,
hl e
Reactor Projects,
Se tion II
Ins ection
Summar
Ins ection
on Januar
6 throu
h Februar
16
1991
Re ort Numbers
50-528 91-01
50-529 91-01
and 50-530 91-01
Areas Ins ected:
Routine, onsite,
and regular
and backshift inspection
y the resident
inspectors
and inspectors
from the Region
V staff.
Areas
inspected
included: previously identified items; review of plant
activities; monthly surveillance testing;
monthly plant maintenance;
(RCS) cooldown rate limit exceeded - Unit 1;
apparent
(RCS) stratification in loop 1 hotleg-
Unit 1; incorrect lube oil added to auxiliary feedwater
pump and boric
acid makeup
pump - Unit 2; emergency diesel
generator air start system
leakage - Unit 3; 'violation of surveillance
requirement to perform
emergency diesel
generator
(EDG) inspections
during plant shutdown-
Unit 3;
use of an engineering
evaluation
(EER) request
not formally
approved - Unit 3; potential for small break
LOCA due to tube rupture in
the reactor coolant
pump seal
cooler - Units 1, 2,
and 3; Probabilistic
Risk Assessment
- Units 1, 2,
and 3; Plant Review Hoard activities-
Units 1, 2,
and 3; and review of licensee
event reports - Units 1, 2,
and
3 ~
During this inspection the following Inspection
Procedures
were utilized:
30703,
40500,
61726,
62703,
71707,
71710,
92700,
92701,
92702
and 93702
'104090135
910321
ADOCK 05000528
Q
Results:
Of the
15 areas
inspected,
two violations were identified in
Un>t 3.
The violations pertained to an
NRC identified departure
from the
plant conditions specified for performing an Emergency Diesel Generator
surveillance
inspections
and the failure to promptly correct
an
identIfied deficiency and perform an adequate
evaluation of the
deficiency.
General
Conclusions
and
S ecific Findin
s
Si nificant Safet
Matters:
Summar
of Violations:
None
2 Cited Violations - Unit 3
Summar
of Deviations:
0 en Items
Summar
7 Items closed,
3 Items left open,
and
6
New Items opened.
j
t
DETAILS
Persons
Contacted:
The below listed technical
and supervisory personnel
were
among
those contacted:
Arizona Publ'ic Service
Com an
(APS)
"R. Adney,
- J. Auston,
- J. Bailey,
"H. Bieling,
¹"T. Bradish,
"M. Czarnylas,
- J. Draper,
"E. Dotson,
¹"T. Engbring,
"R. Flood,
R. Fullmer,
D.
Gouge,
¹"S. Guthrie,
~K. Hall,
"B. Hazelwood,
"R. Henry,
.
P.
Hughes,
~M. Ide,
"S. Kanter,
F. Larkin,
"J. Levine,
J. Minnicks,
"J. Napier,
"G. Overbeck,
"R.
Rouse,
R. Rogalski,
J. Scott,
¹G. Shell,
S. Terngino,
'N. Thibodaux,
Plant Manager,
Unit 3
Fire Department,
Deputy Chief
Vice President,
Nuclear Safety
8 Licensing
Emergency/Fire
Protection,
Manager
Compliance,
Manager
Fire Protection,
Deputy Chief
SCE, Site Representative
Engineering
8 Construction,
Site Director
Lead Engineer,
Systems
Engineering
Plant Manaqer,
Unit 2
gA and Monitoring, Manager
Plant Support,
Manager
(Ch. Plant
Review Bd.)
equality Department,
Deputy Director
El Paso Electric Co., Site Representative
equality Assurance,
Monitoring, Supervisor
Salt River Project, Site Representative
Site
Rad. Protection,
General
Manager
Plant Manager, Unit 1
Sr. Coordinator,
Owner Services
Security,
Manager
Vice President,
Nuclear Power Production
Maintenance
Manager,
Unit 3
Compliance,
Technical
Support, Site Director
Compliance,
Supervisor
gA, Supervisor
Operations
Manager,
Unit 1
equality
Systems,
Manager
Management
Services,
Supervisor
System Engineer,
EDG System
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
"Attended the Exit meeting held with NRC Resident
Inspectors
on
February 21,
1991.
¹Persons
contacted
by M. Ang.
2.
Previousl
Identified Items - Units 1
2 and
3 (92701
and 92702)
A.
Unit 1:
(Closed)
Unresolved
Item (528/90-20-01):
"RCP
Collection
S stem
ubln
- Un)t 1
92
1
This item involved improper restoration of RCP lube oil
collection system tubing following replacement
of the
motors.
The inspector questioned
the requirements
for
quality control classification
and controls over this
piping.
The licensee
has classified the
collection system tubing as equality
Augmented
(gAG) and is
finalizing the specific requirements
as part of the Fire
Protection
Task Force effort.
The licensee
is also
correcting the deficiency in procedure
"Reactor
Coolant
Pump Disassembly
and Reassembly"
to
include steps for restoring this tubing and will include
references
to the drawings
and documents
required for
proper installation.
The Manager of Maintenance
Standards
committed to issuing the revision to 31MT-9RC06 prior to
the start of the Unit 3 outage refueling (approximately
March 1991).
This item is closed.
(0 en) Followu
Item
528/90-20-04
- "Inadvertent
Shutdown
Cool a n
B
ass
-
Uns t 1
92 01
This item involved the discovery of bypass
flow through
valves SI-HV-690/691 when they are slowly jogged closed
because
they are not driven into their seat
by the motor
operator.
The licensee initiated Engineering Evaluation
Request
90-SI-093 which concluded that
a plant
modification would be required to fully address
this
problem.
The
EER is closed
and engineering is pursuing
a
plant modification as long term corrective action.
As an
interim measure,
the licensee
has revised procedures
"Shutdown Cooling Initiation," to require
operators
to manually shut these
valves to ensure that
they are fully closed, eliminating any bypass
flow.
The
inspector
reviewed
EER 90-SI-093
and noted strong
recommendations
which differed from the interim measures
established
prior to closure of the
EER and that the
discusses
problems with manual
operation of these
valves
in that it applies
indeterminate
torque to the valve stem.
It also recognizes
that "...both overthrust
and
underthrust
are both of equal
concern in terms of valve
operability and reliability."
The licensee is considering
revising the interim measures.
This item will remain open
until these
discrepancies
are resolved.
i
3.,
(0 en
Enforcement
Item 50-528/90-25-01:
"Ino erable
mer enc
L> htsn
In resp";,s='o
concerns
regarding the application of
quality assurance
criteria to various aspects
of the fire
protection
system,
the licensee
submitted
a Justification
for Continued Operation
by letter dated July 20,
1990.
In
addition, the licensee
responded
to the
Notice of Violation by letter
dated
November 15,
1990.
These
two documents
contained
several
commitments for
licensee
action.
The licensee
has identified 254 action items
and entered
all of these various
commitments into the Commitment
Action Tracking System.
The tracking system tracks item
status,
responsibility,
source,
due date,
and completion
date.
The licensee
appears
to be making acceptable
progress
in resolving these
items.
Only about four of the
licensee's
internal
commitments
were overdue;
the licensee
was aware of these
and dealing with those
items.
The licensee is tracking emergency lighting failures
quarterly by means of a Component Failure Data Trending
Report.
The report is provided to the System Engineering
Manager.
Failures
can
be accessed
in real time by System
Engineers
using networked
computer terminals accessing
the
maintenance
data
base.
The licensee
plans to have
a
terminal in all System Engineer work spaces
by about
mid-year.
Emergency Lighting Unit No.
3E(DNF02 failed the
8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
test in January,
1991,
and
has not been retested
satisfactorily since.
This unit is one of two redundant
units for the Unit 3 control
room.
The inspector
discussed
the circumstances
at length with licensee
representatives
and ascertained
the following:
a.
A nonconformance
report was written to document the
situation
and provide
a vehicle for resolution
and
corrective action.
b.
A problem resolution sheet
was written to initiate
the necessary
reviews to determine reportability.
The licensee
did not consider the situation
reportable
because
the failed unit is backed-up
by a
redundant unit.
C.
d.
Licensee
engineering evaluation
was that the unit
batteries
need replacement.
Because
the licensee
does
not have sufficient spares
on hand,
new batteries
were placed
on order.
\\
The licensee
has readjusted
the low voltage cut out
on the two control
room battery banks in each unit to
properly compensate
for cable voltage drops.
The
inspector
reviewed these calculations
and found them
acceptable.
The inspector considers
that the licensee is dealing with
the above failure
$ n an acceptable
manner.
The inspector discussed
the licensee's
actions to deal
with emergency lighting failures.
The licensee
has taken
action to see that future emergency lighting failures are
documented
using the nonconformance
reporting system to
assure that problems
are dealt with in a timely manner
with the benefit of engineering
and management
involvement.
The inspector discussed
the
EER backlog with licensee.
representatives
and found that the
EER backlog
had only
been
reduced
by about
10K and the average
EER age
was
excessive.
The licensee
acknowledged
the problem and was
evaluating actions to effect better control of the
backlog and age.
This item remains
open pending further review of the
overall issue
by the inspector.
B.
Unit 3
(Closed)
Enforcement
Item (530/90-20-01):
"Atmos heric
um
a ve
atro
en
ccumu ator
oun
so ate
n)t
This item involved an improper valve lineup performed
by
Unit 3 operators
which isolated the
when
the isolation valve should
have
been
locked open in
accordance
with procedure
40AC-OZZ06, "Locked Valve and
Breaker Control. 'he operators
involved were counselled,
all operators
were briefed
on the importance of attention
to detail,
an investigation
was conducted utilizing the
.
Human Performance
Evaluation
System
(HPES) program,
and
each shift received training on independent verification.
The inspector
reviewed the corrective action,
had
no
further questions,
and concluded that these actions
appear
appropriate to address this event.
This item is closed.
C.
Units 1
2
and
3
(0 en)
Re ort (89-18-P):
"ABB Power
1s
r1 ut1on
nc.
urrent
rans
ormer
nca
su ate Materia
'- Un)ts
1
2
3
2701)
This item involved a softening of the epoxy-anhydride
encapsulate
material in CTs due to high humidity
conditions.
The licensee
has evaluated this in EER
89-XE-28 which refers to
EER 89-NG-10.
The inspector
reviewed these
two EERs
and noted that the disposition
does
not clearly identify the licensee's
action
on this
issue.
This item will remain
open pending additional
information from the licensee.
(Closed
Re ort (89-24-P):
"BW/IP
nternatsona
nc.
s
ressure
win
ec
alve
Failure
- Units
1
2
& 3
92701
This item involved the failure of a check valve at
Comanche
Peak
Steam Electric Station.
The licensee
has
evaluated
the concern,
determined that 69 affected valves
exist in each unit, and concluded that only six valves per
unit would be
a safety concern if they failed to block
flow and potentially cause
an interfacing system loss of
coolant accident
(ISLOCA).
The first refueling outage after receipt of the associated
Information Notice (90-03) occurred in Unit 2 and
coincidentally included scheduled
inspections
of 17
affected valves
under the ongoing Check Valve Preventive
Maintenance
Program.
None of these
valves
had any defect
indications.
Additional affected valves will be inspected
in future outages
in accordance
with the ongoing program.
The licensee is currently performing
a fracture mechanics
study which preliminarily suggests
that
a critical flaw
size would have to be greater
than 0.25 inches for all
valves.
The licensee
is also performing
a Probabilistic
Risk Analysis
(PRA) to quantify the contribution of these
check valve failures to the probability of an
qualitative analysis
suggests
that if the
Commanche
Peak
and Palo Verde data is combined,
the resulting
contribution to ISLOCA appears
to be acceptably
low.
The licensee
expects to finish the fracture mechanics
and
PRA study during the second quarter of 1991.
The
inspector
concluded that these activities appear
appropriate
to address this issue.
This item is closed.
Closed)
Re ort (89-25-P):
"Deficienc
With
L)motor ue
-
0 an
B-00
otor
erator
or ue
Sw)tc es
- Units 1
2
2
1
This item involved a deficiency with cam-type torque
switches in that fiber spacers
permit loosening of
stationary contact
screws.
One consequence
of this type
of failure is the potential for affecting the torque which
will break the torque switch current and stop the operator
from delivering torque to the valve.
The licensee
issued
EER 89-XE-059 on November 27,
1989.
The
EER is still open
and the system engineer
expects to close it during the
next month.
The system engineer
noted that
PCN 3
I
4
to procedure
32MT-9ZZ48, "Maintenance of Limitorque
Motor Operators,"
issued
on January
3, 1991, requires
workers to inspect for fiber spacers
and write a work
request to replace
any torque switch found with fiber
spacers.
The inspector considers
the actions
taken to
have
been slow, but technically adequate for this issue.
This item is closed.
(Closed
Re ort
89-28-P
"Coo er-Bessemer
mer enc
iese
enerator
ran case
x
os)on
nsts
This item involved two crankcase
explosions of diesel
generators
at the Susquehanna
Steam Electric Station.
Cooper-Bessemer
has concluded that both of these
explosions
were due to casting defects
which they consider
to be "extremely rare."
They therefore
conclude "that
there is no generic
impact as
a result of the reported
incident" and that licensees
with similar diesels
need
take
no further action.
The licensee
has reviewed this
event
and
had discussions
with the Cooper-Bessemer
owner's
group and with Cooper-Bessemer.
As a result,
the licensee
has initiated several
actions which will limit the impact
of what is believed to be contributing factors to this
event.
These actions
include submitting
a Technical
Specification
change
request to move the llOX load test to
the
end of the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Surveillance
Test run so the heavy
load test
can occur when the engine is fully warmed
up.
Additionally, the licensee
has modified their monthly
surveillance test procedures
to run the diesels for four
hours
when practical rather than just one hour.
In
addition,
Cooper-Bessemer
has generated
service bulletins
which recommend
loading and unloading profiles which the
licensee
is evaluating for inclusion in diesel testing
and
operating procedures.
According to the system engineer,
a
final root cause of failure has not been fully agreed
on
by Cooper-Bessemer
and the ow'ner's group.
The licensee is
following testing
and other actions being taken
by
Susquehanna
and Cooper-Bessemer
and
has stated that as
further lessons
are learned
from these
events,
they will
receive service bulletins,
owner's
group comments,
and if
warranted,
amended
or additional
10 CFR Part 21 reports.
The inspector
concluded that the licensee
appears
to be
taking appropriate
action.
This item is closed.
(Closed
Re ort (89-31-P
and
LER (528/
enr
ratt
om an
a ve
al ures
nsts
This item involved the intergr'anular cracking
and failure
of spiral pins
used to attach the disk of butterfly valves
to the stem.
This issue
was addressed
in Inspection
Report 528/529/530/89-49,
paragraph
12.
The inspector
reviewed supplement
1 to the initial 10 CFR'art
21 Report
and
had
no further questions.
This item is closed.
3.
Review of Plant Activities (71707
and 93702}
A.
Unit 1
B.
Unit 1 entered this reporting period operating at 100 percent
power.'n January
12,
1991, the unit was downpowered
and the
reactor manually tripped to commence
a scheduled
39 day
surveillance test outage.
Maj or outage activities included
performance of 18 month surveillance tests
(Integrated
Safeguar ds surveillance,
Emergency Diesel
Generator
inspection,
snubber inspections,
Emergency
Safeguards
Features
Battery
surveillance
and others},
ASME Section
KI pump and valve
inspections,
rewiring and testing of many motor operated
valve
operators, circuit breaker testing,
implementation of some site
modifications,
and performance of many corrective maintenance
work items.
The outage
was completed three
days
ahead of
schedule,
with Mode 4 and
Mode
3 entered
on February
13,
1991,
Mode
2 and
Mode 1 on February 16,
and synchronization to the
grid on February
16.
Power ascension
was in progress
at the
end of the reporting period.
Unit 2
Unit 2 operated at essentially
100 percent
power throughout
this reporting period.
Unit 3
D.
Unit 3 operated at essentially
100 percent
power throughout
this reporting period.
Plant Tours
The following plant areas
at Units 1,
2 and
3 were toured by
the inspector during the inspection:
Auxiliary Building
Control
Complex Building
Diesel Generator Building
Radwaste Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The following areas
were observed
during the tours:
1.
0 eratin
Lo s and Records - Records
were reviewed against
ec naca
peel
)catsons
and administrative control
procedure
requirements.
Monitorin
Instrumentation - Process
instruments
were
observe
for corre ation between
channels
and for
conformance with Technical Specifications
requirements.
~Sic f
R <> .'ction warranted
and will review the IIR when
complete
(Fol 1 owup Item 529/91-01-01).
No violations of NRC requirements
or deviations
were identified.
Emer enc
Diesel Generator Air Start
S stem
Leaka
e - Unit 3
61 26 and
62 03
The inspector performed walkthrough inspections
of Unit 1 and Unit 3
(EDG) buildings and the site maintenance
shop.
The repaired Unit 1
EDG inner cooler was observed
in the
maintenance
shop awaiting reassembly
and testing.
The inspector
noted that
a significant amount of coating (appeared
to be belzona)
had been recently applied over portions of the inner cooler flanges
and excess
coating appeared
to have
been applied over portions of
the inner cooler
tube openings.
The system engineer
observed
the
condition concurrently
and requested
maintenance
shop personnel
to
remove the excess
material.
Mhile no surveillance
testing
was observed
in progress,
the
inspector
reviewed records for the most recent testing of Unit 3
air star t receiver relief valves
PSV-5, 6,
7 and
8 and inlet check
valves V-066, -067, -068 and -069.
Review of the applicable test
records
and procedures
indicated that the testing
had been
satisfactorily accomplished.
During the inspection of the Unit 3
EDG building, the inspector
noted
an oily substance
leaking from both of the
EDG "A" air start
receiver
manway cover gaskets
and, to a lesser extent,
from both of
the
EDG "B" air start receiver
manway cover gaskets.
The inspector
noted that work request
tags
and
MR 396847)
on the
"A" air receivers
had identified "oil bubbling from access
covers."
The air pressure
of all in service receivers
(one
was being taken
out of service for 'compressor
maintenance)
were being maintained
by
their corresponding
compressors
at 240 to 250 psig.
The inspector
discussed
the noted condition with the system engineers,
the Unit 3
operations
supervisor,
compliance
and gA.
The inspector inquired
about the ability of the
EDG air start
system in Unit 3 to perform
its design functions specified in UFSAR Section
9. 5. 6.
Specifically, the inspector attempted to determine if a technical
evaluation
had been performed for the noted condition taking into
consideration
the following:
a)
The air receivers
were being maintained at their required
pressure
by a non-safety-related,
non-seismic,
non-class
1E
powered
compressor.
The ability of the leaking air cylinders
to maintain sufficient pressure
to accomplish all its design
functions without the assistance
of the compressors
was
unknown.
The amount of allowable leakage
and the magnitude of
16
the identified leakage
necessary
to be able to make this
determination,
were
unknown.
b)
Evaluations
were not performed to determine
the substa'nce
leaking from the air cylinder manway cover gaskets,
the source
of the substance,
and the possible deleterious
effects of the
substance
on any part of the air start system
such that it
would preclude it from performing its function.
The
PVNGS Updated
FSAR, Section 9.5.6. 1, Design Bases,
states
in
part that "the
DGSS [diesel generator start system] shall provide
a
stored
compressed air supply sufficient for accomplishing diesel
generator
cranking cycle
5 times without starting the'iesel
generator air compressors,"
and "the
DGSS shall
remain functional
during and after an SSE."
The inspector discussed
the above
noted observations
and was
informed of the following by the system engineers,
the operations
supervisor,
gA, and compliance:
A.
WRs 396845
and 396847 were written in Nay 1990
and were
cancelled
by work planning in October
1990 because
inspection
and cleaning of air receiver internals
were scheduled for
January
14,
1991 and February
17,
1991 by W.O. s 458522
and
458523.
The W.O.s were subsequently
rescheduled
for
performance in February
1991.
Since
WRs 396845
and 396847
had been cancelled,
the record for
those work requests
were
no longer available
and the only
records available
relating to the work request
was the
SINS
computer annotation that it had
been cancelled
and included in
W.O.s 45822
and 45823
and the
WR tags that had
been
inadvertently left hanging
on the two
EDG "A" air receiver.
manway cover gaskets.
B.
The air receivers
are not periodically tested'and
the leak rate
from the
manway cover gaskets
had not been determined for the
conditions identified by WRs 396845
and 396847.
The existing
, leak rate, at the time of the
NRC inspection,
was
unknown.
C.
The system engineers
and the operations
supervisor
considered
the leaking air receivers
to be operable.
They were unable to
state
what the manway cover gaskets
leak rates
were nor how
much leakage
was acceptable
for the receivers to be still
capable of performing its design functions.
The engineers
and
supervisors
claimed that the leakage
was acceptable
as long as
the low receiver air pressure
alarm in the control
room had not
activated.
It
D.
There
was
no indication that any monitoring of the leakage
was
being performed to assure that the leaking
manway cover
was not deteriorating
and the leakage
had not increased
since
the condition was identified eight months earlier.
The
inspector
recognized that control
room operators
would become
~
~
17
aware of low pressure
in the receivers
when the low pressure
alarm was annunciated.
However, the inspector also recognized
that as long as the compressors
were available
and the leak
rate did not exceed
the capacity of the compressors,
the alarm
would not activate
and
a deteriorating condition would not be
evident.
E.
F.
The system engineers felt that the leaking substance
was oil,
was coming from the compressors,
and did not feel that the oil
had any deleterious
effects
on any part of the air start
system.
No MNCRs regarding the condition were issued.
The
gC manager
indicated that the condition appeared
to be normal wear and
tear
and as
such did not require
an
MNCR, as allowed by the
MNCR procedure.
10 CFR Part 50, Appendix B, Criterion XVI, requires that measures
be
established
to assure
that conditions
adverse
to quality such
as
deficiencies
and malfunctions
be promptly identified and corrected.
The noted air receiver
manway cover gaskets
leakage
were not
corrected for approximately eight months,
the amount of leakage
for the receivers
to still be capable of performing its specified
functions
had not been determined,
and the actual
leak rate of the
manway cover gaskets
had not been determined.
This appears
to be
a
violation of 10 CFR Part 50, Appendix B, Criterion XVI.
(Enforcement
Item 50-530/90-01-02).
Violation of Surveillance
Re uirement
To Perform
Emer enc
Diesel
enerator
G
ns ect)ons
urban
ant
ut own -
nit
3)
During this inspection period the inspector
noted that recent Unit 3
EDG inspections
recommended
by the manufacturer
were performed to
meet Technical Specification Surveillance
Requirement
(SR)
4.8. 1. 1.2. d. 1, but were not performed during unit shutdown
conditions
as required
by the
SR.
This is an apparent violation of
the
SR (Enforcement
Item 530/91-01-01).
The licensee
performed
some inspections with the unit operating
because
the required
18-month surveillance intervals would have
expired prior to the next refueling outage in March 1991.
In
addition, with the manufacturer's
concurrence,
the licensee
waived
several
of the required mechanical
inspections until the refueling
outage,
as justified in Engineering Evaluation Request
90-DG-07.
The
SR allows the
EDG manufacturer to specify the required
inspections.
The
SR specifies to perform the manufacturer's
recommended
inspections "at least
once per 18 months during shutdown."
The
licensee
meets this requirement
by implementing two Surveillance
Test (ST) procedures,
31ST-9DGOl (for the mechanical
inspections)
and 32ST-9PE01 (for the electrical
generator
inspections).
In
addition, the manufacturer's
recommended
18-month instrumentation
calibrations
and air filter replacements
are performed
by preventive
18
maintenance
tasks.
The inspector also noted that among the manufacturer's
recommended
"annual" inspections
is a task to perform diesel
generator
instrument calibrations.
These calibrations
are covered
by the
licensee's
PM program.
However, the
PM program specified
a
'~g outage
frequency for these calibrations.
This is
inconsistent with the manufacturer's
recommended
"annual" inspection
interval (allowed by the manufacturer to be
12 to 18 months),
especial> lv when prolonged outages
extend the operating cycle.
The
licensee
should determine the required frequency for the instrument
calibrations
and appropriately reflect the frequency in the
scheduling
system.
The licensee
acknowledged
the inspector's
findings at the exit
meeting
and stated that they had determined that performance
of EDG
inspections for SR 4.8. l. 1.2.d.1 with the unit operating at power
was
a reportable
event per 10 CFR 50.73.
In addition, the licensee
committed to the following:
1)
A review of this and other Technical Specifications
surveillance
requirements
which require specified plant
conditions to ensure
they are being properly scheduled
and
performed in accordance
with these
requirements.
2)
A review of the scheduling of EDG instrumentation calibration
PM tasks to ensure
manufacturer's
recommended
intervals are
met.
3)
A review of all
PM tasks
being used to meet surveillance
requirements
to ensure that the required tests
and
verifications are scheduled
and performed within specified
surveillance
intervals.
The licensee
stated that their review would be documented
in
Incident Investigation Report 3-1-91-017A.
One violation of NRC requirements
was identified.
12.
Use of an
En ineerin
Evaluation
(EER
Re uest Not Formall
A
roved
- Unst
3
71707
On January
8, 1991, Unit 3 operations staff removed Spray
Pond
(SP)
Train "B" from service to restore
a temporary modification such that
normal
power cables for the spray
and bypass
valves could be
~
~
0
re-terminated.
Because
the Essential
Chi lier s (EC) use the
system
as
a heat sink, operators
also entered
the Action Statement
for EC train "B" inoperable
(Technical Specifications 3.7.6).
The
Action Statement
requires,
in part, that within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> normal
is verified to provide space cooling to train "B" ESF
rooms
served
by EC.
Earlier the operators
l.;," <<.~estioned
the ability of HVAC to
provide acceptable
cooling since the normal (nonessential)
chilled
water loop in the associated
Air Handling Unit (AHU) had recently
frozen and broken,
and was then isolated.
Operations,
including an
Operations
Supervisor,
were aware that an Engineering
Evaluation
Request
(EER) was being written to determine whether the broken
cooling coils would impact the ability to meet Technical
Specifications
requirements.
Based
on
a verbal discussion with the
final engineering
reviewer/approver,
and prior to his final review
and signature,
operations
proceeded
to remove the
and
EC trains
from service to complete the maintenance.
Subsequently,
the
EER was
approved
as written and specified certain temperature
limits,
outside of which would be required routine temperature
monitoring of
affected
ESF equipment, rooms.
The inspector questioned
the decision
making process
which used
an
EER which had not been formally approved for the following reasons.
1)
The maintenance
was planned,
but was discretionary.
There
was
no apparent
or compelling reason
why the train outage could not
wait for the final
EER disposition.
2)
Engineering
was
aware that the unapproved
EER was being
used
for the operations
decision.
Although the inspector did not
identify any weakness
in the final disposition,
in general
such
,practice
may result in pressur e to complete the document
as
written, without further critical review.
3)
The inspector
noted that in NRC Inspection Report 529/90-46
paragraph
10 a review was
made of an incorrect Night Order
issued
on the basis of a draft MNCR.
The
MNCR was later
changed
but the Night Order was not, causing initial confusion
on the part of operations staff responsible for ensuring the
provisions of the
MNCR were met.
The inspector
noted that management
decision making based
on
incomplete or unapproved
engineering
documents
is
uncommon at
but that it has
caused
confusion in the past
and potentially could
cause
more serious
problems.
The specific case referred to here
appears
not to have created
any problem, but if the practice
becomes
more prevalent it may lead to less than careful, thorough,
and
formal engineering
inputs to the decision making process.
Licensee
management
acknowledged
these
comments
and stated that
their intent was to include all appropriate
supporting
group inputs
to the management
decision making process,
and that such inputs
be
formal and complete
when appropriate.
No violations of NRC requirements
or deviations
were identified.
20
Potential for Small Break
LOCA Due to Tube
Ru ture in the Reactor
oo ant
um
ea
oo er -
n)ts
and
During review of NRC Information Notice No. 89-54 "Potential
Overpressurization
of the
Component Cooling Mater System,"
identified
a s::;;:."
in which a break in the reactor
coolant
pump
High Pressure
Seal
Coolers
(HPSC) could potentially result in a
(RCS) leak being released
outside of the
containment building.
The scenario
involves
a leak from the reactor
coolant
pump
HPSC into the lower pressure
Nuclear Cooling water
(NC)
system.
The resulting leak could potentially overpressurize
the
NC
system.
If this were to occur,
and the
NC containment isolation
valises were unable to shut against the pressure
or flow, and the
operators
were unable to identify the leaking seal
cooler and
isolate the leak with the seal
cooler isolation valves, it could
result in reactor coolant being discharged
from the
NC surge tank
relief valve on the auxiliary building roof.
APS performed
an
analysis of this scenario
and determined that continued operation is
justified.
This justification was documented
in a JCO sent to the
NRC on January
18,
1991 (letter 161-03709-MFC/JST).
This
JCO is being reviewed by the
NRC (Followup Item
528/91-01"03).
No violations of NRC requirements
or deviations
were identified.
Probablistic
Risk Assessment
- Units 1
2
and
3
71707)
Pursuant to the requirements
of NRC Generic Letter 88-20 to perform
an Individual Plant Examination of the relative risks of plant
and equipment malfunctions to the overall probabilistic
risk of core
damage,
the licensee
determined, preliminarily, that
event
sequences
leading to a loss of the "A" 125 vdc Class lE bus
contributed over 80 percent of the total core
damage
frequency
(CDF).
The
APS engineering
group responsible for this probabilistic
risk analysis
(PRA) presented their preliminary results to licensee
management
in May 1990.
Management
was informed that conceptual
engineering
work was
underway to determine the best design
changes
to mitigate the severity of these
sequences.
Although the
preliminary overall
CDF was only 0.001 per reactor year {one core
damage
event expected within 1000 years of operation),
elimination
of this event sequence
was expected to reduce the
CDF by nearly
a
factor of 10.
However, in November 1990, the licensee
Plant
Modifications Committee
(PMC) reviewed the Plant
Change
Requests
which resulted
from the conceptual
engineering
work and,
although
they were approved for detailed engineering
design work in 1991,
they were given
a low priority.
However, in February
1991 following
a presentation
of this event
sequence
to plant operations staff, the
priority was increased
and engineering
design work commenced
immediately.
The inspector
noted the reason for the large contribution to the
was primarily that loss of this
DC bus caused
closure of main steam
and feedwater isolation valves
and initial loss of control power for
21
two out of three auxiliary feedwater
pumps.
This leaves
the only
remotely controlled source of feedwater
to be the "B" auxiliary
pump, since all normal
feed sources
are isolated
by the
closure of the Feedwater
isolation valves.
While the probability of
the "B" auxiliary feedwater
pump being out of service is small, this
potential
could result in a total loss of all feedwater
and is
consequently
a ~ip~ f'J)F ~ask due to the sensitivity of the
design to total loss ot ieeawater with no primary power operated
relief valves.
While the licensee
proceeds
with engineering
design work on plant
changes
to mitigate this event sequence,
the licensee
has stated
that current
Emergency Operating
Procedures will provide sufficient
guidance
for operators
to take manual control of the failed motor
driven auxiliary feedwater
pump and the failed closed valves in its
flowpath.
The inspector noted that general
guidance exists in the
Functional
Recovery Procedures
for the condition of loss of all
and consists primarily of instructions to gain manual
control of available
pumps
and flowpaths.
The abnormal
operating
procedure. for loss of DC bus "A" assumes
the "B" auxiliary feedwater
pump remains available
and therefore
gives
no guidance for manual
restoration of unavailable
The licensee
is
evaluating further procedural
and maintenance
policy changes
as
compensatory
measures
until design
changes
are final. It is
expected that these
changes
would reduce the risk of AFW
unavailability should this event occur,
as well as provide operators
with better guidance
recovering
from the worst case
scenario (i.e.
loss of DC bus with loss of all feedwater).
No violations of NRC requirments
or deviations
were identified.
Plant Review Board Activities
During the inspection,
the inspector
questioned
an observation that
the Plant Review Board
(PRB) had not reviewed
a revised
administrative procedure.
Discussions with the licensee identified
that the Technical Specifications, for each unit had been
amended
such that
PRB review of administrative
procedures
and changes
was
no
longer required.
In addition, the inspector
reviewed the procedure in question
(01PR-DAP01; Administrative Controls Program).
The inspector
questioned
the intent of a step regarding the issuance
of letters,
memoranda,
and orders to provide management
guidance
on a temporary
basis.
The intent was discussed
with licensee
personnel.
The
inspector found that while the wording of step 3.7.6
was consistent
with ANSI N18.7 (1976), the wording was not clear with regard to the
limitations of use.
The licensee
agreed to evaluate
the wording and
revise,
as necessary.
No violations of NRC requirements
or deviations
were identified.
22
16.
Review of Licensee
Event
Re orts - Units
1
2 and
3 (92700)
The following LER was reviewed
by the Resident
Inspectors.
Unit 1
528/89-18-LO/Ll (Closed
- "Henr
Pratt
Com an
Valve Failures"
- Units 1
2
and
3
This event is described
and reviewed in paragraph
2.C.5 of this
inspection report.
Based
on this review, this
LER is closed.
17.
~Ei
5h
The inspectors
met with licensee
management
representatives
periodically during the inspection
and held an exit meeting
on
February
21,
1991.
The licensee
did not identify as proprietary
any
materials provided to or reviewed
by the inspectors
during the
inspection.