ML17305B129
| ML17305B129 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 09/24/1990 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305B123 | List: |
| References | |
| 50-528-90-28, 50-529-90-28, 50-530-90-28, NUDOCS 9010250028 | |
| Download: ML17305B129 (55) | |
See also: IR 05000528/1990028
Text
'0
Re ort Nos.:
Docket Nos.:
'l
License Nos.:
Licensee:
Facilit
Name:
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION
V
50-528/90-28,
50-529/90-28
and 50-530/90-28
50-528,
50-529,
50-530
Arizona Public Service
Company
P.
0.
Box 53999, Station
9012
Phoenix,
AZ. 85072-53999
Palo Verde Nuclear Generating Station Units
1, 28
3
Ins ection Conducted:
July 15 through August 25,
1990
Ins ectors:
D. Coe,
F.
Ringwald,
J.
Sloan,
C.
M
rs,
Senior Resident
Inspector
Resident Inspector
Resident Inspector
R sident Inspector
(Rancho
Seco)
A
roved
8
ong)
1
Reactor Projects
Branch,Section II
ga
at
cygne
Ins ection
Summar
Ins ection
on Jul
15 throu
h Au ust 25
1990
Re ort Numbers
an
e
Areas Ins ected:
Routine, onsite,
regular and backshift inspection
by
t e t ree ress
ent inspectors
and one inspector
from the Region
V staff.
Areas inspected
included: previously identified items; review of plant
activities; engineered
safety feature
system walkdowns; monthly
surveillance testing; monthly plant maintenance;
reactor trip and restart
- Unit 1;
damaged
reactor trip breaker - Unit 1; alarming dosimeter
issued incorrectly - Unit 1; main steam pressure
safety valve testing-
Unit 2; post refueling restart - Unit 2; restart reactor physics
evaluation - Units 1 and 2; main feedwater isolation valve alignment-
Unit 3; improper 0-ring material in Anchor Darling four-way hydraulic
valves
Unit 3; plant shutdown forced by slipped control element
assembly - Unit 3; spent fuel pool activities - Units 1,
2 and 3; motor
operated
valve maintenance
and testing - Units 1,
2 and 3; review of
licensee
event reports - Units 1,
2 and 3; and review of periodic and
special
reports - Units 3.,
2 and 3.
During this inspection the following Inspection
Procedures
were utilized:
30703,
37700,
37828,
40500,
61705,
61706,
61707,
61708,
61710,
61726,
62703,
71707,
71710,
72700,
86700,
92700,
92701,
92702,
and 93702.
'I
90<02~002S
P00PZ~
ADOCK 05000528
Q
PbC
Results:
Of the 18 areas
inspected,
one violation was identified and is
being cited.
This violation related to an improperly set alarming
dosimeter.
Three non-cited violations involve two missed surveillance
tests
and one missed Technical Specification Action Statement.
General
Conclusions
and
S ecific Findin s
Si nificant Safet
Hatters:
None
Summar
of Violations:
Summar
of Deviations:
1 Cited Violation (Unit 1) and
3 Non-Cited Violations (Unit 2)
None
0 en Items
Summar
16 items closed,
2 items left open,
and
7 new items opened.
Persons
Contacted:
DETAILS
The below listed technical
and supervisory personnel
were
among-
those contacted:
ublic Service
Com an
- R.
J.
F.
H.
AT
p.
p.
0
A'p
W.
)hE
J.
R.
S
"K.
R.
- p
+W.
- S
J.
J.
W.
)kG
- J
"R.
- C
E.
J.
T.
J.
J.
"W.
E.
R.
G.
D.
C.
L.
J.
R.
Adney,
Bail ey,
Buckingham,
Bieling,
Bradish,
Brandjes,
Caudill,
Carnes,
Coffin,
Conway,
Dotson,
Draper,
Flood,
Guthrie,
Hall,
Henry,
Hughes,
Ide,
Kanter,
Levine,
LoCicero,
Marsh,
Minnicks,
Overbeck,
Reynolds,
Rouse,
Russo,
Sandhoff,
Schmadeke,
Shriver,
Scott,
Sills,
Simko,
Simpson,
Snell,
Sowers,
Stover,
Stewart,
Templeton,
Fogar ty,
Younger,
Plant Manager,
Unit 3
Vice President,
Nuclear Safety
8 Licensing
Operations
Manager,
Unit 2
Emergency Plan/Fire Prevention
Manager
Compliance
Manager
Central
Maintenance
Manager
Site Services Director
Operations Shift Supervisor,
Unit 3
Compliance
Engineer
Executive Vice President - Nuclear
Director, Site Engineering
8 Construction
S.C.E., Site Representative
Plant Manager, Unit 2
Deputy Director, Quality Assurance/QC
El Paso Electric Engineer
Salt River Project, Site Representative
General
Manager,
Radiation Protection
Plant Manager, Unit 1
Participant Services,
Senior Coordinator
Vice President,
Nuclear
Power Production
Independent
Safety Engineering
Manager
Plant Operations
8 Maintenance Director
Maintenance
Manger, Unit 3
Technical
Support Director
I8C Maintenance
Manger, Unit 3
Compliance Supervisor
.
Quality Control Manager
QAQl, Engineer
Work Control Manager,
Unit 3
Work Control Manager,
Unit 1
General
Manager, Site Chemistry
Rad. Protection Tech/Svcs.
Acting Manager
Maintenance
Manager, Unit 2
Vice-President of Engineering
8 Construction
Chairman-Arizona Public Service
Company
Engineering Evaluations
Manager
Nuclear Safety Manager
Employee
Concerns
Program
Manager
I. S. E., Senior Engineer
Work Control Manager,
Unit 2
Plant Standards
and Control Manager
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
4
"Attended the Exit meeting held with NRC Resident
Inspectors
on,
August 30,
1990.
2.
Previousl
Identified Items - Units 1
2
and
3
92701
92702)
Unit
a.
(Closed)
Enforcement
Item
528/89-43-02
- "Plant Review
oa
evlews
-
nl
b.
This item involved the failure of the
PRB to document
their review of Technical Specification violation events,
ensure
adequate
corrective actions
were taken,
and to
document their determination if unreviewed safety
questions
existed.
The inspector
reviewed
LERs which were
issued
since the corrective actions for this violation
were implemented.
Between January
5, 1990,
and July 17,
1990, the
PRB reviewed
19
LERs and had not reviewed
15
LERs issued during this time period.
As a result of
the inspector's
questions
the
PRB scheduled
a meeting
on
August 29, 1990, to review the backlog of LERs but was
unable to hold it due to schedular conflicts.
The
inspector
acknowledges
the fact that the
PRB has recently
undergone
a reorganization
which required
a Technical
Specification
amendment
and revised their program for LER
reviews
by having
a Compliance
Engineer present
issued
LERs to the
PRB at their meetings.
At the exit meeting
the licensee
acknowledged that
LERs can
be reviewed in a
more timely fashion.
The inspector will continue to
review this area
as part of the routine inspection
program.
This item is closed.
(Closed)
Enforcement
Item
528/90-12-01:
"Deener izin
our
anne
s
0
0 arl
mlc
ower
xcore
eu ron
ux
nstrumentatson
-
nit
e
Thi s item involved the
1 icensee'
intentional
deenergization
of all four channels of Logarithmic Power
Excore Neutron Flux Instrumentation.
The licensee
restored
one channel
approximately five days after'all
channels
were deenergized.
This returned the plant to a
condition covered
under Technical Specifications.
The
Plant Director issued Plant Guideline
No. 12, "Entry Into
Conditions Not Defined by Technical Specifications"
which
expressly prohibits voluntary plant operation in any
'...condition not explicitly addressed
by the Technical
Specification."
The guideline does not prevent operators
from exercising their discretion under 10 CFR Part 50.54x.
The inspector concluded that the action and the
APS and
Region
V management
discussions
on March 30, 1990,
appear
to address this concern.
This item is closed.
p
~
0
~,
Unit 2:
a.
(Closed)
Followu
Item
529/89-30-02):
Suction
s )n
as
ure
-
n)t
Piping associated
with valves
CDN-V628 and
FWN-V110 failed
on July 4, 1989, while the unit was at power,
and forced
a
plant shutdown.
This item was opened pending the
corn)letion of technical analysis,
documented
in
Engineering Evaluation Request
(EER) 89-FW-013.
The
inspect'or
reviewed this
EER, which concluded that the
cause of the failures were .indeterminate.
The
EER stated
that the failures appeared to be due to cyclic stresses
which resulted in fatigue cracking.
Both calculations
and
field observations
supported this conclusion,
though the
. deflection was less than the predicted failure amplitude.
The vibrations appeared
to have been
caused
by reverse
flow through the "B" feedwater
pump bypass valve, which
was found approximately 3/4 inch open.
The licensee
determined in EER 89-FW-021 that additional procedural
controls were needed to prevent excessive
vibration in the
bypass
lines.
These controls
have
been incorporated
and
procedure
and Condensate,"
revised
for all three units.
Additionally, the other-small
pipe
welds in the vicinity were dye penetrant tested
and
no
crack indications were identified.
The inspector
reviewed Incident Investigation Report (IIR)
3-2-89-031.
IIR 3-2-89-031 concluded that the feedwater
pump bypass
valve had been improperly left partially open,
even though
an Auxiliary Operator
(AO) had signed
a step
in a valve alignment during plant startup verifying the
valve was closed.
The discrepancy
resulted
from
miscommunication
among the three
AOs, who jointly
performed the lineup, in determining which valves
had been
checked.
The
AOs involved were counseled
regarding the
necessity for formal communication
when performing
evolutions.
The inspector concluded that the licensee's
actions with
respect to this event were adequate.
This item is closed.
(Closed
Followu
Item
529/89-30-03):
"Work on
Re ulator
er
er
a
nstructlon
-
nest
9
This item was reviewed in Inspection Report 50-529/89-49,
paragraph 2.f, and Inspection
Report 50-529/89-54,
paragraph
2.g,
and was left open pending completion of the
licensee's
equality Assurance
review of programmatic
controls of vendor supplied information.
The licensee
completed its review of these controls
and concluded that
changes
which had been previously. made were ineffective.
Two Corrective Action Reports
(CARs) were issued to
address
identified deficiencies related to this topic.
CAR CS89-0058 pertains to Work Orders
(WOs) being issued
containing out of date
or unapproved
information from
vendor technical
manuals.
This
CAR resulted in several
procedure
revisions,
some training,
and several
additional
procedui e changes
were proposed
but evaluated
as not being
necessary.
CAR CS89-0059 pertains to inadequate
controls regarding
the control, approval
and issuance
of vendor technical
manuals.
This
CAR resulted in procedural
changes
intended
to insure that only "Status
1" vendor technical
manuals
(those with no outstanding
licensee
comments following
review) may be used
as reference
material to support work
at Palo Verde.
This issue
was also addressed
in
NRC
Inspector
Followup Item 529/89-30-04
and closed in
Inspection
Report 529/89-23.
Based
on the implementation
of, these corrective actions
and the continuing long-term efforts of the licensee's
Vendor Technical
Manual Project, this item is closed.
Closed)
Followu
Item
529/89-36-02
- "Post-Tri
Reactor
estart Crstersa
-
nit 2
2 01
During review of actions following the July 12,
1989 trip
of Unit 2, the inspectors
noticed discrepancies
and
informalities in the licensee's
decision making prior to
restart of the unit.
In response
to the inspector's
c'oncerns,
the licensee
strengthened
the administrative
controls regarding unit restart determinations
and
included specific criteria to be used for the restart
decision.
These
changes
are
documented in procedures
79DP-OIP01, "Incident Investigation Report Preparation,"
and 79AC-OIP01, "Incident .Investigation Category
1 and
2
Incidents."
In reviewing these revised procedures,
the inspector noted
an administrative error in the "Restart Criteria" section
of 79AC-OIPOl.
The criteria are divided into two cases,
depending
on whether or not the cause of the trip is
known.
However,
due to errors in the paragraph
numbering,
this division is not clear,
and as written, could lead to
a reactor restart without the intended reviews.
The
licensee
stated that it is unlikely that a restart would
occur without the intended reviews
because of the
management
attention given to both reactor trips and
restarts.
The licensee
committed to include clarifying
changes to these
procedures
in major revisions
expected
to be completed
by March 31, 1991.
The
NRC inspectors
routinely monitor post-trip actions
and restart
activities,
and
no related deficiencies
were identified
during the recent Unit 1 post-trip .restart decision;
therefore, this item is closed.,
Unit
a.
3
~
Closed)
Followu
Item (530/89-21-01):
"Loss of
S ent Fuel
oo
eve
-
nit
This item resulted
from an inadvertent loss of Spent
Fuel
Pool
(SFP) level
due to inaccurate
control
room valve
status
drawings.
This event occurred
on May 22, 1989,
and
in response
the licensee
committed to a broad review of
system status
control requirements.
On August 2, 1989,
Unit 1 experienced
a loss of SFP level
due to an improper
valve alignment.
This was. documented in NRC Inspection
Report 528/89-36
and resulted in a Notice of Violation
(528/89-36-01).
In the licensee's
response
to the Notice
dated
November 21, 1989, the licensee
reported that the
review of system status control
had been completed
and
also described
changes that were planned.
On January
23,
1990, the licensee transmitted the schedule for
implementing these
changes
to the
NRC.
Additionally, on
June
14, 1990, the licensee transmitted to the
NRC the
list of separate
SFP operating procedures
to provide
clearer,
more detailed directions for operators.
These
were originally expected to be in place
by January
10,
1990, but subsequently
the licensee
revised this date to
August 20,
1990.
These procedure's
have
been
implemented.
Based
on the licensee's
progress
on this 'issue,,this
item
is closed.
However, the inspector will review these
changes
when reviewing item '(528/89-36-01) for closure.
b.
(Closed
Enforcement
Item
530/89-36-01:
"Emer enc
iese
enerator
xcess
ow
ec
a ves
o
so ate
as
e uvre
-
n)t
This item resulted
from an interim disposition of an
Engineering Evaluation
Request
(EER) which required that
Excess
Flow Check valves
on all EGG's
be isolated pending
further engineering analysis
and final
EER disposition.
The required isolation was put into effect in Units 1 and
2, but was not implemented in Unit 3.
The inspector
noted
that the licensee's
corrective action to prevent
recurrence
was to issue
a policy memorandum to all system
engineers
requiring formal written transmittal of any
immediate action required by an
EER interim or final
disposition.
Although some weaknesses
in the engineering
communication to user groups
have
been noted in Inspection
Report 530/90-12 since the event in'question,
none
have
involved the failure to implement immediate required
actions.
This item is closed.
C.
(0 en) Followu
Item (530/89-36-02):
"Surveillance Test
ro rammat) c
an es
-
n)
The inspector reviewed the report of a complete
programmatic review of the Surveillance Test (ST) program
prepared
by a .licensee
outside contractor.
The licensee
has not yet incorporated
the recommendations
of this
report into the procedures
governing the
ST program.
Training for the approved procedure
changes
was in
progress
at the end of the inspection report period.
This
item will remain
open pending review of programmatic
"
changes
resulting from the con'tractor's
report.
(Cl'osed)
Enforcement
Item
530/89-36-03
"RCS
S ill
ue
o
a ve
e uencsn
rror
-
ns
This item resulted
when an, Auxiliary Operator
(AO)
performed
a valve lineup in which the improper sequencing
of valves being positioned allowed an inadvertent
RCS flow
path resulting in a primary coolant spill.
The inspector
noted the licensee's
actions to prevent recurrence
included discussions
with Unit 3 operating
crews regarding
communications practices
and identification of- important
valving sequences
when appropriate.
In addition,
a
"sequence"
column was added to the valve lineup sheet
used
to document
and control valve alignments.
This lineup
sheet
was subsequently
discontinued
and replaced
by a form
incorporated
in the Conduct of Shift Operations
procedure,
40AC-90P02, for "special variance" alignments which
includes
a sequence
column.
The inspector
reviewed
several
of these
forms in plant files and also reviewed
clearance
restoration
forms,
and concluded that licensee
personnel
were specifying alignment sequence
on these
documents.
This item is closed.
(Closed
Followu
Item (530/89-54-01:
"Sandblast Grit
oun
) n
nstrument
s r
ose
-
ns t
This item resulted
from the licensee's
investigation of an
improperly operating feedwater control valve, which
determined that a significant quantity of sandblast grit
was present in the air operator
boosters
relay.
The source
of this grit was traced to a newly installed air hose.
The licensee
determined that the grit came from sand-
blasting the end fittings of the hoses prior to brazing
the end connectors
into place.
The grit remained inside
the hose
when the supplier capped the ends
and delivered
them to APS.
The inspector
reviewed
EER 90-IA-004, which analyzed
and
confirmed the source of the grit and initiated corrective
actions.
These actions consisted of quarantining
and
cleaning other hoses
purchased
from the
same supplier
and
changing the configuration item description for applicable
class
and item numbers.
In addition, the licensee
confirmed that similar hoses
purchased
from this supplier
were not installed in other plant systems
and completed
a
training briefing for maintenance
personnel
in all units
on the need for thoroughly inspecting
new components prior
to installation.
The licensee
determined that
a change to
the Conduct of Maintenance
procedure
was not warranted.
The inspector
concluded these actions
were appropriate.
This item is closed.
3.
Review of Plant Activities (71707
and 93702)
a.
b.
Unit 1
The Unit began the report period in Mode 1 at 100 percent
power.
Operational
concerns
included:
electrical
problems with CEA 30 which were corrected;
an increase
in
containment
gases
caused
by minor leaks; frequent alarms
from the loose parts vibration monitoring system which has
deceased
during the report period and appears
to have
stabilized;
and inoperable diesel
generator fuel oil tank
cathodic protection resulting from the const uction of the
Operations
Support Building.
A reactor trip occurred
on
August 14, 1990,
as discussed
in Paragraph
7.
The unit
entered
Mode 2 on August 19, 1990:
The plant ended the
report period at 100 percent
power.
Unit 2
Unit 2 entered this period in Mode 2, having just
completed.its
Cycle
3 refueling outage.
The unit entered
Mode 1 on July 18, 1990,
and synchronized to the grid on
July 19,
1990 (Paragraph ll).
The generator
was brought
briefly off-line for turbine overspeed testing
and was
synchronized to the grid again
on July 19, 1990.
Power
ascension
was performed in conjunction with routine
post-refueling reactor physics testing, but was
hampered
by problems with the Core Operating Limits Supervisory
System, vibrations of a Hain Feedwater
Pump
(MFP) "B"
bearing,
and improper operation of the
HFP "A" miniflow
recirculation valve.
High condenser
hotwell sodium levels forced a power
reduction to 40 percent
on July 30 to allow leaking
condenser
tubes to be identified and plugged.
The power
ascension
was
resumed
on August 2 and full capacity
was
attained
on August 9.
Power was reduced to about
85 percent
on August 16 after power was lost to No.
3
Cooling Tower (CT) as
a result of heavy rains.
Following
the return of CT "3" to service,
condensate
pump "B"
tripped on August 15, 1990, for an undetermined
reason,
while the unit was at 93 percent
power, resulting in
another
unplanned
The unit was returned to
100 percent
power on August 16, 1990.
A failure of the
Core Operating Limits Supervisory
System
(COLSS)
on
August 16, 1990, forced a power reduction to 78 percent.
COLSS was restored to service
and the unit returned to
full power the following day.
The unit remained at
essentially
100 percent
power for the rest of the
reporting period.
c.
Unit 3
Unit 3 began this report period operating at 100 pe'rcent
and continued until August 5, 1990,
when an orderly
shutdown
was completed following an unsuccessful
attempt
to restore
a slipped
CEA.
A faulty circuit card
w'as
identified and replaced
and the Unit was restarted
on
August 7, 1990 (see
Paragraph
15).
Full power operation
was restored
by August 9, 1990,
and the unit continued at
full power through the end of the inspection report
period.
d.
Plant Tours
The following plant areas at Units 1,
2 and
3 were toured
by the inspector during the inspection:
Auxiliary Building
Containment Building
Control
Complex Building
Diesel Generator Building
Radwaste Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The following areas
were observed
during the tours:
. l.
0 eratin
Lo s and Records - Records
were reviewed
against
ec n)ca
peer
scations
and administrative
control procedure
requirements.
2.
Monitorin
Instrumentation - Process
instruments
were
o serve
or corre at>on
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 50.54.(k),
Technical Specifications,
and administrative
procedures.
4.
E ui ment Lineu s - Various valves
and electrical
rea ers were verified to be in the position or
condition required by Technical Specifications
and
administrative procedures for the applicable plant
mode.
5.
~Ei ti
i
-Sl td
pip t,f
hih
tagging requests
had been =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 sn scatsons
o
system leakage,
improper lubrication, or other conditions that would
prevent the systems
from fulfillingtheir functional
requirements.
7.
Fire Protection - Fire fighting equipment
and
~b
df
i hi hi
Specifications
and administrative procedures.
8.
Plant Chemistr
- Chemical analysis results
were
revsewe
or conformance with Technical
Specifications
and administrative control procedures
9.
Securit
- Activities observed for conformance with
regu atory requirements;
implementation of the site
security plan,
and administrative procedures
included
vehicle and personnel
access,
and protected
and vital
area integrity.
10.
Plant,Housekee
in
- Plant conditions
and
materia
equipment storage
were observed to determine
the general
state of cleanliness
and housekeeping.
ll.
Radiation Protection Controls - Areas observed
inc u
e
contro
po)nt operation,
records of
licensee's
surveys within the radiological controlled
areas,
posting of radiation and high radiation areas,
compliance with Radiation Exposure Permits,
personnel
monitoring devices
being properly worn, and personnel
frisking practices.
During this reporting period,
a primary resin sluicing
operation in Unit 1 resulted in unexpectedly
high radiation
levels in the
Radwa te Building.
Levels reached
the threshold
for posting
as
Licensee
personnel
were prompt in identifying this condition as it
occurred
and in securing
and posting the area.
The inspector
sent the licensee's
incident investigation report to
NRC Region
V for. review by the Health Physics staff.
No violations of NRC requirements
or deviations
were
identified.
4.
En ineered Safet
Features
S stem Walkdowns - Units 1
2 and
3
Selected
engineered
safety features
systems
(and systems
important to safety)
were walked down by the inspector to
confirm that the systems
were aligned in accordance
with plant
procedures.
10:-
Dur ing this inspecti on peri od the inspector s walked down
accessible
portions of the following systems.
Un.it 1
o 'igh Pressure
Safety Injection
Unit 2
o
High Pressure
Safety Injection
Unit 3
o
High Pressure
Safety Injection
No violations of,NRC requirements
or deviations
were
identi fied.
5.
Monthl
Surveillance Testin
- Units 1
2 and
3
61726)
ao
b.
Selected
surveillance tests
required to be performed
by
the Technical Specifications
(TS) were reviewed
on a
sampling basis to verify that:
1) the surveillance tests
were correctly included
on the facility schedule;
2) a
technically adequate
procedure
existed for performance of
the surveillance tests;
3) the surveillance tests
had been
performed at the frequency specified in the TS; and 4)
test results satisfied acceptance
criteria or were
properly dispositioned.
Specifically, portions of the following surveillances
were
observed
by the inspector during this inspection period:
Unit 1
~roce ure
Descri tion
AFA-P01 Surveil lance
Core Reactivity Balance
Monthly Core Performance
Surveillance
99 Percent
MTC Determination
Unit 2
~roce
ure
Descri tion
Plant Protection
System
(PPS)
Hot
Functional Test
Control Element Assembly Calculator
(CEAC)
No.
1 Functional Test
Unit 3
~roce
ure
Descri tion
Isolation Valve No.
174 Fast
Stroke Test
No violations of NRC requirements
or deviations
were
identified.
6.
Monthl
Plant Maintenance - Units 1
2 and
3 (62703
a 0
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 equality Assurance/equality
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.
Specifically, the inspector witnessed portions of the
following maintenance activities:
Unit 1
Descri tion
o
Control
Element Drive Mechanism
Power Switch
Connection Troubleshooting
Unit 2
Descri tion
o
Troubleshooting
Steam
Bypass Control Valve SGN-1007
o
Troubleshooting/Repair
SGN-1007 Electronics
o
Troubleshooting/Repair
Diesel Generator
"A" Starting
Air Pressure
Unit 3
Descri tion
o
Rebuild four-way valve for 3SGA-UV-177
o
Install four-way valve for 3SGA-UV-181
No violations of NRC requirements
or deviations
were
identified.
7.
Reactor Tri
and Restart - Unit 1
71707
and 93702
a ~ ~RT
T
R
On August 14, 1990, at 10:23
an automatic reactor trip from 65 percent reactor
power
t
12
due to high pressurizer
pressure.
The operations staff
had just completed
a rapid power reduction to 65 percent
and
had manually trip~ed the main turbine due to loss of
cooling to the
Phase
'B" Main Transformer.
Prior to the event,
the unit was operatin~ at 100 percent
power.
At 9:23
"B
trouble alarm
was received.
An Auxiliary Operator found the supply
breaker for cooling system control power to the Main
Transformer tripped.
Attempts to restore control power to
the cooling system were unsuccessful.
At 9:59 AH, personnel
observed that
no cooling fans were
operating
on Main Transformer "B".
The Hain Transformer
alarm response-procedure,
41AL-1MAOl, directed the
operators
to de-energize
the transformer within 30
minutes.
A rapid power reduction
was
commenced at
10: 02,PM.
The operations staff realized the time limit
would not be met and prepared for a manual turbine trip.
A brief tailboard was conducted
and at 10:23
PH the main
turbine was manually tripped from 65 percent reactor
power.
A Steam
Bypass Control System
(SBCS) quick open signal
was
received
and the seven in-service valves
opened
as
designed.
Approximately 27 seconds after the turbine
trip, a reactor trip due to high pressurizer
pressure
was
received.
The unit was stabilized in Mode 3 and the event
was classified
as
an uncomplicated reactor trip.
Post-Tri
Investi ation
The licensee
conducted
an investigation into this event,
documented
in Incident Investigation Report (IIR)
2-1-90-003.
This investigation determined that the cause
of the Main Transformer cooling system failure was
an
internally faulted control power transformer.
The root
cause of this failure is being pursued
by the licensee.
The
SBCS was expected to prevent
a reactor trip on loss of
load.
However, it was later determined that a trip would
likely occur with one
SBCS valve out of service
upon loss
of load at approximately
70 percent
power or at
approximately
30 percent power.
One
SBCS valve was out of service
based
on a vendor
recommendation
to prevent overcooling due to excess
SBCS
capacity
upon loss of load from 100 percent power.
This
recommendation
was implemented
on February 4,,1989.
Post-Restart
Action Item No. 807, resulting from the
March 3, 1989, Unit 3 reactor trip event, further
addressed
this issue
by requiring a third party review of
SBCS optimization be conducted.
A May 3,
1989 report,
"SBCS Detailed System Investigation," performed
by the
13
licensee,
recommended
that the vendor evaluate
the
SBCS
"to obtain margin to reactor trip actuation for loss of
load and loss of feed
pump events."
Licensee
engineers
reviewed the vendor's evaluation
and found no substantive
problems,
and Post Restart
Item No.
807 was closed
on
April 17,
1990.
Following the August 14, 1990, trip, the
inspector
found that the evaluation report was
and
curgeptly remains in draft form, although its status
had
been questioned
by the
NRC inspector
on June 5, 1990.
The
licensee
stated that the vendor evaluation
had not been
substantially
changed
since the April 17,
1990 review,
and
that the information regarding the absence
of a margin to
reactor trip upon loss of load at 30 percent
power and
..70 percent
power,
was probably available at that time.
equality Deficiency Report ((DR) No. 90-0329
was issued to
evaluate
the discrepancy
between the Updated Final Safety
Analysis Report, which describes
a full load rejection
capability,
and the actual plant inability to withstand
a
loss of load without a reactor trip at certain power
levels
(30 and 70 percent power).
Additionally, the
licensee
committed to determine
why their review of the
vendor evaluation failed to identify the zero margin to
trip, which was
one of the central
purposes
of the
evaluation.
The inspector will review the results of
these evaluations
when available,
followup item
(528/90-28.-01).
Additionally, the inspector is concerned with the
licensee's
closure of Post Restart
Item No. 807 based
on a
draft report.
These
issues
appear to demonstrate
a lack
of thoroughness
in engineering
evaluations
and assurance
of the adequate
resolution of post-restart
issues.
The
inspector will continue to review Post-Restart
Action
Items as part of the routine inspection program.
Unit Restart
Following completion of repairs to the transformer cooling
control
system
and other minor maintenance,
the licensee
restarted
the reactor, with criticality achieved
on
August 18, 1990.
Mode 1 was entered
on August 19 and the
generator
was synchronized to the grid later the
same
day.
The licensee
considered
the higher risk of a reactor trip
if a loss of load occurred at near
30 percent or 70
percent
power 'with one out of eight
SBCS valves out of
service.
However, the licensee
also considered that the
reactor is generally not operated
in these
ranges for very
long and evaluated
the risk of experiencing
an unnecessary
Safety Injection following a reactor trip from any power
level
due to overcooling by all eight
SBCS valves.
The
licensee's
conclusion
was that continued
removal of one
SBCS valve from service
was warranted.
The inspector
concluded that the licensee's
actions
were acceptable
while long term remedies
were considered.
No violations of NRC requirements
or deviations
were
identified.
Dama
ed Reactor Tri
Breaker - Unit 1 (93702
On August 18, 1990, the licensee
discovered
bent linkage in
Reactor Trip Breaker "B".
The breaker could not be closed
during the preparations
to restart the reactor
and
some bent
'inkage
was discovered
when the breaker
was racked out and
inspected.
A spare
breaker
was obtained
from the warehouse;
however,
not all necessary
surveillance tests
could be
performed prior to going to Mode 2.
Licensee
personnel
with
licensee
management
input and after evaluation of Technical
Specification requirements
concluded that changing to Mode 2
was not prohibited with the trip breaker not racked in and
tagged out and not yet demonstrated
to be fully operable.
Mode
2 was entered
and the trip breaker subsequently
declared
The inspector
noted that
a Root Cause of Failure-
Engineering Evaluation Request
was issued
and was not complete
at the end of the report period.
This event review will remain
open
as
an inspector followup item (528/90-28-02)
pending
completion of EER 90-SB-046.
No violations of NRC requirements
or deviations
were
identified.
Alarmin
Dosimeter Issued Incorrectl
- Unit 1
71707)
On August 14, 1990, the
NRC inspector
was issued
an alarming
dosimeter
by a Shift Radiological Protection
(RP) Technician at
the
RP "island" as required
by the Radiological
Exposure
Permit
(REP) for a high radiation area.
The inspector observed
the
technician turn the dosimeter
on, check the batteries,
reset
the alarm setpoint switches to 50 millirem, and then issue the
dosimeter.
The inspector questioned
the technician
as to
whether the alarm setpoint
was changed
by moving the switches
with the unit on or whether the unit would have to be reset or
have the power cycled off, then on, for the
new alarm setpoint
to be in effect.
The technician admitted to not knowing and
subsequent
discussions
revealed that the power would have to be
cycled off then
on for the
new setpoint to be in effect.
Therefore,
the alarming dosimeter
issued to the inspector
was
not set to the alarm setpoint required by the
REP.
This is a
violation of NRC requirements,
Enforcement
Item (528/90-28-03).
The inspector brought this to the attention of the Unit RP
Manager
who surveyed
RP Technicians
in all three units and
determined that approximately 20-30 percent of the
Technicians
did not know the correct
sequence
for setting
up an
alarming dosimeter.
The inspector also met with an
Technician at the
RP Calibration Facility and confirmed that
15
new alarm settings
are not effective until either the power is
cycled off, then on, or the reset button is pressed..
The
inspector
noted that there
was
no APS procedure for setting the
alarming dosimeter
and that the technical
manual did specify
the correct sequence.
Initial RP technician training given to new
RP technicians
does
address, specific instructions
on setting the alarming
dosimeters.
For continuing training, the inspector 1dentified
two concerns:
(1) during the last
RP Continuing Training done
in April 1989, the
Z Tech alarming dosimeter
was in predominant
use
and not the presently
used Dositech dosimeter (different
procedures
for setting the alarm setpoints);
and (2)
experienced
RP Technicians
were "grandfathered"
when this
course
began
and therefore did not receive this training.
The
next Continuing
RP Training course is scheduled for April 1991,
which will include proper alarming dosimeter
setup.
The Unit 1
RP Manager issued
a
memo to all Unit 1
RP Technicians with
copies to Units 2 and
3
RP Mangers.
Site
RP is considering
whether additional
procedura1
requirements
are necessary.
Unit 1
RP also reviewed all individuals who received
a dose
greater
than
50 millirem since the beginning of 1990.
In no
case did an individual receive
a dose greater than that for
which the alarming dosimeter
should
have
been set.
The inspector
noted that during the Unit 1 outage dosimetry was
issued
by contract Dosimetry Technicians
who appeared
to set
alarming dosimeters
properly.
When the outage
ended,
the Shift
RP Technicians
took over this responsibility.
It appears
that
the turnover of this responsibility was incomplete
and
some
Shift Technicians
issuing alarming dosimeters
did not receive
adequate training to assure that the alarming dosimeters
would
consistently
be issued in accordance
with the applicable
REPs.
One violation of NRC requirements
was identified.
/
Pressure
Safet
Valve (PSV
Testin
- Unit 2
The inspector
reviewed the documentation
associated
with
performance of Surveillance Test 73ST-9ZZ18,
PSV
Set Pressure Verification," which was completed in July 1990,
in Unit 2.
In discussing
the interpretation of chart recorder
data with personnel
who performed the test,
the inspector
observed that the charts alone were inadequate
to determine the
liftpressure
in some cases.
The test personnel
explained that
the test performer
had to listen for indications of the
PSV
lifting and that this information was
used in conjunction with
the chart information to determine the percent of load cell
capacity at which the
PSV began to lift. This figure is then
used in calculations to determine the liftsetpoint of the
valve.
J
h
g
S
Upon reviewing the procedure,
the inspector
noted that there
are
no instructions
regarding
how to actually perform the test,
or how to set
up the Trevitest equipment
on the
PSV.
There are
also
no notes or other guidance to clarify the test
methodology.
The procedure
simply. instructs the vendor
representative
to perform the test.
, According to licensee
personnel
involved with the test,
the vendor does not have or
use
any procedures
in setting
up the Trevitest equipment or in
performihg'the test.
A vendor technical
manual is available
but was not referred to during the test.
The licensee
stated that the vendor representatives
who
actually perform the test are extremely well trained
and
experienced with respect to the Trevitest method of PSY set
pressure verification.
Additionally, licensee test technicians
must complete training on Section XI testing in accordance
with
procedure
73DP-OTROl, "qualification and Training Requirements
for Component
and Specialty Engineering."
However,
one of the
lead engineers
assigned
as Test Director for a licensee test
team was
a contractor qualified to ANSI N3.1-1978, but lacked
any prior experience with this type of testing.
He was only
given oral briefings of the test methodology
and procedure
prior to performing the Surveillance Test (ST).
The inspector
concluded that given the minimum training requirements
(ANSI
N3. 1-1978), the procedure
lacked sufficient detail.
A previous revision of the
ST procedure
had more detail
regarding conduct of the test.
However, these
steps
were
removed
because
each step
was too time consuming
and
interrupted the normal progress
of these relatively quick
moving test activities.
However, the inspector concluded that
the absence
of any procedural
steps
addressing
the setup of the
Trevitest equipment or the conduct of the test resulted in
final test data which did not appear consistent.
As a result of these discussions,
the licensee
committed to
revising procedure
73ST-9ZZ18 to include adequate
detail to
assure
consistent
and meaningful test performance
and results.
Instruction Change
Request
No.
38052 was submitted
on
August 10, 1990, to this effect.
The inspector
had no further
questions
and will follow implementation of the licensee's
procedural
improvements,
Followup Item (529/90-28-01).
No violations of NRC requirements
or deviations were
identified.
Post Refuelin
Restart - Unit 2 (71707
The inspector
observed activities
on July 19, 1990, associated
with turbine generator
overspeed testing
and synchronizing the
generator to the grid.
These activities were, in general,
well
controlled and completed in an acceptable
manner.
During the
operation of the turbine and associated
systems,
the inspector
observed
a control
room operator operate
the control
17
e
(MTN-HS-242) for the valves associated
with turbine stop valve
before seal drains,
using
a pair of needle-nose
pliers, since
the
knob for the switch had broken
and not been replaced.
The
Operations
Manager stated that the control board discrepancy
was noted
a week earlier and that replacement
parts were not
readily available.
The inspector
noted that the switch was
replaced
a few days after the startup.
During the'ower ascension,
on July 20, 1990, licensee
engineers
noted problems
wi~th the performance of the Core
Operating Limits Supervisory
System
(COLSS).
The power
ascension
was interrupted for several
hours while these
problems
were being resolved.
The first problem resulted
from
a point in a database
being deleted in a manner which
ultimately caused all later values to be offset by one location
in the database,
so that the
COLSS software went to the wrong
database
location to retrieve required information for
.processing.
The operators
noted the abnormal
COLSS power
limit.
The second
problem involved an apparent transposition
of information from the vendor into the Plant Computer via a
Work Order.
The Core Monitoring Computer was unaffected.
This
error affected the incore sensitivity files in such
a way that
the azimuthal tilt alarm did not clear during startup.
The
licensee is investigating both 'these
problems in Incident
Investigation
Reports (IIRs) 3-2-90-30
and 3-2-90-31.
The
.
inspector will review licensee
actions
and conclusions with
respect to these
events,
Followup Item (529/90-28-02).
High vibration was observed
by the licensee in the "B" Main
Pump
(MFP) on July 26, 1990, while the Unit was at
about 70 percent
power.
This forced
a downpower to 65 percent
to allow the
HFP bearings to be replaced.
The "A" HFP miniflow valve was isolated
on July 26, 1990, after
it unexpectedly
opened.
Problems
were later found in its
controller.
Operators
were sensitized to the need to trip the
reactor
and the
HFP if a loss of load occurred while the
miniflow was isolated to the only operating
HFP.
Power was reduced to about 40 percent
on July 30, 1990,
due to
elevated
sodium levels in the condenser
hotwells.
Water box
inspections
revealed
considerable
debris, including pieces of
plywood, in one train of Circulating Water (CW).
Additionally,
several
tubes
were found to be leaking and were plugged.
The power ascension
was
resumed
on August 2, 1990,
and
100 percent
power was reached
on August 9, 1990.
No violations of NRC requirements
or deviations
were
identified.
e
18
12.
Restart
Reactor
Ph sics Evaluation - Units
1 and
2
61705
1
0 an
, The inspector
observed
the Unit 1 Reactor Startup, portions of
the Unit 1 and
2
Low Power
Physics Testing,
and portions of the
Power Ascension Testing.
The following procedures
were
reviewed:
Units 1 hnd 2:
72PA-9ZZ07
72PA-9SB01
Unit 1
Onl
Reload Criticality and
Low Power
Physics Testing
Reload
Power Ascension Testing
Secondary Calorimetric Power Verification
Core Protection Calculator/Core
Operating Limits
Supervisory
System Input Inter-comparison
Power Calibration
Unit 2 Onl
Return to Criticality During Low Power Physics
Testing
99 percent Hoderator Temperature Coefficient
Determination
13.
Reactivity Computer Checkout
In addition the inspector discussed
testing with several
Reactor
Engineers to evaluate their prepartion
and
understanding
of the testing process.
No violations of NRC requirements
or deviations
were
identified.
Main Feedwater Isolation Valve
FMIV) Ali nment.-.Unit
3
On August 6, 1990, with the unit in Mode 3, Feedwater
Isolation
Valve (FWIV) 3SG-UV-174,
was being tested per 73ST-3XI16,
"Section XI Valve Stroke Timing, Partial Stroke Exercise
and
Position Indication Verification'- Mode 1 thru 6 - FWIV's
(Economizer)."
Following the fast closure of the
FWIV, it could not be
reopened.
A normally throttled and locked hydraulic control
valve ("F") on the
FMIV was found fully closed,
which prevented
another hydraulic control valve from shifting as necessary
to
open the FMIV.
The "F" valve is normally locked 1/8 turn open,
though the locking device
does not prevent it from being
inadvertently shut.
It had last been verified throttled open
in December
1989.
However,
much work had taken place
on and
around the
FWIV since then,
and the licensee
concluded that it
19
was possible that the "F" valve was inadvertently closed while
operators
or mechanics
worked on or around the valve.
The "F" valve being closed
does
not affect the safety function
(quick close) of the
FWIY.
However, it is required to be open
to allow reopening the
FWIV.
The licensee
performed
a 50 percent verification of all Unit 3
locked valves
and confirmed that valves were being properly
controlled.
Because of the vulnerability of the,FWIV 'F" valve
to inadvertent positioning,
measures
are being considered
by
the licensee to reduce the potential of the valve being
unintentionally repositioned.
Additionally, Problem Report
System
(PRS)
number 612 was initiated for trending purposes.
No violations of NRC requirements
or deviations were
identified.
Im ro er 0-rin
Material in Anchor Darlin
Four-Wa
rau )c
a ves -
n)
Following the failure of the partial stroke surveillance test
on Feedwater Isolation Valve (FWIV) SGA-UV-177 on July 5, 1990,
the licensee identified via lab analysis,
on July 23, 1990,
that several
0-rings
used in one of two installed
AD four-way
valves were of a polysulfide material which swells in the
presence
of the Fyrquel hydraulic fluid and can cause
operational
problems with the four-way valve and hence the
FWIV.
The correct material for these 0-rings is Viton.
The
0-rings in both four-way valves associated
with SGA-UV-177 had
been verified in March 1990 by the licensee to have not been
purchased
from AD under rebuild kit serial
numbers that
suspected
of having improper 0-ring material.
AD had issued
a
Part 21 report in January
1990 to inform its purchasers
and
specified the Purchase
Orders
(POs) which could possibly
have
Buna-N O-rings, which are susceptible to swelling in the
presence
of hydraulic fluid.
Based
on= the Part 21 report, the
licensee identified 14 four-way valves in Unit 3 which
contained parts from rebuild kits from POs affected
by the
Part 21 notification.
These valves were replaced in. March
1990, with 10 Main Steam Isolation Valve (MSIV) four-way valves
and four FWIV four-way valves affected.
However,
SGA-UV-177
was not affected.
Later analyses
determined that the backup
0-rings in only one of these
four-way valves (for an FWIV) was
not the proper material.
The licensee's
review of the failed SGA-UV-177 four-way valve
revealed that .it was purchased
under Purchase
Order (PO)
60177315 which contained
20 MSIV 0-ring kits and four FWIV
0-ring kits.
All four FWIV four-way valve rebuild kits had
been installed in Unit 3 on FWIVs 174 and 177.
Ten MSIV
four-way valve rebuild kits had been installed in Unit 3 on
MSIVs 170,
177 and 181.
There are four "four-way valves per
20
MSIV.
Seven
MSIV kits were
used in Unit 1 on MSIVs 170 and
180'he
remaining
MSIV kit was not installed.
The licensee
determined that the swollen 0-ring caused
the
operational
problem with FWIV 177 .in Unit 3, then labeled all
other four-way valves with 0-rings procured
under the
same
PO
as suspect
and replaced
the other three suspect Unit 3 FWIV
four-way valves
on July 28 and 29th.
Because
the replacement
of, four-4'ay valves in FWIVs requires
more time per valve than
allowed per Technical Specification Limiting Condition for
Operation 3.6.3,
a Temporary Waiver of Compliance
was requested
and granted
by Region
Y on July 27,
1990.
The work was
completed in Unit 3 on
FWIVs 174 and 177 with correct 0-rings
by July 29.
On August 1, the licensee
received
a lab report which confirmed
that 0-rings from these three
FWIV four-way valves were also
the incorrect material.
The licensee
subsequently
replaced all
suspect
MSIV four-way valves in Units 1 and 3.
Subsequent
testing of the suspect
MSIV 0-rings
showed that the proper
material
had been
used.
All AD four-way valves currently
installed in all units
have
now had their 0-rings verified to
be the correct material.
The inspector
observed
the disassembly
of a spare
FWIV four-way
valve which had been
assembled
by AD.
Several
0-rings were
found to have been sliced or shaved,
and one was offset from
its proper position.
The valve also appeared to have
an
excessive
amount of grease.
The licensee tested the 0-rings
from this valve and confirmed that they were of the proper
material.
The licensee
also disassembled
and tested parts
from
three other spare
four-way valves assembled
by AD and found
other discrepancies,
including some missing wave washers
in .one
valve.
However, all the 0-rings were determined to be Viton.
Analyses of all backup 0-rings from the MSIV four-way valve
rebuild kits procured
under the suspect
PO was performed.
The
tested 0-rings were determined to be of the correct material.
The licensee is planning to issue
a 10 CFR Part 21 report on
this issue.
'NRC Generic
Communication
and Vendor Branches
have
been alerted to this issue
by Region
V management.
The inspector
concluded that licensee
actions with respect to
this issue
were pr udent
and effective in providing confidence
in the operability of AD four-way valves currently installed in
all units.
No violations of NRC requirements
or deviations were
identified.
Plant Shutdown
Forced
b
Sl:i
ed Control Element Assembl
CEA)
nit
On August 5, 1990, during the performance of CEA exercise
testing, while the unit was operating
near
100 percent
power,
CEA 68 slipped almost fully into the core to about
5 inches
withdrawn.
CEA 68 slipped the rest of the way -in while
operators
attempted to retrieve it.
Because
these
attempts
were uns'4ccessful,
the unit was shutdown to troubleshoot
and
do
repairs.
After the initial slip of CEA 68, operators
began reducing
power,
as required
by Technical Specifications
(TS) to less
than 80 percent.
After the further attempts to recover the
were unsuccessful,
a unit shutdown
was initiated to comply with
the TS.
The turbine was taken off line at 6:15
PM, and
a
reactor
shutdown
began at 6:48
PM.
All regulating
CEAs were
fully inserted
by 8:09
PM.
The inspector confirmed that TS
requirements
were met during the transient.
The licensee
had performed Control Element Drive Mechanism
.
(CEDM) traces,
in accordance
with procedure
CEA Coil Traces at Power Operation,"
a few hours before the
event.
The System Engineer stated that while this monitoring
can detect
many kinds of problems before they result in CEA
slip or drop events,
the monitoring method also
has
limitations.
In particular,
the
CEDMs are paralleled to the
hold bus during the monitoring, which in effect masks
problems
associated
with the Upper Gripper.
In this event,
a faulty
coil driver circuit card was identified and replaced,
which
successfully
resolved the problem.
The System Engineer also
stated that this problem is very difficult to identify.
Earlier during the
CEA exercising, part length
CEA 30 failed to
move.
In this case,
a faulty timer card was identified and
replaced while at power.
The licensee is evaluating
changes to the
CEDM Control
System
to reduce the risk of dropped or slipped
CEAs.
The unit performed minor maintenance
and testing while
shutdown,
and then started
up and achieved
Mode 1 on August 7,
1990.
100 percent
power was reached
on August 9.
No violations of NRC requirements
or deviations
were
identified.
S ent Fuel
Pool
(SFP
Activities - Units 1
2 and 3
86700)
The inspector verified by direct observation that the
SFP water
level was greater than the minimum level, that the Fuel
Building was at a negative pressure,
and that the
temperature
was within the limits of licensee
procedures.
No
discrepancies
were observed of these physical conditions.
22
No violations of NRC requirements
or deviations
were
identified.
17.
Motor 0 crated
Val ve Maintenance
and Testin
- Units I
2
and
37700,
37828 92 01
a.
S rin
Pack Relaxation in Limitor ue Actuators
Spring pack relaxation is a degradation
which has
been
observed
in certain Limitorque actuators.
This relaxation
may cause
premature actuation of the torque switch.
Under
design basis
maximum operating conditions, this deficiency
could result in a failure of the valve to fully stroke to
perform its safety function.
IN
I)
~kk
d
Certain motor operated
valves are actuated
by
Limitorque motor operators
which incorporate
a
belleville washer spring pack in conjunction with a
torque switch to limit valve stem thrust.
The torque
switch is adjusted to allow sufficient thrust to
operate
the valve under design basis conditions but
limit the thrust to preclude
excessive
wear or damage
to the valve or actuator.
The spring pack consists of an assembly of belleville
washers
which is preloaded
in compression
by the
manufacturer
and not normally adjusted in the field.
In operation,
as the actuator develops thrust, the
spring pack further compresses
after the preload is
exceeded.
The additional
compression of the spring .
pack actuates
the torque switch to interrupt the
motor control circuit to stop the actuator.
The
resultant total stem thrust is determined
by the
combination of the initial spring pack preload
and
the subsequent
spring pack compression
during
operation.
Reduction of the spring pack preload over
time would allow the torque switch to actuate at
a
lower valve stem thrust than initially established.
Under design basis
maximum differential pressure
conditions, this could cause the valve to
"torque-out" early, resulting in incomplete valve
travel.
This degradation is not readily apparent
because it
may only affect valve performance
under maximum
design basis conditions.
In less
severe conditions,
which include normal operating conditions
and routine
testing,
some
amount of spring pack relaxation
may
not prematurely stop valve travel.
In the case of
gross degradation of spring pack function (i.e.,
collapse of the washers),
operation of the valve
under
normal or test conditions
may also
be affected.
i
23
While this problem is not completely understood at
this time by the manufacturer,
the nature
and extent
of the problem is being investigated to determine
Part
21 applicability.
Several
Limitorque notices
have
been issued
on the .problem to alert the industry
to the potential for the problem and these
notices
also
recommended
replacement of the spring packs
as
, corrective action.
Indications of potential
degradation
of the spring pack assembly
due to
relaxation include:
a 0
b.
C.
d.
e.
Loose belleville washers
in the spring pack
assembly,
No apparent
spring pack preload,
Excessive
spring pack gap,
Increased
torque switch settings,
or
Underthrust identified in the as-found condition
of the valve during testing.
2)
Licensee's
Ex erience
In discussions
with cognizant licensee
engineering
representatives
regarding the problem of spring pack
relaxation in Limitorque actuators,
the inspector
found that engineering
personnel
were generally
aware
of the problem but did not consider the problem to
have occurred to any significant degree at Palo
Verde.
They indicated that the current
MOV test
procedures
and diagnostic
equipment
(MOVATS) enable
them to detect degradation
of the spring pack.
They
stated that there
had been
no instances
of a detected
loss of preload
due to spring pack relaxation in any
of the baseline testing performed pursuant to IE
Bulletin (IEB) 85-03.
The inspector
reviewed the licensee's
procedures
for
MOVATS testing
and maintenance
of motor operated
valves.
These procedures
included the following:
Procedure
No.
Title
Rev.
3
Maintenance of Limitorque Motor
Operated
Valves
Rev.
1
Valve Motor Operator
Performance
Signature Acquisition using
MOVATS equipment
The inspector found that the licensee's
procedures
included detailed inspection for a condition
identified as spring pack gap
(SPG).
A SPG was
indicative of improper adjustment of a stop collar in
the actuator which restrained
axial movement of the
spring pack assembly.
The licensee
considered that
24
the'xistence
of a
SPG
was
due to mis-assembly
of the
actuator
and readjustment
of the stop collar was the
appropriate corrective action.-
Using
MOVATS testing
to establish
the requi'red output thrust, the licensee
considered
a
SPG to be inconsequential
to the oVerall
operability of the valve.
The inspector
found that the licensee's
procedures
addressed
a loss of preload in the spring pack
as
an
expected
maintenance
condition.
As such,
the
condition did not appear to be recognized
as
a
significant abnormality which jeopardized
the
operability of the valve.
The inspector
reviewed the work control documentation
involving several
instances
in which spring pack
replacement
or adjustment
had been performed.
This
review of selected
documents
included instances
in
which additional instructions
had been requested
from
L'imitorque regarding proper preloading of the spring
pack.
The following work orders
were reviewed:
Work
Order
Date
Valve ID
Descri tion
307873
5/89
419517
6/90
2JSIAHV0685
2JRCEHV0431
312013
12/89
8
1JSIAUV0634
4/90
LPSI-CTHT Spray
PP
Cross
RCP Controlled
Bleedoff
SIT Isol. Disch.
421017
5/90
405988
4/90
378798
8/89
2JSIBHV0609
2JRCEHV0430
1JSIBUV0656
.Pump
Long
Term Cooling
RCP Controlled
Bleedoff
S/D Cooling Cont.
Isol.
The inspector
found that in these
cases
a degradation
of the spring pack had been observed during
maintenance
or testing.
A summary of the spring pack
deficiencies is provided below.
a.
WO 307873 - the spring pack was identified to be
fatigued.
The licensee
was unable to eliminate
an as-found spring pack gap and requested
additional instructions
from Limitorque to
adjust the preload of the spring pack to
compensate
for the spring pack gap.
tq
25
C.
WO 419517 - identified possible collapsed
belleville spring washers with a large spring
pack gap which could not be 'eliminated.
Also,
the, spring pack was observed to have
no preload.
WO 312013 - the spring pack was identified as
fatigued with loose belleville washers
and
a
spring rate lower than comparable
spring packs.
d.
WO 421017 - loose belleville 'washers with one
washer
compressed flat were identified.
e.
WO 405988 - no preload
on the spring pack was
identified.
f.
WO 378798 - excessive
spring pack gap was
identified.
The
NRC inspector discussed
the repeated
occurrences
of spring pack degradation with licensee
engineering
representatives
and found that the licensee
had
considered
the conditions to be
a mis-assembly
problem which was corrected within the scope of
normal maintenance.
The inspector
was concerned that
the licensee
had not recognized
the time dependent
degradation
of the spring packs
and was treating the
condition as expected
normal wear and tear within
their maintenance
program.
As a result of the inspector's
concern,
the licensee
reviewed documentation of previous work activities
on
. MOVs specifically to identify if spring pack
relaxation
may have
been evident.
The licensee
reviewed all
EERs from 1987 through 1990 on all
systems with MOVs and identified that 14 instances
of
spring pack gaps
were reported.
In addition, the
licensee
reviewed the detailed baseline testing
records for 28 MOVs under
IEB 85-03 which had been
baseline
tested twice and found 9 instances
of
apparent
reduction in the spring rate (K-factor) of
the spring pack indicating a potential
loss of
preload
due to fatigue.
As a result of these
findings, the licensee initiated
EER 90-XE-072 to
document the review and will evaluate the findings by
October 15, 1990.
This
EER will be reviewed
when the
licensee's
evaluation is complete,
Followup Item
(528/90-28-04).
The inspector
found the current licensee
actions to
be adequate
to deal with the potential
problem of
spring pack relaxation.
Previous
work activities did
not appear to adequately
evaluate
spring pack
deficiencies to identify time-dependent
degradation.
The inspector found this weakness
appeared
to be
26
,caused
by an over-emphasis
on the baseline testing of
MOVs for future evaluations
rather than the
verification and demonstration
of the as-found
operability of the valves.
This weakness
is further
discussed
in Paragraph
b. of this section.-
b.
Documentation of Deficiencies
The>inspector's
review of the documentation of the
limitorque actuator deficiencies
found that in all six
cases
a Material Nonconformance
Report
(MNCR) had not been
written nor was
a root cause evaluation performed, related
to the spring pack deficiencies,
to establish corrective
actions to preclude
recurrence.
Rather,
an Engineering
Evaluation Request
had been written to request
Engineering
guidance
regarding the acceptability for continued
use of
the spring pack.
The inspector reviewed the working copy documentation
of
the work activity involved in each instance
and found
additional deficiencies
and nonconformances
which were not
identified in the subsequent
EER or any
MNCR.
The
inspector's
findings are summarized
below.
1)
M0307873
a.
The as-found
opening thrust value was only 78K
of the required
minimum.
b.
The as-found closing thrust value exceeded
the
maximum specified
by 76K.
c.
The as-found torque switch bypass
value of 7.6X
of valve stem travel did not meet the required
minimum limit switch setting of 20-25K.
These deficiencies directly affect the ability of the
valve to perform its safety function under design
basis conditions.
Over-thrusting in the closed
direction can increase
the force required to
subsequently
open the valve and can potentially
damage the valve and actuator.
Under-thrusting in
the open direction can prematurely stop valve travel.
Under-bypassing
of the open torque switch may cause
actuation of the open torque switch prematurely
during valve travel before the peak unseating
loads
have
been experienced.
This may cause
premature
stopping of valve travel.
The inspector noted that
none of these conditions were identified or evaluated
in an
MNCR or EER.
27
2)
W0419517
a.
A large spring
pack
gap of .035" was found with
the preload adjusting nut fully tightened.
b.
After verification by Limitorque of the proper
assembly of the spr ing pack under
EER 90-RC-57,
the as-found torque switch settings of 1.5
open/1.5 close were insufficient to allow
complete valve travel.
Adjustment of the torque
switch setting
up to the limiter plate
maximum
of 2.5/2.5
was required to achieve full valve
stroke.
These deficiencies directly affect the capability of
the valve to perform its safety function.
However,
none of these conditions were identified or evaluated
in an
NNCR or EER.
3)
W0312013
a.
The as-found
open thrust value was only 30%
of the required minimum.
b.
The as-found closing thrust value was only 86%
of the required
minimum.
c
The as-found
apparent
spring rate of the spring
pack was only 51K of similar spring packs
on
three other NOVs.
EER 90-SI-060 did evaluate
the continued
use of the spring pack, but did
not evaluate
the as-found operability or root
cause of the deficiency.
As in previously described
cases,
these deficiencies
also directly affect ability of the valve to perform
its safety function.
The valves, which were affected
by these work orders,
were
restored to an operable status.
10 CFR Part 50, Appexdix B, Criterion XVI, requires that
for significant conditions adverse to quality that
measures
shall assure that the cause of the condition is
determined,
corrective actions
are taken to preclude
repetition,
and that these
be documented
and reported to
appropriate levels of management.
The failure to document
the above noted valve deficiencies for engineering
evaluation
and determine
the root cause
appears
to be
a violation of NRC requirements,
Enforcement
Item
(528/90-28-05).
In discussions
with licensee
engineering representatives,
the inspector
found that there
appeared
to be
some
confusion
among licensee
personnel
as to under which
28
conditions
an
EER was appropriate
and which conditions
'equired
an
MNCR.
The inspector
found that the licensee
had recently revised
Procedure
60AC-OQQ01 to more clearly
establish
the separate
reporting requirements
and
appropriate
uses of both documents.
However, the
inspector
found instances
of the problem to have occurred
after the current revision.
The'inspector
found that there
appeared
to be
some
misinterpretation of the design specification
requirements
for the setpoint of limitorque actuators.
According to
the licensee's
program,
the actuator switch setpoints
are
controlled design specifications
communicated to the plant
under the Controlled Motor Operator
Data Base Description
(Design Drawing 13-J-ZZI-004).
For adjustments
outside
the specified range,
a design
change
document
was required
(DCP or S-Mod).
As such,
the specified setpoints
represent
the engineering output to assure
the design
basis operability of the valve.
However, the inspector
noted that the licensee's
handling of as-found
deficiencies in MOVs was inconsistent with the
significance associated
with the specified design
requirement.
A design
change
document
was required to
adjust the switches outside the specified target range.
However, setpoints
found to be outside the specified
target range were not identiifed as nonconforming with
respect to the design requirements.
The inspector
found
this weakness
in engineering
communication with the
operations
and maintenance
personnel
resulted in a lack of
recognition of the operational
significance of these
setpoints.
The inspector discussed
his concern with licensee
management
who acknowledged
the prior inconsistency
in
their program
and committed to initiate MNCR documentation
for deviations from design specifications
incorporated in
Design Drawing 13-J-ZZI-004.
During MOV baseline testing
in support of establishing
the appropriate setpoint
range
for incorporation into Design Drawing 13-J-ZZI-004, the
licensee
committed to initiate either
MNCR documentation
.
or equivalent programmatic controls to assure that
as-found deviations
from the setpoints specified in the
controlling engineering
documents
were evaluated to
address
as-found design basis operability.
Follow-up of Unresolved Item 528/90-12-02:
AFW Isolation
Valve Setpoints
The inspector
reviewed
a previous observation of an
apparent conflict in -license
commitments regarding
Limitorque actuator setpoints for the
AFW isolation valves
(AF-034 through 037).
The inspector
had reviewed
87-AF-42 which identified a failure to fully close
under
maximum differential pressure
for
AFW valve 3JAFBUV0034 on
I 4
29
May 22,
1987.
The actuator
was determined to be
undersized for the application,
however the condition was
determined to be acceptable
based
on a two-phase
Justification for Continued Operation
(JCO) of Units
1 and
2.
Phase
1 of the
JCO identified that the
AFW isolation
valves would continue to be adjusted to seat
based
on a
torque switch setting in excess
of maximum actuator
rating. It further identified that the valve was not
expected
to be able to close under
maximum differential
pressure
conditions, but that operator actions
could be
credited to prevent overfilling the steam generator.
Phase
2 of the
JCO identified that the actuators
of the
valves would be modified to seat
based
on the limit switch
setting, with the torque switch adjusted
the same as. Phase
l.
As in Phase
1, the
JCO identified that despite
the
modification, the valve was not expected
t'o be able to
fully close under
maximum differential pressure.
The inspector discussed
the interim operability and limit
seating modification with various licensee operations
personnel
and found that operations
personnel
were vaguely
aware of the modification activity, but did not consider
it to have any operational
significance.
Operations
management
had been
involved in the review of the
JCO and-
operations
personnel
considered that existing procedures
covered the potential for overfilling the steam generators
and therefore specific notification to operations
personnel
of the potential for the
AFW valves not to go
fully closed under
some conditions
was not considered
necessary.
Under current conditions, this situation would
be described, in an
MNCR and would be reviewed
by operations
personnel.
The inspector reviewed the licensee's
final report for IEB 85-03, dated January
15, 1988, which reported satisfactory
test results for the
AFW isolation valves.
After a review
of the
MOY design basis operating conditions, the licensee
identified maximum design conditions for both the opening
and closing function of the valves.
Note
9 of Appendix
B
of the licensee's
submittal stated:
"The closing forces for. torque seating of the
auxiliary feedwater isolation valves (1, 2,
3
JAFUV0034, 35, 36, 37) as determined
by test
on
1JAFCUV0036 and
3JAFBUV0035 have
been
reduced
by
position stopping rather than torque seating ensuring
these valves
open (which is the safety function)
during worst case accident conditions".
The inspector
noted that limit switch seating
was
reflected in the controlled setpoint
document
(13-J-ZZI-004) in Note 12.
Thi s itern is cons idered cl os ed.
f
30
18.
Review of Licensee
Event
Re orts - Units 1
2 and
3 (92700)
The following LERs were reviewed by the Resident Inspectors.
, It was noted that four 'LERs (529/90-02,
529/90-06,
529/90-08,
and 530/89-, ll) involved missed surveillance tests.
These
missed tests
have occurred since
December
1989.
While it
appears
that the corrective actions
are appropriate for each
incident< the underlying reason
for the missed test should
be
reviewed and, if any trends identified, corrective actions
should
be taken.
Unit 1:
a.
528/90-07-LO
Closed
"Safet
In 'ection Tanks Vent Val ves
rove
e
ower
ontrar
to
ec naca
ecs
>cation
e uirements
, This licensee
event
was discussed
in Inspection
Report
528/90-23,
Paragraphs"'.c.
and 13.
No new information was
provided by this Licensee
Event Report.
This
LER is
closed.
b.
528/90-08-LO
Closed)
"Main Steam Isolation
Due to
roce ura
na
e uac
This licensee
event
was discussed
in Inspection
Report
528/90-23,'Paragraph
12.
The inspector
reviewed Incident
Investigation Report (IIR) 2-1-90-002 which addressed
this
event which occurred
when operators
placed the
SBCS in
automatic with a demand signal present.
The IIR addressed
operator inappropriate action,
inadequate self checking
and corrective action associated
with the individual
operators
involved.
The
LER states
on page
4 of 5,
paragraph I.I., "The event was not the result of a
cognitive personnel error..."
This was not consistent
with the IIR.
However, the
LER indicated corrective
actions included briefing all operators
on the need to
match controller output with demand prior to placing the
controller in automatic.
The inspector noted that
operator training emphasizes
this point.
The inspector
concluded that the licensee's
IIR investigation
and
corrective actions
appeared
to properly characterize
and
treat the extent to which personnel
performance
contributed to this event.
Thus, the inspector
concluded
from the above that licensee
management
was willing to
recognize
and address
operator
performance
issues.
The
inspector
urged licensee
management
to clearly
characterize all casual
factors in LERs to the
NRC.
Licensee
management
acknowledged
these
comments.
This
LER
is closed.
t
g ~
t'
7
31
Unit
a ~
2:
529/90-02-LO (Closed
"Missed Surveillance Test
or
uxor )ar
ee water
stem
Sur veillance Requirements
(SR) 4.7.1.2.a.2
and 4.7.1.2.a.3
were inadvertently not performed during the required
interval for the Train "A" auxiliary feedwater =pump,
AFA-P01.
Personnel
incorrectly documented that
had been completed
on January
16, 1990,
when in
fact, it had only been partially accomplished.
The error
was not discovered. until after the successful
performance
of the test
on February 7, 1990.
The missed
SRs
had last
been accomplished
on December
20, 1989.
The, licensee
determined that cognitive personnel
errors
caused the-
event.
Appropriate corrective actions
appear to have been
taken.
The failure to perform surveillance tests in the required
interval is a violation of NRC requirements.
This
licensee identified violation is not being cited because
the criteria specified in Section
V.G. of the Enforcement
Policy were satisfied.
This
LER is closed.
b.
529/90-06-LO (Closed
"Missed Surveillance Test For
eutron
ux
arms
Surveillance
Requirement
(SR) 4. 1.2.7.b for the startup
channel
high neutron flux alarms
Boron Dilution Alarm
System
(BDAS) was not performed within the required
interval.
It had been performed
on May 9, 1990,
and was
due by June 17, 1990.
The error was identified by the
licensee
on June 18,
1990.
Cognitive personnel
errors
caused
the event,
as the group responsible for performing
the
SR did not do the test despite
reminders
from the
Surveillance
Program Coordinator.
The failure of
operations
personnel
to cancel
a troubleshooting
work
order on the
BDAS also complicated the issue,
as the ILC
personnel
who were to perform the
SR apparently thought
that the
BDAS was inoperable
because
of the outstanding
work order.
However, the appropriate
communications
did
not occur which would have clarified the operability of
the
BDAS and averted the missed
SR.
Also, the personnel
involved (Surveillance Test Coordinator
and ILC) were not
attentive or responsive
enough to prevent the
SR from
being missed,
or to identify the error until about
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later.
This is
a violation of NRC requirements.
However, this
licensee identified violation is not being cited because
the criteria of Section
V.G. of the Enforcement Policy
were satisfied.
32
529/90-07-LO (Closed
"Inadvertent Control
Room
ents
at>on
so ation
n ineere
a et
eatures
c ua
son
This
LER describes
a June
25, 1990, Control
Room
Ventilation Isolation Actuation Signal
(CRYIAS) received
when .a Control
Room Operator lightly tapped the
CRYIAS
Test/Bypass
pushbutton during preplanned
maintenance
to
determine if an unlit indicator lamp was loose.
The
license could not recreate
the actuation
by similar
tapping during troubleshooting
and
no hardware
deficiencies
were identified.
The licensee
concluded that
the cause
was indeterminate.
This
LER is closed.
529/90-08-LO
Closed
Sam le Late Resultin
sn
ssse
ction
Backup samples of the Reactor Coolant System
(RCS) are
required whenever
one startup
channel
high neutron flux
alarm Boron Dilution Alarm System
(BDAS) is inoperable.
On July 4, 1990, with the Unit in Mode 3, and one
channel
inoperable for surveillance testing,
a second
charging
pump was started.
The required sampling
frequency
changed
from once per six hours to once per two
and one-half hours
as
a result of the operation of the
charging
pump.
However, the reactor operator forgot about
this requirement at the time and did not recognize it
until the next
were received,
28 minutes later than required.
The licensee
performed
an
investigation
and documented this in Incident
Investigation Report (IIR) 3-2-90-026.
The IIR closely
matches
the
LER, except that the IIR documents
an
additional corrective action,
e. g., to add
a step to
procedure
42ST-2ZZ24, "Startup Channel
High Neutron Flux
Alarm Inoperable
3. 1.2.7," to require caution tags
be hung
on the charging
pump if a startup
channel
or BOAS alarm is
The licensee's
actions
appear to be
consistent with the identified root causes.
The Technical
Specification requirement for RCS sampling was not met.
However, the licensee identified violation is not being
cited because
the criteria specified in Section V.G. of
the Enforcement Policy were satisfied.
0
V
33
Unit 3:
a.
530/89-11-LO/Ll
0 en
"Missed
ASME Surveillance Test
on
enerator
ir tart
s
em
ec
a ve
This event involved a missed
ASME Surveillance. Test
(ST)
'n the "A" Train air start system
check valve for the "B"
diesel
generator.
The inspector requested
additional
information from the licensee to enable
a more complete
evaluation of this event.
This
LER remains
open.
18.
Review of Periodic
and
S ecial
Re orts - Units 1
2 and
3
Periodic
and special
reports
submitted
by the licensee
pursuant
to Technical Specifications (TS) 6.9. 1 and 6.9.2 were reviewed
by the inspector.
This review included the following considerations:
the report
contained the information required to be reported
by NRC
requirements;
test results
and/or
supporting 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
Monthly Operating
Report for July 1990.
Unit 2
o
Monthly Operating
Report for July 1990.
Unit 3
, o
Monthly Operating
Report for July 1990.
No violations of NRC requirements
or deviations
were
identified.
19.
Exit Meetin
(30703
The inspector
met with licensee
management
representatives
periodically during the inspection
and held an exit meeting
on
August 30, 1990.