ML17306A275
| ML17306A275 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 11/08/1991 |
| From: | Koltay P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17306A273 | List: |
| References | |
| 50-528-91-35, 50-529-91-35, 50-530-91-35, NUDOCS 9111260173 | |
| Download: ML17306A275 (51) | |
See also: IR 05000528/1991035
Text
Re ort Nos.
Docket Nos.
License
Nos.
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
50-528/91-35,
50-529/91-35,
and 50-530/91-35
50-528,
50-529,
and 50-530
and NPF-74
Licensee
Facilit
Name
Arizona Public Service
Company
P.
0.
Box 53999, Station
9012
Phoenix,
AZ 85072-3999
d
t
d
d
d
t
d
tt
d dt tt
Units 1, 2,
and
3
Ins ection Conducted
September
8 through October 12,
1991
A
roved
B
o tay,
ie
Reactor Projects
Section II
pg
c(
a e'gne
Ins ectors
D.
Coe,
F. Ringwald,
J.
Sloan,
M. Young,
M. Ang,
Senior
Resident
Inspector
Resident
Inspector
Resident
Inspector
Resident
Inspector
Project Inspector,
Region
V
Ins ection
Summar
Ins ection
on
Se tember
8 throu
h October
12
1991
(Re ort Numbers
an
Areas Ins ected
Routine, onsite,
regular
and backshift inspection
by
our res)
en
inspectors,
and
one inspector
from the Region
V staff.
Areas
inspected
included:
previously identified items; review of plant activities;
engineered
safety feature
system walkdowns - Units 1, 2,
and 3; surveillance
testing - Units 1, 2,
and 3; plant maintenance
- Units 1, 2,
and 3; reactor
trip and main steam isolation system
(MSIS) actuation - Unit 1; preparations
for refueling - Unit 2; unescorted visitor - Unit 2; scaffolding deficiencies
- Unit 2; worker responsibility - Unit 2; main steam safety valve
(MSSV)
setpoint testing - Unit 2; undersized
welds - Unit 2; equipment qualification
audit review - Units 1, 2,
and 3; employee
concerns
program activities-
Units 1, 2,
and 3; review of employee qualifications - 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:
35502,
35702,
41500,
60705,
61726,
62703,, 71707,
71710,
92700,
92701,
92702,
and 93702,
9lli2hOi73 9iii08
ADQCK 05000528
G
)
I
!
-2-
Results
Of the
16 areas
inspected,
one non-cited
and
one cited violation
were ~Bentified.
The cited violation pertained to the loss of control
over
an escorted visitor in Unit 2 (paragraph
9),
and the non-cited violation
pertained to deficient surveillance test procedures
used in Units', 2,
and
3
(paragraph
4).,
General
Conclusions
and
S ecific Findin
s
Si nificant Safet
Matters
None
Summar
of Violations
Summar
of Deviations
0 en Items
Summar
Stren ths Noted
1
Non-Cited Violation - Units 1, 2,
and
3
1
Cited Violation - Unit 2
None
ll items closed,
8 items left open,
and
3 new items opened.
The licensee's
self assessment
program identified several
weaknesses
in their
environment qualifications
(Eg) program through the use of a gA audit.
Also,
a
QC person with welding experience identified an inadequate
existing weld on
a charging
pump line during observation of unrelated
maintenance.
Meaknesses
Noted
The quality of engineering
work was found weak in two areas.
First was the
recent incorporation of surveillance test criteria, which were slightly
non-conservative
with respect to Technical Specifications.
Second,
a scaffold
was found contacting
a safety-related
cable tray support without an engineering
analysis that approved the configuration.
i
DETAILS
Persons
Contacted
The below listed technical
and supervisory personnel
were
among those
contacted:
Arizona Public Service
(APS)
~R.
Adney,
J.
N. Bailey,
"D. Blackson,
- T. Bradish,
R.
Cherba,
~A. Fakhar,
"R. Flood,
J.
Fogarty,
- D. Fuller,
"R. Fullmer,
D.
Gouge,
"S. Guthrie,
- M. Ide,
J.
Levine,
~D. Mauldin,
- J. Minnicks,
G. Overbeck,
~L. Perea,
~R.
Rouse,
- R. Prabhakar,
C.
Russo,
R. Schaller,
T. Schriver,
J. Scott,
J. Scott,
- R. Stevens,
- J. Thompson,
Plant Manager,
Unit 3
Vice Pres ident,
Nuc 1 ear
Sa fety
8 Licens i ng
(NS8 L)
Manager,
Central
Maintenance
Manager,
Compliance
Manager, Quality Systems
Supervisor,
Site Nuclear Engineering
8 Construction
Plant Manager,
Unit 2
Manager,
Mork Control Unit 2
Manager,
Chemistry Unit 1
Manager, Quality Audits and Monitoring
Manager,
Plant Support
and (Chairman Plant
Review Bd.)
Dep. Director, Nuclear Safety
Plant Manager,
Unit 1
Vice President,
Nuclear
Power Production
Manager, Site Maintenance
Manager,
Maintenance
Unit 3
Site Director, Technical
Support
(STS)
Technical Asst., Technical
Support
Supervisor,
Compliance
Manager, Quality Engineering
Manager, Quality Control
(QA/QC)
Manager, Assistant Plant Unit 1
Manager, Assistant Plant Unit 2
Manager, Assistant Plant Unit 3
General
Manager,
Chemistry
Director, Licensing
8 Compliance
Tech. Asst., Plant Standards
The inspectors
also talked with other licensee
and contractor personnel
during the course of the inspection.
"Personnel
in attendance
at the Exit meeting held with the
NRC Resident
Inspectors
on October 17,
1991.
In addition,
M. Ang, Region
V NRC Inspector,
met with licensee
representatives
on October ll, 1991, for an exit briefing.
The results
of his inspection
are included in this report.
I
0
2.
Prey ious 1
Identi fied Items - Units
1
2
and
3 (92701
and 92702)
Unit 1
(0 en) Enforcement
Item (528/90-20-02):
"Post-Accident
Sam lin
s
em
ver- ressunza
>on
-
ni
2.
This event involved the overpressurization
of the
PASS system
due
to miscommunication
leading to a valve misalignment.
All immediate
corrective actions
were complete.
This item has
been left open to
evaluate
the completion of the commitment in the response
to the
notice of violation to evaluate "...the adequacy of administrative
controls for formal communications for non-operations
department
personnel
manipulating plant equipment at the
PVNGS."
The
licensee
s initial evaluation included the Chemistry Department.
The inspector
questioned
whether this evaluation should
be expanded
to other non-operations
department
personnel.
This question
resulted in a subsequent
evaluation which identified additional
non-operations
groups which manipulate plant equipment
and required
the revision of applicable procedures
to more f'ormally control
communications
during these activities.
Subsequent
to this
additional evaluation,
the inspector identified that Component
and
Specialty Engineering personnel
who perform local leak rate testing
on electrical penetrations
and other non-fluid components
also
manipulate plant components
outside the boundary of a clearance.
The inspector then questioned
whether all non-operations
groups
which manipulate plant components
have
been identified.
The
licensee
is considering this question.
This item will remain
open
pending the completion of this evaluation.
(Closed)
Followu
Item (528/90-20-04):
"Inadvertent
Shutdown
oo
1n
ass
-
nl
This item involved bypass
flow through valves SI-HV-690/691,
resulting from a design wherein the motor operator
may not always
drive the disc into its seat.
A limit switch indicates
the valve
is closed in the control
room when the disc reaches
five percent
open.
Thus, the operator
may release
the
hand switch prior to the
valve becoming fully shut.
Should this occur,
a portion of the
shutdown cooling flow to the reactor
vessel
would be bypassed
back
to the
pump suction without any indication of this in the control
room.
As an interim measure,
the licensee
revised procedures
"Shutdown Cooling Initiation," to require operators to manually
shut these
valves to ensure
they are fully closed.
However, in
Inspection
Report 528/91-01,
the inspector identified a discrepancy
between the interim fix and a recommendation in the Engineering
Evaluation Request,
90-SI-093, for abandonment
of manual
operation
of these
valves
due to the indeterminate
torque applied which could
result in overthrust or underthrust.
Since then, the licensee
has modified their revision to procedures
4XOP-XSI01 to require operators
after receiving
a closed
indication, to hold the hand swstch for five seconds
in the
"JOG
J
1
(
i ~
(
CLOSE" position to ensure that the valve is fully seated.
(Correspondingly,
the licensee
has initiated
a Motor Operated
Valve
Operating Guideline to preclude
problems associated
with overthrust
and underthrust resulting from manual
operation of valves.)
The
inspector
concluded that the interim measure
is consistent with the
recommendation
in the
EER for abandonment
of manual
operation of
val ves SI-HV-690/691.
Further,
as long-term corrective action, the licensee
is pursuing
action via PCR-90-SI-13-051
which recommends
modification of the
control logic of the valve design
such that the limit switch (which
provides indication) and the torque switch (which disengages
the
motor operator)
perform in parallel
when the valve is
a maximum of
one percent
open (instead of current five percent).
This
modification is scheduled
to be implemented durinq the fourth
refueling outage for all three units.
This item ss closed.
(0 en) Followu
Item (528/91-15-01):
"Limitor ue Grease
Ins ection
e uac
-
n>
This event involved identified deficiencies in the licensee's
Limitorque grease
inspection
program.
The inspector
reviewed
completed Incident Investigation Report (IIR) 9-1-0064 (formerly
3-3-91-018).
The IIR had
a list of conclusions
but no action plan
to implement these
conclusions.
The licensee
indicated that each
conclusion will be addressed
by specific actions
and
a Commitment
Action Tracking System
(CATS) item will be generated for each item.
The inspector
noted that
a general
CATS item exists,
but specific
CATS items for each conclusion
have not yet been created.
The
licensee
stated that these
CATS items are being created.
The
inspector
concluded that while this IIR appears
to adequately
address
grease
requirements
from a lubrication standpoint,
grease
requirements
from an Equipment Qualification (EQ) standpoint still
appear to be unclear.
This item will remain
open pending
resolution of this
EQ aspect.
(Closed) Violation (528/91-26-03):
"Failure to Pro erl
Perform
a
urvei
ance
es
-
n>
This item addresses
corrective actions resulting from the failure
to properly perform
a verification step for the Core Protection
Calculator
(CPC) addressable
constants
changed
during Surveillance
Test (ST) 77ST-lSB08,
"CPC Channel
"B" Functional Test."
The
licensee
determined that the event
was caused
by inattention to
detail
by the test performer and
a reactor operator.
In addition
to the administration of discipline in accordance
with the
licensee
s Positive Discipline Program,
changes
were
made to this
procedure
and to two other procedures
to require independent
verification of the proper
changes.
Additionally, a change to the
CPC Addressable
Constants
Log form was initiated to improve it from
a human factors standpoint to more clearly indicate the correct
value to be set in the
CPC.
II
I
0
The inspector
concluded that the licensee's
corrective actions
and
actions to prevent recurrence
were adequate.
This item is closed.
Unit 3
(0 en) Enforcement
Item (530/91-01-01):
"Diesel Generator
ns
ec ion
urve>
ances
o
er orme
urban
u
own
nest
This item identified that the licensee
had not adhered to the
TS
Surveillance
Requirement
(SR) 4. 8. l.l. 2. d. 1 which required
(EDG) inspections
to be performed with
the unit shutdown.
Licensee
LER 1-91-002 reported
occasions
when
these
inspections
were performed with the unit at power.
The
licensee's
response
to the Notice of Violation included identifying
other Technical Specification
SRs which are required to be
performed only when the unit is shutdown
and initiating procedure
changes
to add precautions
in the appropriate
surveillance tests.
The inspector also reviewed the licensee's
Incident Investigation
Report (IIR) 3-1-91-017A on this issue.
Based
on this review, the
inspector
concluded that the corrective actions
noted
above
were
appropriate.
The inspector
noted that the IIR also addressed
the
question of what vendor
recommended
inspections
were required
pursuant to
SR 4. 8. 1. l. 2. d, 1.
The IIR concluded that
APS had
previously excluded
from the Surveillance Test (ST) program several
items from the vendor
annual
inspection list, choosing
instead to
use the corrective
and preventive maintenance
programs to
accomplish
these
items.
One of these
items
was for checking the "operation
and calibration
of all [EDGj control
and safety
shutdown devices."
The IIR noted
that, of the three safety
shutdown trip devices active during the
emergency
run mode of operation,
two of them were Preventive
Maintenance
(PM) tasks with frequency of 1R (refueling), allowed to
extend
up to three years.
One of the IIR conclusions
was to reduce
this interval to 18 months in accordance
with the vendor's
recommendations.
Due to the safety significance of the proper
calibration of these
devices,
the inspector
reviewed the
PM history
for several
of them and determined that one device,
a Unit 1
generator differential relay,
had not been calibrated in over
two years,
and currently did not have
an evaluation
signed
by the
Plant Manager allowing extension of the
PM interval,
as is required
by the licensee's
PM program.
Based
on this observation
the
licensee initiated Condition Report/Disposition
Request
(CRDR)
9-1-0200 to assess
the cause of this condition.
This open item
will remain
open until the licensee
completes their eva'iuation.
The inspector further noted that the IIR acknowledged that there
was
no documented
basis for excluding certain vendor required
inspections
from the
ST program.
The inspector
encouraged
the
licensee to reconsider
the technical
and safety significance basis
I'
for treating certain vendor requirements
as
PMs rather than
STs.
The licensee
indicated that the
CRDR would re-examine this basis.
(0 en) Followu
Item (530/91-19-03):
"Mestin house
ARD Rela
al ure
-
ns
This item involved the failure of a Westinghouse
ARD 660-UR relay,
the associated
10 CFR Part 21 report,
and other failures.
The
licensee
has not completed
Engineering Evaluation
Requests
(EERs)
91-ZA-016 or 01-ZA-033, which include the root cause
of failure
evaluation for these
relays.
This item will remain
open
until the inspector
can review these
EERs.
(Closed)
Followu
Item (530/91-26-01):
"Overvolta
e of the A-C
o)nc>
ence
a rex
ower
u
nl
This item involved an overvoltage condition of the A-C coincidence
matrix power supply PS-12 during testing.
Troubleshooting
was
inconclusive
and the power supply
has performed properly since this
event.
The licensee
has
issued
a work order to replace this power
supply during the next outage.
The inspector
concluded that this
is prudent.
This item is closed.
Units 1
2
and
3
(Closed)
Followu
Item (528/90-42-03):
"Startu
Transformer
oa
1n
-
n>
s
an
This item involves verifying the implementation of changes
to
procedure
4XOP-XNAOl, "13.8
KV Electrical
System (NA)," which were
made
as
a result of an
NRC Electrical Distribution Safety
Functional
Inspection
(EDSFI) observation that the startup
transformers
could be inadvertently overloaded.
This condition
could result from two units sharing the
same startup transformer
secondary windings,
and could
come without warning if an automatic
bus transfer occurs.
The
EDSFI (Inspection
Report 528/90-42,
Paragraph
2.4) considered that the licensee's
proposed
method of
limitinq loads
was acceptable.
This method includes blocking the
automatic transfer for the non-Class
lE loads of the unit whose
loads would have
been
connected
to their alternate
startup
transformer,
and monitoring loads
on the startup transformer
when
it is loaded
by more than
one unit.
The inspector
reviewed the changes
to the procedure.
The changes
appeared
to address
the monitoring, blocking,
and loading
requirements
and methods in detail,
and adequately
implemented the
methodology previously found acceptable
by the EDSFI.
The changes
were implemented
on December
14,
1990.
The inspector also
confirmed during a startup transformer
NAN-X02 outage that the
automatic transfer
was blocked
as required,
and that the Unit 3
Shift Supervisor
was aware of the loading requirements.
Based
on
this review, this item is closed.
(Closed) Violation (528/90-42-06):
"Failure to Per form Maintenance
n
ae
eae
anes
-
n>
s
an
This violation resulted
from failure to implement written
procedures
for the performance
of vendor
recommended
Preventive
Maintenance
(PM) on class
1E load centers
D25,
D26,
D27,
and
D28.
The licensee
scheduled
the
PM to be accomplished
every third
refueling outage.
The vendor recommendation
was for annual
performance.
The
PM tasks
had been prepared
but were not approved
or implemented at the time since the
PMs were not due.
The licensee initially revised the scheduled
PM frequency to once
per refueling.
Additionally, these
and other
PM tasks
were already
being reviewed
as part of a major
PM task force project,
scheduled
for completion
by December
31,
1991.
Further adjustments
to the
scope
and frequency for these
components
resulted
from these task
force recommendations.
The annual
PM addressed
in the violation
had been reassigned
a frequency of once
per three refuelings,
and
the twelve week
PM mentioned in Inspection
Report 528/90-42
(Paragraph
4.3) has
been
enhanced
to include thermography
and
has
been
reassigned
a frequency of once per refueling.
These
changes
were justified on the basis of the maintenance
history, the
controlled environment in which these
panels
are located,
the
operational risk of maintenance
on these
panels while the unit is
on line,
and the scope of other
PMs associated
with these
panels.
The inspector
concluded that the licensee's
corrective actions
appear
adequate.
This item is closed.
(Closed)
Unresolved
Item (528/90-46-01):
"Essential Chiller
e ri eran
eve
era i
s
)ms
s
-
ns
s
an
92701)
This item involves the licensee's
efforts to determine
the
refrigerant level range in which the essential
chillers are
Currently no such
range
has
been determined.
In June,
1991,
the chiller vendor responded
to the licensee's
request for
information but declined to specify
a refrigerant level range,
other than the design
optimum levels, in which the chiller would be
capable of supplying cooling demands
from none to the full design
load.
The vendor dsd present technical
considerations
affected
by
operation at high and low refrigerant levels.
The licensee's
weekly Preventive
Maintenance
(PM) task
(No. 039874)
to monitor operating parameters
under established
standard
conditions
does specify
a required
range (specific to each chiller,
but based
on the
same refrigerant charge),
and instructs the worker
to notify the shift supervisor,
the
HVAC foreman,
and the
responsible
Systems
Engineer
(SE) of all readings
outside the
required
range.
However, the chi llers have not been declared
on the basis of readings
outside the required
range.
The
SE does
not evaluate
these
readings
to determine operability,
since there is no technical
basis for the evaluation.
The inspector
reviewed the
PM data
sheets
and found three
occasions,
one in each unit, in which the refrigerant levels
required adjustment to be restored to the required
band since this
Unresolved
Item was identified in November 1990.
These
are
documented
in Work Orders
(WOs) 455240 (Unit 1
December
18, 1990),
WO 462238 (Unit 2 - February 1, 1991),
and
WO 491622 (Unit 3-
May 9, 1991).
A review of the associated
Unit Logs indicates that
the Essential
Chilled Water loops were not declared
on
any of these
occasions,
though because
Unit 3 was not in Modes
1
though
4 at the time, operability was not required.
The
EC system is required to be operable to support the operability
of other important safety equipment,
including the auxiliary
system
and the Emergency
Core Cooling Systems.
It did
not appear that this issue
was being aggressively
addressed,
as
no
action
had been taken since the licensee
received the vendor's
reply in June,
1991.
This was discussed
with licensee
management,
who committed to regard the required
range specified in the
PM task
as the operable
band,
though at a later time the band
may be
enlarged if justified.
The licensee
committed to revise the
task to clarify this position, to ensure that the Shift Supervisor
was notified as
soon
as
a reading outside the band is identified,
and to document in the
PM work order the as-found readings
and any
corrective action taken.
Based
on these
licensee
commitments, this
item is closed.
(0 en) Followu
Item (528/91-04-02):
"Undervolta
e Rela
Testin "-
nl
s
an
This item involved evaluation of the method
used to test the timing
of Agastat relays in the undervoltage
and low voltage monitoring
circuitry for the 4160 volt Class
1E buses
PBA-S03 and
PBB-S04.
The licensee
had committed to revise the previous test method
because it allowed repetitive testing of the relays,
which in
effect preconditioned
them, potentially giving false assurance
of
their ability to perform their required safety function.
The inspector
reviewed the revised procedure,
"Surveillance Test Procedures
for the Class
4160
Bus Undervoltage
Protective Relays."
The Surveillance
Test (ST) method
was
changed
such that the relays were evaluated
against the acceptance
criteria
on the first actuation,
and repeated
tests
were not allowed.
The
inspector
concluded that this aspect of the test
was adequate.
During a review of the undervoltage
and low voltage acceptance
criteria, which had been
changed during the procedure
revision, the
inspector
determined that both the
new and the old acceptance
criteria were slightly non-conservative
with respect to the
Technical Specifications
(TS) surveillance
requirements.
The
licensee
confirmed this and initiated Condition Report/Disposition
Request
(CRDR) 9-1-0144 to evaluate this condition.
The licensee
confirmed that the relay setpoints actually set or verified during
the most recent
ST performances
are
above the minimum values
specified in the TS.
The licensee
determined that the relays were
l
l
(
I
never non-conservatively
set.
The acceptance
criteria and
requirements
are
summarized
as follows:
TS
Table 3.3-4
Rev.
4
Rev.
5
Loss of Voltage:
> or = 3250
> or = 92.85
> or = 92.8
(3249.75
on bus)
(3248 on bus)
Degraded
Voltage:
83.7 - 106.9
(2929.5-
3741.5)
2930 - 3744
83.7 - 106.97
(2929.5-
3743. 95)
The procedure
gives the acceptance
criteria in voltage
on the
secondary
side of a 4200: 120 volt potential transformer.
Bus
voltages,
shown in parentheses,
are not provided in the
procedure.
The inspector
noted that errors in the acceptance
criteria were not
identified during review and approval of the revisions to the
surveillance
procedure.
The procedure
was reviewed
by the
Procedure
Review Group and was approved
by the Manager,
Plant
Standards.
The critical technical
review of procedures
affecting
safety is essential
to safe operation of the plant,
and the
inspector considers this error serious
because
the process failed
to prevent the erroneous
procedure
from being implemented.
In this
case
the error was not large in magnitude
and actual
setpoints
are
satisfactory,
so the safety significance is minimal.
However, this
indicates
a weakness
in the quality of engineering
support.
The failure to accurately translate
TS surveillance
requirements
into ST procedures
appears
to be in violation of NRC requirements.
The violation is not being cited because
the criteria specified in
Section V.A. of the Enforcement Policy were satisfied
(NCV
528/91-35-01).
The inspector
noted that
PCN 2 to Revision
5 of the
ST corrected
the
Loss of Voltage limit, but not the Degraded Voltage limits.
In response
to thss observation,
the licensee
submitted Instruction
Change
Request
24260 to change
the Degraded Voltage range to 85.0-
106. 9 volts (2975 - 3741. 5 volts), consistent with the
TS.
The ST, apparently consistent with the
TS
allows the Degraded
Voltage setpoint
(70 percent - 90 percent] to be set wel'I below the
Loss of Voltage setpoint
(78 percent).
This does not appear
consistent with the Updated Final Safety Analysis Report
(UFSAR) or
the Safety Evaluation Report
(SER), which both specify
a 90 percent
Degraded Voltage setpoint.
The licensee
is evaluating appropriate
changes
to the TS,
and is currently setting the Degraded
Voltage
relays
near the upper
end of the allowed range.
The inspector
encouraged
the licensee to continue that practice until the
licensee
resolves
the licensing basis for this setpoint.
This item
will remain
open pending completion of the licensee's
evaluation,
being documented
in
CRDR 9-1-0144.
5.
(0 en) Violation (528/91-04-04):
"Control of Motor 0 crated Valve
esl
n
n orma
1on
-
ns
s
an
This violation resulted
from the failure to maintain. design
documents
updated.
The licensee's
corrective
actions
included
deleting the Motor Operated
Valve
(MOV) torque switch settings
(thrust limits) from the design output documents.
This design
information is now being controlled by use of Engineering
Evaluation
Requests
(EERs) instead of the design drawing.
This
appears
to represent
less rigorous control than that required for
design information,
and was questioned
by the inspector.
Corrective Action Report
(CAR) 91-0021
was issued to address
this
programmatic conflict.
The initial response
by Engineering
was
found unacceptable
the equality Assurance
organization.
The revised
response
from Engineerinq,
which was overdue,
was not yet available
for review.
This item will remain
open pending review of the
completed
and accepted
response
to
(Closed)
NRC Information Notice (IN-91-13): "Inade uate Testin
of
mer enc
iese
enera
ors
s
-
nl
s
This item involved the adequacy of
EDG test conditions with regard
to worst-case
loads
and ambient temperatures
during testing,
and
appropriate
load shedding considerations.
The licensee
evaluated
this in Corrective Action Tracking System
(CATS) Item 051261,
and
concluded that
EDG testing for Units 1, 2,
and
3 is adequate
with
regards to worst-case
emergency
loads
and conditions.
The
NRC EDSFI Report dated
December
1990 addressed
similar concerns
for adequate
margin for maximum loads during accident conditions.
In response
to these
concerns,
the licensee
revised the
EDG loading
calculation (Revision 6, dated April 18, 1991) to include power
factors
and loads
under worst-case
conditions.
The resultant
values for maximum loads
and limiting power factors are
bounded
by
Surveillance Test Procedure
73ST-XDG01/02 (Integrated
Safeguards
Testing).
With outside
ambient temperatures
exceeding
113 degrees
F within
the last year (outside that assumed for the site in the
UFSAR), the
licensee initiated Engineering Evaluation
Request
(EER) 90-HC-017
to evaluate
the validity of the ambient temperatures
assumed
in the
EDG design.
The licensee
concluded that the standing calculations
are valid provided temperatures
greater
than
113 degrees
F do not
ersist for a period of time exceeding
0.5 percent of the year.
inally, load shedding is tested per 73ST-XDG01/02 and verified
through
a sequence
of events
recorder.
The licensee
has
concluded
that this test procedure
provides the operators with sufficient
information to allow them to load the
EDGs to simulate worst-case
conditions.
This item is closed.
One non-cited violation of NRC requirements
was identified
(Paragraph 2.c.4.).
10
3.
Review of Plant Activities (71707
and 93702)
Unit 1
b.
Unit 1 entered
the reporting period operating at 100 percent
power.
On September
14,
1991,
a Part-Length Control Element Assembly
(PLCEA) slipped partially into the core, forcing a power reduction.
During the power reduction,
the
No.
economizer valve failed open,
causing the steam generator
level to
increase until the reactor tripped and
a main steam isolation
actuation
occurred
(see
Paragraph
7).
The unit cooled
down to Mode
5 on September
17,
1991.
The economizer
valve positioner
was
replaced
and the cause of the slipped
CEA was corrected.
Other
maintenance
needs
included replacing the "dogbone seal"
between the
main turbine and the "C" condenser,
replacing the gaskets
on two
pressurizer
safety valves,
and repackinq other valves which were
contributing to an elevated
gaseous activity in the containment
building.
Following this maintenance,
the plant was heated
up,
reaching
Mode 4 on September
21 and
Mode
3 on September
22,
1991.
The reactor
was brought to criticality at 2:33 a.m.
on September
24,
and
Mode 1 was entered at 7:09 a.m.
The generator
was
synchronized to the grid at ll:07 a.m.
on September
24, 1991,
and
a
slow power ascension
was conducted.
The power ascension
was
interrupted at 65 percent
power to allow xenon to stabilize while
monitoring dose equivalent iodine.
Power was increased
to
100 percent
on September
28.
On October 7, 1991,
power was reduced
to about
68 percent to allow for inspection
and repair of the "A"
main feedwater
pump low pressure
steam inlet check valve.
The unit
was returned to 100 percent
power on October 8, 1991,
where it
remained until the end of the reporting period.
Unit 2
C.
Unit 2 operated at essentially
100 percent
power throughout this
reporting period.
Significant scheduled activities included main
steam safety valve setpoint testing
and fuel receipt for the
upcoming refueling outage.
Pressurizer
code safety relief valve
RCN-PSV-200 continued to exhibit apparent
seat
leakage, within the
technical specification limits.
Based
on Operations
and
Engineering Departments'valuations,
coordinated
compensatory
actions limited the rise in tail pipe and reactor drain tank
temperatures.
The plant experienced
sticking of No.
2 steam
generator
economizer
feed regulating valve,
SGN-FV-1122;
on
requiring prompt operator
manual action to control
level.
Maintenance
was able to make temporary repairs
and the
valve was returned to service.
Unit 3
Unit 3 remained at essentially
100 percent
power throughout this
reporting period.
j
11
d.
Plant Tours
The following plant areas
at Units 1, 2,
and
3 were toured by the
inspectors
during the inspection:
Auxiliary Building
Control
Complex Building
Diesel
Generator
Building
Fuel Building
Main Steam Support Structure
Radwaste
Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The
2.
3.
4
5.
following areas
were observed
during the tours:
0 eratin
Lo s and Records - Records
were reviewed against
ec naca
peel
)ca lons and administrative control procedure
requirements.
Monitorin
Instrumentation - Process
instruments
were observed
or corre at>on
etween
c annels
and for conformance with
Technical Specifications
requirements.
Shift Staffin
- Control
room and shift staffing were observed
or con ormance with 10 CFR Part 50.54.(k), Technical
Specifications,
and administrative procedures.
E ui ment Lineu
s - Various valves
and electrical
breakers
were ven ie
o be in the position or condition requi red by
Technical Specifications
and administrative
procedures
for the
applicable plant mode.
E ui ment Ta
in
- Selected
equipment, for which tagging
reques
s
a
een initiated,
was observed to verify that tags
were in place
and the equipment
was in the condition
specified.
General
Plant
E ui ment Conditions - Plant equipment
was
o serve
or )n >ca sons
o
sys
em leakage,
improper
lubrication,
or other conditions that could prevent the
systems
from fulfillingtheir functional requirements.
The inspector
noted two occasions
in which the turbine
outboard bearing oil level in the Unit 3 turbine driven
(AFM) pump was about 1/8 inch above the
upper mark in the sight glass.
This is the fourth time in one
year that
a high level indication was observed
by the
NRC,
indicating that the licensee
has not yet identified the root
cause of this condition.
In each
case,
the licensee
restored
the level to within the band.
The licensee
has previously
determined that oil level discrepancies
such
as these
would
not affect the operability of the pumps.
The inspector
encouraged
the licensee to give more attention to this issue.
12
The inspector
noted that the general
conditions in the Unit 2
AFW pump rooms, including the pumps,
though acceptable,
reflect
a lower level of maintenance
attention than the
conditions in Units 1 and 3.
The inspector
noted rust
on the
pump pedestals
and indications of small active oil leaks.
A
pool of oil had accumulated
on the pedestal
of the turbine
driven pump.
The inspector
concluded that these deficiencies
did not appear to affect operability of the
pumps.
The
licensee
responded that the
pumps
and pedestals
were scheduled
for refurbishment during the coming Unit 2 refueling outage.
7.
Fire Protection - Fire fighting equipment
and controls were
f
ithT hi
1Sp i(i ti
d
admi nistrati ve procedures.
8.
Plant Chemistr
- Chemical analysis results
were reviewed for
con ormance
ws
h Technical Specifications
and administrative
control procedures.
9.
~Secor'it
Activities observed for conformance with regulatory
requirements,
the site security plan,
and administrative
procedures
included vehicle and personnel
access,
and
protected
and vital area integrity.
10.
Plant Housekee
in
- Plant conditions
and material/equipment
s orage
were
o served to determine
the general
state of
cleanliness
and housekeeping.
11.
Radiation Protection Controls - Areas observed
included
con ro
po)n
opera )on, records of licensee
surveys within
the Radiological Controlled Areas
(RCA), posting of radiation
and high radiation areas,
compliance with Radiation
Exposure
Permits
(REP), proper wearing of personnel
monitoring devices,
and personnel
frisking practices.
No violations of NRC requirements
or deviations
were identified.
4.
En ineered Safet
Feature
(ESF)
S stem Walkdowns - Unit 2 (71710)
An inspection of the Unit 2
Low Pressure
Safety Injection (LPSI) system
was performed to verify system lineup, configuration and equipment
condition on a sampling basis.
A representative
sample of LPSI
equipment
and piping were inspected
in the Auxiliary Building, the pipe
chase,
the refueling water tank
(RWT) area
and in the control
room.
The following conditions
were noted.
i
13
Valve Handwheel
"OPEN" Direction Arrows
The. handwheels
for manual
operation of the following motor operated
valves
had
"OPEN" direction arrows po'inting both in the clockwise
and counterclockwise directions
marked
on their handwheels:
2 CHA-HV 531,
2 CHB-HV 530,
and
2 SIB-HY 0307
In addition, the handwheel for the
LPSI pump discharge train "A"
manual isolation valve had
an
"OPEN" direction arrow pointing in
the clockwise direction which would be the shut direction for
normal opening valves.
The
"OPEN" direc'tion marking was
on the
bottom of the handwheel
indicating that the handwheel
may have
been
installed upside
down.
The inspector
looked at the stem position
and local valve position indication and noted that the valve
appeared
to be in the required
open position.
The inspector
informed the control
room Shift Supervisor of the
above
noted conditions
and stated that the valves should
be
confirmed to be in their required positions.
The inspector also
informed the Systems
Engineering Supervisor
and Compliance of the
observed conditions,
Systems
Engineering initiated Condition
Report/Disposition
Request
2-1-0130 to identify and correct the
noted condition.
The inspector also noted that
a similar condition
had
been previously noted,
and was discussed,
during the
December
1,
1989 Unit 3 Pre-restart
management
meeting
(NRC Meeting Report
89-55,
paragraph
3).
Pending further inspection of licensee
corrective actions,
the cond)tion was identified as Inspector
Follow-up Item 529/91-35-02.
Subsequently,
the licensee verified
that the subject valves were in their requbed positions.
Pi
e
Su
ort Observation
The inspector
noted that
a snubber type pipe support
2 SI 120
HOOG,
supporting the
LPSI pump miniflow recirculation line, was installed
approximately
5 feet from a pipe restraint that appeared
to
restrict pipe movement in the direction that the snubber
would
normally allow pipe movement for thermal
expansion of the piping.
The inspector
questioned
the installation
and discussed
the design
with Nuclear Engineerinq personnel.
The design personnel
confirmed
the inspectors
observation that the installat)on
was unusual
but
showed the inspector that the piping analysis
had considered
the
unusual installation
and determined it to be acceptable.
The
inspector
had
no further questions
regarding the observed condition.
Pi in
Confi uration
During the walkdown of the
LPSI pump supply piping, the inspector
noted that the piping was routed from the
RWT in the yard area,
through the pipe chase,
to the
LPSI pumps in the Auxiliary
Building and to containment penetrations,
but observed
no
intermediate piping anchors that would allow an analytical
subdivision of the piping analysis.
The inspector inquired
how
14
the varying seismic
response
spectra for the various locations
~ noted were taken into consideration
in the piping analysis.
The
licensee
stated that the subject pipi,ng had essentially
been
analyzed in two parts;
one stress
problem analyzed
the piping from
the
RWT to portions of the piping in the Auxiliary building and
a
second
analyzed the remainder of the piping utilizing a. structural
overlap modeling technique.
NUREG/CR-1980 provided
an
NRC approved
method for dynamic analysis of piping using
a structural
overlap
method that had been
benchmarked
and determined to have
conservatively
accounted
for or minimized the interaction
between
the subdivided parts of the stress
problem.
The inspector
requested
the licensee to inform the inspector, if the
NUREG was
not used,
what methodology
was
used for the overlap modeling
performed
and the basis for the acceptability of the modeling.
UFSAR section 3.9. 1.2. 1 indicates that
non-NSSS piping was analyzed
using
computer program,
ME 101, that
typically performs analysis
anchor to anchor.
The noted
section did not describe
an overlap modeling method for use with ME
101.
Nuclear Engineering piping analysis
personnel
stated that
they would determine
the methodology
used for the overlap modeling
for the subject piping analysis
and would determine
the basis for
acceptability of that methodology.
Pending the licensee's
evaluation of the noted condition and further
NRC inspection of the
licensee
s evaluation,
the condition was identified as Unresolved
Item 529/91-35-03.
No violations of NRC requirements
or deviations
were identified.
5.
Surveillance Testin
- Units 1
2
and
3 (61726)
a.
b.
Selected
surveillance tests
required to be performed
by the
Technical Specifications
(TS) were reviewed
on a sampling basis to
verify that:
1) the surveillance tests
were correctly included
on
the facility schedule;
2)
a technically adequate
procedure
existed
for performance of the surveillance tests;
3) the surveillance
tests
had been performed at the frequency specified in the TS;
and
4) test results satisfied
acceptance
criteria or were properly
dispositioned.
Specifically, portions of the following surveillances
were observed
by the inspectors
during this inspection period:
Unit 1
~roce
ure
Oescri tion
ESFAS Train "A" Subgroup
Relay Monthly Functional
Test
Unit 2
~roce
ure
40ST-9HF01
Descri tion
Log Power Functional Test
Engineered
Safety Feature
Pump
Room Air Exhaust
15
Fuel Building Essential
Ventilation System
Operabi l ity Test 4. 9. 12. a
Unit 3
~roce
ure
Descri tion
40ST-9HP02
73ST-9CL06
Log Power Functional
Test
Containment
Hydrogen Analyzer Functional Test
Diesel Generator
A" Test 4.8. 1. 1.2.A
Containment Ventilation Purge Isolation Valves (42
inches)
56
The inspector
observed
the performance of the Local
Leak Rate Test
(LLRT) on the Unit 3, 42-inch "containment purge valve CP-UV-2A.
The valve failed the test.
The inspector
noted that the valve
had
not been manipulated
since the previous
LLRT, which was successful.
Because this involves
a potential
degradation
of containment
integrity, the inspector will review the root cause of failure
evaluation being documented
in Condition Report/Disposition
Request
(CRDR) 3-1-0141 (Followup Item 530/91-35-04).
The inspector
noted minor discrepancies
during the performance of
"Log Power Functional Test."
These did not appear to
affect the validity of the surveillance test results.
The
discrepancies
were discussed
with appropriate
management
personnel.
The inspector
noted that the lead test performer
(ETP) did not meet
the minimum qualifications for this test although
a second test
performer did meet them.
I8C supervision
s expectation
in this
case
was that the
LTP be qualified but the licensee's
program only
requires
one of the test performers to be qualified.
Involved
personnel,
including the foreman,
were counseled.
The inspector
concluded that the licensee's
corrective actions
were adequate.
No violations of NRC requirements
or deviations
were identified.
6.
Plant Maintenance - Units 1
2
and
3 (62703)
a.
b.
During the inspection period,
the inspector
observed
and reviewed
selected
documentation
associated
with the maintenance
and problem
investigation activities listed below to verify compliance with
regulatory requirements,
compliance with administrative
and
ma)ntenance
procedures,
required equality Assurance/equality
Control
involvement, proper
use of safety taqs,
proper equipment alignment
and
use of jumpers,
personnel
qualif)cations,
and proper retesting.
The inspector verified that reportability for these activities was
correct.
Specifically, the inspector witnessed portions of the following
maintenance activities:
16
II it 2 ~ti t.i
o "8" Feed
Pump Oil Seal
Rework
o Instrument Air equality Preventive
Maintenance
o Troubleshoot/Repair
RU 142,
24 Volt Power
Supply
o Rack out "8" High Pressure
Safety Injection
Pump Breaker
o Troubleshoot/Repair
o Replace
on Pressurizer
PSVs
o "B'eater
Drain
Pump Seal
Repair
Following the observation of work on the Unit 1 pressurizer
safety
valves
by the Central
Maintenance
Department
on September
19, 1991,
the inspector verified the calibration of the tool used.
The tool,
a 100 to 500 foot-pound torque wrench,
was within the correct
calibration band;
however, it was not pre-functionally tested
as
required
by the recently implemented functional test program.
The inspector
noted that the licensee
had initiated a functional
test program that was aggressively
implemented at all three units
by their respective
Mechanical
Maintenance
Departments.
The
inspector also noted that the implementation of the functional test
program varied considerably
between the Central
Maintenance
Departments.
The work observed
on the Unit 1 pressurizer
safety
valves
had
no plans in place for implementation of the functional
test program at the time of the inspection.
Subsequent
discussions
were held with Site Maintenance
Management
to discuss
management
intent for the uniform implementation of the
functional test program.
Management
stated that the intent was
that this program
be consistently
implemented
among all departments
to the extent possible considering the availability of test
apparatus,
time,
and technicians
trained to use the apparatus.
Management
stated that the program
was being implemented
on a
staggered
basis - applying to the individual Units first, then to
central
maintenance.
The licensee
independently initiated this
functional test program which goes
above
and beyond the
requirements
for torque wrench calibration.
The inspector
concluded that such
a program is conducive to safety
and good
maintenance
practices
and when fully implemented will enhance
the
licensee's
maintenance
program.
2 it 2 ~ti ti
o 2EPKAH15
AC Input Breaker Appendix
R Test 32MT-9ZZ74
o Installation of Conduit Support in "A" DC Equipment
Room per
2-XJ-HJ-056
o Fuel Receipt Inspection
During the performance
of 32MT-9ZZ74, "Molded Case Breaker Test,"
on the Swing "A-C" Battery Charger
2-E-PKA-HF-15, the inspector
noted tie wraps missing from one phase of the
adjacent Train "A" battery charger
2-E-PKA-HF-11, compared to the
other two phases,
and compared to all three
phases
on
2-E-PKA-HF-15.
This resulted in one plastic spacer
being
potentially loose inside
a safety grade battery charger.
The
0
l
17
inspector
concluded that in some
cases
unrestrained
material
can
cause
degradation
of safety related
equipment.
At the exit the
licensee
acknowledged
the inspector's
comments
and the inspector
encouraged
the licensee to increase sensitivity in this area.
Unit 3 Descri tion
o Fire Barrier Malkdowns
o Adjust CPA-UV-2A Stop Nuts
o Repack
o Functionally Test Containment
Spray
Pump "A"
o Troubleshoot
Load Limit Potentiometer
on Main Turbine
o Troubleshoot
"B" Core Protection Calculator
o
PPS "B" Power Supply Replacement
Preparations
No violations of NRC requirements
or deviations
were identified.
Reactor Tri
and Main Steam Isolation
S stem
(MSIS) Actuation - Unit 1
an
A reactor trip and
MSIS occurred in Unit 1 on September
14,
1991, at
5:22 p.m.
(MST), after the
No.
economizer
control valve failed full open during a downpower transient.
The
reactor
was at 53K power at the time of the trip, which was caused
by
high level in the
No.
1 SG.
During the event, all safety equipment
actuated
as designed,
with the exception of the
No.
2
SG downcomer
blowdown valve, which failed to close.
However, this valve,
SGA-UV-227,
was previously
known to be faulty and was already isolated
sn accordance
with Technical Specification requirements.
The unit was stabilized in
Mode 3.
The downpower in progress
at the time of the event
was initiated because
a Part-Length Control
Element Assembly
(PLCEA) had slipped approximately
50 inches during routine
CEA surveillance testing at 3:Ol p.m.
The
licensee
was reducing power to less than
50 percent to satisfy
PLCEA
insertion limits requirements,
because
operators
were unable to restore
the slipped
PLCEA to within the group deviation limits.
A failed timer
circuit card in the Control
Element Drive Mechanism
(CEDM) Control
System
was found to have
caused
the slippage.
The inspector
noted that,
as allowed by procedure,
the
PLCEAs had not been tested with the other
CEAs earlier that week during the performance of a surveillance test
which monitors the
CEDM coils, since the
PLCEAs had been
moved during
the previous
week.
The licensee
is considering
a program enhancement
requiring coil traces of all
CEAs prior to performing
CEA operability
checks.
Condition Report/Disposition
Request
(CRDR) 1-1-0073
was initiated to
investigate this trip event,
including the Root Cause of Failure
(RCF)
of the economizer valve failure and the slipped
PLCEA.
A Notification of Unusual
Event
(NUE) was conservatively
declared
during
the event
and was terminated after verification that primary and
secondary
chemi stry parameters
were within expected
ranges.
18
Following the trip, the licensee
elected to cool
down to Mode
5 to
perform unrelated
maintenance.
Mode
5 was reached
on September
17,
1991.
Following completion of this maintenance,
the plant was heated
up, achieving
Mode
3 on September
22.
The reactor
was brought to
criticality at 2:33 a.m.
on September
24.
Mode 1 was entered at 7:09
a. m.
and the generator
was synchronized to the grid at 11: 07 a.m.
on
September
24,
1991
'uring
the power ascension,
(RCS)
Dose Equivalent
Iodine (DEI) was closely monitored because
an increasing trend prior to
the trip indicated increased
fuel defects.
An existing Justification
for Continued Operation
(JCO) requires
equi librium DEI to be less than
0.2 uCi/ml, and the value prior to the Unit 1 trip was
0. 17 uCi/ml.
The
licensee
implemented
an action plan addressing this issue,
including
taking actions to increase
the availability of all three charging
pumps
to maximize purification flow, putting
a freshly mixed resin
bed in the
delithiating ion exchanger,
and frequently sampling the
RCS for DEI
determination.
The power ascension
was interrupted at 65 percent
power
to allow xenon to stabilize near its equilibrium value to allow a better
determination of DEI.
Based
on the licensee's
analyses,
DEI did not
appear to be approaching
the
JCO limit in the short term, though it
might become limiting before the end of the current cycle.
Because
of the previous trend in DEI, the licensee
submitted
a revised
JCO to
NRR for review and approval to increase
the equilibrium DEI
limit to 0.4 uCi/ml.
This revision was approved
on October 9, 1991.
No violations of NRC requirements
or deviations
were identified.
Pre arations for Refuelin
- Unit 2 (60705)
The inspector attended
several
meetings,
reviewed work order status,
conducted plant tours,
reviewed the outage
schedule,
interviewed several
members of the plant and support staffs,
and reviewed several
procedures
to assess
the preparations
for the Unit 2 refueling outage
scheduled to
begin
on October 17,
1991.
The inspector
reviewed the plans for steam
generator
eddy current testing includinq plans for using the movable
rotating pancake
probe.
The )nspector )dentified an example of poor
visitor escort control discussed
in Paragraph
9 of this report which
appeared
to be related to the hiring of a contractor in preparation for
the outage.
The inspector
also identified weaknesses
in the scaffolding
program discussed
in Paragraph
10.
With the exception of these
deficiencies,
the inspector
concluded that in the areas
reviewed,
the
refueling preparations
appeared
appropriate.
No violations of NRC requirements
or deviations
were identified.
Unescorted Visitor - Unit 2 (71707)
At about 2:00 p.m.
on October 7, 1991, the inspector
observed
the
designated
escort of a visitor leave the visitor unattended
in the "D"
Vital
DC Equipment
Room of the Unit 2 Control Building.
The visitor had
not been granted
unescorted
access
to this vital area.
This is an
apparent violation of NRC requirements
(Violation 529/91-35-05).
19
A similar event occurred
on June
12,
1990,
as
documented
in
Inspection
Report 528/90-29,
and resulted
in a Notice of Violation.
This report also
documented
another
example of poor visitor control
by
the assigned
escort.
The escort
program
was revised
as
a result of the
Notice of Violation issued with report 528/90-29.
Inspection
Report
528/91-04 also referred to poor control of visitors by escorts.
The
inspector
noted that the event
on October
7, 1991 and the examples cited
in Inspection
Report 528/91-04 occurred after the escort program
was
revised.
The inspector also noted that the examples cited in Inspection
Report 528/91-04 occurred at the beginning of the last outage at the
Palo Verde Nuclear Generating Station.
The inspector
concluded that
these
examples
represent
a deficiency in escort visitor control.
Based
on the continuing observations
of escort deficiencies,
the inspector
considers this to be
a program weakness.
At the exit the inspector
emphasized
the importance of maintaining
good visitor escort control,
particularly as the Unit 2 outage is about to begin.
One violation of NRC requirements
was identified.
Scaffoldin
Deficiencies - Unit 2 (71707)
On October
7, 1991, the inspector
noted that scaffolding in the Train
"B" Engineered
Safety Features
(ESF) switchgear
room did not meet the
clearance
requirements
of the licensee's
scaffolding program in that
portions of the scaffold were in contact with a safety related
cable
tray,
and certain portions of the scaffold should
have
been in
contact with and braced against the wall, but were not.
Engineering
Evaluation
Request
(EER) 91-ZJ-024,
which evaluated this scaffold, did
not specify minimum clearance
between the scaffold and safety related
equipment,
and required the scaffold to be braced against the wall at
six points.
As a result of the inspector's
questions
the scaffolding was modified to
create
some clearance
from the cable tray.
The inspector
subsequently
noted that the modified scaffolding still was not braced against,
nor in
contact with the wall.
During subsequent
interviews with licensee
Component
and Specialty Engineerinq personnel,
the inspector
determined
that the scaffolding program contains
two potential
weaknesses.
Procedure
30DP-9WPll, "Scaffolding Instructions," requires
the system
engineer to sign the scaffold tag to verify that the scaffold meets
Seismic Category
IX requirements
when scaffolding is erected in
accordance
w)th an
EER, but does not specify
a maximum length of time
that scaffoldinq can
be in place prior to this signature
by the system
engineer.
The inspector concluded that it is possible for scaffolding
which does
not meet Seismic Category
IX requirements
to be present for
an unspecified
length of time before this condition is identified by the
system engineer.
The inspector also determined that the calculations
used to evaluate
the potential
impact of scaffolding on safety related
plant components
do not include the
mass of material that may be placed
on the scaffolding.
The inspector
concluded that the potential exists
for scaffolding in use in the plant, with the load that could reasonably
be placed
on the scaffolding, to exceed
the Seismic Category
IX
requirements
because
the calculations
consider
the scaffolding unloaded.
20
The licensee
committed to perform
a calculation
by November 4,
1991
on
the seismic qualification of the scaffolding in the "B" train
switchgear
room, which did not meet the cl,earance
requirements
of the
licensee's
scaffolding program.
The licensee
has initiated
CRDR
2-1-0131 to address
the inspector's
questions.
The inspector will
review the licensee's
response
to these
programmatic
weaknesses,
the
final
CRDR disposition,
and this calculation
when it is complete
(Unresolved
Item 529/91-35-04)
Worker Res onsibilit
- Unit 2 (71707)
On September
26, 1991, the inspector
noted that the Plant Computer
(PC)
page display
PC-3 for main feedwater
pump performance
indicated
approximately
1095 thousand
pounds
mass
per
hour (klbm/hr) steam flow to
the "A" main feed
pump turbine while the "B" main feed
pump turbine
indicated approximately
625 klbm/hr.
The inspector questioned
the
difference
between
the two pumps
and was told by an operator that the
"B" pump steam flow parameter
was not working, and that it always read
about
625,
The inspector
noted that
a Work Request
(WR) or Control
Room
Deficiency Log (CRDL) entry had not been
made.
An operator stated that
the plant computer
was for information only, and the standard practice
was to not make
CRDL entries for
PC page display deficiencies.
Condition Report/Disposition
Request
(CRDR) 2-1-0112
was written as
a
result of the inspector's
questions.
The inspector
concluded that an
operator's
knowing about
a problem with a control
room display and not
initiating corrective action represented
a weakness
in the overall
corrective action program,
in that corrective action cannot occur if
problems
are not documented
when they are identified.
The licensee
acknowledged
the inspector's
comments.
No violations of NRC requirements
or deviations
were identified.
Main Steam Safet
- Unit 2 (71707)
On October 9, 1991, during
MSSV setpoint testing the inspector
asked
a
Control
Room operator to test the communication
system required
by
Section 6.4 of surveillance test procedure
PSV
[Pressure
Safety Valve] Set Pressure Verification."
The control
operator
was unable to establish
communication utilizing the radio
designated
at the pre-job briefing for this purpose.
A few minutes later the inspector
observed
the engineer
responsible
for
communication with the control
room fail to respond to a plant page
until that individual
s supervisor
prompted
a response.
The inspector
encouraged
licensee
management
to ensure that when communication devices
are issued that personnel
are able to utilize them for plant operations
and testing.
The licensee
acknowledged
the inspector's
comments
and
affirmed management's
expectation for communications to be effective,
No violations of NRC requirements
or deviations
were identified.
t
21
Undersized
Welds - Unit 2 (71707)
During performance
of an unrelated
inspection in the Unit 2 "B" charging
pump room,
a quality control inspector
noted that two welds
on
a drain
line at the
pump discharge
were slightly undersized.
Material
Non-Conformance
Report
(MNCR) 91-CH-2024
was initiated and the welds
were replaced.
The inspector
concluded that this was
a good example of
the benefits of looking beyond the focus of specific tasks to identify
and correct other
deficiencies'o
violations of NRC requirements
or deviations
were identified.
E ui ment
uglification Audit Review - Units
1
2
and
3 (35502
and
The inspector
reviewed the licensee's
self initiated Equipment
qualification (Eg) assessment
(Final Report August 1991)
and discussed
the report
s findings with the licensee.
The report identified several
major weaknesses
in the licensee's
Eg program,
and concluded that "the
existing program will not effectively ensure
continued qualification of
Palo Verde Nuclear Generating Station
(PVNGS)
Eg equipment,
as required
by 10 CFR 50.49."
The immediate impact on the facility was assessed
to
be minimal because "relatively few Eg components
have reached their
required Eg-related
maintenance
interval. 'ad the
Eg program not been
similarly assessed
until 1993 or beyond,
the licensee
concluded that
many more in-plant deficiencies
would have
been identified.,
However,
the small
number of field deficiencies actually identified in this
assessment
were manageable
without impacting plant operations
due to
operability issues.
One significant finding of the assessment
was the lack of a complete
high energy line break analysis for the auxiliary building.
A
Justification for Continued Operation
(JCO)
was developed,
concluding
that power operation
was acceptable
while the analysis
and resultant
corrective actions
were completed.
The assessment
resulted in the issuance
of nine Corrective Action
Reports
(CARs), eight equality Deficiency Reports
(gDRs), five Material
Nonconformance
Reports
(MNCRs), and two Warehouse
Deficiency Notices
(WDNs).
'Several
immediate or short term corrective actions
were
recommended
and management
responses
to these
are being tracked via the
Corrective Action Tracking System
(CATS).
Included in the
recommendations
are plant walkdowns, worker training, backlog reduction,
reevaluation of Preventive
Maintenance
(PM) due dates,
a review of the
thermal
and radiation analyses
associated
with limited life components
to verify their qualified lives and replacement
schedules,
and several
procedure
revisions.
The assessment
was performed at the request of the Vice President-
Engineering
and Construction.
As potential
problem areas
were
identified, the schedule
was extended
twice to allow a more thorough
review.
l~~
22
The inspector
concluded that the licensee
had effectively used the
Quality Assurance
(QA) resources
to identify significant problems in the
EQ program,
and that the
QA organization
was successful
in evaluating
the potential significance of several
minor observations
and in
convincing management
of the
need for major programmatic
changes
and
extensive corrective
actions.
Additionally, the
QA response
to an
engineering
recommendation
to perform this
EQ assessment
was
an
indication of effective functioning of the
QA program.
No violations of NRC requirements
or deviations
were identified.
Review of Em lo ee Concerns
Pro
ram Activities - Units 1
2
and
3
The inspector
reviewed
13 Employee
Concerns
Program
(ECP) files
initiated in 1991 to determine if the identified concerns
were being
evaluated
and dispositioned
in a manner conducive to enhancing
nuclear
safety.
The inspector
found that all of the
ECP files reviewed appeared
to be complete
and thorough.
The technical
issues
were identified and
addressed
with appropriate corrective actions initiated.
Those files
dealing with administrative issues,
such
evaluations,
also indicated corrective actions
where appropriate.
One file indicated that
a person
was only looking for the
NRC's phone
number,
but that the
ECP person receiving the call was able to persuade
the caller to convey his concern to the
ECP.
The
ECP file. indicated
that the concern
was dealt with in a manner which satisfied the caller.
The inspector also found the
ECP evaluation to be complete
and thorough.
Another file involved a complaint of employment discrimination
(demotion) for having brought previous
concerns to the
ECP.
The
complaint was referred to appropriate on-site
management for review and
resolution.
Even though management
conducted this review of its own
performance
regarding the handling of the case,
the review appeared
to
be objective
and provided clear evidence
supporting the demotion of the
individual.
The inspector
concluded that these
ECP files were evaluated
by the
licensee
in a manner conducive to identifying and correcting problems.
No violations of NRC requirements
or deviations
were identified.
Review of
Em lo ee
ualifications - Units 1
2
and
3 (41500)
The inspector
reviewed the qualifications of twenty, randomly-selected
supervisory
and non-supervisory
employees
in the Unit 2 Maintenance
and
Central
Maintenance
Departments.
The educational
and training
backgrounds
and experience
of those
reviewed were evaluated in
accordance
with ANSI Standard
3. 1-1978, to assure that the minimum
supervisory or non-supervisory
requirements,
as applicable,
had been
met.
Based
on the review, all employees
were found to meet or exceed
these
requirements.
No violations of NRC requirements
or deviations
were identified.
Review of Licensee
Event
Re orts - Units 1
2
and
3 (92700)
The following LERs were reviewed
by the Resident Inspectors.
23
a.
Unit 2
(Closed)
LER 529/87-04-Ll:
"Reactor Tri
While Performin
roun
so
a ion
ue
o
na
e
ua
e
n orma ion
-
ni
2.
This item was initially reviewed in Inspection
Report
529/87-28.
The supplement
was issued to address
specific
corrective actions which have
been identified and
implemented
since the initial report.
The inspector evaluated
these
actions
and concluded that they appear appropriate.
This item
is closed.
(Closed)
LER 529/91-01-LO:
"Containment
Pur
e Isolation
c ua ion
s
em
on ro
oom
ssen ia
i
ra ion
c ua ion
s
em
ni
c ua ion
ue
o
ersonne
rror"
This event
was discussed
in Inspection
Report 529/91-19 in
Paragraph
118.
The
LER does
not suggest
any additional
issues.
This item is closed.
(Closed)
LER 529/91-02-LO: "Dail
Pum
i ra ion
a
a
n ineerin
va ua ion
isse
-
ni
(92700)
This item involved the fai lure of the Shift Technical
Advisor
(STA) to perform the daily engineering
review of Reactor
Coolant
Pump
(RCP) vibration data
on June
18,
1991 as required
by item IV.A.2 of the Unit 2 Confirmatory Order Modifying the
Facility Operating
License
NPF-51 date
November
19,
1987.
This is
a repeat of a similar event reported in
This failure was discovered
on June
19,
1991.
The June
18,
1991 data were reviewed
and found to meet the acceptance
criteria.
The licensee
concluded that this was
a coqnitive
personnel
error.
The licensee
s investigation identified that
the individual responsible for the omission initialed the
turnover check sheet for this item as required
by step 3.5. 1
of 72AC-9ZZ01, Shift Technical Advisor Shift Conduct,
but did
so prior to performing the evaluation
and then subsequently
failed to perform it.
A similar event,
documented
in
Inspection
Report 528/529/530/89-43,
resulted in a Notice
of Violation for an Operator initialing completion of a step
which had not been completed.
The corrective action for the
present
event included disciplining the individual and
discussing
the event with all STAs.
In addition, although not
documented
in the
LER, the licensee
is adding this activity to
the technical specification tracking reminder computer in the
control
room which alarms to remind operators
to perform
various required activities.
At the exit meeting,
the
inspector confirmed that the licensee
management
expectation
is for items to be complete before being checked or initialed
on checklists.
This item is closed.
l
i',
24
b.
Units
2 and
3
l..
(0 en)
LER 529/90-04-LO/Ll Pressurizer
Code Safet
Relief
ave
e-o)ns
u
o
oerance-
nl
an
ae
ave
e
owns
u
o
oerance
- Unit3
These
LERs reported
as-found Pressurizer
Code Safety Valves
(PSVs)
and Hain Steam
Code Safety Valves
(HSSVs) outside the
tolerance permitted by Technical Specifications
(TS) (plus or
minus
one percent).
As-found HSSV setpoints
ranged
from 2.8
percent
low to 1.7 percent high.
PSVs were
up to 3.6 percent
high.
The licensee attributed these results to setpoint
drift, a performance limitation of these
valves.
TS change
requests
have
been submitted to relax these tolerances
up to
three percent.
Evaluations
have
been performed which suggest
that postulated
accidents with these
as-found setpoints
would
not have resulted in reactor coolant system pressure
rising
above the
TS safety limit.
The inspector raised
several
questions
regarding these
evaluations.
The licensee
is
obtaining additional information to answer the inspector's
questions.
These
items will remain
open pending the
completion of the inspector's
review.
c.
Unit 3
l.
(Closed)
LER 530/91-07-LO:
"Reactor
Shutdown
Re uired
b
ec
n>ca
ecl
1ca ion
-
nl
)s repor
escr)
es
e
uqus
,
, shutdown of Unit 3
required
by Technical Specification 3.8.3. 1 due to a failed
Class
1E inverter.
This event is described
in NRC Inspection
Report 530/91-29,
Paragraph
17.
This item is closed
on the
basis of the prior rev>ew.
No violations of NRC requirements
or deviations
were identified.
1 ~ .
~Eit
N ti
Exit meetings
were held on October ll
licensee
management,
during which the
this report were generally discussed.
proprietary any materials provided to
during the inspection.
and 17,
1991 with
observations
and conclusions
in
The licensee
did not identify as
or reviewed by the inspectors
1
i