ML17306A833
| ML17306A833 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 06/29/1992 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17306A831 | List: |
| References | |
| 50-528-92-17, 50-529-92-17, 50-530-92-17, NUDOCS 9207210007 | |
| Download: ML17306A833 (29) | |
See also: IR 05000528/1992017
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION
V
R
9
.
5 -525/92-17,
50-529/92-17,
0
5 -550/92-17
2
5
k
N
.
50-92,
5 -529,
d ND-55D
N
.
I/PF-41,
d NPF-74
Licensee
Arizona Public Service
Company
P. 0.
Box 53999, Station
9012
Phoenix,
AZ 85072-3999
~Fili
N
II
d
N
I
5
i g
Units 1, 2,
and
3
Ins ection
Conducted
roved
B
April 12 through Hay 30,
1992
ong,
se
Reactor Projects
Sec ion
2
ate
igne
Ins ectors
D.
F.
J.
L.
D.
Coe,
Ringwald,
Sloan,
Tran,
Kirsch,
Senior Resident. Inspector
Resident
Inspector
Resident
Inspector
Resident
Inspector
(Rotational
Assignment)
Technical Assistant,
Division of Reactor Safety
and Projects
Ins ection
Summar
Ins ection
on
A r'l
12 throu
h
Ma
30
1992
Re ort Numbers
50-528 92-17
50-529 92-17
and 50-530 92-17
~ltd:
R ti,
it,
gl
dk kkiiti
0 ti
Nltk
four resident
inspectors,
and
one Region
V inspector.
Areas inspected
included:
review of plant activities
engineered
safety feature
system walkdowns
Units
2 and
3
inadequate
thread
engagement - Units
2 and
3
surveillance testing
Units 1, 2,
and
3
plant maintenance
Units .1, 2,-and
3
secondary
chemistry
pH excursion
Unit 2
alert declared
due to partial loss of annunciators
and plant computer-
Unit 3
feedwater isolation valve 0-ring failures
Unit
1
individual plant examination. status
and results
Units 1, 2,
and
3
design basis reconstitution
program results
and status - Units 1, 2,
and
3shift technical
advisor manning - Units 1, 2,
and
3
9207210007
920b29
ADOCK 05000528
8
fol1 owup on previously ident ifi ed items,
and
review of licensee
event reports
(LER) Units 1, 2,
and 3.
During this inspection the following Inspection
Procedures
were utilized:
30702,
40500,
41500,
61725,
61715,
61726,
62703,
71707,
71710,
92700,
92701,
and 93702.
Results:
Of the
13 areas
inspected,
one apparent violation in Units 1, 2,
and
3 was identified regarding
inadequate
thread
engagement
(Paragraph
3).
General
Conclusions
and
S ecific Findi
s:
Si nif'ca t Safet
Matters:
None
Violations:
eviations:
One violation Units 1, 2,
and
3
None
0 en Items:
Stren ths Noted:
Weaknesses
Noted:
Two new items were opened,
nine open items were closed.
Licensee
use of Probabilistic Risk Assessment
(PRA)
techniques for safety system unavailability management
continues to be seen
as
a strength.
t
The licensee incorrectly reassembled
a containment
i.solation check valve and did .not discover it through post
maintenance testing.
This issue will be discussed
in
special
inspection report 50-528/92-23.
ersons
Contacted
DETAILS
The below listed technical
and supervisory
personnel
were
among those.
contacted:
rizona Public Service
Com an
R.
- J
- R.
- T
- C
R.
+R.
- S
- W.
- A.
- J
D.
G.
- R
- J
- T
R.
Adney,
Baxter,
Bouquot,
Bradish,
Churchman,
Flood,
Fountain,
Friedlander,
Guthrie,
Ide,
Johnson,
Levine,
Mauldin,
Oyerbeck,
Rouse,
Scott,
Shriver,
Stevens,
Plant Manager,
Unit 3
Engineer,
Compliance
Supervisor/gA Audits gA&H
Manager,
Compliance
.Site Nuclear Engineering Director (Acting)
- Plant Manager,
Unit 2
'Supervisor/Acting
Hanager
gA&H
Manager,
Component
and Specialty
Engineering
Site Director, guality Assurance
Plant Manager,
Unit
1
Supervisor,
Compliance
Vice President,
Nuclear
Power Production
Director, Site Maintenance
& Hods
Site Director, Technical
Support
(STS)
Supervisor,
Station Operating
Events
Department
Assistant Plant Manager,
Unit 3
Assistant Plant Manager,
Unit 2
Director, Nuclear Licensing
& Compliance
S'te
Re resentatives
- J. Draper,
Site Representative,
Southern California Edison
- H. Benac,
Manager,
El
Paso Electric
(EPE)
- R. Henry,
Site Representative,
Salt River Project
t
The inspectors
also talked with other licensee
and contractor personnel
during the course of the inspection.
Denotes
personnel
in attendance
at the Exit meeting held with the
NRC
resident
inspectors
on June 4,
1992.
2.
eview of Plant Activities Units
1
2
and
3
40500
61715
71707
and 93702
a ~
Unit
1
Unit
1 entered this inspection period with the reactor defueled
and
a refueling outage in progress.
Mode
6 was entered
when reloading
'he fuel into the reactor
began
on April 15,
1992.
Refueling
activities were completed
and the unit entered
Mode
5 on April 28,
1992.
The unit heated
up to Mode 3,
and went critical on Hay 21,
1992.
The power ascension
was halted at 43X for several
days while
investigating stator water cooling flow problems,
and again at 69X
while resolving feedwater
system problems.
Full power was achieved
on June
1,
1992,
and
was maintained for the rest of the reporting
period.
Unit 2
Unit 2 operated
at essentially
100X power throughout the reporting
period.
Unit 3
Unit 3 entered this inspection period operating at
100X power.
On
Hay 4,
1992,
an electrical
surge occurred in the plant annunciator
circuitry degrading the annunciator
system.
A subsequent
related
failure of the plant computer forced
a power reduction to
approximately
75X.
These conditions precipitated
the declaration of
an Alert at 8:19
AN (NST) on Nay 4 (see
Paragraph
8).
The Alert
condition continued until Hay 6,
1992 at ll:21 PN, at which time the
event
was terminated
and
a plant shutdown
was
commenced.
The unit
remained
shutdown in Node
3 from Hay 7 through
Hay 14 performing
troubleshooting,
repairs,
and testing of the annunciator
system.
The unit was returned to power operation
on Hay 15,
1992,
though
problems with a main feedwater
pump and
a feedwater isolation valve
kept the unit from reaching
100X power operation until Hay 19,
1992.
The unit operated
at essentially
100X for the rest of the inspection
period.
Plant Tour
The following plant areas
at Units 1, 2,
and
3 were toured
by the
inspector during the inspection:
Auxiliary Building
Control
Complex Building
Diesel Generator Building
Fuel Building
Hain Steam Support Structure
Radwaste
Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The following areas
were observed
during the tours:
(1)
0 eratin
Lo
s
and Records - Records
were reviewed against
technical
specifications
and administrative control procedure
requirements.
(2)
Nonitorin
Instrumentation - Process
instruments
were observed
for correlation
between
channels
and for conformance with
technical
specifications
requirements.
(3)
(4)
~Eh'<< ffi
C
1
d *hift
fA g
b
for conformance with 10
CFR Part, 50.54. (k), technical
specifications,
and administrative procedures.
E ui ment Lineu
s Various valves
and electrical
breakers
were
verified to be in the position or condition required
by
technical specifications
and administrative procedures
for the
applicable plant mode.
The inspector performed
a field verification of containment
integrity in Unit
1 by selecting
several
containment
and confirming that they were properly align'ed in
accordance
with licensee
procedures
"Containment
Integrity Penetrations
4.6.1.1.a,"
and 41ST-lSI04,
"Containment Spray Valve Verification 4.6.2. l.a,c
and -=
4.6.2.2."
No deficiencies
were identified during this
walkdown.
(5)
(6)
(7)
(8)
(10)
(11)
E ui ment Ta
in - Selected
equipment, for which tagging
requests
had
been 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
observed for indications of system leakage,
improper
lubrication, or other conditions that could prevent the systems
from fulfillingtheir functional requirements.
Fire Protection - Fire fighting equipment
and controls were
observed for conformance with technical specifications
and
administrative procedures.
Plant Chemistr
Chemical analysis results
were reviewed for
conformance with technical specifications
and administrative
control procedures.
~gecurit
Activities observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative
procedures
included vehicle
and personnel
access,
and protected
and vital area integrity.
Plant Housekee
in - Plant conditions
and material/equipment
storage
were observed to determine the general
state of
cleanliness
and housekeeping.
Radiation Protection Controls
Areas observed
included control
point 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.
(i2)~if
T
Eliftt
4
p il
1ti
briefings were observed for effectiveness
and thoroughness.
On April 24,
1992, during shift turnover, the inspector
noted
that the red
"OPEN" light indication for valve SIA-UV-684,
Containment
Spray
(CS) Train A discharge
valve to the shutdown
heat exchanger,
was not illuminated.
Subsequently,
this was
determined to be due to poor light bulb electrical contact.
The inspector further noted that this abnormal control board
indication was not discussed
among control board operators
during the board walkdown portion of the shift turnover.
The
inspector noted that alarms would al.ert operators to a valve
loss of power or out of position condition, that these
alarms
are reviewed during turnover,
and that the management
expectation is for light bulb problems to be identified
sometime during the shift but not specifically during shift
turnover.
The inspector
was also informed that the oncoming
primary side operator
had noted the abnormal
condition and
had
elected to not question
or discuss this during turnover because
a separate
analog valve position indicator showed this valve to
be fully open
and alarms were .not present for an out of-
position or loss of power condition.
The inspector also noted
that the shift turnover procedure,
requires
a
control board walkdown during shift turnover which should
include "...Reasons
for abnormal indications."
The inspector
concluded that this .abnormal
indication should have
been
discussed
during turnover.
'The licensee
agreed with the
inspector's
conclusion.
No violations of NRC requirements
or deviations
were identified.
3.
En ineered
Safet
Feature
S stem Walkdowns
Units
2 and
3
71710
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 this inspection
period the inspectors
walked down accessible
portions of the following
systems:
Unit 2
o
"A" and "B"
Unit 3
o
-
High Pressure
Safety Injection "A" and "B"
o
"A" and
"B"
e
nade
uate Thread
En
a ement
Units
a
d 3
17 0
During
NRC walkdowns of safety-related
systems,
the inspector identified
several
components
which had thread
engagement
less that required
by the
licensee's
program,
documented
in procedure
"Fastener
Tightening/Preload."
During a walkdown of the high pressure
safety injection (HPSI) system in
Unit 3, the inspector identified three valves apparently
having
inadequate
thread
engagement.
The "B" train HPSI long term cooling
isolation valve,, 3SIB-HV-609, was found to have inadequate
thread
engagement
on the nuts
and bolts connecting the motor operator to the
yoke assembly.
The licensee
stated that .specification
13HN510, Section
.
8.8. 1, indicates that the minimum engagement
required is such that all
the threads of the nut are fully engaged with threads
on the bolt.
This
requirement
is. clarified in procedure
"Fastener
Tightening/Preload,"
which states that full engagement
is achieved
when
the end of the bolt is flush with the face of the nut.
The inspector
found that the nut on one of the four bolts
on valve 3SIB-HV-609 was
approximately
one thread short of full engagement.
The licensee
initiated Material Nonconformance
Report
(HNCR) 92-SI-3083,
which
concluded that the nuts were larger than the minimum required
and that
the actual
thread
engagement
was greater
than that available with the
vendor-specified
smaller-sized
nuts,
and that the existing configuration
provided adequate
strength for the application.
The inspector also identified apparently insufficient thread
engagement
on the packing gland nuts for 3ECB-HCV-66 and 3ECB-V-52.
The licensee
determined
in HNCR 92-EC-3002 that these
packing gland nuts were thicker
than required,
and that the actual
thread
engagement
was greater
than
that available with the vendor-specified
smaller-sized
nuts.
The
HNCR was
conditionally released,
requiring longer bolts to be installed during the
next refueling outage.
During a subsequent
walkdown of the Auxiliary Feedwater
(AFM) systems
in
Units
2 and 3, the inspector identified 'the following examples of
apparently insufficient thread
engagement:
Unit 3 "A" train
AFW:
3AFA-V-161
3AFN-V-143
3AFC-UV-36
3AFA-V-67
Packing
Packing
Packing
Packing
Packing
Packing
Packing
Packing
Gland
.Gl and
Gland
Gland
Gland
Gland
Gland
Gland
Retainer
Retainer
Retainer
Retainer
Retainer
Retainer
Retainer
Retainer
Hinge Bolt
Hinge. Bolt
Hinge Bolt
Hinge Bolt
7
Unit 3 "B" train
AFW:
3AFB-V-83
3AFB-Y-94
Packing
Gland Retainer
Packing
Gland Retainer
Packing
Gland Retainer
Packing
Gland Retainer
Unit 2 " " train AFW:
2AFA-V-14
2AFA-V-67
Packing
Gland Retainer
Hinge Bolt
Packing
Gland Retainer
Packing
Gland Retainer
Packing
Gland Retainer
Unit 2 "B" train AFW:
2AFB-V-.40
Packing
Gland Retainer
2AFB-UV-35'acking Gland Retainer
Hinge Bolt
pl
In .some cases,
nuts were engaged
2 to 3 threads
less
than full
engagement.
The licensee
subsequently
conducted
a walkdown of the
pump rooms in all three units
and identified some
additional similar thread-engagement
deficiencies.
In addition, after
the end of this inspection report period,
an
NRC inspector identified
that valve I-SIB-HV-609 had less than
SOX thread
engagement
on all four
actuator to yoke mounting bolts.
This deficiency will be described
in a
subsequent
resident
inspection report.
The licensee
determined
in discussions
with the valve vendor that the
packing gland retainer
hinge bolts engagement
of only three threads
is
needed
to provide the required strength.
Since all identified examples
met this criterion,
MNCRs were not required to document the condition.
The licensee's
evaluation is being documented
in Engineering
Evaluation
Request
(EER) 92-AF-004.
The licensee
evaluated
the remaining conditions under
MNCRs 92-AF-1014
(Unit 1), 92-AF-2015 (Unit 2),
and 92-AF-3016 (Unit 3).
The
licensee-identified
conditions in Unit
1 were dispositioned for rework,
which was completed
on May 27,
1992.
The inspector
reviewed the
licensee's
calculation
13-MC-AF-402, which evaluated
the adequacy of the
deficiencies identified in MNCRs 92-AF-2015
and 92-AF-3016.
These
MNCRs
were dispositioned
"use
as is" based
on this calculation,
which concluded
that all identified deficient components
had sufficient strength.
The strength of fasteners
is compromised
by inadequate
thread
engagement,
which in the case of packing gland retaining fasteners,
could result in
the packing blowing out of the valve, potentially degrading
the ability
of the system to perform its safety function.
Additionally, such
a
failure could create
a personnel
or equipment
hazard.
The licensee's.
program controls thread
engagement
during maintenance
and modification
practices to ensure that functional integrity of systems
does not become
degraded.
The inspector's
observations
indicated
a weakness
in program
implementation,
even though
some of the conditions were found acceptable
from a strength perspective.
In response
to the multiple deficiencies
identified, the licensee initiated
an engineering
evaluation to determine
~ the minimum acceptable
thread
engagement,
with the intent of later
performing system walkdowns to assure
conformance to the resultant
requirements.
The failure to comply with the procedure
30DP-9MP02 is
an apparent
violation of NRC requirements
(Violation 50-528/92-17-01).
One apparent violation of NRC requirements
was identified.
Surveillance Testin
- Units
1
2
and
3
61726
Selected
surveillance tests
required to be performed. by the technical
.
specifications
(TS) were reviewed
on
a sampling basis to verify that:
1)'he 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
Procedure
Descri tion
Unit 2
Integrated
Safeguards
Test, Train
B
'P
d
.
Pedi
ADV Nitrogen Accumulator Drop Test
On Hay 2,
1992, the inspector
observed portions of surveillance test
ADV Nitrogen Accumulator Drop Test,
and noted
two areas
where
minor performance variations
appeared
to affect the result
by a few psid.
Since this test often only passes
by only a few psid, these differences
could impact the overall result of the test.
Two specific performance
variations were observed.
The first was
how and where
on the accumulator
the temperature
measurement
was taken.
The second
was the inspector
noting that the test
gauge instrument root valve was not fully open,
and
when it was opened
more fully, the pressure
reading dropped
2 psid.
The
inspector discussed
these
performance variations with the System
Engineering Supervisor
who indicated that the System Engineer
had noted
data scatter in the test results
and
had drafted
a series of
recommendations
to minimize this scatter
and raise the margin between
result
and acceptance
criteria.
The inspector
concluded that these
measures
appear to address
any concern raised
by the observed
performance
variations
and encouraged
the licensee to implement these
recommendations
in a timely manner.
The licensee
responded
by stating that the
recommendations
are expected
to be approved
by June 30,
1992,
and
implemented in a timely manner.
Unit 3
~d
Il
72ST-3RX09
36ST-9SB02
No violations
PASS Functional Test
PPS Functional
Test - RPS/ESFAS
Logic
PPS Bistable Trip Units Functional
Test
of NRC requirements
or deviations
were identified.
lant Maintenance - .Units
1
2
and
3
62703
'uring
the inspection period,
the inspector
observed
and reviewed
selected
documentation
associated
with maintenance
and problem
investigation activities listed below to verify compliance with
regulatory
r equirements,
compliance with administrative
and maintenance
procedures,
required quality assurance/quality
control department
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 Reload
o
SIB-UV-614 Terminal Block Replacement
~Un't
2
o
Emergency Lighting Battery Replacement
On April 29,
1992, the "A" emergency diesel
generator
(EDG) tripped on
under-frequency.
CRDR 2-2-0149
was written for root cause of failure
determination.
At the
end of the report period,
CRDR 2-2-0149
was still
open
and the inspector
noted that the preliminary root cause of the trip
appeared
to be
an improperly installed U-ring in an air valve in the
diesel tripping system.
The inspector
noted that preventive maintenance
was performed
immediately prior to the trip and the
procedure
did not contain specific instructions regarding the proper
orientation of U-rings in these
types of valves.
The'inspector further
noted that improper operation of these valves would not affect the safety
function of the
EDG.
In one case,
the affected valves
are
bypassed
during
an emergency start of the diesel
generator;
therefore,
the valves
10
affect starting capability.
In other cases,
the valves would need to
operate to shut
down the diesel after starting
and therefore
would not
prevent the diesel generator's ability to start (these valves are
routinely tested).
At the exit meeting,
the inspector
emphasized
the apparent similarity
.
between
improper maintenance
practices
regarding these U-rings and other
recent
problems
such
as the Feedwater Isolation Valve 0-ring problems
noted in Paragraph
7 of this report.
The licensee
acknowledged
the
inspector's
comments.
Unit 3
o
CEDH HG Set No.
1 Troubleshooting
o
SGA-UV-184A Troubleshooting
a
o
Hain Transformer, "A" Phase
Grounding Connection
o
Essential
Spray
Pond Filter Hedia Replacement
o
"B" Class
lE Battery Charger Input Breaker Trip Troubleshooting
o
RK/RJ System High Voltage Short Troubleshooting
No violations of NRC requirements
or deviations
were identified.
Secondar
Chemistr
H Excursion - Unit 2
71707
On May ll, 1992, the unit exceeded
the upper
pH limit of 9.6 (an
administrative limit, not .Technical Specifications)
during
a realignment
of the condensate
system to full bypass
flow around the condensate
demineralizes
(CDs) for chemistry test data gathering
and repairs to the
system.
Since condensate
pH is normally kept low in the
pH band of 9. 1-,
9.6 with the
CDs online,
and the band
changes
by procedure to pH=9.3-9.6
with CDs bypassed,
the unit was in a chemistry action level for low pH as
soon
as the
CDs were bypassed.
In anticipation of this, unit chemistry
personnel
planned for and initiated an
ammonia addition
as
soon
as the
CDs were bypassed
and targeted
pH 9.5 as the final goal.
Control of condensate
pH with the
CDs online was normally accomplished
by
controlling the
ammonia addition rate, relying on the
ammonia
removal
by
the CDs'nd online monitoring of pH.
Therefore,
no calculation
was
needed
because
a= balance
was achieved
and maintained.
Chemistry personnel
assumed
that the normal technique
would also work
when raising
pH with the
CDs bypassed.
No calculation
was performed.
Chemistry personnel
were unaware of the time response
characteristics
of
the online
pH monitoring instrumentation.
Without ammonia
removal
due to
the
CDs being bypassed,
a balance
no longer existed.
A calculation would
have provided
an estimate of the amount of ammonia
needed to achieve the
desired
pH.
Chemistry personnel
terminated the
ammonia addition when the
pH read 9.5, yet the system
pH trended
up to
a peak of 9.8.
The
pH
excursion
also raised
condensate
conductivity out of its control
band
resulting in an action level for conductivity as well.
The inspector
concluded that the failure to perform
a calculation for the
ammonia
addition
and the unfamiliarity of chemistry technicians
with the time
response
characteristics
of the
new online
pH monitoring system,
represented
weaknesses
in the administration of the chemistry control
program.
The inspector
acknowledged that this
pH excursion out of the
control
band appeared
to have
no significant adverse
impact on the
secondary
system.
The licensee
agreed with the 'inspector's
conclusion
and will be identifying these
as lessons
learned in an evaluation of the
CD bypass evolution as part of a secondary
chemistry control evaluation,
which is ongoing.
No violations of NRC requirements
or deviations
were identified.
7.
eedwater Isolation Valve
0-Rin
Failures
Unit 3
71707
The
NRC inspector's
review of recent
FWIV 0-ring failures indicates that
further licensee
action is necessary
to prevent recurrence.
Additionally, the inspector
noted that
some engineering
evaluations of
these failures lacked
a thorough analysis of the potential for these
failures to impact the safety function of the valve.
On Hay 7,
1992 during fast closure of FWIV's SG-137
and SG-174 in Unit 3,
while performing
a controlled reactor shutdown,
the submanifold
"B" port
0-ring on the "H" 4-way valves failed.
This caused
hydraulic fluid to
leak out of the interface
between the 4-way valve submanifold
and the
actuator
body.
Similar failures occurred
on valve SG-137 in Unit 3 on
June
21,
1991
and August 31,
1991.
The first of these resulted
in a root
cause of failure
EER (91-SG-133)
which focused
on leakage
through
a
solenoid valve, but not the 4-way valve,
even though 4-way valve 0-rings
were found damaged with sections
missing.
The second of these resulted
in a
CRDR (3-1-84).root
cause of failure evaluation which noted .that
one
0-ring had disappeared
completely.
The cause
was evaluated
to be the
high pressure
hydraulic flow turbulence
impacting the 0-ring to the
extent that it was dislodged
and carried into the valve actuator with the
hydraulic flow.
This prompted
an Engineering
Evaluation
Request
(EER 91-
SG-175) to redesign
the submanifold to better "capture" and.hold the 0-
ring in place.
This design equivalent
change
EER was given priority 5
and was not yet complete
when the Hay 7,
1992 failures occurred.
Both
failures in Hay 1992 were found to be due to missing the
same 0-ring as
in the August
1991 failure.
This prompted the licensee
to upgrade the
EER to priority 3 with an expected
completion date within 90 days,
such
that replacement
submanifoldswill
be ready for installation prior to the
next Unit 3 refueling outage,
and for subsequent
failures if they occur.
The inspector considered
the possibility that the 0-rings
had not been
installed,
but since
no leakage
occurred during prior valve testing or
operation this possibility was not credible.
The inspector noted that the
CRDR 3-1-84 evaluation for the August
1991
failure did not include
an assessment
of the potential for safety
function impact due to an 0-ring being in the
FWIV hydraulic closure
system,
nor did it assess
the potential for loss of hydraulic fluid due
to leakage during the closing stroke
such that the FWIV's ability to
close
(perform its safe'ty function) was impacted.
The licensee
determined that the hydraulic accumulators
held approximately
10 gallons
12
8.
of fluid and required
5 gallons to completely close the
FWIV.
Mechanics
estimated
the total leakage
during and after closing to be
a maximum of
two gallons.
Licensee
engineering
management
acknowledged
the need for
thorough safety function impact reviews
and -subsequently
evaluated
both
questions
during their evaluation of the May 7 failures
(MNCRs 92-SG-
3043/3044
and
EER 92-SG-44).
Both evaluations
concluded that the safety-
function would not be impacted.
The inspector further noted that the licensee's
inspection of the
"M"
valve on Unit 3 valve SG-137 also identified other internal 0-rings which
were damaged.
These
were identical to the 0-rings which failed in Unit
1
during April 1991
and for which
a team root cause of failure effort
identified personnel
error during valve assembly
as the cause.
The
inspector also noted that this Unit
1 failure was manifested
by a sudden
~ and sustained
loss of 'accumulator
pressure
due to internal
leakage within
the 4-way valve.
The inspector considered
that the Unit 3 0-rings which
failed appeared
identical to the Unit
1 failures
and that sudden
and
sustained
internal
leakage
could occur during
a closing stroke should the
0-ring fail at that moment. This type of failure would effectively allow
a loss of hydraulic fluid through the 4-way valve similar to the loss
through the submanifold to actuator interface described
above,
although
such
a failure has not been
seen to have
impacted
any
FWIV to date.
The licensee
agreed
and stated that the potential for 4-way valve
internal
leakage to imp'act the
FWIV safety function would be evaluated.
After the report period ended,
on June 9, 1992, Unit 1 experienced
another
apparent failure of an
"M" 4-way valve on FWIV SG-132 while
conducting surveillance testing at power.
Due to the recurring nature of
this failure mechanism,
the inspector will review the licensee's
further
evaluation of the Unit
1 failure in light of the historical failures,
and
will review the licensee's
evaluation of potential internal
leakage
impacting the safety function of the
FWIVs (Followup Item 50-528/92-17-
02).
No violations or deviations of NRC requirements
were identified.
Alert Declared
Due to Partial
Loss of Annunciators
and Plant
Com uter-
Unit 3
93702
On May 4,
1992, while Units
2 and
3 were operating at
100X power and Unit
1 was in Mode 5, Unit 3 experienced
a partial loss of control
room
-and
a subsequent
loss of the plant computer.
The Unit
declared
an Alert at 8: 19
a downpower to
approximately
75X to meet Technical Specification requirements
associated
with a loss of the Core Operating Limit Supervisory
System
(COLSS).
The
loss of annunciators.occurred
due to a maintenance activity in which a
DC lead from the annunciator
system inadvertently
came into contact
with a 480V AC electrical
bus,
causing
blown power supply fuses
and
annunciator light bulbs,
and damaging
many annunciator
system logic
circuit cards
and
some relay cards that interface
between the annunciator
system
and the plant computer.
The plant computer
became
overloaded
by
the surge of alarm state
changes
and stopped functioning.
13
0
The Alert condition ended
on Hay 6,
1992, following restoration of alarm
and computer
systems
and acceptable
system testing.
Unit 3
was then shutdown to Node
3 to continue testing
and maintenance
of the
system.
An NRC Augmented Inspection
Team (AIT) evaluated this event,
which is
documented
in Inspection
Report 50-530/92-19.
Ind'vidual Plant Examination Status
and Results
Units
1
2
and
3
37 00
The inspector
examined the licensee's
processes
for performing the
Individual Plant Examination
(IPE) in accordance
with Generic Letter 88-
20, through review of the results,
discussions
with personnel,
and
assessing
the licensee's
use of the
IPE results.
The licensee
had completed the Level
1 Probabalistic
Risk Assessment
(PRA) for internal events
and the Containment Analysis (Level 2)
PRA.
The results
were submitted to the
NRC for staff review on April 29,. 1992.
The licensee
intends to complete their Fire Analysis
and External, Events
analyses
(except seismic)
by June
1994.
The seismic schedule is under
NRC review.
In the area of external
events,
the licensee
has taken
prudent action to minimize external
events
hazards
in providing
mitigating action to preclude tornado
borne missiles.
For example,
the
licensee
had determined that spray
pond nozzles
may be damaged
by tornado
borne missiles.
In response,
the licensee
had established
program
controls
and periodic site inspections for temporary structures
and,
transient missiles.
Another example of proactive
use of IPE/PRA results
was observed
in the
licensee's
use of shutdown risk evaluations.
Shutdown risk evaluations
have
been
performed for the third refueling outages of Units
1 and 2.
The evaluation
team consists of members
from the
PRA group,
outage
management,
and unit operations.
The licensee
has defined critical
safety functions during the outage
and evaluated
the various reactor
coolant system conditions during the outage
against the minimum
acceptable
level of redundancy for each. critical safety function.
As
a
result,
an outage
work activity schedule
was developed
which provided the
minimum levels of redundancy.
Outage
management
was aware of the minimum
levels of redundancy
by use of a critical safety function board in the
outage
work control
area
and assessed
emergent
work advisability using
these criteria.
In the area of emergency
planning, the licensee
plans to integrate
results
and techniques
into scenario
development to challenge
engineering
and operations
regarding
success
path definition.
PRA event
and fault
trees will be placed in the
TSC and
EOF about June
1992.
The
PRA group
is represented
in the
TSC to take advantage
of this knowledge in dealing
with events.
In the area of training, the licensee
has developed training for
operators
in the results of the
PRA and
has provided insight for the
14
staff on the affects
on plant safety of the discretionary
removal of
safety equipment
from service during operating
and shutdown conditions.
In the area of maintenance,
the
PRA group
had identified risk sensitive
systems to the. maintenance
organization.
For example,
the
IPE/PRA
'rganization
was represented
on the task force established
by the
licensee to review the preventive maintenance
needs of the facility and
to establish
a defensible definition of the necessary
equipment
preventive maintenance
tasks.
System unavailability targets for these
" systems
have
been placed into the facility business
plan
and assured
that
work control supervision
was
aware of the targets
and the allowed
unavailability remaining.
The twelve week schedule,
used to establish
which systems
are available for maintenance
at any time,
was being
reviewed
by the PRA-group to provide planners with guidance
regarding the
advisability of simultaneous
removal
from service of the safety
systems
in a train and to review the relative risk during each
week of the twelve
week schedule.
The inspector
found that the licensee's
IPE/PRA organization
was well
staffed
and
managed
and
had actively assured
that plant
and line
organizations
were
aware of the benefits of a risk based
approach to
decisions
and that these organizations
actively involve the
IPE/PRA
organization in plant activities.'n addition, the licensee
has
established
station goals limiting the system unavailability due to on-
line maintenance
and surveillance for the emergency diesel
generator,
and high pressure
injection systems,
with two more
systems to be
added to the program in the near future.
The inspector
established
through interviews of plant operations,
maintenance,
and
engineering staff and management
that the licensee
had generally
developed
a high level of sensitivity at the facility directed
toward
assessing
the advisability of a wide range of plant activities using risk
reduction/avoidance
as
a criteria for controlling safety equipment
unavailability.
No violations of NRC requirements
or deviations
were identified.
10.
esi
n Basis Reconstitution
Pro ram Results
and Status
Units
1
2
and
3
37700
The inspector
examined the licensee's
design basis reconstitution
program
to assess
the degree of progress,
the program,
and the results of the
effort.
The licensee
had established
a procedure set,
in 1991,
assigning
responsibilities
and measures
for:
(1) compiling documents
necessary
to
support the development of a design basis
manual
(DBM); (2) reviewing the
assembled
design
documents
in support of developing
a
DBM; (3)
developing, finalizing, reviewing,
and issuing the
DBM to assure
consistency
in organization,
format and content;
(4) identifying,
screening, prioritizing, tracking,
and evaluating
open items,
(5)
assessing
the impact of open items for safety
and operability concerns
and resolving
such concerns;
(6) controlling and changing
completed
DBMs;
15
P
I
t
0
and (7) defining the criter ia, objectives,
and methodology for ver ifying
and validating the DBHs.
The procedure, for verifying and validating the
DBHs was issued
and the
licensee
was in the selection
phase to obtain
a contractor for the
performance of the verification and validation effort.
None of the
completed
DBHs had yet been validated.
The scope of the effort involves about
75 DBHs, consisting of about
55
systems
and
20 topicals.
The program began in 1989
and is scheduled
to
be completed
about
December
1995.
The level of effort is distributed
about 80X/20X in contractor/utility staff resources,
respectively.
The licensee
had completed
about fourteen
DBMs in 1991
and
had scheduled
about another eighteen .for completion in 1992.
The inspector reviewed
two'ompleted
DBHs in a cursory manner
and examined
one (spray ponds)
in
detail.
The inspector
found that the
DBHs were missing
some significant
information:
for example,
system specific regulatory requirements
and
commitments;
overall
system functional/performance
requirements;
control
=
logic, interlocks,
and sensors;
system setpoints
and bases;
system/component
design capabilities,
requirements
and margins;
reasons
for design parameters;"and
descriptions of how design
and regulatory
requirements
were met.
The'nspector
expressed
the concern to the
licensee's
management
that while there
was
no regulatory requirement for
the development of the
DBMs, the early
DBHs appeared
to be of limited
usefulness.
The licensee
acknowledged
the inspector's
concern
and noted
that recent
DBMs contained
more information.
The inspector's
examination of the spray
pond
DBH identified that the
licensee
had opened
27 open
items
as
a result of the completion of the
DBH.
The open
items were all opened
on June
25,
1991;
however, four had
not been
screened
for importance or affect on system operability until
September
1991, twelve were not screened
until February/March
1992,
and
eleven
had not been
screened
yet.
In addition,
none of the
open items
had yet been referred to engineering for resolution.
Although none of
the open items reviewed identified any issue
which made spray
pond
operability indeterminate,
the inspector
expressed
the concern that
untimely screening
reviews
and untimely referral to engineering for
resolution could cause significant issues
to be unreviewed for a long
period of time.
The licensee
acknowledged
the inspectors
concerns
and
took immediate actions to assess
and correct
DBH open item deficiencies.
This action included
an audit of all open items in the data
base to
ensure that all documentation
had
been
completed
as required
by procedure
and represented
accurately in the tracking data
base.
In addition, the
licensee
revised their open item procedure to enhance
the overall
administrative
process for resolving
open items.
No violations of NRC requirements
or deviations
were identified.
16
Shift
echn'ical
Advisor
Mannin
Units
1
2
and
3
07
12.
During an
NRC review of a
PVNGS Technical Specification
amendment
request,
dated August 28,
1991, to allow reducing the number of STA's to,
a minimum of two on site with three operating units, the
NRC determined
that for a period between July and October
1990,
PVNGS operated with a
total of two STA's on site while all three units were simultaneously
in
mode
4 or above.
The
NRC noted that the
PVNGS Updated Final Safety
Analysis Report
(UFSAR) allowed for a minimum of one
STA when all units
'ere
in operational
modes requiring STAs, but considered
the Technical Specification 6.2.4 language requiring "the STA to be onsite
and
available in the control
room within 10 minutes whenever
one or more
units are in MODE 1, 2, 3, or 4" to be more restrictive, requiring
an
assigned
to each, unit individually when required
due to operating
mode.
By letter dated
December
30,
1991, the licensee
withdrew the portion of
their Technical Specification
amendment
request relating to reducing th'
number of STA's to a minimum of two on site when three units were in
modes
1 through 4.
Furthermore,
licensee
management
committed to revise
the
UFSAR to reflect the need for each unit to have
an individually
assigned
STA when its mode required
one.
The inspector
concluded that the
UFSAR,. and the supporting
language of
the associated
NRC Safety Evaluation Report allowed for different
interpretations
of Technical Specification requirements,
but that the
licensee's
current commitment'for each unit to have
an
STA when in modes
1 through
4 is appropriate for a three. unit site having physically
separate
control
rooms,
thus
no further
NRC action is necessary.
ollowu
on Previousl
Identified Items
Unit
1
92702
Closed
Violation
528 91-04-04
"Control of Motor-0 era'ted
Valve
Desi
n Information" Units
1
2
and
3
92702
This violation resulted
from the licensee's
failure to maintain design
documents
up-to-date.
Followup questions
regarding the method of control
of motor-operated
valve design data
are being addressed
as Followup Item
528/91-25-07.
This item is closed.
No violations of NRC requirements
or deviations
were identified.
eview of Licensee
Event
Re orts
LER - Units
1
2
and
3
90712
and
92700
Through direct observations,
discussion with licensee
personnel,
or
review of the records,
the following LERs were closed.
a.
Unit
1
91-10,
Revision
"Units
1 and
3 Reactor Trips Caused
by Grid
Perturbation"
17
92-02, Revision Ll
"Diesel Generator Surveillance
Performed while
Unit Operating"
b.
~Un't 2
90-04, Revision LO/Ll
"Pressurizer
Safety Relief Valve Setpoints
Out of Tolerance"
The issues
raised in these
LERs are redundant to
LER 50-529/91-
05-LO which is still open.
These
.LERs are closed
and the
issues will be'valuated
as part of the review for LER 50-
529/91-05-LO.
90-01, Revision
"Hanual Reactor Trip"
c.
Unit 3
91-01, Revision LO/Ll
"Safety Valve Setpoints
Out of 'Tolerance"
The issues
raised in these
LERs are redundant to
LER 50-529/91-
05-LO which is still open.
This
LER is closed
and the issues
will be evaluated
as part of the review for LER 50-529/91-05-
LO.
92-01, Revision
"Reactor Trip Following Reactor
Power Cutback
Due to Loss of Hain Feedwater
Pump"
This event
was previously discussed
in Inspection
Report
530/91-50,
Paragraph
15 and is closed
based
on that review.
No violations of NRC requirements
or deviations
were identified.
14.
Exit Heetin
30702
Exit meeting
was held
on June
4,
1992, with licensee
management
and the
resident
inspectors
during which the observations
and conclusions
in this
report were generally discussed.
The licensee
did -not identify as
proprietary any materials
provided to or reviewed
by the inspectors
during the inspection.
18