ML17305A510
| ML17305A510 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 01/19/1990 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305A508 | List: |
| References | |
| 50-528-89-50, 50-529-89-50, 50-530-89-50, NUDOCS 9002140011 | |
| Download: ML17305A510 (56) | |
See also: IR 05000528/1989050
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Re ort Nos.
Docket Nos.
License
Nos.
Licensee:
Facilit
Name:
50-528/89-50,
50-529/89-50,
50-530/89-50
50-528,
50-529,
50-530
NPF""51,
Arizona Nuclear Power Project
P.
0.
Box 52034
Phoenix,
AZ, 85072-2034
Palo Verde Nuclear Generating Station
Units 1, 28
3
Ins ection Conducted:
November
13 through
December
17,
1989
Inspectors:
Approved By:
T. Polich, Senior Resident Inspector
D.
Coe,
Resident
Inspector
J.
Ringwald, -Resident Inspector
J.
Sloan,
Resident
Inspector
W. Wagner,
Reactor Inspector
T. Meadows,
License
Examiner
W. Ang,
roject Inspector
ong,
ie
Reactor Projects
Section II
/ /$~
a
e
igne
Ins ection
Summar
Ins ection on November
13 throu
h December
17
1989
(Re ort Nos.
an
Areas Ins ected:
Routine, onsite,
regular
and backshift inspection
by the
our ress
en
inspectors.
Areas inspected
included: previously identified
items; review of plant activities; engineered
safety feature
system walkdowns;
monthly surveillance testing;
monthly plant maintenance;
sign-offs not made
as
maintenance
was performed - Unit 1; misplacement of fuel assembly
event - Unit
1; stuck fuel assembly - Unit 1; wrong assembly
grappled=and lifted in the
spent fuel pool - Unit 1; unofficial procedure
change - Unit 1; incorrect
clearance
- Unit 1; reactor- coolant system
heatup rate limit exceeded
- Unit
2
refueling water tank makeup water spills - Unit 2; reactor startup - Unit
pump pressure
pulsations - Unit 3; missing handwheels
on downcomer feedwater isolation valves - Unit 3; allegation followup; review
of licensee
event reports - Units 1,
2 and 3; and review of periodic and
special
reports - Units 1,
2 and 3.
During this inspection the following Inspection
Procedures
were utilized;
30702,
30703,
40500,
60705,
60710,
61726,
62703,
71707,
71720,
92700,
92701,
and 93702.
Safet
Issues
Mana ement
S stem
(SIMS
Items:
NONE
Results:
Of the nineteen
areas
inspected,
two violations were identified.
Tfie 7>rst violation is for failure to follow procedures.
Electricians
performing work, with a equality Control inspector in attendance,
failed to
signoff work order steps
during the conduct of maintenance
at Unit 1.
The
second violation is for issuing directions for core reload which contained
an
error
and resulted in placing a new fuel assembly into other than its analyzed
location.
General
Conclusions
and
S ecific Findin s:
Si nificant Safet
Matters:
NONE
Summar
of Violations:
Summar
of Deviations:
0 en Items
Summar
TWO violations
NONE
8 items closed
and
2 new items opened.
DETAILS
V
Persons
Contacted:
The below listed technical
and supervisory personnel
were
among those
contacted:
Arizona Nuclear Power Pro ect
- R.
J.
J.
B.
H.
T.
Ap
kp
AW
- D
p.
W.
J.
J.
J.
+W.
- T
Adney,
Al 1 en,
Bailey,
Ballard,
Bieling,
Bradish,
Brandjes
Caudill,
Conway,
Heinicke
Hughes,
Ide,
Kirby,
Levine,
LoCicero
Marsh,
Cogbur n,
Rouse,
Russo,
Shell,
Shriver,
Sowers,
Taufiq,
Willsey,
Younger,
- R.
C.
G.
T.
- G
- A.
)kN
R.
J
Plant Manager, Unit 3
Engineering
8 Construction Director
Vice President,
Nuclear Safety
8 Licensing
equality Assurance
Director
Emergency Plan/Fire Protection
Manager
Compliance Supervisor
Central
Maintenance
Manager
Site Services Director
Executive Vice President - Nuclear
Plant Manager,
Unit 2
Radiation Protection
8 Chemistry Manager
Plant Manager,
Unit 1
Nuclear Production Support Director
Vice President,
Nuclear Power Production
Independent
Safety Engineering
Manager
Plant Director
(Acting) Standard
and Tech.
Support Director
Lead Compliance
Engineer
Assistant
equality Assurance
Director
equality Systems
Manager
Compliance
Manager
Engineering Evaluations
Manager
Independent
Safety Engineering Senior Engineer
(Acting) Emergency
Planning
and Fire Protection
Plant Standards
and Control Manager
Manager
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
December 27,
1989.
Previousl
Identified Items - Units 1
2
and
3 (92701
92702)
a,
(Closed
Information Notice
IN-88-47: "Slower Than
Ex ected
Rod
ro
>mes.
The inspector
reviewed licensee
procedure
"CEA Drop
Time," with respect to the licensee's
commitment, per
NRC Inspection
Report 528/89-36, to account for the increase
in CEA drop time due
to the testing methodology.
The inspector
noted the acceptance
criteria had been adjusted
accordingly
and observed
the performance
of a portion of the surveillance test,
the results of which appeared
'I
b.
to meet the
new criteria,
based
on preliminary review.
The
inspector
had
no further questions-.
This item is closed.
Closed
Unresolved
Item (528/89-49-03
"Remote
Shutdown
Room
ommunsca
sons
evince
oun
sn
.
The inspector discussed
applicable
seismic criteria regarding the
radios in question
and determined that the criteria had been met.
This item >s closed.
3.
Review of Plant Activities (60705
71707
71710
93702)
a 0
C.
Unit 1
Unit 1 remained .in Mode
6 throughout this inspection period.
Refueling operations
continued,
however several
problems
were
encountered
during refueling operations
(see Sections
8,
9 and 10).
Unit 2
Unit 2 entered the inspection period in Mode 5, performing
corrective maintenance
on nuclear cooling water, essential
cooling
water,
and auxiliary feedwater valves.
The Unit began
a heatup
on
November 21,
1989.
Shortly after entering
Mode 4 on that date,
the
heatup
was terminated
due to exceeding
heatup rate limit.
As a conservative
measure,
the Unit was cooled
down to Mode 5
(COLD SHUTDOWN) on November 22,
1989.
A heatup to
Mode 3 (HOT STANDBY) was performed
on November 23, where the unit
stabilized to perform maintenance
on an auxiliary feedwater
valve.
The reactor
was started
up on November 30, 1989, but the power
increase
was halted in Mode 2 due to indications of a potential
control element drive mechanism coil ground.
The Unit borated to
subcriticality on December
1,
1989 (see Section 15).
The reactor
was started
again
and entered
Mode 1 on December 2, 1989.
The-plant
was synchronized to the grid on December
2, 1989 and reached
lOOX
power on December
5.
The plant operated at essentially
100X power
for the remainder of the inspection period.
Unit 3
I
Unit 3 began this report period in Mode 5,
and was nearing
completion of its first refueling outage.
As post-outage
maintenance
and testing were completed
and required prerequisites
were met, Unit 3 heated
up to Mode 4 and then achieved
Mode 3 on
November 30,
1989.
During steam testing of the turbine-driven
pump, the licensee
determined that operability
questions
associated
with pump discharge
pressure
oscillations
and
throttle valve gland leakage
required
pump disassembly
(see Section
17).
Thus, Unit 3 was returned to Mode 4 in compliance with
technical specification (T/S) requirements
System operability.
Following pump reassembly,
the Unit was retur ned to Mode
3 and
remained in Mode 3 through the end of the inspection period.
tI
d.
Plant Tours
The following plant areas
at Units 1,
2 and
3 were toured by the
inspector during the inspection:
Auxiliary Building
Containment Build)ng
Control Complex Building
Diesel Generator Building
.Radwaste
Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
Central
and Secondary
Alarm Stations
The
2.
3.
5.
7.
8.
9.
following areas
were observed
during the tours:
0 eratin
Lo s and Records - Records
were reviewed against
ec n)ca
pec>>ca
)on and administrative control procedure
requirements.
Monitorin
Instrumentation - Process
instruments
were observed
or corre at)on
etween
c annels
and for conformance with
Technical Specification requirements.
Shift Mannin
- Control
room and shift manning were observed
or con ormance with 10
CFR 50.54(k), Technical Specifications,
and administrative
procedures.
E ui ment Lineu
s - Various valves
and electrical
breakers
were
ver) )e
o
e )n 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
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 )ons
o
sys
em leakage,
improper
lubrication, or other conditions that would prevent the systems
from fulfillingtheir functional requirements.
Fire Protection - Fire fighting equipment
and controls were
'f
ithT hi
1SP if'i
d
administrative procedures.
Plant Chemistr
- Chemical analysis results
were reviewed for
con ormance w)th Technical Specifications
and.administrative
control procedures.
~Securit
Activities observed for conformance with regulatory
requ)rements,
implementation of the site security plan,
and
administrative procedures
included vehicle and personnel
access,
and protected
and vital area integrity.
The Central- Alarm Station
and Secondary
Alarm Station were
included in plant tours.
The inspector raised
concerns
regarding
compensatory
posts
which were discussed
with NRC
security personnel'ollowup
on these
items will be performed
by Region
V based Security Inspectors.
10.
Plant Housekee
in
- .Plant conditions
and material/equipment
s orage
were
o served'to
determine
the general
state of
cleanliness
and housekeeping.
Housekeeping
in the
radiologically controlled areas
was evaluated with respect to
'ontrolling
the spread of surface
and airborne contamination.
11.
Radiation Protection Controls - Areas observed
included control
po>n
opera
>on, recor
s
o
icensee
surveys within the
radiologicalIy controlled areas,
postinq of radiation
and high
radiation areas,
compliance with Radiation Exposure Permits,
personnel
monitoring devices
being properly worn,
and personnel
frisking practices.
The inspector
noted
one isolated=occurrence
of an apparent
improper transfer of material
across
a posted
contaminated
area
barrier
on Unit 2, which could have resulted in a personnel
contamination,
although
none actually occurred.
This was
discussed
with and acknowledged
by the appropriate
management.
No violations of NRC requirements
or deviations
were identified.
4.
En ineered Safet
Feature
S stem Malkdowns - Units 1
2 and
3
Selected
engineered
safety feature
systems
(and systems
important to
safety)
were walked
down by the inspector to confirm that the systems
were aligned in accordance
with plant procedures.
During the walkdown of
the systems,
items such
as hangers,
supports,
electrical
cabinets
and
cables,
were inspected
to determine that they were operable,
and in a
condition to perform their required functions.
Accessible portions of
the following systems
were walked
down during this inspection period:
Unit 1
o
Containment Recirculation
and Tri-Sodium Phosphate
Baskets.
Unit 2
o
"A" and "B" Emergency Diesel Generators.
Unit 3
o
Containment Recirculation
and Tri-Sodium Phosphate
Baskets.
0
Condensate
Storage
Tank.
No violations of NRC requirements
or deviations
were identified.
5.
Monthl
Surveillance Testin
- Units 1
2 and
3
61726
Selected
surveillance tests
required to be performed by the
Technica'l Specifications
(T/S) 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 T/S; and 4)
test results satisfied
acceptance
criteria or were properly
dispositioned.
Specifically, portions of the following surveillances
were observed
by the inspector during this inspection period:
Unit 1
Procedure
Unit 2
Procedure
Unit 3
Descri tion
Containment
Bui 1 ding Atmospheri c Penetrati ons
~oi ti
Excore Linear Calibration,
Channel
"A"
C.
Procedure
D~iti
Atmospheric
Dump Va1ve Testing in Mode
3
The inspector
was
made
aware that
a System Engineering
Lead Engineer
had written a memorandum to the System Engineering
Manager
expressing
concern that
some completed surveillance test packages
were being reviewed
and signed
by system engineers
who were not
properly qualified in accordance
with ANSI 3. 1.
The inspector
contacted
the Lead Engineer to determine the content of the-
memorandum.
Based
on this discussion,
the inspector confirmed that
the
Lead Engineer
had written a memorandum to the System Engineering
Manager;
however, the memorandum
described
the lack of a program to
document engineer qualifications.
A copy of this memorandum
could
not be located
by the
Lead Engineer or System Engineering
Manager.
The Lead Engineer
had
no concern
regardinq
improper signatures
on
surveillance
packages.
The inspector
reviewed the licensee's
procedure for tracking the
ANSI qualifications of Evaluation
I Engineering
Department personnel
that perform surveillance t'est
procedures.
This procedure,
70DP-OTR01, "gualification and Training
Requirements for Engineering Evaluations Department,"
which was
issued
on September
1, 1989, is currently under revision and three
separate
procedures will be issued.
These will be for the system
engineers,
reactor engineers,
and technical
support engineers.
The
inspector determined
the current procedure
and the proposed
revisions are sufficient to document the qualification status of
Evaluation Engineering
Department
personnel
provided the procedures
are fully implemented.
No violations of NRC requirements
or deviations
were identified.
6.
Monthl
Plant Maintenance - Units 1
2 and
3 (60710
62703)
a.
b.
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 administrative
and
maintenance
procedures,
required guality Assurance/guality
Control
(gA/gC) 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.
Specifically, the inspector witnessed portions of the following
maintenance activities:
Unit 1
o
Core Reloading Activities
o
Stuck Fuel Assembly Recovery
o
Installation of Fuel Assembly Restraining
Device
o
Control Element Drive Mechanism Lift Coi] De-stacking
and
Inspection
o
Fuel'uilding Upender Hydraulic Power Unit Repair
o
Troubleshooting the "B" Channel
Plant Protection
System
Parameter
13 Bypass Light Failure
Unit 2
o
Electrical
Reassembly
of Valve AF-V31
o
Troubleshooting
a Control Board Annunciator
o
Removal of Lagging from valves
PC-V024 and
Unit 3
o
Pressure
switch- calibration
on MSIV 180
o
Troubleshooting
Steam
Bypass
Control Valve 1008
o
Troubleshooting Auxiliary Feedwater
Pump "A"
No violations of NRC requirements
or deviations
were identified.
0
Si n-offs Not Made As Maintenance
Was Performed - Unit 1 (62703
The inspector
observed
maintenance
being performed
on the Unit 1 "B"
containment
spray
pump motor on November 14, 1989.
The inspector
reviewed Work Order
(WO) 362320 at the work location and observed that
none of the work steps
contained in the work instructions
had been
initialed, even though the job had proceeded to the point that power
cables
were being reassembled.
The
gC inspectoi
present
explained the
work instructions
and indicated that step 4.5 was in progress.
The
NRC inspector
asked the electrician
how the completion of each step
of the procedure
was assured
and was told that it was
done by memory and
documented
on the official copy when the job was completed.
When asked
if this was the way work was normally done, it was indicated that check
marks were sometimes
placed
on the "field copy" as work progressed.
The
gC inspector
showed the
NRC inspector his notebook,
which contained
a
list of steps
completed
where
gC hold points were included.
The inspector reviewed
a copy of the
WO in the electrical
shop
and
observed that it also did not contain initials indicating completion of
prerequisites
or initial notifications.
Similar failures to perform
signoffs
as the work was completed
were identified at Unit 2 in
Inspection
Reports
50-529/88-28,
Section
12,
and 50-529/88-31,
Section
10
and for Unit 3 in Inspection
Report 50-530/89-28.
This 'was the subject
of Notice of. Violation Items 529/88-31-01
and 530/89-28-09.
Arizona Nuclear Power Plant
(ANPP) procedure
"Conduct of
Maintenance,"
step 3.8.6 states,
"Work instruction steps,
sections of
steps
and data sheets
shall
be properly documented at the time of
performing the step or soon thereafter if conditions
do not permit."
The
failure to follow procedures
is a violation of Technical Specification 6.8. 1(a)
and is an example of management
expectations
not being fully
implemented at the working level in both the maintenance
and quality
control areas
(528/89-50-01).
The
NRC inspector discussed
the incident with both Unit 1 and
gC
management.
The electricians
and
gC inspector involved in this situation
have
been instructed
on management's
expectations
in their respective
areas
and disciplinary action was taken to reinforce management's
intentions.
The
WO was
amended
and the work was reperformed
satisfactorily.
Mis lacement of a Fuel
Assembl
Event - Unit 1 (40500
60705
60710
During the Unit 1 core reload, at approximately 9:35
PM on November 16,
1989,
a new fuel assembly
was grappled
from the wrong spent fuel pool
location and was almost fully inserted into the wrong core location
before the error was discovered
by the on-shift Reactor
Engineer.
I
I
k
Pre aration of the Transfer
Forms
The error occurred
because
the fuel transfer
form which specifies
the transfer
sequence,
serial
numbers,
and locations incorrectly
specified spent fuel pool location
P38 where location
P28 should
have
been specified.
These
forms are partially printed, then
. handwritten to fill in fuel assembly serial
numbers,
spent fuel pool
locations
and core locations.
The completed
forms consist of
several
hundred line entries.
The Reactor Engineering Technician
who made the error prepared.-the
entire core load transfer
form but
did not sign it.
The Reactor Engineer
who signed the form as
preparer
said that approximately
75K of the form had been reviewed
line by line prior to signing.
The 'Reactor Engineer
who signed
as
approver signed without a line by line review.
There
was
no
requirement for the Reactor Engineering Supervisor to review the
transfer form prior to use.
The procedure
which governs
the
reparation of the transfer
forms,
72AC-9NF01, "Control of SNM
ransfer
and Inventory," did not specify who is to sign the form as
preparer or approver other than
on the signature
page,
Appendix
C of
this procedure<
which simply identifies the signer in both cases
as
a "Rx Eng Rep."
This procedure
also did not specify what these
reviews should entail.
Failure to have
an adequate
procedure
appropriate to the circumstance
is
a violation of NRC requirements
(528/89-50-02)
and highlights the need to improve the performance
engineering
and technical
work.
The inspector also noted that
approximately six weeks elapsed
between
the preparation
review of
these transfer forms,
and their actual
use,
thereby giving ample
time for a thorough review.
The licensee
responded
by changing procedure
72AC-9NF01, "Control of
SNM Transfer
and Inventory," to change
the second
approval
signature
to an "Independently Verified and Approved For Use" signature with
procedural
steps defining what the two transfer form signatures
represent.
The independent
review signature
was defined to be "...
a 100'erification of all information on the
MBA Transfer Form...."
The licensee
also revised the Unit j. Core Reloading procedure,
72IC-lRÃ03, to: 1) clarify what the refueling Senior Reactor
Operator's
(SRO) function is and where the
SRO is to be stationed
during core alteration,
2) define what fuel assembly
intermediate
storage
locations
should
be used,
in order of preference,
as well as
defining the criteria for using in-core locations for intermediate
storage
locations
and,
3) using visual verification of assembly
seating
as
each
assembly is seated
where practical.
Procedure
72AC-9NF01 is generic to all three units at Palo Verde.
There is a
separate
core off-loading and core re-loading procedure for each
unit,
a total of six procedures.
The license
subsequently
revised
these
procedures.
Immediate Actions
After the error was discovered,
the on-shift Reactor Engineer
documented
the error in the Reactor
Engineer Test
Log portion of
72IC-lRX03, "Core Reloading," but did not include
a full description
of pertinent information in that
he did not specify
how far the
assembly
had been inserted
into the core prior to the discovery of
the error.
Core reloading
was halted for about five and one-half
hour s while the remainder of the transfer form was verified to be
correct.
After this review was complete core reloading continued at
3: 12
AM.
Later that morning, the Operations
Supervisor
was
appraised
of the error but was assured .that the error was detected
before the incorrect assembly
reached
the core.
Since the
Operations
Supervisor
understood that the assembly
was never placed
into the core, the event
was not considered to have major importance
and was, therefore,
not communicated to higher management.
The
significance of this event was finally app'arent to higher
management
the following week durin'g the investigation of the subsequent
stuck
fuel event (see paragraph
9).
The inspector stated to management
his opinion that it is important
'for abnormal
events to be fully evaluated
by appropriate
levels of
management
and for all pertinent
lessons
learned to be implemented
prior to continuing the activity which did not proceed
as expected.
The inspector
noted that core loading was halted for five and
one-half hours while the transfer
form was reviewed.
The licensee
further noted that the Shift Supervisor
was the most senior
management
representative
who was
aware of the event until the
following morning after refueling,had
continued.
The inspector further noted that it was
a communication error that
led the Operations
Supervisor to not appreciate
the significance of
the event
and not raise the issue
higher until after the
investigation of the stuck fuel event uncovered this event three
days later.
The licensee
responded
by reviewing the remainder of the transfer
form and by having the fuel vendor evaluate
the effect of this event
and the mis-positioning of the four most reactive
assemblies
in the
four most reactive core locations.
The results of these analysis
were that both configurations resulted in a shutdown margin well
within the Technical Specification requirements.
Mana ement Control of Plant Activities
The inspector
concluded that with regard to this event,
management
failed to define the threshold for raising problems
beyond the Shift
Supervisor in a timely fashion,
and core alterations
continued
before
management
was provided the opportunity to review the event
to ensure that lessons
learned
were appropriately
implemented.
Inaccurate
communication of the details of this event also
contributed to the failure to appraise
management
of the situation.
The inspector
concluded that additional
management
attention is
necessary
in these
areas.
10
9.
One apparent violation of NRC requirements
was identified.
Stuck Fuel
Assembl
- Unit 1
40500
93702
While reloading the core,
the Refueling Senior Reactor Operator
(SRO) was
unable to fully lower the fuel assembly'nto
core location L-17 (the last
'ocation
in that core row).
After discussion with the on-shift Reactor
Engineer,
the refueling team
assumed that the assembly in L-17 was
bowed,
and caused
the difficulty in fully seating
L-17.
The team decided to
move the fuel assembly
in L-17 to an intermediate
storage
location,
move
the assembly in L-16 to an intermediate
storage location, place the
assembly for location M-17, and then try to place .the assembly for
location L-17.
This was accomplished
successfully.
The refueling team
then tried to seat the assembly for location L-16 which could not be
fully seated
but was obstructed further into the core than L-17 had been.
This seemed to confirm the theory that L-17 was
bowed toward L-16.
The
team .then decided to repeat this process
by moving the assemblies
in L-16
and L-15 to intermediate
storage locations,
then to fully seat
L-16.
This was also accomplished
successfully.
When they then tried to seat
L-15, it could not be fully seated
but was obstructed
even further into
the core than L-16 had been.
When the team attempted to repeat this
sequence
of "backing down the row" they were unable to remove the
assembly at L-15 and were forced to stop the core reload
so they could
decide
how to move the assembly at L-15.
A subsequent
inspection
using lights suspended
into the core basket
and
binoculars
revealed that the assembly at L-17 was not significantly
bowed, but that the assembly in L-14 was
bowed sufficiently to not be
seated at all.
The bottom nozzle of the L-14 assembly
straddled
the core
basket pins, which are normally shared
by assemblies
was obstructing about half of L-15's bottom seating
area.
The assembly
in L-15 was stuck about 40 inches
above the core bottom and the bottom
nozzle of the assembly
in L-15 was compressing
the fuel pins of L-14
inward.
~
The Resident
Inspectors verified containment integrity and evaluated
and
confirmed that existing
FSAR analyses
bounded the worst case
event
associated
with the stuck assembly.
The inspector also visually verified
the position of the stuck assembly,
determined that the refueling machine
did have
a secure grip on the assembly
and was supporting the stuck
assembly's
weight,
and evaluated
the location and reason for the location
of all other assemblies
not in the spent fuel pool. It was during this
verification that the inspector
learned that the event addressed
in
paragraph
8 of this report occurred.
The inspector also evaluated
the
increased
chemistry
and radiological sampling/surveys
which were
instituted
as
a result of the stuck assembly
and
had
no further questions
regarding sampling/surveys.
The inspector
noted that the Unit 1 Plant
Manager directed core alterations
and any attempts
to free the stuck
assembly to be halted
as
soon
as
he was notified of the problem on
November 19, 1989,
so the, situation could be fully evaluated
and recovery
efforts proceed in a well-controlled manner.
During the following week
the licensee
had numerous
conversations
with the Resident
Inspectors,
Region
V and the
NRR Licensing Project Manager,
to clarify various
technical
and licensing issues.
~I
Two of these technical
issues
related to Radiological Controls.'he
first was
a reappraisal
of the radiation exposure
levels at the refueling
bridge and at the reactor vessel
flange due to the stuck spent assembly
protruding 40 inches
above the .top of the core in the event of a cavity
seal failure.
The second
was
an evaluation of the expected
airborne
concentration
should
one fuel pin rupture.
The first issue
had not been evaluated
when the inspector questioned
the
Unit 1 Radiological Protection
Manager
on November 20, 1989,
two days
after the assembly
was stuck.
The following day the licensee
determined
an estimated
dose rate at the reactor vessel
The inspector
concluded that the licensee
required prompting to consider the possible
radiological effects of this incident assuming
a concurrent incident,
such
as cavity seal failure, for which licensee
established
procedures
were available,
but which assumed normal;initial conditions.
The second
issue associated
with expected
airborne concentrations
from
the rupture of one. fuel pin resulted in a calculation which was reviewed
and passed
to Region
V based
inspectors.
The result which was initially
passed
to
NRC Region
V was
a factor of 1,000 higher that the correct
calculation
due to an error which was not discovered
during the
licensee's
review.
When Region
V inspectors
questioned
and performed
independent calculations,
the error was discovered.
The licensee
acknowledged their error when questioned
by the Region
V inspector.
The
inspector
considers it important for technical
data to be accurate,
especially during abnormal-situations-
when people or organizations
are
likely to act
on this information.
The licensee
responded
by correcting
the calculation
and acknowledging the inspector's
concern.
This point
was also emphasized
during the exit meeting for Region
V inspection
report 89-51.
The licensee
prepared
the detailed designs
to fabricate temporary devices
to restrain the assembly at L-14 prior to attempting to move the assembly
in L-15.
As a parallel activity, the licensee
wrote procedure
"Fuel Assembly Recovery," which required
a 10
CFR 50.59
review concluding that this activity did not present
an unreviewed safety
question.
The inspector
reviewed this procedure
and the
10
CFR 50. 59
review and concluded it was adequate.
Once the procedure
was approved
and the restraining
devices
were in
place,
the licensee
recovered
the assembly
by exerting approximately
1630
pounds of force to begin moving the assembly,
then approximately
1750
pounds of force to free the assembly grid straps
when they first
interlocked.
The assembly
was then inspected
and seated
in an incore
intermediate
storage
location.
The inspector
observed
the assembly
recovery from containment
and noted that the recovery
was carefully
planned
and executed with appropriate
controls
and contingency plans.
Several
days of subsequent
fuel inspections
ensued
which resulted in the
licensee
deciding to reconstitute
the
bowed assembly in L-14 and attempt
reconstitution
on the
new assembly in L-16.
The remainder of the core
was loaded
and locations
L-14, L-15, L-16 and L-17 remained
empty pending
reconstitution at the
end of this inspect'ion period.
12
The licensee's
response
to this event
was closely intertwined with their
response
to the fuel misalignment event since
management
beyond the Shift
Supervisor
was not fully aware of the mis-fueling event until this stuck
assemble
event recovery
was underway.
Beyond the procedural
enhancements,
the refueling
SRO drafted
a
memo to Fuel
Load Teams
documenting the problems
and the procedui al enhancements
desiqned to
eliminate these
problems.
The licensee's
response
to the radiological
concerns
raised
by the
NRC are discussed
above.
The inspector concluded that the. licensee
proceeded
in the face of
uncertainty
when the assemblies
in core locations
fully insert and was not identified to supervision
beyond the Shift
Supervisor until after the assembly in L-15 was stuck.
The licensee's
response
to use
a light to verify the seating of each
assembly
as it is
loaded into the core where practical indicates
the ease
by which the
operators
could have stopped to ensure'hat
they fully understood
the
problem before proceeding to a stuck assembly.
In addition, the inspector
concluded that the licensee
subsequently
failed to rapidly and accurately anticipate
the potential radiological
consequences
of this abnormal
event
and its bounding events.
No violation of NRC requirements
or deviations
were identified.
Mron
Assembl
Gra
led and Lifted in the
S ent Fuel
Pool - Unit 1
1
After the stuck fuel assembly
was freed
and core reloading continued,
the
Spent
Fuel
Pool
(SFP) machine operator grappled the fuel assembly at
location
N31 and raised it approximately
3 inches (to ensure it was
grappled)
before the Reactor
Engineer discover ed it was the wrong
assembly
and stopped its movement.
The
SFP operator
had just moved the
assembly in SFP location A29 to containment.
The next location assembly
to be moved was AA29.
The
SFP operator misread the sheet,
thought the
AA29 assembly
had been
moved, turned the page
and grappled the next
assembly to be moved at
SFP location N31.
The refueling team
had been directed to contact the Unit 1 Operations
Manager if anything abnormal
occurred during the continuation of core
loading.
This did not occur,
and the refueling team reseated
the
assembly inadvertently lifted at location N31, and proceeded
with core
load.
The Unit 1 Operations
Manager
was not appraised
of the error,
until questioned
by the
NRC Resident
Inspector at which point refueling
was immediately halted.
An investigation
ensued
and another
change
was
made to procedure
72IC-lRX03, "Core Re-Loading," to define specific
communications
requirements
designed to catch this and other fuel
handling errors.
The licensee
revised the "Core Re-Loading"
and "Core
Off-Loading" procedures
to incorporate
these
communications
requirements
prior to recommencing
fuel movement.
The inspector considers it important for fuel movement to be
a very
carefully controlled evolution so errors are minimized if not eliminated.
The inspector
concluded that even in light of the recent fuel handling
problems,
management's
expectations
for communicating problems to
13
management
so the problems
can
be resolved
and lessons
learned
be
implemented prior to proceeding
has still not effectively been
communicated to the working level.
No violation of NRC requirements
or deviations
were identified.
Unofficial Procedure
Chan
e - Unit 1 (61726)
During the. performance of 41ST-lZZ08, "Containment Building Atmospheric
the Chemistry Effluent Technician
used Unit 1 Chemistry
Standing Guideline 1-EFF-89-006:-'0,
"Channel
and Channel
Functional
Checks
on RU-37 and RU-38" in lieu of Steps 6.4.4.3, 6.4.4.4
and 6.4.4.5 of
procedure
"Gaseous
Radioactive
Release
Permits
and Offsite
Dose Assessment."
This Chemistry Standing Guideline was developed
on
October 20, 1989, in response
to
HPES Evaluation 89-021 when
a Unit 3
Chemistry Effluent Technician inadvertently r'estored
10 times the
required high alarm setpoint during a weekly channel
check.
This was
an
interim measure while a new surveillance
procedure
was being developed to
standardize
the details
on operating the radiation monitor keyboard.
The
inspector discussed
this with the Chemistry Effluent Supervisor
and
Chemistry Manager
and noted that management's
endorsement
of this lack of
formality in the performance of activities associated
with surveillance
testing is contrary to conservative plant operation.
The licensee
agreed
that -this is not the message
that management
should
be
be communicating
to plant workers
and coincidentally learned that the
new procedure
would
be completed
near the end of this inspection period.
The inspector
had
no further questions
on this issue.
No violations of NRC requirements
or deviations
were identified.
Incorrect Clearance - Unit 1 (93702)
The clearance
to repair/rework 1-1/2 inch sealtite
and fittings for
instrument rack 01JRCEA01A required opening breaker
52-D-1202, which
removed power from the Reactor Coolant System
(RCS) and Chemical
and
Volume Control System
(CVCS) process
instrumentation.
When this
clearance
was performed
a large
number of RCS and
CVCS instruments lost
power.
Among these
was Volume Control Tank (VCT) level.
When the
level instrument lost power, the charging
pump suctions
were
automatically realigned
from the
VCT to the Boric Acid Hakeup
Pump
(BANP).
Since the Refueling Water Tank was below 73X for refueling, the
BANP did not start
and the charging
pump tripped on low suction pressure.
When the operators
realized what had happened
they restored
power to the
RCS and
CVCS instrumentation
by shutting breaker
52-D-1202
and restored
charging flow.
This incident was caused
by inattention to the
preparation
and review of the clearance.
The licensee
stated that the
involved individuals
had been counseled.
No violations of NRC requirements
or deviations
were identified.
S stem Heatu
Rate .Exceeded - Unit 2 {93702)
During a reactor coolant system
(RCS) heatup
on November
21,
1989, the
RCS heatup rate limit was exceeded.
The heatup started at 12:45
PH from
an
RCS cold leg temperature
(Tc) of 190 degrees
F, with three reactor
coolant
pumps
(RCP's)
and Shutdown Cooling (SDC) in operation.
At least
one Reactor Operator
(RO) had expressed
anxiety regarding the status of
the
Mode 5 to Mode 4 change checklist,
which was believed to expire at
1:30
PH.
The Shift Supervisor
had assured
the
ROs that the checklist
had
been completed within the required
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period,
and that
no time
constraint existed for performing the actual
mode change.
Mode 4 would
be entered
when Tc reached
210 degrees
F.
At 1: 15 PH, Tc was 208 degrees
F,
and at 1:45
PM, Tc was
232 degrees
F.
During the hour ending at 1:45
PH, Tc had in'creased
by 42 degrees
F,
exceeding
the 40 degrees
F per hour limit specified in Technical
Specification (T/S) Limiting Condition for Operation 3.4.8.1(a).
The
action statement
was entered at 1:45
PM, and all requirements
of the
action statement
were performed.
At 2: 15
PM, Tc was
252 degrees
F,
resulting in a maximum one hour heatup
.of 44 degrees
F, however, the
heatup rate for that half hour was 40 degrees
F per hour, which is within
the T/S limits and is in compliance with the action statement.
At approximately 4:45
PM, the inspector
asked what time
SDC had been
secured.
As no entry had been
made in the control
room logs, the
operators
determined that the
Low Pressure
Safety Injection (LPSI) pump
had been stopped at 2:25
PH, but that
SDC had effectively been
secured at
some previous
undetermined
time by bypassing
the
SDC heat exchanger.
Subsequent
investigation determined that the
SDC heat exchanger
had been
bypassed
immediately prior to the start of the heatup.
After the absence
of information in the control
room logs regarding the securing of SDC was
pointed out by the inspector to the RO's,
a late entry was
made
indicating the stopping of the
LPSI pump and completion of terminating
SDC.
The inspector
concluded that insufficient attention
had been given to
controlling the heatup
by the Control
Room operators
and their
super vision.
The inspector
reviewed procedure
"Cold Shutdown
to Hot Standby,
Mode 5 to Mode 3," and determined that procedure
guidance
for monitoring the heatup
had been met.
The inspector
concluded that the
guidance in this procedure
was inadequate.
Additionally, the inspector
concluded that the Control
Room logs did not contain adequate
information
regarding the major evolutions involved in the heatup.
The licensee
independently
concluded that procedure
420P-2ZZ01 should be
enhanced
to provide more guidance
on monitoring heatup rate
and
a
procedure
change
was
made.
The inspector
observed
the first briefing
given to operators
on these
changes,
and considered
the briefings
satisfactory.
Also, in response
to a refueling water tank makeup water
spill on November 26, 1989,
more specific guidance
was being developed
on
maintaining adequate
operator
loqs (see
paraqraph
14).
Additionally, the
Assistant Shift Supervisor
on shift at the time has
been relieved of
control
room duties pending
a management
evalution of his.ability to
fulfillhis responsibilities
in overseeing plant evolutions.
The
inspector
concluded that these
actions
appeared
adequate.
No violations of NRC requirements
or deviations
were identified.
15
14."
Refuelin
Mater Tank
RMT) Makeu
Mater
S ills - Unit 2 (93702)
On November 26, 1989, while performing procedure
"RCS Mater
Inventory Balance,"
two spills of slightly contaminated
water occurred.
One spill was in the vicinity of the Boric Acid Batch Tank (BABT), and
the other was next to the
RMT, outside the Auxiliary Building but'nside
the Radiologically Controlled Area (RCA).
The spills:resulted
from two
valves,
CHN-V649 (BABT eductor inlet valve), and
CHN-V126 (BABT eductor
outlet valve), being open after their manipulation during a boric acid
, addition to the
RMT on November.
9., 1989.
Additionally, the
body-to-bonnet bolts
on CHN-V126 and
PCN-V024 were insufficiently
torqued,
such that they would not withstand their normal design pressure
without leaking.
During the performance of 42ST-2RC02, with both a Boric Acid Makeup
Pump
(BAMP) and
a Reactor Mater Makeup
Pump
(RWMP) in service,
the makeup
mode
selector switch was taken to manual.
This causes
closure of CHN-V510,
and resulted in a pressure
spike, estimated at 191 psig.
Because of the
inadvertently
open valves, this pressure
was exerted
on portions of the
RMT makeup piping not normally exposed to this pressure.
Mhile this
pressure
is less that the design pressure
of the system, it was
sufficient to unseat the bonnets
on CHN-V126 and PCN-V024, resulting in
the spills.
After closing
CHN-V126 failed to stop the spill, CHN-V649
was closed
and the spill was terminated.
The spill from CHN-V126 covered most of the floor on the west side of the
120 foot elevation of the Auxiliary Building.
The area
was immediately
posted
as
a contaminated
area,
and the spill was cleaned
up.
The valve
was replaced
and the bonnet bolts retorqued.
During the repair of CHN-V126, it was noted that the heat tracing went
over the bonnet.
After the valve manufacturer indicated that the heat
tracing could damage the bonnet,
the licensee initiated work orders to
check all diaphragm valves to ensure
the heat tracing did not go over the
The spill from PCN-V024 was estimated to be about
50 gallons,
and was
limited to the concrete
surfaced
area
immediately around the valve.
After the area dried, it was covered with stripable paint.
The valve
was replaced
and the bonnet bolts retorqued.
Decontamination
efforts were not complete at the end of this report period.
Two significant problems
were identified during the course of the
licensee
s investigation.
First, since two valves were apparently left
open inadvertently,
the licensee failed to maintain adequate
control of
system status.
Since
no other explanation
could be determined,
the
licensee
believes
the valves
may have
been left open following the last
boric acid addition.
Second,
operator
logs contained insufficient
information regarding the manipulation of valves
and equipment to allow
determination of the sequence
of events
leading
up to this event.
Letters providing interim guidance
on these
subjects
have
been
issued
and
reviewed with each operating shift.
Once refined, the licensee
committed
to incorporate this guidance into appropriate
procedures.
16
No violations of NRC requirements
or deviations
were identified.
Reactor Startu
- Unit 2 (71707
On November 30, 1989, the Unit 2 reactor
was started,
going critical at
5:25
PM.
At 10:59
PM, with the reactor at 1/2 percent power, while
withdrawing Group 4 and Group
5 Control Element Assemblies '(CEAs), full
scale deflection of the Control Element Drive Mechanism
(CEDM) control
system
ground detector indication occurred.
Procedure
"CEA
Operation
While Monitoring for Ground Faults," prohibits motion of any
CEA with a known ground while in Modes
1 and 2,
and requires
a reactor
shutdown
by boratson if ground. indication is observed
on any
CEA coil in
regulating groups 3, 4,
5 or P.
Boration was
commenced at 2:42 AM, on
December',
1989,
and the reactor
was subcritical at 3:40 AM.
After extensive monitoring of approximately 1,000
CEDM steps
on both
groups
4 and 5, the licensee
determined that the ground indication was
not reproducible
and
no grounded
CEDM coils were identified.
The reactor
was brought to criticality on December
2, 1989, at 4:41
PM, and
Mode 1
was entered at 10:48
PM.
The unit was paralleled to the grid on December
3, 1989,
and reached
100 percent
power at 5:13
AM on December
5, 1989.
No violations of NRC requirements
or deviations
were identified.
One violation of NRC requirements
was identified.
Auxiliar
Pum
Pressure
Pulsations - Unit 3
62703
92700
and
On December
4, 1989 during performance of surveillance test 43ST-3AF02
on
the turbine-driven auxiliary feedwater
pump,
a discharge
pressure
of 100
psi higher than the previous baseline
readings for miniflow recirculation
was observed.
Pulsations
were also observed
on pressure
instrumentation
and heard
by the system engineer.
These pressure
pulsations
were similar
to problems
encountered
during initial startup testing of the auxiliary
pumps.
The initial cause of the pressure
pulsations
was believed to be the
impeller assembly or a blocked flow orifice.
The impeller had been
replaced during the refueling outage to correct
an unrelated
problem.
The licensee
did not find any obstruction in the orifice, the rotating
assembly
was replaced
and surveillance test 43ST-3AF02
was reperformed
on
December
12,
1989.
High discharge
pressure
and pressure
pulations
were
again present with the
new rotating assembly.
The licensee
continued troubleshooting efforts by changing out the
miniflow recirculation orifice from Unit 1.
The Unit 1 flow orifice also
failed to correct the problem.
The licensee
was in the process
of
further troubleshooting at the end of this inspection report period which
consisted of a proposed microflow line in addition to the miniflow
recirculation orifice.
The licensee
consulted
the
pump vendor
and concluded that the
pump was
however the long-term effects of the pulsations is currently
under -investigation
by an independent
pump expert..
No violations of NRC requirements
of deviations
were identified.
Missin
Handwheels
on Downcomer Feedwater Isolation Valves - Unit 3
10
During a Unit 3 plant tour on December
5, 1989, the inspector
noted that
handwheels
on Downcomer Feedwat'er Isolation valves
SGA-UV-175 and
SGA-UV-172 appeared
to be missing.
The licensee
stated that these
valves
are immediately adjacent to identical redundant
valves
such that the
handwheels
would interfere with each other if both were mounted.
The
licensee further stated that the handwheels
mounted
on the adjacent
valves could be removed
and placed
on valves
SGA-UV-175 or -172 if
needed.
The inspector
noted that the operations
procedure
which governs local
manual operation of these valves,
made
no mention of the
need
to share
one
handwheel
between
two valves.
also, this condition existed
in Units 2 and 3, but not in Unit 1 where
a slightly modified handwheel
was used to avoid interference.
Finally, a system engineer
had noted
this discrepancy
in Unit 2 on November 5, 1989 and
had initiated a work
request
(¹347089) to replace the missing handwheels.
The work request
had not been entered into the work control computer
system
(SIMS) as of
one month later.
The safety significance of these
valves is that the only available
flowpath for one of three auxiliary feedwater
pumps
(AFN-P03) required
by
Technical Specifications is through these
valves.
The valves are
remotely operated
and held open by instrument air with a nitrogen
backup.
The
FSAR (10.4.7.1.1)
requires that these
valves
continue to f'unction remotely for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following a loss of offsite
ower (LOOP).
Local manual operation capability is not required by the
icensing basis,
although it is highly advisable
as
was
shown by the
need
to manually operate
ADV s following the Unit 3 Parch 3, 1989 reactor trip
event.
In fact, the licensee's
valve equipment
and operating procedures
provide for this capability.
In summary,
the inspectors
stated
the following concerns.
Procedural
guidance
was not available to auxiliary operators
which described
the
need to transfer
handwheels
between adjacent
valves for manual
valve
operation.
Further,
although this discrepancy
was identified by a system
engineer in Unit 2, the work request
only addressed
the Unit 2 condition
and was not in the work planning system
one month after it had been
written.
The difference which exists
between Unit 1 and Units 2/3 is an
indication of a divergence of systems
and procedures
between the three
units that
may be taking place.
Finally, Unit 3 routine operations
tours
failed to identify this discrepancy.
At the resident inspector exit meeting for this inspection,
'licensee
management
stated that the handwheels
would be made consistent
among the
three Units.
Responsible
engineering
management
later indicated that the
previously initiated work request for Unit 2, pIus
a similar one for Unit
3, would provide handwheels
where they were missing.
No violations of NRC requirements
of deviations
were identified.
18.
Al le
A.
~ B.
C.
ation Follow-u
- ATS NO. RV-88-A-055
Characterization
uality Assurance
is not following up on Corrective Action Requests
~
~
CARs).
Im lied Si nificance to Desi
n
Construction or 0 eration
Failure to verify the adequacy of corrective actions
could challenge
safe operation of the plant.
Assessment
of Safet
Si nificance
The following six CAR's were reviewed by the inspector to verify
that
QA was actively following-up in accordance
with the licensee's
QA program.
These six CAR's are part of a total of eleven
identified by the alleger; the other five CAR's were previously
reviewed
and documented in NRC Report Nos. 50-528/89-12,
50-529/89-12
and 50-530/89-12.
CP87-0111 - This
CAR was
opened
by Vendor Quality to Cooper Energy
Zervices
Group
(ESG)
on December
15,
1987 for not initiating a
Request for Drawing Action (RFDA) prior to making drawing changes.
This
CAR was
one of eleven
CARs issued
as the result of the Vendor
Quality Assurance
Audit conducted at
ESG on November 16-19,
1987.
The initial response
was
due by January
14,
1988 and
on January
12,
1988
ESG requested
an extension to February 29, 1988.
The Manager
of Procurement Quality informed
ESG on January
22,
1988 that the
extension
would be granted to February
15,
1988 on a one-time basis
only.
ESG responded
on February 2, 1988.
On February 29,
1988 the
Director Corporate
QA/QC sent
a letter to
ESG expressing their
disappointment
in the lack of effort ESG was putting forth regarding
all eleven
CARS.
On March 23,
1988 the Director Corporate
QA/QC
sent
a letter to
ESG thanking them for their cooperation with two
Vendor Quality representatives
in resolving the outstanding
issues
regarding the deficiencies
described
in the
CARs.
These
same
two
Vendor Quality representatives
visited the
ESG facility to assess
the status
of Correct Action Commitments which were
due by April 30,
1988.
This visit was documented
in a letter from the Director
Corporate
QA/QC to
ESG dated
May 17, 1988; this letter also included
additional actions
by
ESG to resolve the deficiencies.
Vendor
Quality again visited
ESG the week of September
12,
1988 to evaluate
the progress
completed to resolve the issues
addressed
in all eleven
CARs.
Vendor Quality returned to the
ESG facility the week of
September
26,
1988 to assess
completion of the open items
and to
assist
ESG in achieving those
means.
The results of the September
visits by Vendor Quality was sent to
ESG on a letter dated October
6, 1988.
The director Corporate
QA/QC sent
a letter to
ESG on
19
October
25,
1988 regarding
Vendor Quality's evaluation of their
responses
which incl,uded
CAR CP87-0111.
Final verification of
corrective actions
was performed by Vendor Quality during an audit
conducted
on December 14-16,
1988.
This
CAR was closed
on January
3, 1989.
CP88-0002 - This
CAR was issued
by Vendor Quality to Borg-Warner
~nustr)al
on January
12,
1988 for failure to implement design
changes.
Specifically,
as described
in LER No.87-003,
two Unit 3
shutdown cooling isolation,valves
did not have the required bolting
for the yoke to adaptor plate
as specified
on the applicable
revision of the valve assembly
drawing.
QA was involved in meetings
held at Borg-Marner facilities during
October,and
December of 1987 concerning the subject valves resulting
in several
unanswered
concerns, which initiated this
CAR with an
initial response
due by February 4, 1988.
The Borg-Marner response
is documented
in a letter to the Procurement Quality Department
dated January
29, 1988.
Two Vendor Quality Engineers,
following-up
on this response,
notified Borg-Marner that their response
was
acceptable
and corrective action verification was scheduled
the week
of March- 21,
1988.
Borg-Warner's
QA manager
requested
an extension
for the verification scheduled
on March 17, 1988, which was granted
by Procurement Quality and extended to April 15,
1988.
The licensee
received
and evaluated
Borg-Warner responses
addressed
in letters
dated
May 25,
1988 and July 1, 1988.
This review
prompted
a letter,
dated July 20, 1988,
from the Director, Corporate
QA/QC to Borg-Warner dated July 20,
1988 requesting
the performance
of additional actions
and
a response
addressing
root causes
and
actions taken to prevent occurrence
be submitted
by August 19,
1988.
This response
was issued
by Borg-Marner on August 15,
1988.
This
CAR was left opened
pending Engineering's
closing of EER 88-118
which was accomplished
on August 30,
1989.
On September
28,
1989
Vendor Quality performed
an audit at Borg-Marner to assist
Engineering in review of design
documents.
On September
29, 1987,
the issuance
date of LER No.87-003,
the licensee
imposed
Note 14 on
Borg-Marner.
Note 14,
a supplement to the Approved Vendors List, is
'ssentially
a restriction
on the release
of any items from the
Borg-Marner facility without prior licensee
approval.
As of this
inspection this restriction is still applicable.
Final verification
of the corrective actions
taken
was completed
by October 6, 1989 and
CAR CP88-002
was closed
by Vendor Quality on October 9, 1989.
CE 88-0005 - This
CAR, issued to the Central
Maintenance
I8C Rework
panes
s y,
was opened
on February 3, 1988, with an initial response
due by March 7,
1988.
This
CAR identified numerous
rework orders
that were not processed
through the warehouse/material
control
process.
That is, the storage,
issuance
and disposition of material
by the
I&C Rework Facility'as not in accordance
with approved
procedures.
Central Maintenance's
response
of February
18,
1988
denied the existence
of any conditions adverse
to quality and
therefore,
concluded that the
recommended
corrective actions
were
not required.
QA soundly rejected this response
and
on June
3,
1988
20
issued
a letter to Central
Maintenance stating this along with the
reasons
for their rejection.
Central
Maintenance
provided
gA with
an additional
response
on June
27,
1988 complete with action items
and projected completion dates.
This response
was evaluated
as
acceptable
by gA on July 15, 1988; it was noted at this time that it
would take several
months for implementation of all the corrective
actions.
The following additional
gA letters associated
with CAR
CE-88-0005
were issued
on the following dates:
August 4, 1988
(Status of Act'ion Items), August 17,
1988 (Commitment Extension
Request),
September
14,
1988 (Corrective Actions), October 17,
1988
(Corrective Action Verifications), March 27,
1989 (Verification),
March 31,
1989
(Reworked Items Awaiting MRS into Warehouse
Inventory), April 13,
1989 (Corrective Action Verification and
Status of Remaining Actions), July 7,
1989 (Verification of
Corrective Actions).
was closed
by gA on August 4,
1989.
~
~
~
~
~
C
88-0007 - This
CAR, issued to Unit 3 Operations/Radwaste
to
a
ress valve leakage
in the gaseous
radwaste
system,
was opened
on
January
21,
1988 with an initial response
due by February 12,
1988.
The response
was submitted
on February 9, 1988.
gA evaluated
the
response
and found it acceptable
on February 23,'988.
Interim
corrective action verification was found satisfactorily completed
as
documented
in a gA letter issued to Unit 3 Operations
on April 8,
1988.
This letter'escribes
gA's review of a draft procedure that
was revised to incorporate
proper controls
when. valve leakage is
suspected
and torque is to be checked.
The
CAR remained
opened at
this time pending final approval
and implementation/effective
date
being verified.
gA follow-up verification and
CAR closure
was
completed
on May 17,
1988.
CA 88-0084 - This
CAR, issued to Nuclear Engineering,
was opened
on
~co)er TI, 1988 with an initial response
date of November 10,
1988.
The adverse
condition reported
concerned
the review and approval of
vendor manuals.
The initial response
of November 15,
1988 was late
even though
gA reminded Engineering
on November 7, 1988 of the due
date.
Scheduled
completion dates for verification by gA of
corrective actions
taken were rescheduled
with gA approval.
gA
corrective action verification was partially completed
on April 15,
1989 with two items remaining
open pending resolution of a Vendor
Document
Review (VDR) checklist from EED and
PSEC.
gA follow-up was
scheduled for April 18,
1989.
On April 3, 1989,
gA sent
a letter to
Engineering Evaluation Department
(EED) regarding this
emphasizing
the importance of their direct involvement to resolve
the deficiency.
This April 3,
1989 letter also requested
a response
by April 17,
1989.
gA notified EED on April 17,
1989 that their
response
was not received;
EED subsequently
sent their response
on
April 21,
1989.
The
PS8C response
of April 26,
1989 was also late.
On April 27,
1989
gA approved the corrective actions identified by
EED
8
PS8C.
Corrective action verification was completed
on June
30, 1989;
gA closure of this
CAR was
on July 31,
1989.
The licensee
corrective action procedure,
60GB-O(01, in effect at the time of the
CAR required the Managers/Supervisors
of site organizations
to
respond to gA/gC on or before established
due dates.
Since the
21
package
status
sheet indicated
QA's awareness
of Engineering not
being in compliance with this procedure,
the inspector interviewed
QA management
about their plans to correct the problem.
This
interview revealed that
QA management
provided appropriate
corrective actions
by revising their program requirements
as
follows:
1)
Procedure
60AC-OQQ02 entitled "Corrective Actions" was revised
to read in Section
3. 1.3 that "Lack of corrective action to
identified nonconformances
is
a significant violation of the
Program.
Overdue corr'ective action responses
and/or corrective
action implementation shall
be brought to the attention of
higher management
in accordance
with the escalation
program
defined in 60AC-OQ04,
Management
Escalation
Program for
Quality/Nuclear Safety Related
Issues
and Deficiencies".
2)
A new procedure,
was issued with the purpose
being
to establish
the method to sequentially escalate
resolution of
quality/nuclear safety-related
issues
and deficiencies to
higher levels of management
when either responses
to or
completion of actions for resolution are not timely.
This
procedure
was drafted
and issued for review on August 22,- 1989
and received final
QA approval,
along with procedure
60-AC-OQQ02,
on October 6, 1989.
The'inspector
did not issue
a citation for failure of Nuclear
Engineering to follow procedures=- because
the licensee's
department
was aware of the problem and took proper corrective
actions to assure. that late responses will be resolved at
higher levels of management.
CE 88-0103 - This
CAR was issued
by Quality Engineering to the
nglneersng
Evaluations
Department
(EED) on December
6,
1988 with an
initial response
due by January
6, 1989.
This
CAR addressed
a
programmatic deficiency in the Engineering Evaluation
Request
(EER)
process.
The
EED response
of January
6, 1989 was determined
by QA
to be unacceptable;
a
new response
due date of February 2,
1989 was
established.
EED's response
was evaluated
by QA on February 18,
1989 and found acceptable
based
on the contingency that the
identified deficiencies
would be corrected
on or before
June 1,
1989.
This
CAR package
shows that although the
EED response
letter was
dated January
6, 1989, it was not received
by QA until January
9,
1989.
However,
on January
9, 1989 and prior to receiving EED's
response,
QA issued
an Overdue Notice to,EED.
Also,
EED did not
meet the June 1,
1989 contingency for revising procedure
73
AC-OZZ29.
This is expressed
in a
QA letter to
EED on July 18,
1989
which states that the
EED commitment was not addressed
in subsequent
revisions of 73 AC-OZZ29.
QA's letter further states
that
"Consequently,
the subject
CAR cannot
be closed
and is in a
delinquent status
since all of the corrective actions
were not
completed
by June 1,
1989 as committed."
EED's response
was
22
subsequently
submitted
and verified as acceptable
by gA thus closing
this
CAR on August 11, 1989.
D.
Conclusions
and Staff Positions
Review of documentation
indicated that gA was in constant
communications with the applicable organizations
responsible for
correcting adverse
conditions.
From review of the
CARs, it was
evident that the
gA follow-up actions
were adequate
to assure that
corrective actions
were adequate
and properly implemented in a
timely manner consistent with the seriousness
and complexity of the
adverse
condition.
E.
~Ati
R
i
d
None
19.
Review of Licensee
Event
Re orts - Units 1
2 and
3 (90712
and 92700)
The followinq LERs were reviewed by the Resident
Inspectors.
Based
on
the information provided in the report, it was concluded that reporting
requirements
had been met, root causes
had been identified,
and
corrective actions
were appropriate.
The below listed
LERs are
considered
closed:
Unit 2
TIMBER
89-09-LO +
89-09-L1
~ll
i ti
"Reactor Trip Due to Partial
Loss of Forced Flow."
In addition, the following LERs and special-reports
were reviewed
and
closed.
A.
(Closed)
LER 529/89-04-LO - Missed T/S Action Statement - 4. 16
KV
us
The licensee
reported that on June
17,
1989, the operability and
action requirements
of Technical Specification 3.8. 1. 1 had not been
met as
a result of the onsite class lE distribution system not being
supplied by two physically independent circuits.
The occurrence
resulted
from each of the two 1E buses
being transferred
from their
normal
power supplies to the
same alternate
startup transformer for
maintenance
on consecutive
days.
The transfer to the alternate
power supplies
were performed in accordance
with existing
procedures.
The following day, the condition was discovered,
the
affected
bus declared
bus
2E-NAN-S06 shifted back to its
normal
power supply and the T/S action statement
was exited.
Licensee corrective actions for the
LER were reviewed.
Personnel
involved in the event were counseled
by the licensee
and
a night
order issued in Unit 2 to enhance
operator
awareness
ot correct
electrical
bus alignment.
Yellow caution tags
were placed
on the
applicable control panel
breaker controls to emphasize
the
23
requirements
of T/S 3.8.1.1.
Operating
Procedure
420P-2NA01 - 13.2
KV Electrical
System
(NA), was revised to add
a precaution that
reiterates
the requirements
of T/S 3.8. 1. 1.
The equiva1ent
procedures
for the other two units were also
ch'anged.
Based
on the
review of the changes,
the
NRC inspectors
determined that the
procedures still allowed the reported condition to occur without
adequate verification to preclude the occurrence.
The, lice'nsee
responded
by stating that they would further change the affected
procedures
by adding 'a signature verification step that would
require verification of compliance with T/S 3.8.1. 1 prior to
shifting class
1E electrical
busses
from their normal
p'ower
supplies.
The licensee
committed to complete this action by
December 8, 1989.
The licensee
evaluations
and committed corrective
actions
appeared
to adequately
resolve
and preclude the reported
condition.
.The
LER was closed.
(Closed
LER 530/89-06-LO - Missed Surveillances
The licensee
reported that on June 6, 1989, while in a refueling
outage,
survei11ances
performed
once
each shift for the spent fuel
pool area monitor (RU-31) channel
check
and verification that Steam
Generator
pressure
was within the T/S limits were not performed
within the required interval.
Upon discovery, the licensee
performed the surveil'1ances
and verified compliance with applicable
action requirements
of the
T/ST
The action requirement for T/S
3. 7. 2 was met since the Steam Generator pressure
did not exceed the
specified limit.
The action requirement for T/S 3.3.3.1
was met
since
no fuel movement or crane operation
over the storage
pool were
in progress.
The licensee corrective actions
were reviewed.
-The cause of the
event
was attributed to personnel
error by responsible
operations
personnel.
In addition to completion of the required surveillances,
the licensee
issued
a night order to remind operations
personnel
of
the importance of completing T/S surveillances within the specified
time limits.
The licensee
also revised the Control
Room data sheets
to require time dependent
sign-offs for surveillances
performed
each
shift.
The licensee is also performing an incident investigation to
further eva1uate
human performance
concerns.
The licensee
evaluation
and corrective actions
appeared
to adequately
provide for
the correction
and prec1usion of repetition of the reported
condition.
The
LER was closed.
(Closed)
LERs 530/89-07-LO
and 530/89-07-Ll - Potter Brumfield
e
a
a
unc
>ons
On May 3, 1989, the licensee
determined that deficiencies
discovered
during the installation of Potter
and Brumfield relays were
reportable
under both 10
CFR Part 21 and
10
CFR 50.73.
On August 3,
1988, the licensee
reported
a defect in Potter
and Brumfield MDR
series
relays being utilized at
PVNGS, in LER 528/88-18-LO.
As
corrective action to that reported
defect,
the licensee
and Potter
and Brumfield designed
replacement
MDR series
relays to be installed
during each refueling outage.
The redesigned
reIays were
24
subsequently
installed in Unit 3.
During post installation testing
of the 42 relays tested in Unit 3,
5 seized
and .5 operated
slowly.
The malfunctioning relays were installed in the "B" train
Engineered
Safety Features
Actuation System.
Licensee evaluation
and corrective action
had been previously
inspected
by the
NRC and those inspections
were documented
in
inspection reports 50-528/88-39,
50-529/88-39,
50-530/88-37,
50-528,
50-529,
50-530/89-21,
50-528,
50-529,
50-530/89-37
and 50-528,
50-529, 50-530/89-41.
During the current inspection,
previous
NRC
inspection
documentation
were reviewed with the licensee.
In
addition, licensee corrective actions
were again reviewed.
The
licensee
and the vendor
had determined that the malfunctions of the
relays observed
during post-installation testing resulted
from a
manufacturing process
deficiency whereby epoxy was
used to touch
up
parts of the relay without being subsequently
cured.
The uncured
epoxy flowed onto the rotor and stator mating surfaces
and was
subsequently
cured by normal heat
when the relays
were energized.
This resulted in binding the relays in the energized position.
The
affected relays
were
removed from Unit 3.
The manufacturer
corrected the manufacturing process
deficiency,
and relays
manufactured
using the corrected
process
were installed
and were
being tested in Unit 3.
The licensee
evaluation -and corrective
actions
appeared
to adequately correct
and preclude the identified
condition.
The'ER
was closed.
D.
(Closed)
10
CFR Part
21
Re ort 89-02P - Limitor ue Motor 0 erators
an
-
or ue
w) c
a> ures
On November 3, 1988, Limitorque Corporation notified the
NRC and
ANPP of two types of defects associated
with SMB-000 and
SMB-00
actuators.
The first defect related to post-mold shrinkage of
Melamine torque switches
and
recommended
replacement with
environmentally qualified Fibrite torque switches.
The second
defect identified that RH-insulated motors
may not develop full
rated starting torque at elevated
ambient temperatures.
The licensee
evaluated
the reported defect regarding
Melamine torque
switches in Engineering Action Request
(EAR) 89-0448.
The
EAR
determined that the noted condition was previously addressed
by
Design
Change
Package
(DCP) lOJ/20J/30J-SI-052.
The
DCP required
walkdowns of all safety-related
motor operated
valves
and
replacement
of Melamine torque switches with Fibrite and Durez
torque switches.
During discussion
of the corrective action between
the
NRC inspector
and the licensee,
the licensee
was unable to
readily show the acceptability of the Durez torque switches.
The
licensee
subsequently
contacted
Limitorque Corporation
and obtained
a letter on November 30,
1989 stating that the defect noted with
Melamine torque switches
was not identified for Durez-type switches
and that it had different material characteristics.
The letter
fur ther stated that Limitorque stopped manufacturing
Durez type
switches in approximately
1981 because
the production
volume did not
justify manufacturing
switches
using both Melamine and Durez
25
materials.
The licensee
concluded that the reported
discrep'ancy did
not apply to Durez material torque switches.
The licensee
evaluated
the reported defect regarding RH-insulated
motors for Limitorque motor operators
in Engineering Evaluation
Report 88-XE-015.
In this evaluation,
the licensee
determined
the
applications
where RH-insulated motors were used
and the design
temperature
conditions they were exposed to. In its report;
Limitorque had provided the maximum ambient temperature
at which
full rated torque could be developed for var'ious motors.
The
licensee
compared the Limitorque data with the design data for the
affected motors
and determined that the applications in which they
were using the motors in question
were still within the temperature
limitations identified by Limitorque.
The inspector
reviewed the licensee
evaluations
and corrective
actions
and discussed
them with the licensee.
The licensee
evaluations
and corrective action appeared
to adequately
provide for
the deficient conditions reported
by Limitorque Corporation in its
November 3, 1988,
10
CFR Part 21 report.
This item was closed.
(Closed)
10
CFR Part 21
Re ort 89-04P - Coo er Ener
Services
es>
n
ass>>cat>on
e >c)enc
On November 21, 1988,
Niagara
Mohawk Power Corporation reported
a 10
CFR Part 21 defect regarding its Cooper Energy Services
EDGs.
The
defect consisted of a post-lube pilot valve for the
EDGs that was
classified
as non-critical by Cooper. Energy Services.
Niagara
Mohawk determined that failure of the post-lube pilot valve could
prevent the
EDGs from achieving full rated power,
and consequently
should
be classified
as safety-related.
During the current
NRC inspection, it was determined that Arizona
Nuclear
Power Project
had not received the subject
10
CFR Part 21
report.
The report was provided to the licensee, by the inspector
and
reviewed
and discussed
with the licensee.
The licensee
and the
inspector
reviewed drawing number 13-M-DGP-001, revision 23,
Lube
Oil, Diesel Generator
System
and the
EDG technical
manual
MM018-389.
Both the system
diagram
and the technical
manual
indicated that the
subject valve was not a part of the
EDGs for the diesel
generators
supplied to*Palo Verde.
The licensee
subsequently
contacted
Cooper
Bessemer
and determined that the diesel
generators
at Palo Verde do
not utilize post-lube pilot valve assemblies.
The ET-24
supplied with the Palo Verde engines
do not use the
subject pilot valve assemblies.
Cooper Bessemer
stated that it
would document the conversation
by means of a letter to the licensee
confirming the above
noted design differences.
The licensee
subsequently
concluded that the 10
CFR Part 21 report did not apply
to Palo Verde.
The licensee
evaluation
appeared
to be adequate.
The
item was closed.
S
A
EE
26
20.
Review of Periodic
and
S ecial
Re orts - Units 1
2 and
3 (90713
Periodic
and special
reports
submitted
by the licensee
pursuant to
Technical Specifications
(T/S) 6. 9. 1 and 6. 9. 2 were reviewed by the
inspector.
This review included the following considerations:
the report contained
the information re9uired to be reported
by NRC requirements;
test results
and/or supportinq information were consistent with design predictions
and
performance specifications;
and the validity of the reported information.
Within the scope of the above,
the following reports
were reviewed by the
inspector:
Unit 1
o
Nonthly Operating Report for November 1989.
Unit 2
o
monthly Operating Report for November
1989.
Unit 3
o
Monthly Operating
Report for November 1989.
No violations of NRC requirements
or deviations
were identified.
21.
~tit 2 tt
The inspector
met with licensee
management
representatives
periodically
during the inspection
and held an exit meeting
on December '27,
1989.
A