ML17305B468
| ML17305B468 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 02/15/1991 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305B466 | List: |
| References | |
| 50-528-90-54, 50-529-90-54, 50-530-90-54, NUDOCS 9104220083 | |
| Download: ML17305B468 (40) | |
See also: IR 05000528/1990054
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Re ort Nos.
Docket Nos.
License
Nos.
Licensee:
~Fi1it
II
50-528/90-54,
50-529/90-54
and 50-530/90-54
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, 2&3
>is 0/
Approved By:
a
e
sgne
Ins ection
Summar
Ins ection
on December
2
1990 throu
h Januar
5
1991
(Re ort
um ers
-
-
-
-
an
Ins ection Conducted:
December
2,
1990 through January
5, 1991
Inspectors:
D.
Coe,
Senior Resident
Inspector
F. Ringwald,
Resident
Inspector
J.
Sloan,
Resident
Inspector
ong,
ie
Reactor Projects
Branch,Section II
Areas
Ins ected:
Routine, onsite,
regular
and backshift inspection
by
e
ree resl ent inspectors.
Areas inspected
included: previously
identified items; review of plant activities; monthly surveillance
testing; monthly plant maintenance;
inadvertent dilution of reactor
coolant system boron concentration - Unit 1; diesel
generator operability
- Unit 1; turbine driven auxiliary feedwater
(AFM) pump oil levels-
Units 1 and
3,; closure of one of four main steam isolation valves
(MSIV)
while at 100 percent
power - Unit 2; use of improper fuses in
safety-related
applications - 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:
61726,
62703,
71707,
92700,
92701,
92702,
and 93702.
Results:
Of the 10 areas
inspected,
1 violation was identified in
Unit 1.
The violation pertained to a licensee-identified
inadequate
procedure to place
a
new letdown ion exchanger
resin
bed into service.
91042"OOS.:
51021g
F'DR
ADOCK 00005:28
n
General
Conclusions
and
S ecific Findin
s
Si nificant Safet
Matters:
Summar
of Violations:
Summar
of Deviations:
0 en Items
Summar
None
1 Violation (Unit 1) regarding
an inadequate
procedure
None
14 items closed,
1 item left open,
and
3 new items opened.
DETAILS
1.
Persons
Contacted:
The below listed technical
and supervisory personnel
were among
those contacted:
Arizona Nuclear
Power Pro'ect
(ANPP)
"R. Adney,
"J. Bailey,
"T. Bradish,
"E. Dotson,
".R. Flood,
"R. Fullmer,
"D. Gouge,
"S. Guthrie,
~K. Hall,
"R. Henry,
P.
Hughes,
"M. Ide,
F. Larkin,
"J. Levine,
"J. Minnicks,
"G. Overbeck,
~R. Rogalski,
"J. Scott,
"S. Terrigino,
Plant Manager,
Unit 3-
Yice President,
Nuclear Safety
8 Licensing
Compliance,
Manager
Engineeri,ng
8 Construction,
Site Director
Plant Manager,
Unit 2
gA and Monitoring, Manager
Plant Support,
Manager
(Ch. Plant Review Bd.)
~
~
~
~
~
A, Dep. Director '
Paso Electric Co., Site Representative
Salt River Project, Site Representative
Site
Rad.
Protection,
General
Manager.
Plant Manager,
Unit 1
Security,
Manager
Yice President,
Nuclear
Power Production
Maintenance
Manager,
Unit 3
Technical
Support, Director
gA, Supervisor
Operations
Manager,
Unit 1
Management
Services,
Supervisor
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
January
8, 1991.
2. ~P'
Id
iit
d it
Il it
1
2
d 1 292701
d 927027
a.
Unit 1:
1.
(Closed)
Enforcement
Item (528/89-56-02):
"Motor 0 crated
702)
This violation consisted of two examples in which the
MOY
database
document,
was found to be inappropriate.
The first example
concerned
a technician
who selected -incorrect
switch settings
from 13J-ZZI-004, apparehtly
due to confusion"
resulting from 34 Drawing Change Notices
(DCNs) which had not
been incorporated.
The licensee
has since determined that the
values selected
were actually correct
and that none of the
outstanding
DCNs were applicable to the valve in question.
However, the licensee
recognized that confusion could result in
errors
and has
developed unit-specific database
documents
and
0
2.
has
implemented administrative controls to keep them more
current.
The inspector
reviewed these
documents
and 3J-ZZI-004) and found them to be updated in accordance
with
the administrative controls.
, The administrative controls
require future
DCNs related to implemented
changes
to be
incorporated
such that none is over six months old and
no more
than five of these
implemented
change
DCNs exists at a time.
These actions
appear
adequate.
The second
example
concerned
the lack of review and approval
documentation to support the calculations for the setpoints
in
The licensee
stated that the calculations
and
appropriate
review. and approval
documentation
does exist.
The
inspector
reviewed the documentation
supporting the 13J-ZZI-004
setpoints for the following ten safety-related
valves:
1J- EWA-UV0145
.
While the information was not readily available or well
organized,
the licensee
was able to produce the required
documentation,
including review and approvals,
for the opening
and closing thrust minimum and
maximum values for all these
valves,
as appropriate
(some valves
open
and close
based
on
limit switch position and
do not have thrust values in the
database).
.Procedure
"Valve Motor Operator
Monitoring and Test Program," specifies
the defau]t settings
'nd methodology for determining limit switch settings.
The
limit switch settings
appeared
consistent. with this procedure.
The licensee is taking steps to better organize the
calculations
which preceded
the Generic Letter 89-10 program.
The inspector
also noted that several of the calculations
have
been
superseded
by new calculations resulting from the partial
implementation of the Generic Letter 89-10 program.
These
.
'ctions
appear
adequate.
This item is closed.
(Closed)
Enforcement
Item (528/89-56-10):
"Inade uate
orrec
>ve
c ions
or
ar
o
1 ica ion on
hami or ue
o or
nsu
a ion an
ec naca
anua
e scienc
"
nl
This violation was presented
in two examples of 'inadequate
corrective actions,
the first dealing with a 10 CFR Part 21
I
Notification and the second dealing with the response
to
The licensee
disagreed that the first example represented
a
violation because
the facts presented,
while accurate,
do not
constitute
a violation of regulatory requirements.
The
violation concerned failure of the licensee to address
both
Type
SMB and Type
SB Limitorque operators
in its evaluation,
even though the
10 CFR Part 21 notification had only specified
Type
SMB operators
as having the potential
problem.
The
inspector
reviewed Engineering Action Requests
(EARs) 89-0448
and 89-0449,
and Engineering Evaluation Request
{EER)
88-XE-015,
and conf)rmed that, consistent with the licensee's
response,
EER 88-XE-015 addressed
the 10 CFR Part 21
Notification applicability to both Type
SMB and Type
Limitorque operators.
The inspector
concluded that the
licensee's
r'esponse
to the violation was accurate
and that this
example
does not constitute
a violation.
The second
example resulted
from a technical
manual
not being
updated following the licensee's
response
to Information Not>ce
85-22.
The licensee
determined that technical
manual
J605-162
was the only manual
not updated.
This manual
has subsequently
been
updated
and issued.
Additionally, the licensee's
Vendor
'Technical
Manual project,
expected to be complete
by
December
31, 1993, appears to include in its scope
the types of.
deficiencies identified in this and other findings related to
technical
manuals.
These corrective actions
appear
to be
adequate.
This item is closed.
(Closed)
Followu
Item (528/90-03-02):
"Load Shed Potential
rans
ormer
al ure
-
ns
This item involved a load shed of a 13.8KV bus,
NAN-S02, due to
a failure of the potential transformer across
the "8" to "C"
phase of the bus.
A similar failure occurred
on the
NAN-S01
bus "A" to "B" potential transformer shortly before this event.
The licensee
conducted
a root cause of failure via Engineering
Evaluation Request
{EER) 90-NA-002.
The cause of failure was
determined
by Genera'l Electric to be internal turn-to-turn
=-
shorting of unknown origin.
An APS Nuclear Engineering fai'lure
rate analysis
concluded that the mean failure rate for this
type device is 6. 14E-7 which is close to the industry failure
rates
represented
by the
IEEE Reliability Data.
The inspector
concluded that these
results- appear
appropriate.=-
This item is
closed.
'0
en) Foll owu
Item (528/90-03-03):
"Fuel Buildin
Rollu
Door
ama
e
en
s
a ion
am er
um er
ns
a
a son
-
ns
This event involved damage to the Fuel Building rollup door as
a result of improper control of the insta11ation of pneumatic
jumpers.
Engineering Evaluation
Request
(EER) 90-ZF-009 was
initiated as
a result of this event.
EER 90-ZF-009 is still
open.
This item will remain
open until
EER 90-ZF-009 is closed
and reviewed by the inspector.
Closed)
Followu
Item
528/90-23-02
- "Review of Historicall
al ve
revents ve
as n enance
as
s
-
n)
This item involved a review of the licensee
commitment to
ensure that there are
no
PM tasks which had been waived which
could affect safe plant operation.
A significant number of PN
review forms- were found to contain inadequate
documentation for
the conclusion
reached.
The licensee
committed to repeating
the review, identifying those which were inadequately
documented,
and providing adequate
documentation
where needed.
In addition, the licensee
committed to notifying the inspector
of any additional
concerns
or
PM requirements
identified during
this re-review.
No additional
concerns
were identified by the
licensee.
The licensee
completed the re-review as committed.
The inspector
reviewed about
lOX of the approximately
2000
task review sheets
and
had
no concerns with the additional
documentation.
This item is closed.
(Closed)
Enforcement
Item (528/90-23-03):
"Im ro er
erat>on
o
an
tmos
er>c
um
a ve
>n
anual"-
n>t
This item involved the failure to correctly follow a procedure
which resulted in the manual mis-operation of ADV SGB-HV-178,
while under the supervision of a more experienced
Auxiliary
Operator
(AO) and
a licensed'Senior
Reactor Operator
(SRO).
The licensee's
System Engineer evaluated
the mis-operation
and
concluded that
no damage
had occurred.
The licensee
sampled
the knowledge
and abi 1>ty of several
AOs at all three units and
determined that the
AOs knew how to properly operate
the
ADYs
manually and this issue
was not a training concern.
A Human
Performance
Evaluation System report was completed which
concluded that:
(1) inadequate
work practices
caused
the
event,
(2) the newly qualified
AO was under stress
due to the
presence
of the
NRC Inspector,
(3) having two actions
combined
into one step
was
a contributing factor to the mis-operation of
the
ADV, and (4) a thumbscrew would eliminate the
need for the
AO to use
a tool which could be dropped - not a contributing
factor, but identified during the investigation.
The licensee
counseled
and reexamined
the
AO who mis-operated
the
ADV and
verified that this task could be properly performed.
In
addition, Instruction Change
Request
(ICR) 11033
was written to
have the tightening of the setscrew
made
a separate
step in
procedure
4XOP-XOPOl, "Manual Operation of Air Operated
Valves," and
a plant change
request
was issued to replace the
setscrews
with thumbscrews.
This item is closed.
5
7.
(Closed)
Followu
Item (528/90-23-04):
"0 eratin
Procedures
evsew
or
n
e en
en
eri
sca
son
e usrements
-
nit
This item was associated
with Enforcement
Item 528/89-16-03,
which was closed in Inspection Report'28/90-23.
The
enforcement
item was closed
by evaluating the licensee's
commitment to review operating procedures "...for human factors
considerations,
locked valve and breaker
requirements,
and the
new independent verification requirements."
The inspector
noted that this procedure
review initiative went well beyond
the scope of the violation.
However, the January
2, 1996,
scheduled
completion date
seemed
not to be timely, particularly
with respect to independent verification requirements.
In
addition,
Enforcement
Item 530/89-56-01
noted further
independent verification weaknesses
and is reviewed in
Paragraph
2. C. l. of this report.
This Notice of Violation
included
a commitment to revise "...applicable Operations
. procedures
to include sign off steps to document
independent
verification" by September
2, 1991.
This action will be more
timely and will also address
the independent verification
questions
associated
with this Followup Item.
This item is
closed.
8.
9.
I
(Closed)
Followu
Item (528/90-39-02):
"Technical
Su
ort
701)
en er
a ter)es
o
ar
e
ro er
-
nl
The inspector
noted specific gravity problems with the
diesel
generator batteries that were noted but not addressed
in
Employee
Concerns File 89-104-12.
Based
on the inspector's
questions,
the licensee
then supplemented
the existing file to
address
these
comments.
The supplement reflected
an expanded
look at
TSC battery preventive
maintenance
(PM) tasks.
This
expanded
look resulted in guality Deficiency Report ((DR)
(Closed)
Followu
Item (528/90-28-02):
"Dama ed Reactor
r>
rea er
-
nl
This item involved the unexpected
operating characteristics
and
subsequent
damage to a reactor trip breaker while racking it in
and out.
The Root Cause of Failure Engineering Evaluation
Request
(EER) 90-SB-046
was completed
on December
21, 1990.
This
EER concluded that
a slightly bent or misaligned closing
spring discharge
linkage was the most likely root cause of
failure.
Secondary
damage
during removal
hampered
a complete
understanding
of the root cause of failure.
Corrective action
included replacing the breaker,
routing this
EER to Training
for all Operations
Department personnel,
and the issuance
of
Instruction Change
Request
25254 to eliminate unnecessary
breaker racking operations.
The training on
EER 90-SB-046 will
.be for people
who rack breakers
to be alert for any abnormal,
off-normal or unusual
condition and to determine
the cause'f
the anomalous
condition before proceeding.
This item is
closed.
90-0440 which documented
a negative trend in the performance of
PM tasks
on these batteries,
which are non-safety related.
Problems
noted included personnel
not identifying, documenting,
or reporting problems,
and makin~ administrative
and
calculation errors while performing
PH tasks
on TSC batteries.
In addition,
examples
were noted in which Work Group
Supervisors
signed
PH task work orders
as satisfactory
when the
acceptance
criteria had not been met, failed to note the
administrative
and calculation errors noted above, failed to
initiate appropriate corrective action documentation,
and
signed
a
PH work order as complete
and satisfactory
two days
prior to the dates of the actual
work.
In addition, this
supplement identified problems in which the Central Haintenance
Electrical
Work Control Planner/Coordinator
misunderstood
information on the Station Information Management
System
(SIMS)
terminal display and
made errors
due to inattention to detail.
The inspector
reviewed
(DR 90-0440
and the associated
corrective actions.
The Central
Maintenance Electrical
Supervisor is conducting mandatory briefings for all Central
Maintenance electric
shop personnel
includ>ng Electricians,
Foremen
and Work Group Supervisors,
and Central
Maintenance
Electrical
Work Control Planner/Coordinators
addressing
the
concerns
noted above.
The inspector
concluded that this
corrective action appears
appropriate.
This item is closed.
Unit 2
(Closed)
Followu
Item (529/90-23-01):
"Inadvertent Tri
of the
eac
o
oo an
um
rea er
-
ns
This item involved the tripping of a second
Pump
(RCP) breaker in a three month period due to jarring of an
adjacent
breaker cubicle while manually rolling the adjacent
breaker into its cubicle.
Engineering Evaluation
Request
(EER)
90-NA-009, which was issued
as
a result of the first event,
was
closed without additional corrective action recommendations.
The Site Maintenance
Manager
and Maintenance
Standards
Manager
discussed their intent to devise
a tool to use to move these
breakers
into their cubicles with the inspector.
During the
Unit 1 Surveillance Testing Outage
due to. begin
on January .12,
1990, Central
Haintenance
plans to remove
a breaker to
take'easurements,
then devise
and fit up and finalize the design of
the tool.
No permanent
changes will be made to plant
equipment.
The inspector
concluded that this represents
a.
positive step toward providing improved control of these
breakers.
This item is closed.
(Closed)
Followu
Item (529/90-28-01:
"Inade uate Detail
s n
urves
ance
roce ure
-
ns t
This item addresses
the "Main Steam
PSV Set Pressure
Verification" procedure,
73ST-9ZZ18, which contained
no steps
detailing the proper connection of test equipment or
performance of the test,
using the Trevitest method.
The
0
C.
2.
inspector
reviewed Revision 4, Procedure
Change Notice
2 of
procedure
73ST-9ZZ18, which was effective
on November
6, 1990.
Sufficient detail
was
added to the procedure to ensure
the test
device
was properly installed
and the test properly performed..
Based
on this review, this item is closed.
Unit 3
(Closed
Enforcement
Item
530/89-56-01):
"Failure to Follow
urves
ance
roce ure
-
n)
This item involved the failure to close valve SIA-UV-603 at
step 8.2. 12 while performing surveillance test procedure
"Iodine Removal
System - S.C.A.P.
Discharge
Flow
and Pressure
Test."
-The licensee
restored
the valve lineup,
counselled
the operator involved and issued
a night order
addressing
the issue to all operators.
The procedure
was
revised to include
an independent verification signoff;
The
licensee further committed to reviewing all Operations
procedures
to include signoff steps to document
independent-
verification by September
2, 1991.
The licensee
has also
conducted training for all operators
on the
new independent
verification requirements.
This item is closed.
(Closed)
Enforcement
Item
530/89-56-05):
"Im ro er Atmos heric
um
a ve
ac in
-
nest
This item involved the improper packing of valve
The licensee
reviewed this event in Human
Performance
Evaluation System
Report 89-038 which concluded
that there
was inadequate
self-checking
on the part of the
mechanics
and
an inadequate
program to control valve packing.
The
HPES report noted the development of a new valve packing
program and concluded that it should prevent recurrence
of the
use of valve packing which did,not meet the valve
manufacturer's
specifications.
The inspector
reviewed this program and noted that it is
described in program procedure
Program,"
and implemented in procedure
"Valve Stem
Packing
and Gland Adjustment,'n the
new valve packing
specification
13-PN-220,
and the valve packing drawings
OX-P-ZZG-019 and OX-J-ZZI-005 where
X is the unit number.
According to the licensee,
specification
13-PN-220
was based.
heavily on EPRI Report NP-5697,
"Valve Stem Packing
, Improvements,"
which recommended flexible graphite packing,
and
Equipment
Change Evaluation
ECE-ZZ-A158, which justified the
use of graphite valve packing material at Palo Verde Nuclear
Generating Station.
The inspector noted two weaknesses
in the program.
The first
weakness,
in procedure
Program," is that in the list of responsibilities
of Component
and Specialty Engineering
(C8SE), the program
does not require
P
3.
C8SE to review the Valve Survey and Data Sheets
(VSDS) for
technical
appropriateness
prior to forwarding them to Nuclear
Engineering for incorporation into the valve packing drawings.
The Manager,
C&SE, committed to having procedure
revised to state this technical
review as
a responsibility of
C8SE.
The second
weakness
was that the Unit 1 valve packing
drawings were not issued
and
no schedule existed for the
issuance
of these
drawings.
The Manager,
CESE,
committed to
having these
drawings issued during the three
month period
following the end of the present Unit 1 surveillance test
outage.
The inspector
noted that the valve packing procedures
have only been issued for Unit 3 and are scheduled
to be issued
for Unit 2 February 28,
1991.
The inspector
concluded that the
corrective actions taken
as
a result of this violation appear
adequate
and that the
new valve packing program represents
an
improvement.
This item is closed.
(Closed)
Enforcement
Item (530/89-56-06):
"Failure to Identif
e
orrec
ann enance
om onen
-
ns
This item involved the installation of parts
from containment
purge exhaust valve 3J-CPA-UV-02B on containment
purge supply
valve 3J-CPB-UV-03A with a Quality Control
(QC) holdpoint
verification signoff.
The licensee
responded
by counselling
the individuals involved, performing
a Human Performance
Evaluation
System
(HPES) evaluation,
and c'onducting training on
"Effective Work Practices" for all site maintenance
personnel.
According to the Manager of Quality Control,
QC Inspectors
were
not requ>red to attend "Effective Work Practices" training,
however
a number of them did attend.
QC revised their Plant
Inspection
Report document to require
QC verification of
component identification and
QC personnel
were briefed on the
new form and on this event.
The
HPES report concluded that
inadequate
verbal
communication
and inadequate written
communication contributed to the event.
Corrective action
included reviewing the
HPES report with all affected work
groups,
conducting the "Effective Work Practices" training,
and
issuing Instruction
Change
Request
(ICR) 18899 to evaluate
the
use of accurate
descriptions
in work orders.
This item is
closed.
3.
Review of Plant Activities (71707 and 93702
a.
Umt 1
Unit 1 remained at essentially
100 percent
power throughout
this reporting period,
except for a downpower to 75 percent
on
December 17, 1990,
due to a Core Operating Limits Supervisory"
System
(COLSS) failure.
The unit was restored to full power
the
same
day.
b.
Unit 2
Unit 2 remained at essentially
100 percent
power throughout
this reporting period except for an HSIV closure event
on
December
21,
1990', which resulted in a forced power reduction
to approximately
65 percent for several
hours
(see paragraph
9).
c.
Unit 3
Unit 3 operated at approximately
100 percent
power throughout
this report period with the exception of a downpower to
40 percent
from December 25, to December 27,
1990, to locate
and repair a condenser
tube leak.
d.
Plant Tours
The following plant areas
at Units 1,
2 and
3 were toured by
the inspector during the inspection:
Auxi'liary Building
Control
Complex Building
Diesel Generator Building
Radwaste Building
Technical
Support Center
Turbine Bui1ding
Yard Area and Perimeter
The following areas
were observed
during the tours:
1.
0 eratin
Lo s and Records - Records
were reviewed against
ec nica
peci ica sons
and administrative control
procedure
requirements.
2.
Monitorin
instrumentation - Process
instruments
were
o serve
or corre
a ion
etween
channels
and for
conformance with Technical Specifications
requirements.
3.
Shift Staffin - Control
room and shift staffing were
o serve
or conformance with 10 CFR'art 50.54.(k),
Technical Specifications,
and administrative procedur'es.
5.
E ui ment Lineu
s - Various valves
and electrical breakers
were veri ie
o be in the position or condition required
by Technical Specifications
and administrative procedures
for the applicable plant mode.
E ui ment Ta
in - Selected
equipment, for which tagging
requests
a
een initiated,
was observed to verify that
tags
were in place
and the equipment
was in the condition
specified.
6.
General
Plant
E ui ment Conditions - Plant equipment
was
o serve
or in ica ions
o
sys
em leakage,
improper
~
'
10
lubrication, or other conditions that would prevent the
systems
from fulfillingtheir functional requirements.
The inspector
noted that
a bolt was missing from the
casing
on the Unit 1 Essential
Cooling Water "B" pump
The licensee -.initiated Haterial
Non-Conformance
Report
(MNCR) 90-EW-Oll to address
the deficiency and the
bolt was replaced.
Fire Protection - Fire fighting equipment
and controls
g
dgg
dd
Specifications
and administrative procedures.
Plant Chemistr
- Chemical analysis results
were reviewed
or con ormance with Technical Specifications
and
administrative control procedures.
Securi t
- Activities observed for conformance with
regu
a ory requirements,
implementation of the site
security plan,
and administrative
procedures
included
vehicle and personnel
access,
and protected
and vital area
integrity.
Plant Housekee
in
- Plant conditions
and
mater>a
equipment storage
were observed to determine
the
general
state of cleanliness
and housekeeping.
Radiation Protection Controls - Areas observed
included
con ro
porn
opera Ion, records of licensee's
surveys
within the Radiological Controlled Areas
(RCA), posting of
radiation
and high radiation areas,
compliance with
Radiation Exposure
Permits
(REP), personnel
monitoring
devices
being properly worn, and personnel
frisking
practices.
material
Control - Warehouse
and material receipt,
g,
g
d
dddd
d
d.
The inspector discussed
the recent
implementation of--
Level I certified gC inspectors for material receiving
inspections with several
warehouse
personnel,
including
supervision
and Level I and II certified inspectors.
The
inspector
noted that although four warehousemen
were given
Level II training in October 1990, the licensee
implemented
a change to their receipt process
which only
required these
personnel
to be qualified to the lesser
Level I standard
(ANSI N45.2d 6).
Based
on discussions
with two of the four recently certified Level I
inspectors,
and
a review of training and certification
records,
the inspector determined that the change to the
licensee's
receipt inspection process
was being controlled
by procedure,
that the procedure
provided for specific
attributes for Level I receipt inspection, that this level
of inspection
was consistent with the level of
certification given to the Level I inspectors,
and that
previously all receipt inspections
for quality related
material
were performed completely by Level II certified
inspectors
even though non-certified warehousemen
also
routinely performed
some of the checks which would be
normally done by Level I inspectors.
Licensee
personnel
stated that receipt inspections
were
now more efficient in
taking credit for the Level I inspector's
checks,
freeing
the Level II inspector
to inspect higher level attributes.
Based
on these discussions,
the inspector
concluded that.
NSI N45.2.6 requirements
relative to receipt inspector
qualification and activities were being governed
by
approved
licensee
procedures.
No violations of NRC requirements
or deviations
were identified.
4.
Monthl
Surveillance Testin
- Units 1
2 and
3 {61726)
a.
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 perfoi mance 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.
b.
Specifically, portions of the following surveillances
were
observed
by the inspector during this inspection period:
Unit 1
~voce
ure
Descri tion
Unit 2
Hone
Diesel
Engine
18 Month Inspection
18 Month Surveillance Test of Diesel Generator
Surveillance Test Procedures
for the Class
4160
Bus,Under Voltage Protective
Relays
Unit 3
~roce
ure
Descri tion
Routine Surveillance Daily Midnight Logs
No violations of NRC requirements
or deviations
were identified.
5.
Monthl
Plant Maintenance ; Units 1
2 and
3
62703
'a.
During the inspection period, the inspector
observed
and
reviewed selected
documentation
associated
with maintenance
and
problem investigation activities listed below to verify
compliance with regulatory requirements,
compliance with
0
12
administrative
and maintenance
procedures,
required Quality
Assurance/Quality
Control involvement, proper use of safety
tags,
proper equipment alignment and
use of jumpers,
personnel
qualifications,
and proper retesting.
The inspector verified
that reportability for these activities was correct.
b.
Specifically, the inspector witnessed portions of the following
maintenance activities:
Unit 1
Descri tion
o
Inspection of Emergency Diesel Generator
Piping and Oil
Sample
Unit 2
Descri tion
o
Repair of "B" Emergency Diesel Generator Silencer
Unit 3
~D
o
"B" Emergency .Diesel Generator High'ibration Trip
Troubleshooting
No violations of NRC requirements
or deviations
were identified,
6.
Inadvertent Dilution of Reactor Coolant
S stem Boron Concentration
n>t
an
The details of this event are described in LER 50-528/90-11
and the
licensee's
Incident Investigation
Report (IIR) 2-1-90-004.
In
summary,
on December
6, 1990, with Unit 1 at lOOX power, the reactor
coolant system boron concentration was'iluted
by approximately
3 ppm
when
a new ion exchanger
was placed into service without adequate
boron saturation.
There were several
weaknesses
which were evident
during the event
and missed opportunities which could have prevented
or mitigated the dilution event:
a.
There
was inadequate
technical
basis for the 20 minutes
specified in the procedure for the flush of the ion exchanger
and
an informal process
was
used to communicate the criteria in
the development of the procedure.
b.
Operations'nitial
concern with the adequacy of the time
specified in the procedure for boron saturation of the ion,
exchanger prior to being placed in service
was not pursued to
conclusion.
Operations
discussion with chemistry personnel
were not adequate
to resolve the concern.
0
13
c,
The decision to concurrently perform high rate
blowdowns of the
also raised reactor
power in addition to the
dilution and caused
the Core Operating Limits Supervisory
System master
alarm to annunciate.
The operators
expected
the
alarm due to the high rate
blowdowns
and therefore
the alarm
did not alert the operators
to the dilution event.
d.
Computer technicians failed to coamunicate to the operators
the
inability of the control element
assemblies
to move in
sequential
control
mode which further complicated operator
response
to the dilution event.
The dilution occurred
from approximately I:53 a.m. to 2:49 a.m.
on
December
G. 'uring this time the steam generators
were being given
a series of two minute high rate blowdowns.
In combination with the
dilution effect, this caused
actual
reactor
power to exceed
100 percent for between
one to two hours
and exceed
101 percent for
between
14 to 26 minutes.
Although licensee calculations
show that
"best estimate"
thermal
power did not exceed
the safety analysis
upper limit of 102 percent,
the licensee
acknowledges
in the IIR and
LER that engineering calculations
which account for a11 worst case
uncertainties
can
be shown to result in peak power of nearly
104 percent.
The licensee
submitted the
10 CFR 50.73 report based
on having exceeded
licensed
thermal
power.
When the operators
attempted to drive CEAs into the core to limit the increased
reactor
power and
RCS temperature,
the
CEAs would not respond
in the manual
sequentia)
mode
due to the unrecognized
impact of a p')ant computer
system malfunction.
Operators
were able to control
CEAs in the
manual
group mode
and mitigate the transient.
The inspector reviewed the licensee's
IIR, LER, supporting
documents,
and noted the following:
The licensee
determined that
a dilution event in Mode I is bounded
by the faster
CEA withdrawal event which results in a reactor trip
on
VOPT or low Departure
From Nucleate Boiling Ratio
(DNBR), and no
fuel damage,
even
assuming
no operator action.
Maintenance of.
reactor
power below 102 percent
on
a steady state
basis
assures
consistency with safety analysis
assumptions.
Furthermore,
licensee
policy guidance to operators
allows for variations
above the
100 percent licensed
power, but held within the
102 percent limit,
based
on 1980
NRC guidance which suggests
100-102 percent
power is
"briefly" permissible "for as long as
15 minutes'," provided the
shiftly average of reactor
power remains at or below the licensed
(1GO percent) limit.
This guidance for shiftly average
power
appears
to have
been met in this case.
The licensee
review
acknowledges
the need to maintain tighter control over
parameters
during such evolutions
and management
counseled
the shift
supervisor
in this regard.
The inspector considered this action
appropriate.
The licensee's
review determined that computer technicians
were
aware of a computer malfunction which caused
de-energization
of
circuit cards in the plant computer
two days prior to this event.
The IIR did not acknowledge that these technicians
should
have been
able to provide operators
with enough information to alert them to
14
7.
the impact on
CEA Control:
This was demonstrated
by the
. technician
s ability to provide information to operators
in the
context of the plant indication and control which would be lost
whi,le restoring power to the cards.
In subsequent
discussions
with'he
inspector,
licensee
management
agreed to emphasize
to operators
and computer technicians
the need for thorough analysis of current
plant impact due to malfunctioning equipment.
Finally, the licensee
issued equality Deficiency Report
to correct the procedure
guidance for placinq
a
new resin
bed in
service
and for preventing recurrence of similar procedural
inadequacies.
The inspector
noted that the IIR did not delve into
the reasons
why the procedure
was deficient, relying instead
on the
(OR program to sufficiently resolve this issue.
The inspector
determined that the under lying cause
was that technical
information
regarding the length of time needed to.borate
a new resin
bed to
'oncentration
was communicated verbally from Chemistry Standards
to
the Operations
Standards
group writing a procedure
revision in May
1990.
Apparent misunderstanding
and lack of critical review of the
basis for this information contributed to its being approved in the
revision.
The response
to the (DR was to incorporate
the licensee's
existing Engineering Evaluation Request
(EER) program
as
a means of
documenting the transmittal
of technical
information between
Standards
groups.
Although this appears
to provide more formality,
the inspector
emphasized
to licensee
management
that such
documentation
must still.=be critically reviewed
and challenged
when
necessary
prior to its use in approved procedures.
A 'previous
example of a procedure deficiency due to misunderstood
engineering
input was recently discussed
in NRC Inspection
Report 528/90-46
(paragraph
9), but resulted in more conservative
requirements
than
were necessary.
The inspector
concluded that the failure to provide
a required procedure with appropriate criteria for determining the
satisfactory
accomplishment of this important activity is a
violation of 10 CFR Part 50, Appendix B, Criterion V
(50-528/90-54-03).
Diesel Generator
0 erabilit - Unit 1
61726
and 92700
Mhile observing performance of Surveillance Test 31ST-9OG01,
"18.
Month Diesel Generator Inspection,"
on the "B" Emergency Diesel-
'enerator
(EOG) on December
18, 1990, the inspector, noticed that the
opposite Train
EDG (Train "A") had
a "Diesel Inoperable/Malfunction"
local annunciator lighted.
The local annunciator for low lube oil
pressure
was also"lighted.
If these
alarms
were valid, the
EOG
.
would be inoperable.
The inspector determined that the
EOG "A" inoperable indication had
been first identified on December
15, 1990,
and that the Shift
Supervisor
(SS)
had evaluated
the problem and determined that it was
an annunciator
problem only and that the
This was
based
on the licensee's
verifications that none of the parameters
identified in the alarm response
procedure
were in a condition to
provide
a valid alarm, that
no control
room
EOG trouble alarm or
Safety Equipment Status
System
(SESS)
alarm was present,
and that
a
0!
~,
15
valid local annunciator
would result in the appropriate
control
room
alarms.
Additionally, the Assistant Shift Supervisor
telephoned
the
duty Instrumentation
and Controls (I8C) Technician
and explained the
observations.
The I8C Technician concurred with the conclusion that
However,
no log entries
document the checks
which were
made to verify EDG
operability.'n
Monday,
December
17, 1990,
High Pressure
Safety Injection (HPSI)
Train "B'as taken out of service for planned
maintenance.
Later
that day, the Operations
Manager
became
aware of,the
EDG "A"
"Inoperable/Malfunction" annunciator
and directed that I8C confirm
that the condition was simply an annunciator circuit problem.
This
effort consisted of checking continuity across
the contacts
which
cause
the ahnunciator to be on.
The contacts
were determined to be
closed,
which should not cause
the alarm.
I8C concluded that the
annunciator circuit card was faulty.
However, the condition was not
corrected at that time.
Additionally, the
I&C Technician
used
an
uncontrolled diagram instead of controlled drawings while performing
this troubleshooting confirmation.
Licensee
management. stated that
their expectation
was that controlled drawings should
have
been
Used.
The Operations
Manager authorized the
SS to take the opposite Train
"B" EDG out of service
and declare it inoperable for 18 month
surveillance testing, providing the
had
no operability questions
about the "A" EDG after the
I8C troubleshooting.
The "B 'DG was
thus
removed from service
on December
18, 1990.
The annunciator
circuit card on the "A" EDG was subsequently
replaced.
After detailed discussions
with the licensee's
engineering staff and
examination of the related logic prints, the inspector
agreed that
the
EDG "A" annunciator'problem
did not impact operability.
However,
up to this point, engineering
had not been involved in the
resolution of the problem,
and
no other attempt to confirm the scope
of the problem via the logic diagrams'had
been
made.
Procedure
"Conduct of Shift Operations,"
states that
"when key decisions
are made,
the thought process for that decision
should
be logged, for reconstruction at
a later time."
The
determination that
EDG "A" was operable in spite of the
"inoperable/malfunction" annunciator, particularly prior to making
opposite train equipment inoperable for planned maintenance,
appears
to be
a "key" decision.
The inspector
concluded that adequate
information was
used
by the
to verify EDG "A" operability, but that documentation
of this
verification was poor.
The licensee
concurred that this should. have
been
documented.
No violations of NRC requirements
or deviations
were identified.
16
Turbine Driven Auxiliar
(AFW) Pum
Oil Levels - Units 1
an
On December
28, 1990,
a Unit 1 Auxiliary Operator
(AO) reported that
the oil level in the turbine driven
AFW pump,
1AFA-P01, was 1/8 inch
higher than the upper limit mark on the s'ightglass.
A locally
mounted placard declares that oil level must be maintained
between
the marks
on the sightglass.
As a result of this finding, the
pump
was successfully
operated to ensure that the high oil level would
not prevent operation.
Subsequently,
the oil was changed
and level
restored to the normal
band.
A sample of the old oil was obtained,
analyzed,
and found to be normal.
On January 1, 1991, the oil level in lAFA-P01 was again observed to
be about 1/8 inch above the upper mark.
This oil was
sampled for
lab analysis
and about
12 ounces of oil were drained out to restore
the level.
The licensee initiated Engineering Evaluation Request
(EER) 91-AF-01 to determine
why the level
was too high.
On January 4, 1991, the inspector
checked the Units 2 and
3 turbine
driven
AFW pumps,
and found that the Unit 3 pump,
had
an
oil level about 1/8 inch above the mark at the inboard bearing.
Level was about 1/4 inch above the mark at the outboard bearing
sightglass.
The Unit 3 shift supervisor
noted that the oil had been
changed
and
a routine oil sample
had been taken
a few days
previously.
He requested
maintenance
to drain the oil as necessary
to restore
the level.
The inspector
noted that the
AO logs
have
a different acceptance
criteria for oil level than what is provided by the placard.
The
logs
have
no limit on the maximum allowed level,
and the minimum
level allowed is "no visible level."
The normal level given is
50 percent,
though the sightglass
has
no numerical scale or
mid-point mark.
The licensee
submitted Instruction
Change
Request
(ICR) 15434 to correct this discrepancy.
The significance of marginally high oil levels
has not been
determined.
This item will remain
open until the inspector reviews
the results of the licensee's
evaluation of the cause
and
significance of high oil levels (Followup Item 528/90-54-01).
No violations of NRC requirements
or deviations
were identified.
Closure of One of Four Main Steam Isolation Valves
(MSIV
While at
ercen
ower -
n>
At approximately 5:45 AM, (MST) on December
21, 1990,
MSIV 170
unexpectedly
closed while the plant was operating at 100 percent
power.
This malfunction affected only one of two MSIVs associated
with the
No.
Operators
reduced plant power to
approximately
65 percent
and stabilized plant parameters.
Plant
response
to this event
was subsequently
determined
by the licensee
to be as expected,
with no significant abnormalities
noted.
Operator action was briefly required to operate
the
No.
1 steam
17
generator
feedwater control system in manual,
and an approximately
seven
degree difference in cold leg temperatures
between
steam
generators
created
a sufficient core azimuthal flux tilt (1.03) to
require changing the Core Protection Calculator
(CPC) AZTILT
parameter
in accordance
with the provisions of Technical
Specifications.
Additionally, the unaffected
steam line on the
No.
1 steam generator initially passed
excessive
steam flow and
over-ranged
the steam flow instrument
used to correct the steam
pressure
instrument which inputs to the Core Operating Limits
Supervisory
System
(COLSS) secondary calorimetric power calculation.
The steam flow instrument
came into range at power levels less than
70 percent
as expected.
The licensee
determined that the cause of MSIV closure
was
a failed
solenoid operated air valve (Skinner/Honeywell
Model V5-61090)
associated
with the Anchor/Darling MSIV.
Once plant conditions were
stabilized,
the air valve was replaced,
and the MSIY was opened
and
surveillance tested satisfactorily.
The licensee initiated a
root-cause-of-failure
analysis
on the failed valve (Engineering
Evaluation Request
90-SG-221).
The overall licensee
response
to this event appeared well
coordinated.
The
NSSS vendor was promptly consulted,
Nuclear Fuels
Management
department quickly provided
a simulation of plant
response
which helped confirm that the actual
response
was
as
'expected,
Reactor
Engineering coordinated on-site engineering
evaluation
and assessment,
and maintenance
and material
support were
efficient and effective in restoring the MSIV to service.
The
licensee
restored
the plant to normal operations
late that afternoon
and restored full power operation later that evening.
The licensee
also initiated an Incident Investigation to assess
the transient in
more detail.
The inspector
noted two areas
of apparent
weakness
in the licensee's
performance in response
to this event.
First, the licensee
based
the determination of satisfactory plant response
on the simu'1ation
which showed
a maximum seven
degree delta T-cold, operator
statements
that delta T-cold was not seen to be larger than seven
degrees,
engineering
judgement which extrapolated
a four degree
delta T-cold at 83 percent
power to a seven
degree delta T-cold at
100 percent" power,
a review of CPC functional requirements
of which
protection from this specific transient
was included,
a physical
check of CPC auxiliary trip setpoints
of fifteen degrees
delta
.
T-cold, and
NSSS vendor concurrence
with the above.
The inspector
noted that after the plant had been restored to normal operation but
prior to restoring full power operation,
available precise plant
parameter transient
response
(TDAS) data
was not accessed
and
reviewed.
Although the inspector considered
the licensee
had
sufficient basis to assure
the plant remained within its design
envelope
throughout the transient,
the
TDAS plots represented
the
most precise
data available to confirm actual plant response.
Licensee
management
agreed that this data could have further
contributed to confirmation of plant response.
18
Second,
the inspector questioned unit operations
management
during
the transient
on how the over-ranged
steam flow instrument affected
the calculations
performed
by COLSS.
Operations
management
at that
time could not confirm that
COLSS was impacted
by this over-ranged
instrument.
The operations staff or shift. had .not been
informed of
any impact and were not considering the possibility of any adverse
effect.
On further questioning,
the operators
and
a computer
technician
confirmed the use of this instrument
as
an input to
Subsequently
the licensee
informed the inspector that the
impact on
COLSS did not affect the validity of COLSS calculations.
The inspector stressed
the need for operators
to task supporting
groups
such
as engineering to provide such assessments.
Licensee
management
acknowledged
these
comments
and noted that consideration
was being given to creating additional reference
documents
to assist
operators
in assessing
the impact of various sensor or instrument
failures.
Additionally, development of an operations
procedure
was
initiated to provide specific guidance to operators for this event.
No violations of NRC requirements
or deviations
were identified.
Use Of Im ro er Fuses
In Safet -Related
A
lications - Units 1
2
an
The inspector
reviewed
an issue previously identified by the
licensee
related to the possible
use of incorrect fuses in Beta
Products
equipment.
The inspector
reviewed Reportability Evaluation Report
(RER) 89-03,
which determined that these
problems did not warrant
a 10 CFR Part 21 report.
The corrective action section did, however, indicate the
need for an evaluation of other Beta supplied fused equipment to
determine if this problem existed in other equipment.
This
evaluation
was to be documented
in Engineering Action Request
(EAR)
89-0831.
The inspector concluded that the
RER appeared
appropriate.
The inspector
reviewed
EAR 89-0831
and found that it was still open.
The
EAR was initiated on May 10,
1989 with the Nuclear Engineering
Department responsible for this
EAR.
Unit 3 inspections
were
completed
by August 1989,
however,
due to personnel
changes,
the
Nuclear Engineering
Department
was
unaware of this status
until;"=
January
1991.
The status of the inspections
and individual
responsibility for the
EAR had not been
communicated until
questioned
by the
NRC inspectors
in December
1990.
The
NED
supervisor responsible for the completion of this
EAR indicated=that
it had routine priority and that it would be completed after.
completing higher priority work.
The inspector
concluded that in
this case,
the
EAR prioritization process
was weak, in that after
..
one year there
was
no planned completion date.
The inspector-
further concluded that in this case
communications
were ineffective
in transmitting requested
data from the field to NED.
The inspector reviewed Work Orders
393611,
393528,
400054,
and
429555,
which covered all the units.
These work orders
were issued
to perform these
fuse inspections
in various safety
and non-safety
19
cabinets.
The inspector
noted that the form used to collect the
data in Unit 2 had
a pen and ink column added to document
independent verification of the reinstallation of the fuses.
In the
work orders for Unit 3, the data form had pre-printed
columns which.
duplicated the independent verification pen-and-ink
columns
used at
Unit 2.
Unit 1 used
a determ/reterm
sheet:
The inspector
noted
that Procedure
30DP-OAPOl, "Maintenance Instruction Writer's Guide",
states
in Section 3.2.4
on page ll of 44 that "The removal
and
reinstallation of the
same
component shall
be documented
on
a
component removal/reinstallation
form ... or controlled by the work
instruction."
While the
use of a column on a form or a
determ/reterm
sheet is not explicitly in accordance
with the
requirements
of 30DP-OAP01, its use provided the
same
independent
verification of that required
by the component
removal
form.
The
inspector
concluded that this was
a minor difference.
In addition, the inspector
noted that the work order entry for Work
guality Related
("WK gR") was listed
as
no ("N") on the cover page
of the work orders for each unit, yet the work orders
received the
technical
and quality reviews normally associated
with guality Class
work orders.
The reason for this is that
some of the fuses being
inspected
were g-Class
and
some were not,
and this had been marked
"N" in error.
The work order received
a technical
and quality
review despite the incorrect flag in the
"WK gR" field.
The
inspector concluded that except
as
noted above,
the work orders
appeared
appropriate for the planned task with adequate
detail
and
references.
Work order 393611 for Unit 1 had not been completed.
According to
notes in the work order and discussion with personnel
from Work
Control
including the Planner
Coordinator, this work stopped
when
a
g-Class
fuse for the annunciator circuit for a Class
1E circuit was
broken in May 1990.
These discussions
also indicated that this fuse
only had
a Beta Products part number which they could not cross
reference
to any other fuse.
In addition, other higher priority
work delayed the procurement of the replacement
fuse.
By June
14,
1990 the Planner
Coordinator initiated a request to Materials for a
replacement
fuse.
Purchase
Request
9535389
was written on August 2,
1990.
The Station Information Management
System indicates that the
lead time for procuring this fuse after a purchase
order is issued
is 37 weeks.
According to the Planner Coordinator,
as of January
7,
1991
a Purchase
Order had not been issued.
This broken fuse
had
no
impact on the affected equipment
because it was in a redundant
power
supply.
The inspector discussed availability of g-Class
fuses with
an
18C Foreman,
the
18C System Engineer for these
systems,
the
NED
I8C Engineer for these
systems,
and with a Procurement
Engineering
representative.
None of these
discussions
identified any unusual
difficulties in obtaining g-Class
fuses.
The'inspector
also
discussed this with the Planner Coordinator who said that there
had
been difficulty obtaining fuses in some situations
and that in this
case there
was
a class
and item number but no stock for the fuse in
the warehouse.
The inspector
concluded that low priority resulted
in the lengthy delay in obtaining the replacement
fuse.
'
20
The inspector
concluded that inadequate
ownership of this issue
appears
to have delayed the completion of corrective action.
The
licensee initiated Problem Resolution Sheet
1613 to evaluate
the
significance of the concerns
raised regarding this
EAR and any
possible
broader implications.
The inspector will review the
results of this investigation
when the
PRS is closed (Followup Item
528/90-54-02).
ll.
Review of Licensee
Event
Re orts - Units 1
2 and
3 (90712
an
The following LER was reviewed by the Resident
Inspectors.
Unit 1
528/90-ll-LO (Closed
"Reactor Thermal
Power License Limit
xcee
e
.
-
n)
This event is described
and reviewed in paraqraph
7 of this
inspection report.
Based
on this review, thss
LER is closed.
12.
~Eit N
The inspector met with licensee
management
representatives
periodically during the inspection
and held an exit meeting
on
January
8, 1991.
0
i