ML17300B270
| ML17300B270 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 06/21/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17300B267 | List: |
| References | |
| 50-528-96-07, 50-528-96-7, 50-529-96-07, 50-529-96-7, 50-530-96-07, 50-530-96-7, NUDOCS 9606280120 | |
| Download: ML17300B270 (65) | |
See also: IR 05000528/1996007
Text
ENCLOSURE
2
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-528
50-529
50-530
NPF-51
50-528/96-07
50-529/96-07
50-530/96-07
Arizona Public Service
Company
Palo Verde Nuclear Generating
Station,
Units 1,
2,
and
3
5951
S. Wintersburg
Road
Tonopah,
April 21 through June
1,
1996
J.
Kramer, Resident
Inspector
D. Garcia,
Resident
Inspector
D. Carter,
Resident
Inspector
J. Russell,
Resident
Inspector,
San Onofre
D. Acker, Senior Project Inspector
A. Mcgueen,
Emergency
Procedures
Analyst
B. Olson, Project Inspector
P. Goldberg,
Reactor
Inspector
D. F. Kirsch, Chief, Reactor Projects
Branch
F
9bOb280120
9b0b2i
ADOCK 05000528
6
I
EXECUTIVE SUMMARY
Palo Verde Nuclear Generating Station,
Units 1, 2,
and
3
NRC Inspection
Report 50-528/96-07;
50-529/96-07;
50-530/96-07
This integrated
inspection
included aspects
of licensee
operations,
engineering,
maintenance
and plant support.
The report covers
a 6-week period
of resident
inspection.
~0eratioos
~
The conduct of operations
was generally professional
and safety
conscious
(Section 01.1).
~
Operators
exhibited
an overall strong performance
during the Unit
1
reduced
inventory condition.
The dedicated
midloop reactor operator
displayed
an excellent
example of board monitoring by noticing
unexpected
volume control. tank level loss
due to chemistry sampling
(Section 01.2).
I
Operators
performed the startup of the Unit
1 reactor
and main generator
in a careful
and professional
manner.
The control
room staff
appropriately
addressed
the failure of a control element
assembly
(CEA)
to initially move (Section 01.3).
The Unit 2 startup
communications
were generally concise
and utilized
repeatbacks.
The"control
room supervisor maintained positive control
over the evolution.
On two, occasions,
the operators
appropriately shut
down the reactor
when they encountered
reactivity discrepancies
(Section
01.4).
~
Operations
management
corrective actions for previously identified
p. oblems
appear to address
the observed
inconsistency
in operator
performance
(Section 01.5).
~
Crew briefings enhanced
communications within and between
crews (Section
01.6).
~
The inspectors
identified an example of a violation regarding
the
failure of operators
to follow procedure
and declare
both trains of low
pressure
safety injection (LPSI) inoperable.
In addition, the
operations
crew, site shift manager,
and
a compliance representative
decided the
by using
a justification that did
not contain
an adequate
technical
basis
(Section 04. 1).
An additional
example of a violation was identified regarding
the
failure of an auxiliary operator
to follow the
blowdown
system realignment
procedure,
which resulted
in exceeding
the licensed
thermal
power limit by
a small
amount
(Section 04.2).
I
I
-3-
Maintenance
~
The inspectors
observed
a high level of interaction
between
the shift
supervisor,
maintenance
engineers,
and technicians
to ensure that
feedwater control
system troubleshooting
did not result in a feedwater
(Section Ml.1).
~
The inspectors
observed
several
maintenance
activities during the report
period.
The activities were performed
as required
by instructions
and
in a professional
manner
(Sections
Ml. 1 and H1.2).
~
Troubleshooting efforts to determine
the root cause of the initial
overspeed trip of the auxiliary feedwater
(AFW) pump were extensive
and
detailed
(Section H1.3).
~
A noncited violation was identified regarding the failure to verify the
correct type of trisodium phosphate
required
by Technical Specification
(TS).
The licensee's
effort to identify the discrepancy
and to obtain
an emergency
TS change
was very good.
However,
the licensee
missed
an
opportunity to identify another
problem with a related surveillance
requirement
during review and submittal of the emergency
request
(Section M3.1).
~
The inspectors
identified
a noncited violation regarding
the failure of
a technician to follow procedures
when propping
open heating,
ventilation,
and air conditioning
(HVAC) doors.
Management's
response
to the inspectors-identified
problem was prompt (Section
M4. 1).
~
A noncited violation was identified regarding the Licensee
Event
Report
(LER) for failure to comply with the
TS surveillance
requirement
to test "at least
10 percent" of the circuit breakers
each
18 months
(Section
H8. 1).
~
A noncited violation was identified regarding the
LER reported
containment
spray
TS violation resulting from an unrecognized mini-flow
recirculation valve failure (Section H8.2).
~
A noncited violation was identified regarding the
LER reported failure
to comply with the
TS surveillance
requirement
to verify containment
penetration circuit breakers"were
open
(Section M8.3).
En ineerin
~
Engineering's effort to understand
the root cause of American Telephone
and Telegraph
(AT8T) round cell battery degradation,
to better predict
future cell performance,
and the technical
actions in response
to the
Unit 2 battery test results
were excellent
(Section
E2. 1).
l
1
I
Engineering's
original root cause
determination of a solenoid valve wire
degradation
was incorrect,
although it was reasonable
based
on
information available at the time.
Engineering's
planned corrective
actions to address
the long term environmental qualification of the
valves
were appropriate
(Section E2.2).
~
Engineering calculations
demonstrated
that
a full core offload of the
fuel assemblies
during refueling operations
was acceptable
(Section
E3.1) .
Plant
Su
ort
A noncited violation was identified regarding
the failure of a chemistry
technician to follow procedure.
During midloop operations
a technician
opened
a sample valve without notifying the control
room and left the
area.
The loss of inventory had
no safety
consequence
(Section Rl. 1).
The containment material condition
and housekeeping
improved,
as
compared to the previous Unit 3 containment
walkdown.
The safety
consequence
of the debris
found in containment
was negligible.
Additional walkdowns of containment,
as jobs were completed,
were
appropriate
(Section
R2. 1).
The inspectors identified
a violation with three
examples of improper
posting
and inadequate
contamination control.
Routine tours
by RP,
maintenance,
and operations
personnel
had not been effective in
identifying leaking components
which had inadequate
contamination
controls
(Section R2.2).
1
l
f
f
1
I
I
Re ort Details
Summar
of Plant Status
Unit
1 began this inspection
period in Mode 5.
The unit was in an outage to
replace
the shaft
on Reactor
Coolant
Pump
2B.
On May 3, the unit returned to
100 percent
power
and remained at essentially
100 percent
power for the
duration of the inspection period.
Unit 2 began this inspection period defueled.
On Hay 4, following completion
of Refueling Outage
2R6, the unit commenced
a reactor startup
and
power
ascension.
On May 8, the unit reduced
power to 40 percent to repair
a leak in
manway.
On May 10 Unit 2 returned to 100 percent
power
and remained at essentially
100-percent
power for the duration of the
inspection period.
Unit 3 operated
at essentially
100 percent
power for the duration of the
inspection period.
I. 0 erations
Ol
Conduct of Operations
01. 1
General
Comments
71707
Using Inspection
Procedure
71707,
the inspectors
conducted
frequent
reviews of ongoing plant operations.
In general,
the conduct of
operations
was professional
and safety conscious.
Specific events
and
noteworthy observations
are detailed in the sections
below.
a.
Ins ection
Sco
e
71707
The inspectors
reviewed preparations
for and control of the reduced
inventory operations,
conducted
in accordance
with Procedure
"Reactor Coolant System Drain Operations."
b.
Observations
and Findin
s
On April 21, the inspectors
observed
the operators
drain the reactor
coolant
system to
a midloop condition.
The inspectors
observed
good
communications
between the operators
and
a strong
command
presence
of
shift supervision.
The inspectors
observed
a nuclear
assurance
evaluator
ask probing procedural
and equipment questions.
On April 22, the dedicated
midloop reactor operator noted
an unexpected
response
in volume control tank level.
The reactor operator's
observation
subsequently
led to the identification of the uncontrolled
loss of inventory caused
by an open
and unattended
sample
valve
as
discussed
in Section
R1.1.
01.3
Plant Startu
Unit
1
a
~
Ins ectors
Sco
e
71707
The inspectors
observed
portions of reactor startup
performed in
accordance
with Procedure
"Reactor Startup."
In addition,
the inspectors
observed
portions of main generation
and excitation
system startup
performed in accordance
with Procedure
"Main
Generation
and Excitation."
b.
Observations
and Findin
s
01.4
The inspectors
observed
the operators
withdraw shutdown
Group
A control
element
assemblies
(CEAs)
and noted that the operators
performed the
operation in accordance
with the procedure.
When the operators
started
to withdraw shutdown
Group
B,
CEA 23 failed to move with the rest of the
shutdown
group
and
was out of sequence
with the other
CEAs in the group
by approximately
5 inches.
The operators
attempted
to move the'CEA in
manual with no success.
The licensee
performed troubleshooting
and
identified
a failed card associated
with this
CEA.
The licensee
replaced
the card
and successfully
withdrew shutdown
Group
B.
The
inspector
found that the licensee's
actions
were appropriate
in stopping
operations
to identify and correct the equipment
problem.
Reactor Startu
Unit 2
a.
Ins ection
Sco
e
71707
On May 1, the inspectors
observed
the initial attempt to perform the
Unit 2 reactor startup in accordance
with Procedure
Reactor
Startup."
b.
Observations
and Findin
s
The control
room supervisor maintained positive control of the evolution
by providing appropriate direction to reactor operators,
reactor
engineers,
and other members of the operating staff.
The inspectors
noted during the startup that operators
on two occasions
appropriately
inserted
CEAs due to reaching licensee
established
administrative limits
for differences
between
the estimated critical position
and the critical
position plotted during the startup.
The engineering
aspects
of the
startup
are discussed
in Section
E1.3.
01.5
0 erations
Recent
Performance
a.
Ins ection
Sco
e
71707
The inspectors
had discussions
with the operations director,
an
operations
department
leader,
and nuclear
assurance
operations
concerning
recent operations
performance.
b.
Observation
and Findin
s
The licensee
had determined that improvements
in operation
performance
were not consistently
sustained.
Previous
NRC inspection reports
documented
negative findings concerning control board monitoring,
attention to detail,
and procedural
adherence.
The licensee
had taken several
actions
in response
to the
inconsistencies
identified in crew performance:
The Nuclear Assurance
organization
assigned
a staff of about
15
people dedicated
to the assessment'f
operations
performance.
This staff performs operations
audits
and assessments,
and
operations
department training.
The Operations
organization initiated several
actions to improve
crew performance.
Operations
management
clearly defined
a set of
operations
standards
for performance,
assured
that all operations
staff were trained
and knowledgeable of the standards,
and
=implemented
a practice of discussing
standards
and shortcomings
with individuals involved in events.
Several
self-assessments
of
operations
performance
were conducted,
and feedback
was provided
to the staff.
A continuous
assessment
program
was established
for
use
by individuals performing or monitoring activities to assess
various attributes of performance
in the areas of safety,
ownership
(watchstanding,
monitoring, verification practices,
logs, shift turnover,
documentation,
communications,
etc.),
professionalism,
and leadership.
In addition, expectations
have
been reinforced during requalification crew training.
The results of these, initiatives have
been manifested
by several
recent
evolutions which were performed well (Units
1 and
2 midloop operations,
Units
1 and
2 reactor startups
and shutdowns,
Unit 2 stuck fuel assembly
removal,
and Unit
pump repair outage).
However,
as
noted in Section
04, additional attention is warranted to establish
consistent
good performance.
The licensee
plans to continue
implementation of activities to provide further improvement
and
consistency
to operations
organization
performance.
01.6
Shift Crew Briefin s
a ~
Ins ection
Sco
e
71707
b.
The inspectors
attended
several
operations
morning shift crew briefings
and held discussions
with the auxiliary operators.
Observations
and Findin
s
The inspectors
observed that auxiliary operators
played
an active role
in the crew briefings.
At the start of the brief, each auxiliary
operator
presented
the status of their areas
of responsibility.
The
inspectors
found that the auxiliary operators
were very familiar with
equipment status
and problems in their areas
of responsibility.
The licensee
had established
a reflection period
oF approximately
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, during the middle of the shift, where all nonessential
work is
stopped.
The operations
crew members
met in the control
room and
discussed
the morning activities
and plans for the remainder of the
shift.
In addition,
management utilized the time for lessons
learned
briefings,
as well as safety meetings.
At the end of the shift, operations
performed
a shift briefing similar
to the morning briefing.
The briefing'allowed the staff to focus
on the
information passed
on to the next crew.
01.7 'onclusions
on Conduct of 0 erations
Operators
exhibited
an overall strong performance
during the Unit
1
reduced
inventory condition.
The dedicated
midloop reactor operator
displayed excellent
board monitoring by noticing unexpected
volume
control tank response,
resulting in the early identification of reactor
coolant inventory loss.
The licensee
performed the startup of the Unit
1 reactor
and main
generator
in a careful
and professional
manner.
The licensee
appropriately
addressed
a failure of a
CEA to initially move.
The Unit 2 startup
communications
were generally concise
and utilized
repeatbacks.
The control
room supervisor maintained positive control
over the evolution.
The operators
performed appropriately to shut
down
the reactor
when they encountered
reactivity discrepancies.
Operations
management
corrective actions
appear
appropriate
to address
the observed
inconsistency
in operator
performance.
The crew briefings enhanced
communications within and between
crews.
04
04.1
Operator
Knowledge
and Performance
0 erabilit
Unit 2
'a ~
Ins ection
Sco
e
71707
'b.
On May 2, during
a tour of the control
room, the inspectors
reviewed the
unit log and noted
an entry indicating that both trains of LPSI may have
been inoperable,
but not declared
Subsequently,
the
inspectors
reviewed the applicable
procedures
being utilized, 400P-
9SI02,
"Recovery from Shutdown Cooling to Normal Operating Lineup,"
and
40AL-9RK2B, "Panel
B02B Alarm Responses."
Observations
and Findin
s
The inspectors
reviewed the unit log and identified
a discrepancy
during
the performance of the boration of the cold leg injection lines.
The
unit log indicated that three of four pressure
indicators (safety
injection tank line pressure)
showed pressure
greater
than
1540 psig,
a
condition that could impact both
LPSI trains.
The log also indicated
that the shift technical
advisor, shift supervisor,
site shift manager,
and
a nuclear compliance representative,
discussed
the condition and
agreed that,
since the condition was .caused
by the performance of an
approved plant Procedure
and that actions
were taken to
promptly rectify the situation, operability of the
LPSI trains
was not
affected.
The licensee
had previously determined that if the pressure
exceeded
1540 psig downstream of the
LPSI injection valves,
the valves might not
"open with the large differential pressure
across
the valves
(pressure
locking).
Specifically, under worst case
design basis,
the valve
actuator
motor would be subject to stall torque conditions
and could not
open the injection valve.
The inspectors
requested
a pressure
history for the four transmitters
from the shift technical
advisor.
In review of the trends,
the
inspectors
noted that initially all four transmitters
indicated that
pressure
exceeded
1540 psig
and that pressure
on three of the four
remained
above
1540 psig for approximately
15 minutes.
In addition, the
maximum pressure
on one of the transmitters
reached
approximately
1700
psig.
Procedure
40AL-9RK2B, alarm window SI
CHK VLV LEAK PRESS
HI prescribed,
in part, that, if the indicated pressure
is greater
than
1540 psig, it
was necessary
to declare
the associated
LPSI train inoperable
and enter
the associated
TS.
The inspectors
considered
that the licensee's
stated
reason for not declaring the
LPSI trains inoperable
(because
the
operators
were performing
an approved plant procedure
to borate the cold
leg injection lines)
was without
a technical
basis
and was, therefore,
an inadequate justification for operability.
In addition,
when the
-10-
04.2
operators
decided
not to declare
the valves inoperable contrary to the
actions prescribed
by Procedure
(40AL-9RK2B), they did not take action
to revise the procedure.
The inspectors
concluded that operators failed
to declare
both trains of LPSI inoperable
as required
by 40AL-9RK2B.
This is an example of a violation of TS 6.8. 1 (50-529/96007-01).
On Hay 8, the inspectors
informed valve services
and system engineering
groups of the problem.
Both groups
were unaware of the event
and
indicated they would perform an operability evaluation
based
on actual
plant conditions to determine if the
LPSI trains were, in fact,
Subsequently,
engineering
determined that,
although the
pressure
in the alarm response
procedure
was exceeded,
revised
calculations with new degraded grid information provided
a technical
basis that the
LPSI valves were operable until the pressure
transmitters
exceed
1850 psig.
On Hay 17, the licensee
revised
Procedure
40AL-9RK2B to reflect the
new
pressure
value
and issued
a night order to the operating
crews to inform
them of the change.
Misali nment of Steam Generator
Blowdown
S stem
Unit 2
'a ~
Ins ection
Sco
e
71707
The inspectors
reviewed the licensee's
response
to the Hay ll,
misalignment of the steam generator
blowdown system,
which resulted
in
power operation
in excess
of the licensed
thermal limit.
b. Observations
and Findin
s
On Hay 11, Unit 2 operators
reduced reactor
power to 99 percent
and
performed high rate
blowdowns to the main condenser.
Subsequently,
an auxiliary operator
was dispatched
to realign the steam
generator
blowdown system for normal
blowdown to the blowdown flash
tank.
The realignment
was completed,
and reactor
power
was returned to
100 percent.
On May 13,
a reactor operator questioned
a difference
between reactor
power calculated
from primary plant parameters
and reactor
power
calculated
from secondary
plant parameters.
At the
same time,
an
auxiliary operator questioned
the lineup of the blowdown system.
Investigation
found that the
blowdown system
from one of the steam
generators
to the
blowdown flash tank was isolated.
The isolation of
the system resulted
in actual
reactor
power being greater
than indicated
reactor
power.
The licensee
calculated that actual
reactor
power
exceeded
indicated
power by approximately 0.28 percent for a period of 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br />.
The
highest rolling 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> average of actual
reactor
power was determined
to be 100.27 percent.
The inspectors
noted that this event
was
bounded
~ I
F,
-11-
04.3
by the assumptions
in the Updated final Safety Analysis Report
(UFSAR)
for thermal
power of 102 percent.
The inspectors
discussed
the event with Unit 2 operations
management.
The inspectors
learned that the auxiliary operator
had not carried
a
copy of nor followed Procedure
"Operating the
Steam
Generator
Blowdown System,"
and
had relied
on memory while realigning
the blowdown system.
The failure of the auxiliary operator to follow
procedure is
a second
example of a violation of TS 6.8. 1
(50-529/96007-01).
The licensee initiated Condition Report/Disposition
Request
(CRDR) 2-6-0113 to evaluate
the event.
In addition to determining that
the auxiliary operator did not use
a procedure to perform the valve
realignment,
the licensee
determined that:
supervision
was not
adequately
ensuring
the operations
expectations
were being met with
regard to procedural
adherence;
and control
room operators
made wrong
assumptions
regarding the response
of indications
from the blowdown
flash tank after the realignment.
Conclusions
on 0 erator
Knowled
e and Performance
A violation was identified involving .two examples of failure to follow
procedures:
the failure to follow the 'alarm response
procedure
by not
declaring
both trains of LPSI inoperable,
and the failure to follow the
blowdown procedure,
which resulted
in slightly exceeding
the licensed
thermal
power limit.
The decision that the
was
based
on inadequate
technical
information and did not include engineering's
evaluation.
An
engineering
evaluation of the situation
was not performed until the
inspectors
raised questions.
The licensee
performed additional
engineering
evaluations
and concluded that the
LPSI system
was operable
at the pressures
encountered
and revised the procedure to include the
new operability criteria.
The licensee
appropriately initiated
an investigation into the causes
of
the misalignment of the steam generator
blowdown system.
The results of
their preliminary investigation
appeared
to reflect the causes
of the
event.
08
08.1
MISCELLANEOUS OPERATIONS
ISSUES
(92901)
Closed
LER 50-529 94007:
momentary entry into TS 3.0.3
due to
personnel
error.
This
LER was
a minor issue for which the licensee's
actions
were appropriate.
This
LER was closed.
-12-
II. Maintenance
Hl
Conduct of Maintenance
Ml. 1
General
Comments
on Maintenance Activities
a
~
Ins ection
Sco
e
62703
The inspectors
observed all or portions of the following work
activities:
~
Maintenance of Westinghouse
Type DS-416 Reactor Trip
Switchgear
(Unit 3)
~
Pump Disassembly
and Assembly (Unit 1)
Troubleshoot
Control
System to Determine
Cause of Spurious Oscillations (Unit 2)
b.
Observations
and Findin
s
The inspectors
found these
work activities were performed in accordance
with procedures.
In particular,
the inspectors
observed
a high level of
interaction
between
the shift supervisor,
maintenance
engineers,
and
technicians
to ensure that the feedwater control
system troubleshooting
did not result in
In addition,
see
the specific discussions
of maintenance
observed
under Section Ml.3.
M1.2
General
Comments
on Surveillance Activities
a.
Ins ection
Sco
e
61726
The inspectors
observed all or portions of the following surveillance
activities:
~
18 Month Surveillance Test for Westinghouse
Type 4DS-416 Reactor Trip Breakers
(Unit 3)
~
Testing Atmospheric
Dump Valves in Mode
3 (Unit 2)
~
Startup
Channel
High Neutron Flux Alarm
3. 1.2.7 (Unit 2)
b.
Observations
and Findin
s
The inspectors
found these surveillances
were performed
as specified
by
applicable
procedures.
-13-
Ml.3
AFW Pum
Tri
Unit 2
a
~
Ins ection
Sco
e
62703
On May 1, the inspectors
observed initial troubleshooting of the
overspeed trip of the turbine driven
AFW pump during the Unit 2 startup.
In addition,
the inspectors
reviewed the operability determination
and
discussed
the determination with maintenance,
engineering,
and
operations.
On May 17, the inspectors
observed
a performance test of
the
AFW pump.
b.
Observations
and Findin
s
C.
Approximately 10 minutes into
a postmaintenance
test run, the
AFW pump
speed
ramped
up over
a
15 second
period,
and the
pump tripped
on
The licensee initiated
an investigation
team to troubleshoot
and gather data.
The licensee
instrumented
and performed additional
test runs of the
pump.
Equipment evaluated
by troubleshooting
included:
the governor valve linkage, turbine governor controls
(both electric
and
hydraulic),
DC control
power,
and the steam drains.
After comprehensive
troubleshooting,
the licensee
concluded that
no abnormal
conditions
which would impact future turbine operation
could
be found.
The
licensee
wrote
which included the results
of the troubleshooting.
The licensee initiated
a weekly pump testing
program
on the
AFW pump to
monitor and detect
abnormal
pump performance.
On May 17, the inspectors
observed
one of the weekly tests
and noted
no discrepancies.
Conclusions
N3
The licensee
performed extensive troubleshooting efforts to determine
the root cause of the initial overspeed trip of the
AFW pump.
The
licensee
appropriately
performed additional tests of the
AFW pump.
Based
on the troubleshooting
and additional tests,
the inspector
concluded that the licensee's
was reasonable.
Maintenance
Procedures
and Documentation
M3.1
Emer enc
TS Chan
e
a
~
Ins ection
Sco
e
61726
The inspectors
reviewed the licensee's
entry into TS 4.0.3
and their
emergency
request for a TS change
concerning trisodium phosphate
maintained
in containment.
I
-14-
Observations
and Findin
s
On Hay 14, the licensee
entered
TS 4,0.3 after determining that part of
TS Surveillance
Requirement 4.5.2.d.2,
to verify every
18 months that
a
minimum of 464 cubic feet of trisodium phosphate
was located in
containment,
had not been
performed in the three units.
During
a review
of the TS, the licensee
found that the form of trisodium phosphate
located in containment
was anhydrous rather than dodecahydrate,
as
specified
by the TS.
On Hay 15, the licensee
submitted
an emergency
request to change
the
TS to specify that anhydrous
trisodium phosphate
was to be verified in containment.
The emergency
request
was approved,
and the 'licensee
exited
The inspectors
discussed
this event with chemistry
and nuclear licensing
personnel
and reviewed original design calculations,
purchase
orders,
and the original
TS
~
The licensee
was designed for anhydrous
trisodium
phosphate
to condition water in the containment
sump following a loss of
coolant accident.
However, the original
TS was approved indicating that
the dodecahydrate
form of trisodium phosphate
would be used.
Surveillance
Requirement 4.5.2.d.3 tested
the ability of a specific
amount of trisodium phosphate
to condition water from the refueling
water storage
tank.
The inspectors
questioned
chemistry personnel
about
the requirement
and whether the amounts specified
by the test were based
on the anhydrous
or dodecahydrate
form of trisodium phosphate.
The
chemistry department
subsequently
determined that the amounts specified
were based
on the dodecahydrate
form of trisodium phosphate.
On Hay 20,
the licensee
performed
a determination
using
some of the original
trisodium phosphate
design calculations to confirm that operability was
maintained.
The inspectors
observed that Section
6. 1. 1.2 of the Palo Verde
indicated that trisodium phosphate
dodecahydrate
would be used in
containment.
Section
6. 1. 1.2 indicated that the chemical
would be
tested,
but the test parameter for water temperature
differed from the
water temperature listed in Surveillance
Requirement 4.5.2.d.3.
The licensee
developed
an action plan to address this issue.
The
inspectors
reviewed the plan
and found that the licensee
intended to
develop
a new test to verify the ability of anhydrous
trisodium
phosphate
to condition water from the refueling water tank.
The
licensee
intended to revise Surveillance
Requirement 4.5.2.d.3
based
on
the
new test.
The licensee
also intended to investigate
and correct the
inconsistencies
between
the surveillance
requirements
and the
While the licensee
maintained the design basis,
the Surveillance
Requirement 4.5.2.d.2 to verify the type of trisodium phosphate
located
in containment
was not met.
This licensee-identified
and corrected
violation is being treated
as
a noncited violation, consistent
with
Section VII.B.I of the
NRC Enforcement Polic
(50-528;529;530/96007-02).
-15-
Resolution of the
UFSAR inconsistency will be reviewed in
a future
inspection (IFI 50-528;529;530/96007-03),
Conclusions
One noncited violation, regarding the failure to meet the
TS
Surveillance
Requirement 4.5.2.d.2,
was identified.
The licensee's
effort to find the discrepancy for the type of trisodium
phosphate
used
in containment
and to obtain
an emergency
TS change
was
very good.
However,
the licensee
missed
an opportunity identify another
problem with a related surveillance
requirement during review and
submittal of the emergency
request.
The licensee's
action plan to
resolve this entire issue
was appropriate.
Naintenance Staff Knowledge
and Performance
Containment Ventilation Pur
e Isolation Valve Leak Rate Test
Unit 3
Ins ection
Sco
e
61726
On Hay 7, the inspectors
observed
performance of Procedure
"Containment Ventilation Purge Isolation Valves (42")
57."
Observations
and Findin
s
The inspectors
noted that the objective of the test
was to verify that
the leakage rate of the containment
purge isolation valves
was within
the limits specified in TS.
The test accomplished
the objective
by
pressurizing
the volume between
the two valves (inside
and outside of
containment
purge isolation valves)
by applying air to the drain/test
valve located
between
them.
The technician
was unable to properly pressurize
the volume between
the
valves.
The licensee
stopped
the surveillance test
and entered
the
appropriate
action statements.
The licensee
determined that the valve
outside containment
was not seated
properly.
Following maintenance
on
the valve, the technician
reperformed
the test satisfactorily.
The inspectors
noted several
discrepancies
during the performance of the
initial surveillance test.
The local leak rate test
(LLRT) technician
failed to perform the procedure
in sequential
order.
The technician
performed
Step 8.7 prior to performing Steps
8.5
and 8.6.
Step 8.7
opens the drain/test valve;
Steps
8.5 and 8.6 attach test fittings and
connect
an air supply, respectively.
Although the failure to perform
the procedure
in sequential
order did not have
an impact
on the outcome
of the test,
the action did not meet management's
expectation.
During the performance of the test,
the inspectors
observed
two propped
open
HVAC doors,
A347 and A348, through which
a rubber service air hose
-16-
protruded.
The doors were labeled with direction to contact fire
protection prior to propping open.
The technicians
indicated that they
had not contacted fire protection or any other organization prior to
propping
open the doors.
The doors
were listed
as
HVAC barrier doors in
Procedure
"Control of Security,
Fire and
HVAC Barrier Doors,
Hatches
and Floor Plugs."
The procedure
indicated that fire protection
was to be contacted prior to propping
open doors to ensure that
appropriate
compensatory
measures
were implemented.
The inspectors
contacted fire protection,
and they determined that
no compensatory
measures
would have
been required for the propped
open doors.
The
failure to contact fire protection prior to propping
open the doors
constitutes
a violation of minor significance
and is being treated
as
a
noncited violation, consistent with Section
IV of the
NRC Enforcement
~Pol ic
(50-530/96007-04)
.
The inspectors
discussed
the performance of the test with the licensee.
The licensee initiated
a
CRDR to evaluate
the event.
Maintenance
supervision
discussed
the issues of concern with all the
technicians
and reinforced management's
expectations.
Conclusions
The inspectors
identified that licensee
personnel
failed to follow
procedures
and instructions
when propping
open
two labeled
HVAC barrier
doors.
Management's
response
to the problem was prompt
and thorough.
Miscellaneous
Maintenance
Issues
(90712)
Closed
LER 50-528 94001-01:
Surveillance
Requirement 4.8.4. 1 not
fully met,
The licensee
determined that they did always
comply with the
TS surveillance
requirement to test "at least
10 percent" of the circuit
breakers
each
18 months.
Due to rounding,
the licensee
sometimes
tested
less
than
10 percent of the breakers;
however, their program would have
ensured
100 percent testing over
10 years.
As corrective action,
the licensee
tested
other circuit breakers
to
ensure that the "at least
10 percent"
requirement
was met.
The licensee
also
changed
preventive maintenance
tasks to ensure that the sample size
would meet the requirement,
The inspectors
reviewed
CRDR 9-3-0569 which included the licensee's
investigation of this event.
The inspectors
found the licensee's
investigation to be thorough
and their corrective actions to be
appropriate.
The inspectors
also reviewed
a sample of the preventive
maintenance
tasks
and found that the test
sample size met the
10 percent
requirement.
This failure constitutes
a licensee-identified
and
corrected violation of minor significance
and is being treated
as
a
roncited violation, consistent
with Section
IV of the
NRC Enforcement
~Polic
(50-526/96007-05).
I
-17-
M8.2
Closed
LER 50-528 95016:
TS violation due to unrecognized
containment
spray valve failure.
The Train
B mini-recirculation motor-operated
valve failed when
a motor set
screw
was tightened,
binding the motor.
The licensee
found that the motor's stator
had previously
been
replaced
and
had
been
machined to allow proper fit into the motor housing.
The
licensee
determined that enough material
had
been
removed to affect the
ability of the set
screw to hold the motor in place.
The licensee
determined that the valve had
been
inoperable for greater
than
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />,
in violation of TS 3.6.2,1.
H8.3
The licensee
corrected
the problem
by adding
and the valve operator
was reoriented to improve performance.
The
licensee
also inspected
other similar valves
and verified those to be
The inspectors
reviewed
CRDR 1-5-0231,
which included the licensee's
investigation of this event.
The inspectors
found the licensee's
investigation to be thorough
and their corrective actions to be
appropriate.
This licensee-identified
and corrected violation is being
treated
as
a noncited violation, consistent
with Section VII.B.1 of the
NRC Enforcement Polic
(50-528/96007-06).
Closed
LER 50-529 95004:
TS violation due to missed surveillance
requirement.
On two occasions,
two inoperable
containment penetration
circuit breakers
were not verified to be open every
7 days
as required
by TS 3.8.4. 1, Action a.
The licensee
subsequently
identified that the
breakers
had remained
open
and were under clearance
control.
The
licensee's
corrective actions
included the use of a controlled procedure
for subsequent
verifications of breaker positions
and
a review of the
procedure after completion of the task.
The inspectors
reviewed
CRDR 2-5-0250,
which included the licensee's
investigation of this event.
The inspectors
found the licensee's
investigation to be thorough
and their corrective actions to be
appropriate.
This failure constitutes
a licensee-identified
and
corrected violation of minor significance
and is being treated
as
a
noncited violation, consistent with 'Section
IV of the
NRC Enforcement
~Polic
(50-529/95007-07).
III. En ineerin
El
Conduct of Engineering
El. 1
Reactor Startu
Unit 2
a
~
Ins ection
Sco
e
37551
On Hay 1, the inspectors
observed
the Unit 2 reactor startup in
accordance
with Procedure
Reactor Startup,
and evaluated
engineering's
response
to identified reactivity anomalies.
4
0
-18-
Observations
and Findin
s
During the reactor startup,
the inspectors
observed
the reactor engineer
and shift technical
advisor correctly enter the information into the
computer to perform the I/m plot.
Two consecutive
anticipated critical
positions projected that the reactor would achieve criticality 500
pcm
below the estimated critical position.
In accordance
with licensee
administrative
procedures,
operators
inserted
the regulating
group
control element
assemblies,
and engineering
and management
evaluated
the
condition.
The licensee initiated
a
CRDR to evaluate
the problem.
Reactor
engineering
reviewed previous reactor startups
and noted similar
characteristics
during previous startups.
The licensee
determined that
the estimated critical position was accurate.
The licensee
determined
that it was appropriate
to perform another startup.
Operators
performed the second startup
and did not receive
two
successive
anticipated critical positions within 500
pcm below the
estimated critical position.
However,
as operators
performed the second
approach
to criticality, engineering
determined that with the next pull
of the
CEAs the reactor would become critical at
a 'point 500
pcm below
the estimated critical position.
The licensee
again performed
a reactor
shutdown.
The licensee
evaluated
the condition
and noted that this was the first
startup that included
an
11 parts
per million boron adjustment for the
use of guardian grid fuel.
Approximately two-thirds of the fuel
assemblies
in Unit 2 were manufactured
with the guardian grid.
The
licensee initially inserted
the ll parts per million adjustment to
increase
the accuracy of the low power physics test predictions
based
on
the results of the recent Unit 3 refueling startup.
The licensee
removed the guarding grid bias from their "simulate" model prediction,
which lowered the estimated critical position,
and successfully
performed the reactor startup.
The inspectors
noted that the 500
pcm limit was
a licensee
administrative requirement
based
on the
TS requirement that the overall
core reactivity balance
shall
be compared to the estimated
values
and
agree within 1000
pcm.
The licensee
planned to continue to evaluate
the
reactivity discrepancies.
Conclusions
Following the second
startup attempt,
engineering
research
into the
startup
anomalies
was thorough
and
had appropriate
management
review.
~.
t
j
-19-
E2
E2.1
The licensee
decisions
to shut
down when administrative limits were
approached
was conservative.
Engineering
Support of Facilities
and Equipment
Review of Class
IE Batter
Test Results
Unit 2
b.
Ins ection
Sco
e
92903
The inspectors
reviewed the test data from the Class
lE battery testing
performed during the recent
outage,
inspected
the batteries,
reviewed
licensee corrective actions,
reviewed licensee operability evaluations,
and discussed
preliminary root causes
for the degradation
of the
ATILT
round cell batteries with licensee
personnel.
Observations
and Findin s
During the recent
outage,
the licensee
performed battery performance
discharge
(capacity) testing of the Class
lE batteries.
The licensee
noted that the capacity of the batteries
was below expectations.
Surveillance
Requirement 4.8.2. l.e requires that
AT&T batteries
demonstrate
90 percent or greater capacity
when subject to
a performance
discharge test.
Surveillance
Requirement 4.8.2.1.f requires that
ATILT
batteries
be tested
annually if their capacity drops
below 95 percent
or
more than
5 percent
since the previous test.
Battery
A tested
at
107 percent,
a reduction of 7 percent
since the
previous test.
Battery
C tested
at 88 percent,
a reduction of
20 percent
since the previous test.
Test equipment failed during
testing of Battery
D.
The licensee
had previously picked the "best" individual cells from
several different lots of cells.
Therefore,
the batteries
contained
cells manufactured
at different times with different testing histories.
The licensee
determined that the recent Unit 2 battery degradation
was
lot related.
For example,
Battery
C contained cells from lots HG-l,
HG-14,
HG-16,
and
HG-18.
For battery
C, the capacitances
of the lots
were:
HG-1,
114 percent;
HG-14,
91 percent;
HG-16,
105 percent;
and
HG-18,
82 percent.
The lots experienced
similar results
in Battery A.
In order to comply with the
TS surveillance,
the licensee
reconfigured
the cells in all four batteries.
Battery
A currently contains
HG-1 cells,
Battery, B contains
new cells from the manufacturer,
Battery
C contains
HG-16 cells,
and Battery
D contains
new cells
received
from another utility.
The licensee's
preliminary root cause
investigation identified positive
plate destruction
on the
HG-18 cells.
In addition, the licensee
determined that the vendor
had increased
the
amount of platinum in the
l
!
-20-
negative plate of cells produced after mid 1994.
The vendor
added
additional
platinum to the negative plate to improve the float behavior
of the cells.
The platinum decreased
the charging efficiency of the
negative plates to more closely match the charging efficiency of the
positive plates.
Subsequent
testing of batteries
in all three units
showed corresponding
lower negative half-cell voltage readings
in the
Unit
2 batteries,
when compared
to the readings
from the Units
1
and
3
batteries,
which contained
the lower amount of platinum.
The licensee
planned to evaluate
the effect the increase
in platinum in
the negative plate
may have
on the long term capacity of the Unit 2
batteries.
In addition,
the licensee
planned to continue to monitor the
positive
and negative plate performance of the Unit 2 batteries
by
taking half-cell voltage readings.
The licensee
informed the
NRC of
potential generic
issues
concerning
AT&T round cell batteries
through
several
meetings
and conference calls.
Conclusion
The Unit 2 reconfigured
Class
1E batteries
were operable
and met the
TS
requirements.
The licensee's
effort to understand
the root cause of
AT&T round cell battery degradation,
in order to better predict future
cell performance,
and the technical
actions
in response
to the Unit 2
battery test results
were excellent.
Solenoid Valve 0 erator
De raded
Internal Wirin
Ins ection
Sco
e
92903
Inspection
Report 50-528;529;530/95025,
Section
7, discussed
resolution
of a problem with overheating of certain solenoid valves inside
containment.
Subsequent
to this report,
the licensee identified similar
problems with pressurizer
steam
space
sample line containment isolation
Valve SS-UV-205 in Unit 2 which indicated that the original root cause
was incorrect.
The inspectors
reviewed the problem with Valve SS-UV-205
and discussed
corrective actions with the licensee.
Observation
and Findin
s
The licensee
had determined that certain solenoid valves
had heat
damaged
wire insulation
and environmental
seals
because their electrical
circuits had failed and the solenoids
were continuously energized with
120
VAC, in lieu of the nominal
42
VAC.
The licensee
had replaced
the
heat
damaged
equipment
and repaired the electrical circuits.
Subsequently,
the licensee identified that solenoid Valve SS-UV-205 had
a heat
damaged
environmental
seal.
Electrical
checks
indicated that the
valve
had not been subjected
to
an over-voltage condition.
Based
on
this
new information and the temperature
measurements
on the external
surface of a similar valve, the licensee
determined that the
E
-21-
c
~
environmental qualification life of several
of the valve's internal
components
may
be nonconservative.
Because
the licensee
had recently
inspected
and repaired
Valve SS-UV-205 in Units
2 and 3, the licensee
concluded
these
valves
were operable.
The licensee
deenergized
and
tagged
Valve SS-UV-205 in Unit
1 in the required safety position.
The
inspectors verified that the Unit
1 valve was deenergized
and tagged.
This type of solenoid valve
and environmental
seal
were used in other
systems within containment,
but with lower process fluid temperatures.
The licensee
noted that inspection of these
valves indicated
no heating
problems.
The licensee
indicated that they have not experienced
failures of this type valve, only degradation
of environmental
seals
and
internal wiring.
The licensee
planned to perform laboratory testing of this type of valve
to determine
the expected
internal
temperatures
and adjust environmental
qualification life as required.
The licensee further planned to modify
the valves to lower the temperature
at the environmental
seal
area
and
remove the internal wiring with the lowest temperature
rating,
The
licensee
planned to complete these
actions
in Unit
1 to support the next
outage.
Conclusion
E2.3
The licensee's
was acceptable,
pending the
testing results,
The licensee's
original root cause
determination
was
incorrect,
although it was reasonable
based
on information available at
the time.
The licensee's
planned corrective actions to address
the long
term environmental qualification of these
valves
appear
appropriate,
Review of Facilit
and
E ui ment Conformance to UFSAR Oescri tion
A recent discovery of a licensee
operating its facility in
a manner
contrary to the
UFSAR description highlighted the need for a special
focused
review that compares
plant practices,
procedures
and/or
parameters
to the
UFSAR description.
While performing the inspections
discussed
in this report,
the inspectors
reviewed the applicable
sections of the
UFSAR that related to the inspection
areas
inspected.
The following inconsistency
was noted
between
the wording of the
and the plant practices,
procedures
and/or parameters
observed
by the
inspectors.
As noted in Section
M3. 1, the inspectors
identified
a difference
was
identified between
the criteria for trisodium phosphate
contain in the
TSs
and
UFSAR section
6. 1. 1.2.
As noted in Section
E3. 1 the inspectors
identified several
differences
between
licensee
procedures,
the Combustion
Engineering
Standard
Safety
Analysis Report,
and
UFSAR Section
9. 1.3.3 concerning
the
SFP.
These
differences
were:
-22-
~
Cooling lineup prescribed
to cool
SFP,
when shutdown cooling is
not needed.
~
Description of water depth
above fuel assemblies.
~
Primary source of cooling water to the heat exchangers,
primary
heat sink,
and primary makeup source.
E3
Engineering
Procedures
and Documentation
E3. 1
S ent Fuel
Pool Current Licensin
Basis
a.
Ins ection
Sco
e
Representatives
of the NRC's Office of Nuclear Reactor Regulation
reviewed
UFSAR Section
9. 1.3,
"Spent
Fuel
Pool Cooling and Cleanup
System,"
and the licensee's
operation of the system in accordance
with
the
UFSAR descriptions.
b.
Observations
and Findin
s
UFSAR Section
9. 1.3.3. 1. 1 states
that one train each of the shutdown
cooling system
and the fuel pool cooling system will be in use in the
event of a full core offload.
Under these conditions,
(a core offload
90 days after startup
from previous refueling
and the pool containing
fuel from 12 previous refuelings)
the
maximum pool temperature will be
limited to less
than 125.2'F.
The inspectors
noted that
Table 9. 1-2 lists the maximum fuel pool temperature
as
145.5
F, with a
footnote stipulating that this was the design
heat load (one-third core
offload) with one fuel pool cooling train out of service.
The
information in this table did not show that
a calculation for a full
core offload with one train of spent fuel pool
(SFP) cooling had
been
performed
and will maintain
maximum fuel pool temperature
less
than
145.5'F.
The inspectors verified that the information in UFSAR
Section
9. 1.3.3. 1. 1 shows with a maximum heat load (full core offload),
and
a fuel pool cooling train augmented
by a shutdown cooling train, the
licensee
has
a calculation
on record indicating that pool temperature
remained
less
than 125.2'F.
The licensee
noted that the
SFP cooling pumps were not in the inservice
testing
program because
the
pumps
do not fall under the American Society
Of Mechanical
Engineering
(ASME) Section
XI applicability,
as described
in
a letter to the staff on December
12,
1984.
The letter explained
that there
was substantial
assurance
that these
pumps were ready to
operate
on demand
since they were normally running.
In a recent review
of the in-service testing
program,
the licensee identified the
need to
routinely monitor the performance of the fuel pool cooling system
and
issued
a
CRDR to evaluate
the concern.
-23-
Procedure
"Fuel
Pool Cooling," provided lineups for the
cooling trains.
Section 3.0 of the procedure
states
that
a single
pump
and two heat
exchangers
should
be attempted
to maintain fuel pool
temperature
less
than 145'F prior to initiating shutdown cooling.
The
UFSAR states
that this lineup should
be used to maintain temperature
less
than 125'F,
and that two pump two heat
exchanger
operations
should
be employed
above
125'F.
The licensee
planned to address
the
discrepancy
between
the
UFSAR and procedures.
The inspectors verified
that Section 4.3.5 of the Procedure
directs the operator to
augment with shutdown cooling if temperature
exceeds
145'F.
The
inspectors
also verified that the
TS requirement
to not move fuel prior
to the reactor being shutdown
100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />
had
been satisfied for the last
three refueling outages.
The inspectors
noted that
UFSAR Section
9. 1.3.3. 1.3 states
that "a
minimum of 9 feet of water is maintained
over spent fuel assemblies."
However,
TS 3.9.11 requires
23 feet over the top of the fuel assemblies
seated
in the storage
racks.
The licensee
responded
that
UFSAR 9. 1.4.6
describes
the Combustion Engineering
Standard
Safety Analysis Report
interface requirement to maintain
9 feet of water above the active
portion of a fuel assembly during fuel handling,
and
UFSAR 9. 1.4.7
describes
the ability to meet that requirement.
Further,
Combustion
Engineering
Standard
Safety Analysis Report Section
9. 1.4.3.4,
which is
referenced
in UFSAR Section 9. 1.4.3.4,
describes
travel stops in both
the refueling
and spent fuel handling machines that restrict withdrawal
of the spent fuel assemblies
to maintain the minimum 9 feet of water
over fuel being moved.
The licensee
planned to review the need to
supplement
UFSAR Section 9. 1.3.3. 1.3 to clarify that the
9 feet
requirement
was for fuel being moved,
and that there
was
a
23 foot TS
requirement
above fuel assemblies
seated
in the storage
racks.
The inspectors
noted that
UFSAR Section
9. 1.3.3. 1. 1 lists essential
cooling water prior to nuclear cooling water
as the cooling source to
the
SFP heat
exchanges.
The inspectors
noted that nuclear cooling water
should
be listed first since it is the normal
method.
The inspectors
verified that the licensee
has
a procedure for manually initiating
essential
cooling water.
The inspectors
also noted that
Section
9. 1.3.3. 1. 1 stated that the spray
ponds
were the
SFP cooling
This would only be true if the licensee
had
switched the heat
exchanger
cooling to its backup (essential
cooling
water)
source.
The inspectors
questioned
certain control
room staff regarding
normal
makeup
paths to the
SFP.
The control
room staff indicated that the
normal
makeup
method
was the liquid radwaste
system monitor tank (in
order to minimize waste).
However,
UFSAR Section
9. 1.3.3. 1.3 states
that normal
pool
makeup is from the refueling water tank.
The backup
source
is from liquid radwaste
system monitor tank or condensate
storage
tank.
Plant procedures
address
makeup
from all of the
above sources.
~
'
-24-
C.
The licensee
indicated that they would review the noted
discrepancies
and clarify that
a full core offload was routinely
performed.
These
changes
were not completed prior to commencement
of
the Unit 2 refueling outage that started
March
16,
1996.
Additionally,
the licensee
planned to review the
UFSAR sections
pertaining to the
to further verify the consistency
between
actual plant operation
and
UFSAR descriptions.
Resolution of the
UFSAR inconsistency will be
reviewed in
a future inspection (IFI 50-528;529;530/96007-03)
Conclusion
E8
E8.1
Since the plant has
two independent
SFP trains
(each
capable of being
augmented
by
a shutdown cooling train),
and
has stored less
than half of
the maximum design
number of spent fuel assemblies,
the licensee
demonstrated
that
a full core offload of fuel assemblies
(the normal
practice)
was acceptable.
Miscellaneous
Engineering
Issues
(92903)
Closed
LER 50-529 94005-01:
high pressure
safety injection motor
operated
valve failed to open during
ASHE Section
XI testing.
The valve
failure resulted
in one subsystem of the emergency
core cooling system
being inoperable.
The failed valve
(2JSIAUV0627)
was
a
2 inch rotating
stem globe valve with a Limitorque SMC-04 actuator.
The licensee
determined that the root cause of the failure of the valve
to open
was
a combination of pressure
over the seat
and excessive
stem
to disc friction.
Downstream
check valve leakage
caused
the pressure
over the seat.
The licensee
did not determine
the specific cause of the
excessive
stem to disc friction.
However, the licensee
determined that
both the pressure
over the seat
and
a high stem to disc friction had to
occur simultaneously for the failure to be repeated.
The licensee
indicated that the Limitorque SMC-04 actuator
was obsolete
and not supported
by the original manufacturer.
The licensee
indicated
that
a previously approved
design
change
was
implemented to upgrade
the
Limitorque SMC-04 actuator to
a Limitorque SMB-00 actuator.
The
inspectors
reviewed draft equipment root cause failure analysis,
CRDR 9-4-0598,
and the report,
"Generic Evaluation of the Limitorque
SMC-04 Actuator and Borg Warner
2 Inch Angle Globe Valve in HPSI
Service," Revision 0.
The report indicated that
a conservative
determination of the
SMC-04 actuator torque required to operate
the
valve was approximately
75 ft-lbs, without considering
seating
The licensee
concluded that the
SMC-04 actuator
maximum output combined
with packing load adjustment
could not accommodate
the valve torque
requirements.
Therefore,
the licensee
installed the
SMB-00 actuator
with a 250 ft-lb rating.
The inspectors
reviewed
which replaced
the
SMC-04 actuator with the
SMB-00 and noted the work
was completed
October
19,
1994.
1
-25-
In addition,
the valve
had
a rotating stem which resulted
in operating
torque loads
on the actuator
which were not taken into account
when the
original application
was determined.
The licensee
indicated that
a
modification had
been
approved to change
the valve from a rotating
stem
to
a rising stem valve which would eliminate the stem to disc friction.
The licensee
issued
a purchase
order to the valve manufacturer
to design
a new valve.
The inspectors
concluded that the licensee
had taken appropriate
short
and long term corrective actions.
Closed
Violation 50-530 94012-03:
failure to take
immediate action
required
by TS.
This violation indicated that the feeder breaker for
the Train A LPSI
pump was racked into the test position rendering the
associated
shutdown cooling loop inoperable.
In addition,
immediate
action
was not initiated to restore
the shutdown cooling loop to service
or to establish
at least
23 feet of water above the reactor pressure
vessel
as required
by TS.
The licensee
stated
they had not
considered
the
pump inoperable
because
they had taken credit for manual
operator action.
The licensee
stated that they had reasonable
assurance
that the breaker could have
been
racked
back in within the 3-hour time
period required to initiate shutdown cooling.
The licensee's
corrective actions
included surveying nuclear utilities
to determine
how other utilities view manual
operator actions for the
LPSI pump.
The licensee
concluded that the majority of the utilities
would have considered
the
pump inoperable.
The inspectors
reviewed
Procedure
"Operability Determination," Revision 3,
Appendix
C.
The licensee
had revised this procedure to include guidance
for use of manual
actions to maintain operability.
Appendix
C of this
procedure listed the actions which had to be performed in order to take
credit for manual
operation.
It also included evaluations
of the
qualifications
and ability of the personnel
performing actions,
the
number of qualified personnel
needed,
the time needed
to accomplish
the
actions,
the communications
necessary,
and the criteria of 10 CFR 50.59.
The inspectors
reviewed
CRDR 3-4-0340,
dated July 15,
1994,
which was
prepared
to evaluate
the licensee's
position
on appropriate
manual
actions to support continued operability.
The licensee
developed
a
position paper
and distributed it to operators
in the three units.
The
position paper which contained
the minimum requirements
to credit manual
operator actions
in maintaining operability was
an expanded
version of
the Appendix
procedure.
The inspectors
concluded that the licensee's
corrective actions
were appropriate.
l'
IV.
Plant
Su
ort
Rl
R1.1
Radiological
Protection
and Chemistry Controls
Chemistr
Sam lin
Durin
Hidloo
Unit
1
a
~
Ins ection
Sco
e
71750
b.
On April 22, with Unit
1 in midloop operations,
the midloop reactor
operator
noted
an unexpected
level decrease
in the volume control tank.
Subsequently,
the licensee
determined that chemistry personnel
had
begun
a purging operation
associated
with reactor
coolant sampling without
required notification to the control
room.
The inspectors
reviewed the
licensee's
response
to the event, corrective actions,
and discussed
the
event with chemistry personnel.
Observations
and Findin
s
At approximately II a.m.,
on April 22, the senior chemistry technician
and
a chemistry technician discussed
performing the required shiftly
system
sample in accordance
with Procedure
"Primary Sampling Instruction."
The chemistry technician initiated the
purging process
by opening
a sample valve with an understanding
that the
senior chemistry technician
would actually draw the sample.
The
technician left the area.
The inspectors
noted that the purging process
takes
approximately
15 minutes at
a flow rate 0.5 to I gallon per
minute.
The senior chemistry technician believed the chemistry
technician
was doing the entire sample.
Neither technician notified the
control
room.
Procedure
Step 4.3.4 requires notification of
the control
room prior to sampling.
At approximately
12:30 p,m., the midloop reactor operator detected
a
slight loss in volume control tank level.
A control
room operator
contacted
chemistry
and discovered that the
sample
purge
had
been
initiated
and
was still in progress.
The reactor operator
estimated
that the volume control tank decreased
by approximately
1.5 percent or
approximately
60 gallons.
The licensee
discussed
the event in the control
room with operations,
chemistry personnel,
and the site shift manager.
Chemistry determined
that the flow rate
was approximately 0.75 gallons per minute
and that
the total loss of inventory from the volume control tank was
approximately
80 gallons.
The licensee initiated
a
CRDR and notified
chemistry management.
The site shift manager did not contact the
operations
department
leader or the operations director during the
shift.
The licensee notified the
NRC approximately
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the
event.
The licensee
determined that the root cause of the event
was the failure
to follow procedure
by the chemistry technician in that the technician
-27-
C.
did not notify the control
room prior to sampling,
In addition,
communications
and notifications to licensee
management
and the
NRC did
not meet management's
expectations.
The inspectors
concluded that the licensee's
corrective actions
were
appropriate.
Additionally, the inspectors
noted that the event
was
identified by the licensee
and that there
were
no similar violations
identified by either the inspectors
or by the licensee
which could have
reasonably
prevented this occurrence.
This licensee-identified
and
corrected violation, failure to notify the control
room prior to
sampling,
is being treated
as
a noncited violation, consistent with
Section VII.B.I of the
NRC Enforcement Polic
(50-528/96007-08).
Conclusions
R2
R2,1
Chemistry personnel
did not follow procedures
for notifying the control
room prior to sampling, resulting in a noncited violation.
In addition,
chemistry personnel
failed to adequately
communicate,
resulting in an
unattended
open
sample valve
and subsequent
loss of inventory during
midloop operations.
The inventory lost was not significant.
The licensee's
investigation into the event
was thorough.
The
notifications to operations
management
were slow, in that the event
was
not discussed
until the following day.
Status of Radiological
Protection
b. Chemistry Facilities
and Equipment
Containment
Closure
Walkdown
Unit 2
a
~
Ins ection
Sco
e
71750
b.
On April 30, the inspectors,
accompanied
by a radiation protection
(RP)
technician
and the containment coordinator,
toured the containment to
assess
the state of housekeeping
and material condition prior to the
unit startup.
Observations
and Findin
s
The containment cleanliness
and material condition was generally good.
The inspectors
observed
minor debris,
such
as tie wraps,
in the reactor
coolant
pump areas.
The
RP technician
immediately retrieved the debris.
The containment coordinator indicated that the
pump bay areas
would be
recleaned
to ensure all small material
was removed.
There were minor
material discrepancies
with the few remaining jobs in containment.
The
containment coordinator indicated that additional
walkdowns would be
performed to verify containment cleanliness
as the work was completed.
I
I
~ g
~
4
-28-
R2.2
Material Condition of the
Units
1
2
and
3
a.
Ins ection
Sco
e
71750
The inspectors
made tours of the radiologically controlled areas
(RCA's)
in each of the units.
Additionally, on Hay 9, the inspectors
and
a
NRC
manager
toured the RCA's for all three units.
b.
Observations
and Findin
s
On May 9, the inspectors
identified two Unit 2 leaks which were not
posted
as contaminated
areas.
For both leaks,
the previously
unidentified contamination levels were greater
than the licensee's
criteria for posted
contamination
areas
(greater
than
1000
disintegrations
per minute per
100 square
centimeters
(dpm/100cm').
~
Valve SIA-UV-655 had
a packing leak.
RP determined that the floor
under the valve had smearable
contamination of 15,000
dpm/100cm'.
RP subsequently
posted
the area
as
a "contaminated
area."
The
inspector determined that the packing for this valve had
been
worked during the refueling outage.
Maintenance
and
RP had
performed
walkdowns of the area
on May
1 and Hay 6, respectively,
and
had not identified leakage
or any contamination.
~
The pipe cap
down stream of valve SIB-V555 appeared
to be leaking,
with boron crystals
apparent
on both the pipe cap
and the floor;
RP subsequently
determined that smearable
contamination
was 30,000
dpm/100cm'n
the pipe cap
and 70,000 dpm/100cm'n
the floor.
decontaminated
the valve and cleaned
up the area.
The inspector
determined that SIB-V555 had
been previously identified by the
utility maintenance
group
as having
a packing leak.
Maintenance
and
RP had performed
walkdowns of this area
on Hay
1
and
May 3,
respectively,
and
had not identified leakage or any contamination.
During the
May 9 tours,
the inspectors
also observed that Unit
1 valve
SIA-UV-655 had
a packing leak.
The bonnet
was posted
as
a "High
Contaminated
Area,"
and there
was
a drip catch installed underneath
the
valve bonnet
area to contain the leak.
The inspector
observed that
a
stalactite of boron crystals
had formed outside the drip catch.
On Hay 10, the
NRC manager
discussed
the general
conditions of the
with licensee
management.
Licensee
management
subsequently
directed
and utility maintenance
personnel
to perform walkdowns of the
RCA's in
all three units.
As
a result of the walkdowns,
the licensee identified
numerous
valves
and
pumps that needed repair and/or decontamination.
Licensee
management
classified
these material condition issues
as
a
Management
Level
1 issue,
establishing
a high priority for resolution
and increased
management
awareness.
In addition,
the licensee initiated
CRDR 9-6-0557 to investigate
the discrepancies.
-29-
On May 14 and
15,
a
NAP inspector
performed radiological
walkdowns in
all three units
and documented
the results
in Evaluation Report 98-0303.
The
NAP inspector identified two contaminated
leaking valves in Unit
2
and one in Unit I which had not been properly posted.
The
NAP inspector
did not identify Unit
1 valve SIA-UV-655 as having improper posting.
On May 16, the inspectors
toured the Unit
1
RCA and observed that the
stalactite
formation outside the drip catch of valve SIA-UV-655 had
allowed liquid to drip onto the floor, forming
a puddle.
This area
had
not been
posted
as
a contaminated
area.
The inspector contacted
RP,
and
a technician
determined that the contamination
levels
on the floor were
up to 40,000
dpm/100cm'.
The utility maintenance
technicians
decontaminated
the area
and extended
the drip catch under the valve.
On May 21, the inspectors
discussed
the Unit
1 valve SIA-UV-655
observations
with the
NAP inspector.
On May 22, the
NAP inspector
observed
a puddle
on the floor under the valve in an area that was not
posted.
The
NAP inspector
found 150,000 dpm/100cm'mearable
contamination
on the floor, which met the criteria for a "high
contamination area."
The
NAP inspector notified RP,
who posted
the
floor as
a "high contamination
area."
The inspectors
held discussions
with RP management
and reviewed the
licensee's
program for identifying leaking components
and controlling
contaminated
areas.
The inspectors identified the following:
RP technicians
were required
by procedures
to perform monthly and
weekly surveys of the
RCA.
The surveys for the SIA-UV-655 valves
were performed monthly,
and the survey for the SIB-V555 was
performed weekly.
The most recent
surveys
had
been
performed
within a week of the
May 9
NRC walkdown.
The surveys did not
identify the valves or the areas
under the valves
as contaminated.
The
RP program included both shiftly tours
by
RP and area
ownership for technicians.
RP management
stated their
expectations
are that technicians
should
be performing both spot-
checks
and detailed tours of their area.
The licensee
had established
a Zone Inspection
Program
(ZIP) to
provide additional controls
and responsibilities for utility,
mechanical
maintenance,
and operation
departments
for identifying
and tracking leaking components,
The program
had established
a
monthly wal kdown of each unit.
However,
the program
was
disco'ntinued
in Unit 2 during the outage,
and
RP was given the
responsibility for contamination control.
The licensee
had previously recognized that the packing for the
SIA-UV-655 valves were unevenly loaded,
contributing to packing
leakage.
Although the packing
on the Unit 2 valve
had recently
-30-
been adjusted, it appeared
that the licensee
had
removed
an
installed drip catch without verifying the success
of the
adjustment.
Unit
1 valve SIA-UV-655 had
an open work request,
initiated in January
1994, to address
packing leakage.
~
In February
1996,
NAP documented
concerns
in Evaluation Report 96-
0089, that contaminated
areas/components
were not being identified
during
RP tours
and surveys.
NAP had concluded that
communications
between
RP, maintenance,
and operations
personnel
were inadequate.
In addition,
NAP found that documentation
and
resolution of problems varied
among
RP crews,
and that ZIP records
did not reflect the condition of leaking valves identified by
and
NAP.
During walkdowns in March
and April 1996,
NAP noted
improvements
in contamination control.
The inspector determined that the licensee
had established
programs to
address
leakage
in the
RCA to prevent the spread of contamination.
Additionally, prior to this inspection,
the licensee
had recognized
weaknesses
in the implementation of these
programs
and
had
implemented
corrective actions.
However, the valves with leakage
were in accessible
areas
of the
RCA, there
was sufficient prior knowledge of deficiencies,
and the leakage
was significantly developed
to be clearly visible.
The
inspector
concluded it was reasonable
to expect that the licensee
identify the contaminated
areas prior to the
NRC tours.
Procedure
75RP-ORPOl required that areas
identified as having
contamination levels greater
than
1000 dpm/100cm'e
posted with
radiation warning sign(s)
bearing the words:
"Caution,
Contaminated
Area."
The inspector
concluded that the three
examples of unposted
contaminated
areas
represented
a violation (528,529/96007-09).
c.
Conclusions
One violation was identified for failure to follow procedure.
The
inspector
concluded that the three
examples of improper posting
and
inadequate
contamination control reflected
poor performance of the
licensee's
program for the control of contaminated
areas
in that routine
tours
by RP, maintenance,
and operations
personnel
had not been
effective in identifying leaking components
which had inadequate
contamination controls,
P8
Miscellaneous
Emergency
Preparedness
Issues
(92904)
PS. 1
Closed
Violation 529 94019-01:
failure to classify unusual
event.
On
May 3,
1994,
the licensee telephonically notified the
NRC Headquarters
Operations Officer that
an unusual
event
had occur'red at the site at
2:45 p.m.,
on March 12,
1994.
The licensee
indicated
an Unusual
Event
should
have
been declared at the time of the event
due to the manual
start of a third charging
pump to recover pressurizer
level while
I
~
s
~
h
-31-
drawing the bubble
The event
was reviewed
by the
resident
inspectors
(NRC Inspection
Report 50-528;529;530/94009).
The licensee
indicated at
a May 25,
1994,
meeting with NRC inspectors
that three corrective actions
had
been identified and initiated.
~
The Director of Operations
prepared
a letter for all shift
supervisors
discussing
the failure to consider
and classify
an
event.
The letter reviewed the event
and emphasized
the failure
at the time of the event to "evaluate this incident with emergency
action levels in mind" and indicated that "a classification at the
Notification of Unusual
Event level would have
been appropriate."
~
Training in the nuclear
management
and resources
council
emergency
action level
scheme for the site
was prepared for immediate
training of emergency
response
personnel
and for immediate
implementation
upon approval
by the
NRC.
The licensee
nuclear
management
and resources
council
emergency
action levels were
subsequently
found acceptable
by the
NRC and the appropriate
training was conducted.
~
The Manager,
Operations
Training, indicated at the exit interview
that training "Lessons
Learned" regarding this and similar events
had
been
added to the Operations
Training program.
The inspectors
determined
during the Nay 1994 emergency
preparedness
inspection that appropriate corrective actions
had
been
implemented to
preclude
recurrence
of this type event.
Two subsequent
emergency
preparedness
inspections
at the site,
the
1995 annual
emergency
exercise
(Inspection
Report 50-528;529;530/95004)
and
a routine emergency
preparedness
inspection
(NRC Inspection
Report 50-528;529;530/95022)
observed
demonstrations
of assessment
of plant conditions
and
classification
of- emergency
events
by the licensee.
The classification
performance
in the annual
exercise
was characterized
as
good
and in the
control
room walkthrough scenarios,
during the routine inspection
as
generally good.
No failures to appropriately classify emergency
events
have occurred
in the two years
since this event.
V. Mana ement Meetin
s
Xl
Exit Neeting
Summary
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on April 16,
1996.
The
licensee
acknowledged
the findings presented.
The inspectors
asked
the licensee
whether
any materials
examined during the
inspection
should
be considered
proprietary.
No proprietary information was
identified.
ll
PARTIAL LIST OF
PERSONS
CONTACTED
Licensee
W. Stewart,
Executive Vice President,
Nuclear
R. Flood,
Department
Leader,
System Engineering
J.
Hesser,
Director, Nuclear Engineering
W. Ide, Director, Operations
L. Johnson,
Department
Leader,
Chemistry
A. Krainik, Department
Leader,
Nuclear Regulatory Affairs
J.
Levine, Vice President,
Nuclear Production
D. Mauldin, Director, Maintenance
J.
NcDonald, Director,
Communications
G. Overbeck,
Vice President,
Nuclear Support
H. Shea,
Director, Radiation Protection
D. Smith, Director,
Outage
E. Sterling,
Department
Leader,
Nuclear Assurance-Operations
II
IP 37551'P
61726:
IP 62703:
IP 71707:
IP 71711:
IP 71750:
IP 92712:
IP 92901:
IP 92903:
IP 92904:
~0en ed
INSPECTION
PROCEDURES
USED
Onsite Engineering
Surveillance
Observations
Maintenance
Observations
Plant Operations
Restart
From Refueling
Plant Support Activities
In-office LER Review
Followup
Operations
Followup - Engineering
Followup
Plant Support
ITEMS OPENED
CLOSED
AND DISCUSSED
50-528/96007-05
50-528/96007-06
NCV
50-529/96007-07
50-528/96007-08
50-528;529/96007-09
Cl osed
50-529/96007-01
50-528;529;530/96007-02
50-528;529;530/96007-03
IFI
50-530/96007-04
failure to adhere to procedure
requirements
failure to meet surveillance
requirement
4.5.2.d.2
review of resolution of UFSAR inconsistencies
for SFP
and testing of trisodium phosphate
failure to follow procedure for blocking open
controlled doors
surveillance, requirement 4.8.4. 1 not fully met
containment
spray technical specification
violation due to unrecognized
valve failure
technical specification violation due to missed
surveillance
requirement
failure to follow chemistry procedure
failure to maintain required contamination
controls
50-529/94007
50-528/94001-01
50-529/95004
50-529/94005-01
50-530/9412-03
50-529/9419-01
50-528/95016
LER
LER
LER
LER
VIO
momentary entry into technical specification 3.0,3
surveillance
requirement 4.8.4. 1 not fully met
technical specification violation due to missed
surveillance
high pressure
safety injection motor operated
valve failed to open during
ASME section
XI
testing
failure to take action required
by technical
specification
failure to classify unusual
event
LER
containment
spray technical
specification
violation due to unrecognized
valve failure
ia
4
l
I
l
-3-
50-530/96007-04
50-528/96007-05
50-528/96007-06
50-529/96007-07
50-528/96007-08
NCV
NCV
50-528;529;530/96007-02
failure to meet surveillance
requirement
4.5.2.d.2
failure to follow procedure for blocking open
controlled doors
surveillance
requirement 4.8.4.
1 not fully met
containment
spray technical specification
violation due to unrecognized
valve failure
technical specification violation due to missed
surveillance
requirement
failure to follow chemistry procedure
C ~
0
J
~
w
~
~ 5
e
AT&T
CRDR
LER
TS
LIST OF ACRONYMS USED
American Society of Mechanical
Engineers
American Telephone
and Telegraph
Control
Element Assembly
Condition Report/Disposition
Request
Heating Ventilation and Air Conditioning
Licensee
Event Report
Local
Leak Rate Test
Low Pressure
Safety Injection
Percent Millirho
Radiological
Control Area
Radiation Protection
Spent
Fuel
Pool
Technical Specification
Updated
Final Safety Analysis Report
~ a
I