ML17312B184
| ML17312B184 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 01/14/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17312B182 | List: |
| References | |
| 50-528-96-17, 50-529-96-17, 50-530-96-17, NUDOCS 9701210456 | |
| Download: ML17312B184 (53) | |
See also: IR 05000528/1996017
Text
e
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
50-528/96-1 7
50-529/96-1 7
50-530/96-1 7
Arizona Public Service Company
Palo Verde'uclear Generating Station, Units 1, 2, and 3
5951 S. Wintersburg Road
Tonopah, Arizona
November 17 through December 28, 1996
K. Johnston,
Senior Resident Inspector
J. Kramer, Resident Inspector
D. Garcia, Resident Inspector
D. Carter,'esident
Inspector
D. Acker, Senior Project Engineer
G. Good, Senior Emergency Preparedness
Analyst
Dennis F. Kirsch, Chief, Reactor Projects Branch F
ATTACHMENT: Supplemental
Information
9701210456
970114
ADQCK 05000528
6
0
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EXECUTIVE SUMMARY
Palo Verde Nuclear Generating Station, Units 1, 2, and 3
NRC Inspection Report 50-528/96-17; 50-529/96-17; 50-530/96-17
~Oe rations
Although the conduct of operations was generally professional
and
safety-conscious,
inspectors identified issues in each unit involving failure to follow
procedures.
In Unit 1, known equipment problems and human performance errors
contributed to the overflow of the spray pond hypochlorite tank.
In Unit 2,
operators did not initiate a manual safety equipment status system (SESS) alarm for
inoperable emergency core cooling system
(ECCS) equipment, which was an
example of a violation of Technical Specification (TS) 6.8.1.
In Unit 3, inadequate
communications
between operations
and maintenance
during the performance of a
work activity contributed to the degraded
condition of a charging pump, which was
an example of a violation of 10 CFR Part 50, Appendix B, Criterion V
(Section 01.4).
The licensee has established
an effective program for assessing
and correcting
operator work arounds that have an impact on event response.
Although the
licensee corrected'operator
work arounds which had an impact on routine
operations,
and existing work arounds were not an undue burden to operators, their
program did not assure that all work arounds were assessed
for their cumulative
impact (Section 02.1).
The training for clearance
process changes
has been acceptable
and the changes
were properly communicated to operators.
The licensee's
plans for upcoming
training were acceptable
(Section 05.1).
Three issues were identified where the operations crew involved in a performance
weakness
or error did not promptly initiate a condition report/disposition
request
(CRDR) to assure that the problems were identified to management
in a
timely manner for their consideration
and resolution (Section 07.1).
'Maintenance
~
The licensee did not properly apply their work control process following their
~decision to install a temporary restraining device to reactor coolant pump (RCP) 2B
shaft impeller.
No written instructions were provided to the craft for installation and
the work was not adequately documented
on a clearance.
These issues
are
examples of a violation of TS 6.8.1.
The licensee's initial event evaluation was
inadequate
in that it did not recognize these weaknesses
(Section M1.3).
-3-
The licensee identified that maintenance
personnel failed to contact operations,
as
instructed by a work order, to secure charging pump seal lubrication water.
This
was an example of a violation of 10 CFR Part 50, Appendix B, Criterion V (Section
01.4).
Maintenance
personnel did not adequately communicate with site management
the
status of emergent gas turbine generator
(GTG) issues.
As a result, site
management
was not provided the opportunity to factor these emergent issues into
planned vital equipment
outages
(Section M3.1).
~En ineerin
Workers installing a pipjng modification to the essential cooling water (EW) system
did not ensure that the modification was installed according to design
specifications, by verifying required tolerances for the distance of piping from pipe
supports.
This is an example of a violation of 10 CFR Part 50, Appendix B,
Criterion V. In addition, workers installing the piping had not had all the required
training in pipe installations (Section E1.1).
The licensee was proactive in addressing
problems with offsite power and keeping
the staff informed.
The inspectors
also concluded that the licensee's
administrative
actions were acceptable to maintain offsite power operable.
However, the
inspectors concluded that Revision 2 of the Licensee Event Report (LER) and
CRDR 9-6-0273 were incomplete, in that they did not address the root cause of the
problem (Section E8.2).
Plant Su
ort
The process for performing onshift dose assessments
was described
in the
emergency plan and implementing procedures
(Section P3,1).
~
An escort, visitor, and supervisor failed in their responsibilities to prevent an
unescorted
visitor from gaining unrestricted access to an area containing vital safety
equipment, which was a violation of TS 6.8.1.
The corrective actions performed by
the licensee and contractor were thorough (Section S4.1).
l
Re ort Details
Summer
of Plant Status
All units operated
at essentially 100 percent power for the duration of the inspection
period.
I. 0 erations
01
Conduct of Operations (71707)
01.1
S ra
Pond
H
ochlorite Tank S ill Unit 1
a.
Ins ection Sco e-
During a review of the Unit 1 unit log, the inspectors observed
an entry, on
November 14, 1996, describing an incident where the spray pond hypochlorite tank
had overflowed, spilling 'hypochlorite out of its vent and into a berm surrounding the
tank.
The inspectors discussed
the event with operations
personnel
and operations
management.
b.
Observations
and Findin s
A hypochlorite addition system was provided as part of the nonsafety-related
chemistry control for the spray ponds.
Each unit has a hypochlorite tank, two
hypochlorite addition pumps, and supply lines to each spray pond.
Hypochlorite is
provided to all three units from the water reclamation facility. A level control valve
is provided in each supply line from the water reclamation facility to control the
level in the hypochlorite tanks.
The unit log entry of 10:20 p.m. on November 14 identified that an auxiliary
operator (AO) had discovered that the hypochlorite tank was overfilling and had
shut a manual isolation valve, which was in series with the level control valve.
Operations initiated a work request to have the level control valve repaired,
The inspectors did further inspections of the system and determined the following:
~
The level control valves had a history of leaking and system operating
procedures
required that the manual isolation be kept closed except during
fill operations.
The hypochlorite tank had a high level control room annunciator.
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The licensee had not initiated a CRDR to evaluate the November 14 event.
There had been a history of both equipment problems and operator
performance
errors on the hypochlorite system.
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The inspectors discussed
these concerns with operations management
and on
December 2, a CRDR was initiated.
The shift supervisor (SS) on shift during the
spill event was contacted
during the CRDR evaluation.
He said that he had intended
for a CRDR to have been initiated but had not ensured
one was written. Further
discussion
on situations where a CRDR was not initiated in a timely manner is
.contained
in Section 07.1.
At the end of the inspection period, the licensee had not determined when the
manual isolation valve had been opened.
They did determine that some crews were
not aware of the hypochlorite operations procedure requirement to have the valve
closed except while fillingthe tank.
In addition, the licensee determined that a local level indicator was out of service
and had been since May 1996.
AOs had been using level control valve position as
an indication of tank level ~ Work on the level indicator had been canceled
based on
plans to abandon the automatic hypochlorite addition system.
This modification,
however, had not yet been implemented.
Accordingly, the inspectors considered
that the level indicator work cancellation decision was premature and not well
coordinated.
Operations management
considered the use of the level control valve
in lieu of level indication to be an operator work around that had not been
previously identified. They used it as an example to operators of the type of
problem that should be brought to management
attention to assure prompt repair.
Further discussion
on operator work arounds
is contained
in Section 02.1.
Operations reviewed annunciator printouts and determined that there had not been
a high tank level alarm.
They subsequently
determined that the alarm, which
receives its input from the level control valve controller, was not functioning.
This
condition was subsequently
repaired.
Operations discussed
this event with the crew involved and distributed
a night order
to inform other crews.
In addition, the level instrument and control room alarm
were repaired.
The licensee plans extensive modifications to the system, which
would retire the hypochlorite pumps and tank.
01.2
Control Room Observations
Unit 2
a.
Ins ection Sco
e
On November 25, Unit 2 was performing a post accident sampling system
surveillance.
The inspectors were performing a routine walk down of the control
boards and noticed an ECCS valve out of its normal position.
The inspectors
questioned
operators,
reviewed logs and observed the performance of operator
actions.
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b.
Observations
and Findin s
The inspectors, while walking down the control boards, observed the licensee
performing a post accident sampling system surveillance in accordance
with
Procedure
During this surveillance the Train A low pressure safety
injection pump was running on full flow recirculation to allow a sample to be taken.
While in this condition the inspectors observed valve SIA-UV-660 (the combined
miniflow recirculation valve from the ECCS pumps back to the refueling water tank)
closed.
The inspectors questioned
the SS regarding the reason that a manual SESS
alarm input was not initiated.
The SS indicated that the A train of ECCS was
declared inoperable and that a manual SESS input was not required.
The inspectors reviewed the Conduct of Shift Operations procedure which indicated
that a manual SESS alarm was required.
The inspectors discussed
this with the SS
who agreed with this conclusion.
Subsequently,
the inspectors
polled other crews
and supervisors
and found that there was not a consistent understanding
of the
requirements.
The ability to initiate a manual SESS was provided so that operators,
in response
to an event, would have a visual reminder of equipment status.
Operator action would have been required to prevent ECCS pump damage
in the
event of a safety injection actuation signal with reactor coolant system
(RCS)
pressure
above the ECCS pump discharge
pre'ssure.
The failure of the operations staff to initiate a manual SESS alarm, as required by
procedure, was an example of a violation of TS 6.8.1 (Violation 50-529/96017-01).
The licensee issued
a Night Order describing this occurrence
and stated that
operators should have inserted
a manual SESS alarm.
In addition, the licensee
initiated an instruction change request to add a step to Procedure 74ST-9SS03, to
have a manual SESS alarm input initiated when performing these sections of the
procedure.
The operations department planned to review the conduct of shift
operations procedure for possible clarification and/or improved guidance
on specific
use of the manual SESS.
The licensee did not promptly initiate a CRDR to evaluate the implications of this
occurrence.
The licensee's
program requires that a CRDR be initiated when it is
identified that personnel failed to follow a procedure.
Although, operations
otherwise took appropriate corrective action in response to this issue,
a CRDR
would have been useful in establishing performance trends.
A CRDR was
subsequently
written on December 23, recommending
the above actions.
See
Section 07.1 for further discussion of instances where operations
did not promptly
initiate a CRDR.
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01.3
Water Intrusion in Char in
Pum
B Unit 3
a.
Ins ection Sco
e
The inspectors reviewed CRDR 3-6-0197 issued on November 15, 1996, describing
the water intrusion to charging Pump B crankcase
oil during a routine preventative
maintenance
task on charging Pump
E on November 7. The inspectors
also
reviewed the evaluation performed by mechanical maintenance
engineering.
b.
Observations
and Findin s
In the past, the drain lines have become clogged, causing
a backfill of water to
flood the well (see NRC Inspection Report 50-528/95-16; 50-529/95-16;
50-530/95-16).
The accumulated
water in the well would drain directly into the
pump crankcase through drainage holes in the oil baffle packing region.
As part of
the corrective action, a preventive maintenance
task was initiated to perform a
periodic flush of the drain lines.
On November 7, 1996, a maint'enance
team performed
a routine drain line flush on
charging pump E, in accordance
with work order (WO) 0775357.
There are three
charging pumps, each with a well that drains to a common header leading to a
charging pump oil drain tank.
The well is located between the power block and the
oil crankcase.
The well drain collects both seal lubricating water leakage and oil
leakage,
and directs it to the tank for processing.
After maintenance
completed the drain line flush of charging Pump E, and had not
identified any problems,
an AO identified that it appeared that the oil level in
charging Pump B had increased and'suspected
that charging Pump B well drain had
backed up with water. The SS initiated a work request to sample the oil in the pump
crank case for possible water intrusion.
Both charging Pumps
B and
E were placed
in service.
An oil sample was drawn sometime before noon on November 8.
On November 14, the oil sample revealed 27,000 ppm water in the charging
Pump B oil. The acceptance
criteria for water in the oil was 1000 ppm.
On
November 15, the mechanical maintenance
engineer notified the control room and
charging Pump B was declared inoperable,
The oil was changed
and the pump was
returned to service.
The mechanical maintenance
engineer initiated CRDR 3-6-0197
to evaluate the event.
The inspectors reviewed the evaluation performed by the mechanical maintenance
engineer.
The following missed barriers were identified in the evaluation:
WO 0775357 had a precaution for maintenance
to contact operations to
secure seal lube if one of the pumps has excessive
seal lube leakage.
On
November 2, a work request was initiated for excessive
seal lube leakage on
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charging Pump B. The evaluation found that while operations was aware of
the condition they were not informed of the WO precaution by maintenance
and seal lube was not secured for this pump.
WO 0775357 included a step for maintenance to stand by and observe the
other two pumps to ensure that water did not back up into those drains.
Maintenance subsequently
observed that the plexiglass covers over the wells
were difficultto see through due to condensation.
The inspectors observed that it had taken eight days to receive the results of the oil
analysis and take action to change the oil in the pump.
On November 7, operations
had not informed the site shift manager or engineering of the situation and had not
documented
the event by either a log entry or a CRDR. The inspectors were
concerned that operators
had not promptly responded
with sufficient urgency in
light of the circumstances
surrounding the increased
oil level.
The Unit 3 Unit
Department Leader shared this concern and discussed it with operations personnel.
The licensee conservatively concluded. that charging Pump B was inoperable,
although it had operated satisfactorily for 8 days and showed no signs of wear.
However, during this period, they maintained the TS minimum requirement of two
operable charging pumps.
In addition, the licensee concluded that this event should
be tracked as a functional failure in accordance
with 10 CFR 50.65.
The inspectors
determined that the failure to isolate seal lube water to charging Pump B was an
example of a violation of 10 CFR Part 50, Appendix B, Criterion V, for failure to
follow work instructions (Violation 50-530/96017-02).
Although the violation was
identified by the licensee, they missed an opportunity to promptly correct the
condition.
As a result, charging Pump B was in a degraded
condition for 8 days.
01 A
Conclusions
on Conduct of 0 erations
Although the conduct of operations was generally professional
and
safety-conscious,
inspectors identified issues
in each unit involving failure to follow
procedures.
In Unit 1, known equipment problems and human performance errors
contributed to the overflow of the spray pond hypochlorite tank.
In Unit 2,
operators
did not initiate a manual SESS alarm for inoperable
ECCS equipment.
In
Unit 3, inadequate
communications
between operations
and maintenance
during the
performance of a work activity contributed to the degraded
condition of a charging
pump.
j
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02
Operational Status of Facilities and Equipment
02.1
0 erator Work Arounds
a 0
Ins ection Sco
e 71707
The inspectors reviewed the licensee's
methods for addressing
operator work
arounds.
In addition, the inspectors reviewed different operator aids found in the
control room and discussed
the observations with control room operators
and
licensee management.
b.
Observations
and Findin s
The inspectors found that operator work arounds did not appear to have a
significant impact on plant operators during routine operations
and would not be
expected to have a significant impact during a plant event.
The licensee had
developed
a formal Procedure
79DP-9ZZ01 which required the shift technical
advisors to perform a weekly review of plant conditions which could impact their
response to an event.
The resultant lists were submitted to operations management
and work control to assure that the condition receives priority for repair.
In
addition, the lists were reviewed by the plant review board every month.
The inspectors found that there were a number of methods used to assure that
operator work arounds, which did not impact event response,
were promptly
addressed.
The control room deficiency log (CRDL) items, which included
deficiencies with an impact on control room controls and annunciation,
were
addressed
with high priority. In addition, other conditions identified as operator
work arounds were added to the operations,
engineering,
and management
concerns list, which were routinely discussed
in the operation's morning meeting.
The inspectors performed
a review of "temporary notes" active in the Unit 3 control
room. Temporary notes, controlled in operations
Procedure 40DP-90P14, "Control
of Operator Information Aids," were defined as supplementary
information, of a
temporary nature, concerning the operation or maintenance
of plant systems,
subsystems,
or components.
At the time of the inspector's review, there were 43
active temporary notes in Unit 3. The inspectors found that a significant number
could be considered
operator work arounds
in that they represented
deficiencies
that complicated normal operation of plant equipment and were compensated
for by
operator action.
Most of these had not been addressed
in the programs used to
highlight work around conditions.
Many of the conditions listed in the temporary notes were appropriately scheduled
for repair during the next scheduled
refueling outage, to begin in late February
1997.
The remaining conditions appeared to be addressed
in the work control
process with sufficient priority. However, since the licensee had not included most
of these items in their processes
to identify operator work arounds, they had not
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provided themselves
the opportunity to assess
the cumulative impact of the
conditions on plant operators.
The inspectors
also found four notes for which the
associated
work had been completed and the condition no longer existed.
This
indicated a weakness
in the process for removing the notes.
Based on discussions with the inspectors
and independent
review, licensee
management
initiated an evaluation of their program for assessing
operator work
a rounds.
Conclusions
The licensee had established
an effective program for assessing
and correcting
operator work arounds that have an impact on event response.
Although, the
licensee corrected operator work arounds which had an impact on routine
operations,
and existing 'work arounds were not an undue burden to operators, their
program did not assure that all work arounds were assessed
for their cumulative
impact.
03
Operations Procedures
and Documentation
03.1
0 erations Shift Turnover
Ins ection Sco
e 71707
The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) Section
18.I.C.2 and compared it to Procedure 40DP-9OP33, "Shift Turnover."
Section 18.I.C.2 documented
the licensee's
response
to NUREG 0737 item
requirements for shift relief and turnover procedures.
b.
Observations
and Findin s
The inspectors found that the shift turnover procedure was consistent with UFSAR
Section 18.I.C.2, with one exception.
The UFSAR included a reference to a
jumper/bypass
checklist,
Procedure 40DP-9OP33 did not have a specific check of
jumpers or bypasses.
The inspectors informed the licensee of the apparent
discrepancy.
The licensee initiated a CRDR to evaluate the guidance provided-in Procedure
The licensee found that most jumpers and bypasses
would be
reviewed as part of other portions of the shift turnover.
For example, jumpers were
used on the plant protection system pa'rameters
during modes of operation when
aspects
of the plant protection system were not required.
These jumpers were
documented
in the technical specification component condition record and reviewed
during shift turnover.
Additionally, the licensee has periodically jumpered
malfunctioning annunciator inputs.
These jumpers have been documented
as CRDL
entries, with blue stickers placed near the annunciator window to indicate a
I
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discrepancy.
There was no explicit direction provided in the turnover checklist to
review CRDLs, however, reactor operators were required to perform control board
walkdowns, which includes control room annunciators.
The inspector concluded that the lack of an explicit step in the shift turnover
procedure for the review of jumpers and bypasses
was a minor deficiency and was
being appropriately addressed
through the licensee's corrective action program and
other licensee administrative control methods.
06
Operator Training and Qualification
05.1
Clearance
Process Trainin
a.
Ins ection Sco
e 71707
The inspectors reviewed the licensee's clearance process
and discussed
the training
aspects of the process with the training department personnel,
licensed operators,
and nonlicensed
operators.
b.
Observations
and Findin s
Plant operators indicated that their biggest challenge with the clearance
process
was that the program requirements were often changing.
The inspectors discussed
this concern with the clearance
process owner.
The process owner indicated that
their evaluation of the program also identified that the numerous revisions to the
clearance procedure
have caused difficulties for the operators.
As a result, only
minor word clarifications were planned for the procedure revision prior to the Unit 3
outage in February 1997.
Training department personnel indicated that all operations department personnel
were required to receive training on the clearance process during the training cycles.
The licensee performed
a clearance training session prior to the Unit 1 outage in the
fall of 1996.
However, the inspectors noted that although operators were tested on
the clearance
process early in 1996, they have not been tested on the revisions that
have since been implemented to the clearance
process.
Training department personnel indicated that previous clearance training highlighted
only the changes
in the clearance
process.
The training planned prior to the Unit 3
outage would include a comprehensive
review of the entire clearance
process to
reinforce the fundamentals
of the process
and ensure that all operators
have a clear
understanding
of the entire program, not just the recent changes.
To improve the quality of the recent clearance training, the licensee ensured that the
clearance procedure
and process owner was available to answer detailed questions
about the procedure
changes
and to provide background
as to why the changes
were performed.
In discussions
with operators,
the inspectors noted that operators
-9-
found the training more beneficial when the system or process expert was available
to answer detailed questions
beyond the normal expected knowledge of the
instructor.
In addition, operators indicated that the overall training received on the
clearance changes
was acceptable..
C.
Conclusions
The training for clearance
process changes
has been acceptable
and the changes
were properly communicated to operators.
The licensee's
plans for upcoming
training were acceptable.
07
Quality Assurance
in Operations
07,1
CRDRs Not Prom tl
Initiated for 0 erations Issues
a.
Observations
and Findin s
Sections 01.1,-01.2, and 01.3 of this report identify a common element involving
CRDRs not being initiated in a timely manner; although CRDRs were eventually
issued.
~
Section 01.1 described
a spray pond hypochlorite overflow event in Unit 1.
In this event, where operator error and equipment problems were
contributors, the SS had delegated
CRDR initiation, but had failed to ensure
his direction was accomplished.
~
'-Section 01.2 described the failure of operators to input a manual SESS alarm
for a condition which rendered
a train of ECCS equipment inoperable.
Although the licensee initiated corrective actions such as a procedure
revision and a night order, they did not initiate a CRDR.
Section 01.3 described
an event where water inadvertently got into the
crankcase
oil of a charging pump.
In this instance, operators waited for the
results of the oil sample to initiate a CRDR, rather than at the time of the
event.
The inspectors discussed
these issues with the Director of Operations, who took
action to discuss the threshold for initiating CRDRs with all crews and was
evaluating the clarity of initiation criteria. The inspectors found that in 1996, the
licensee initiated approximately 3000 CRDRs and, overall, did not identify any
lowered sensitivity to initiating CRDRs.'owever,
the. inspectors were concerned
that these, seemingly, isolated situations may indicate a negative trend in the
thoroughness
of problem identification and resolution.
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b.
Conclusions
Three issues were identified where the operations crew involved in a performance
weakness
or error did not promptly initiate a CRDR to assure that the problems
were identified to management
in a timely manner for their consideration
and
resolution.
08
Miscellaneous Operations Issues
08.1
TS Inter retations
The inspectors conducted
a survey of the licensee's TS interpretations
and
determined that none of the documents
contained informal references to NRC
review and approval without formal NRC documentation.
The inspectors
emphasized to the licensee that any informal reference to NRC review and approval
in a TS interpretation is not recognized
by the Commission and is not an acceptable
practice.
II. Maintenance
M1
Conduct of Maintenance
M1.1
General Comments on Maintenance Activities
a.
Ins ection Sco
e 62707
The inspectors observed
all or portions of the following work activities:
WO 781258:
test K227 relay and associated
contacts for the essential
chiller (Unit 3)
~
WO 070666:
shim emergency diesel generator
(EDG) B fuel pumps for
adjustment of firing pressure
(Unit 1)
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WO 780386:
reactor switchgear undervoltage
and short trip circuit testing
(Unit 2)
b.
Observations
and Findin s
The inspectors found the work performed under these activities to be professional
and thorough.
All work observed was performed with the work package present
and in active use.
Technicians were experienced
and knowledgeable
of their
assigned tasks and demonstrated
good communications
between work groups.
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M1.2
General Comments on Surveillance
Activities
a.
Ins ection Sco
e 61726
The inspectors observed
all or portions of the following surveillance activities:
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EDG A
= ~
Boron Injection Flowpaths Operating
Essential Chilled Water (EC) System Flow Balance
~
EC Valve Verification.
The inspectors found these surveillahce were performed acceptably
and as specified
by applicable procedures.
M1.3
RCP Restrainin
Device Failure - Unit 1
a e
Ins ection Sco
e
~
On October 24, 1996, while Unit 1 was in Mode 5 after the completion of refueling,
maintenance
personnel
installed a temporary device to prevent reverse rotation of
the shaft of RCP 2B. After initial RCP sweeps, the device was found wrapped
around the shaft of RCP 2B, clearly indicating that the impeller had rotated in the
reverse direction during the start/stop cycles of the other RCPs.
The inspectors
observed the damage
and the licensee's subsequent
repairs.
In addition, the
inspectors evaluated the thoroughness
and depth of the licensee's event
investigation.
b.
Observations
and Findin s
Event Descri tion
On October 22, 1996, Unit 1 was in Mode 5 on shutdown cooling and operators
were in the process of restoring the RCS for operations.
Maintenance was in the
process of testing RCP 2B motor, a refurbished motor installed to replace the
existing motor, which was scheduled
for refurbishing.
During initial uncoupled
motor testing, the motor was energized
in reverse rotation due to an error in wiring.
Although the motor antirotation device prevented the motor from turning
backwards, the motor experienced
a locked rotor condition for approximately
20 seconds.
Maintenance subsequently
performed testing on the motor to assure
it had not been damaged.
Concurrently, as part of the RCS restoration,
Operations planned to start RCPs for
short runs to sweep the air from the steam generator tubes.
However, the
inspection and testing of RCP 2B motor had delayed the coupling of this motor to
the impeller shaft.
Since the motor has the antirotation device, without the motor
coupled to the impeller shaft the impeller was free to spin in either direction.
The
I
-1 2-
licensee planned to start RCPs 1A and 2A for pump sweeps,
but was concerned
that this would cause the impeller of RCP 2B to spin in reverse with no restraint.
Mechanical maintenance
engineering was requested
to evaluate whether there was
a means to temporarily restrain the shaft.
Mechanical maintenance
engineering
recalled that, in 1986, a tool, used to move
the impeller shaft to line up the coupling to the motor, had been used to restrain an
impeller so that its motor could be uncoupled while the other three pumps were
running.
This was documented
in an engineering
evaluation request
(EER); a
technical review process
no longer used by the licensee.
On the night shift of
October 22, mechanical maintenance
installed the device to temporarily restrain the
shaft of RCP 2B.
The restraining device consisted of a U-shaped,
6 inch radius 5/8 inch thick plate,
which had three 2 inch holes fitted perpendicularly with 3 inch lengths of stainless
steel pipe.
These were designed to fit over the impeller coupling bolts.
The center
of the U had a fitting for a 48 inch length of 1/2 inch schedule 80 stainless steel
pipe.
This shaft had a hole near its end used to pass the hooks for two chain falls.
The two chain falls were directed horizontally and perpendicular to the restraint
shaft.
One chain fall was secured to a handrail and the other to scaffold used to
support shielding.
Maintenance workers installed the restraining device as an add-on to RCP 2B motor
installation WO 0756527.
No work steps or instructions were provided for the
installation of the restraining device.
In addition, the 1986 EER, used as the basis
for installing the restraining device, was not referenced
by or attached to
The only documentation
of the installation was in a work activities
sheet attached to the WO following the maintenance,
stating: "Install holdback on
upper rigid coupling, tied come-a-longs to handrail and scaffold.
Tied tool onto rigid
[coupling] with tie wraps."
A maintenance
engineer inspected
RCP 2B after both RCPs 1A and 2A had been
run.
The shaft of the restraining device was found completely wrapped around the
shaft of the RCP.
The hooks for the chain falls were still secured to the shaft of the
restraining device.
Both the scaffold and the handrail had been deformed; drawn
towards the shaft.
One of the chain fall hooks was slightly deformed.
The
licensee's subsequent
inspection of the shaft identified that only a RCP speed probe
had been damaged.
On October 24, the licensee initiated CRDR 1-6-0269 to document the inspection,
repairs, and event investigation.
The CRDR was determined by the CRDR review
committee to be "significant," requiring a root cause evaluation,
and the evaluation
was assigned to maintenance
for review.
Maintenance completed their review on
November 25.
I'
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-1 3-
In their initial CRDR evaluation, mechanical maintenance
engineering determined
that there were substantial differences in the conditions for which the 1986 EER
was initially used and its use during the Unit 1 outage.
In 1986, the device was
installed on an idle pump before the motor and impeller were decoupled.
This
ensured that the restraining device saw only a static load.
During the Unit.1
outage, the restraining device experienced
a dynamic load when other pumps were
started to sweep the generators.
Additionally, the licensee postulated that as air
was swept from the steam generators,
there could have been
a substantial
load
change at the restraining device as the voids were collapsed.
Nuclear Assurance performed an evaluation, requested
by the maintenance
department,
in accordance
with their "Human Performance
Evaluation System"
program.
The evaluation found that personnel
did not use documents that fully
evaluated current plant conditions when determining actions to be taken to restrain
an RCP shaft from reverse rotation and that no policy was provided for guidance to
personnel evaluating
a course of action using engineering information evaluated for
similar, yet different conditions.
0
Mechanical maintenance
proposed corrective actions to determine the appropriate
method for using previous engineering information for similar, yet different,
conditions and to develop the basis necessary for installing the modification in the
Fall, 1997, Unit 2 refueling outage.
Review of Initial Cause Evaluation
The inspectors reviewed the licensee's evaluation and found that, while it had
addressed
significant aspects
regarding the lack of technical rigor, it failed to
address the failure to implement processes
and procedures for the control and
documentation
of work activities.
The licensee's evaluation included a discussion of the use of the WO process
and
concluded that no work instructions were necessary
since the restraining device use
was within the skill of the qualified worker. The inspectors found that the
installation of the restraining device was not within the skill of the qualified worker
in that there were several aspects of the job which required technical and
procedural guidance.
For example, the craft chose to restrain the device with
rigging equipment secured to a handrail and to scaffolding.
The inspectors noted
that maintenance
had not referenced the licensee's
procedural requirements
on the
use of scaffolding to support rigging equipment.
Additionally, the use of the
handrail should have required
a specific evaluation considering the load at the
handrail, since handrails at Palo Verde have been typically designed to support
a
200 pounds force.
The evaluation stated that RCP 2B was tagged out under Clearance 96-01325 at
the time the restraining device was installed.
The inspectors found that this was
not accurate.
The motor had been restored from this clearance
on October 21 to
-14-
allow the uncoupled motor run and was not tagged out on this clearance
until
October 24. Additionally, Clearance 96-01325, the clearance initially specified for
WO 0756527, applied only to the motor for RCP 2B. To provide adequate
protection to the workers installing the restraining device, it would have been
necessary to provide a clearance that tagged out all four RCP motors.
The
licensee's work control procedure,
Procedure
30DP-9WP02, required that an
expansion of the clearance
boundary was an expansion of work scope requiring a
WO amendment
by the job planner.
The inspectors noted that the event evaluation had considered the use of the
restraining device as similar to the use of a maintenance
tool on equipment that was
out of service.
The inspectors found-that considering the restraining device as a
tool was an error in judgement and a significant causal factor in the event.
The
restraining device was installed to protect the RCP seals in that the licensee did not
have an evaluation of the impact on the seals of the shaft rotating in reverse.
The
RCP seals were in service as an RCS boundary when the restraining device was
installed.
Therefore, the restraining device was relied upon to perform a function to
protect the RCP during a routine startup procedure
and should have received
reviews consistent with a procedure
change or system modification.
Res
onse to Ins ector Issues
The licensee reperformed the evaluation of the event following discussions, with the
inspectors.
They determined that the WO was incomplete, deficient in detail and
direction, and not in compliance with the work control program.
Additionally, they
determined that the addition of the restraining device constituted
a change
in work
scope'requiring
a WO amendment
in accordance
with Appen'dix 0 of
Procedure 30DP-9WP02.
This is an example of a violation of TS 6.8.1 for failure to
follow procedure (50-528/96017-01)
~
The licensee determined that installing the restraining device had been adequately
covered by a Clearance 9-6-01734, which tagged out all four RCP motors.
The
inspectors
agreed that this clearance
provided adequate
protection; however, the
inspectors found that WO 0756527 was never listed as an active job on this
clearance.
The mechanical maintenance
work group supervisor noted that although
this WO was not listed on the clearance,
another job under his responsibility was.
He stated that he verified all four pumps were tagged out of service prior to
allowing his crew to install the device.
However, the clearance control procedure
required that the specific WO associated
with a clearance
be listed on that
clearance.
This assures that all work listed on the clearance
is completed before
the clearance
is removed.
This is an example of a violation of TS 6.8.1 for failure
to follow procedure (50-528/96017-01).
-1 5-
C.
Conclusion
The licensee did not apply their work control process following their decision to
install a temporary restraining device to RCP 2B shaft impeller.
No written
instructions were provided to the craft for installation and the work was not
adequately documented
on a clearance.
The licensee's
initial event evaluation was
inadequate
in that it did not recognize these weaknesses.
M3
Maintenance Procedures
and Documentation
M3.1
Assessin
the Im act of Ern'er ent GTG Maintenance
on Planned Maintenance
Activities
a.
lns ection Sco
e 62707
Beginning on December 3, 1996, the licensee experienced
several start attempt
failures of the two GTGs.
The inspectors observed maintenance
activities and
reviewed the application of maintenance
rule requirements for assessing
the risk of
the resultant emergent work on planned maintenance
activities.
b.
Observations
and Findin s
Palo Verde has two GTGs for coping with loss of offsite power during a station
blackout event.
These generators
are installed in parallel, and can be connected to
~
each of the three units at Palo Verde.
The licensee considered
only one of these
GTGs as required to cope with a station blackout event.
The GTGs are not included
in plant TS and their availability has been controlled through administrative
procedures.
Although the GTGs are maintained by site maintenance,
they are
outside the protected
area and are operated
by the site water reclamation facility
staff.
Since the installation testing of the GTGs, the licensee has had problems with
starting the GTGs during peak high and low temperatures,
and has included the
generators
in 10 CFR 50.65 Maintenance
Rule Category (a)1.
The licensee had
performed some adjustments
on GTG
1 during warmer weather and had not
established
confidence that it would start with cooler weather.
However, the
licensee had previously established
some confidence that the low temperature start
issue had been addressed
for GTG 2.
On the morning of December 3, 1996, the licensee initiated testing of GTG
1 as
part of their Maintenance
Rule Category (a)1 action plan to test the GTG
1 with
lowering ambient temperatures
(temperatures
around 35'F).
GTG
1 failed to start
on four successive
start attempts.
Later in the day, following adjustments,
GTG
1
was started successfully.
However, since ambient temperatures
had increased,
maintenance
personnel
had not established
confidence that the adjustments
enabled
the GTG to start during lower temperatures.
Additionally, based
on findings with
(
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GTG 1, maintenance
personnel
developed
concerns that GTG 2 may not start.
They planned to test both GTGs the following morning as temperatures
dropped.
At 5 a.m. on December 4, 1996, the licensee initiated a planned outage of Train A
EDG and associated
train components
in Unit 1. At 7 a.m. on December 4, 1996,
the licensee initiated a planned outage of the turbine-driven auxiliary feedwater
(AFA) pump, and the A train high pressure safety injection (HPSI) pump in Unit 3.
At around the same time, the licensee attempted to start both GTGs and both failed
to start on the first attempt.
Both GTGs did start on a second attempt.
The
licensee subsequently
considered
GTG
1 unavailable,
and continued
troubleshooting,
and GTG 2 available, based on its ability to start within 3 start
attempts.
Palo Verde has a risk matrix, generated,
in part, to comply with the Maintenance
Rule, to assist operations
and maintenance
personnel
in determining the risk of
various components
being out of service.
The inspectors determined that site
management
was not fully aware of the concerns maintenance
had developed
on
December 3 regarding the ability of both GTGs to start during cold weather.
As a
result, they did not consider the GTG availability impact on the plan with the
December 4 outages of the Unit 1 EDG and the Unit 3 AFA and HPSI pumps.
The licensee's
risk matrix, which rates activities on a low, medium, and elevated
risk scale, identified that both the EDG and AFA/HPSI outages were medium risk.
The addition of a GTG outage would not have increased the risk out of the medium
range.
However, the matrix notes stated that a GTG outage and an EDG outage
should not be performed concurrently.
The shift manager recognized that had he been aware of maintenance
concerns
regarding the performance of GTG 2 in cold weather, further discussion would have
taken place on the need for testing GTG 2 and the planned outages
in Units
1 and
3.
The license issued an operations night order for unit operations to maintain status of
the gas turbine availability. Additionally, the licensee initiated a CRDR for this risk
management
issue.
Conclusions
Maintenance
personnel
did not adequately communicate with site management
the
status of emergent GTG issues.
As a result, site management
was unable to factor
these emergent issues into planned vital equipment outages.
lt
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-1 7-
M8
Miscellaneous Maintenance Issues
M8.1
Closed
LER 528 95011-01:
inadequate
main steam isolation valve and feed water
isolation valve operating air inservice tests in all three units.
The licensee noted
that they had not considered
all appropriate uncertainties
in testing the subject
valves, therefore, the existing tests did not insure operability in violation of
The licensee developed
interim procedures to maintain operability,
updated their test procedures,
and satisfactorily tested the valves.
The inspectors
verified the acceptability of the interim procedures
and verified the completed test
data for Unit 1 valves, including procedure
adequacy.
The inspectors concluded
that the licensee's corrective actions were adequate.
This licensee-identified
issue is being treated as a noncited violation consistent with
Section Vll of the NRC Enforcement Polic
(50-528;529;530/96017-03).
III. En ineerin
E1
Conduct of Engineering
E1..1
Modifications to the EW S stem Su
I
to the Essential Chillers
a.
Ins ection Sco
e 37551 and 92903
During this inspection period, the licensee completed portions of a modification to
the EW return from the EC condensers
in both trains of each unit. The inspectors
observed portions of the field work in each unit, reviewed the design modification,
and discussed
the modification with the craft, maintenance,
and design engineering
personnel.
b.
Observations
and Findin s
The modification was designed to reduce the overcooling of the EC condensers
in
the winter when low EW temperatures
and low system loading have resulted in low
condenser
pressure.
This has caused refrigerant to migrate from the evaporator to
the condenser
and has resulted in low refrigerant level trips (see NRC Inspection
Report 50-528/95-25; 529/95-25; 530/95-25),
To reduce overcooling, the licensee
installed a pressure control valve in the EW return line that modulated closed with
decreasing
condenser
pressures.
A manual bypass valve was placed in parallel with
the pressure
control valve to address worst case design basis conditions involving
EW supply to the spent fuel pool and EC heat loads.
The inspectors,
based
on interviews in the field, had questions
regarding the
familiarity of the installation work group supervisors with the piping design
specification as it applied to the piping installation and cold spring requirements.
The inspectors discussed
the concern with licensee management.
Nuclear
-1 8-
Assurance reviewed training requirements
and the qualifications of the contract
personnel
performing the work. They determined that the work group supervisor
had not completed
all the required classroom training in pipe installation.
The licensee performed
a review of the work group supervisor's
experience
at Palo
Verde and other nuclear facilities and determined that he had experience
in the work
performed.
They also determined that his work on the EW modification had
adequate
engineering
and Nuclear Assurance oversight.
The licensee initiated a
CRDR to evaluate this issue.
The pressure control valve was the final component installed to complete the piping
portion of the EW modification and it was installed using bolted flange connections.
Downstream of the pressure control valve was an elbow, followed by a box style
hanger.
Upstream of the pressure control valve was a piping tee with one end
going to the bypass valve, and the other end going to a flanged connection to the
chiller.
Th'e inspectors observed that as the piping modification was completed in Units 2
and 3, the piping passing through the box style hanger was in contact with the
hanger on the pressure control valve side.
The work instructions for the
modification referenced Specification 13-PN-204 for installation details.
This
specification allowed piping to be in contact with the hanger,
as long as the piping
was free to slide.
The inspectors were concerned that, had the piping been in
contact with the hanger on the pressure control valve side prior to bolting'the valve
in place, the act of bolting the flanges would have resulted in cold spring of the
piping and stressing both the hanger and the piping.
Specification 13-PN-204
stated'that
all situations involving cold spring should be evaluated
by engineering.
The inspectors discussed
this concern with the design engineer, who subsequently
initiated CRDR 9-6-1371 to evaluate this concern.
Design engineering
estimated
that bolting the flanges would provide roughly 0.1 inches of spring.
Engineering
calculated the additional stress that would be added to the hanger, the additional
stress added to the piping, and any impact this condition had on the response
to a
seismic event and to expected thermal expansion
and contraction.
Engineering
determined that the initial stresses
on the hanger and the piping corresponded
to
roughly half of the code allowable initial stress limits.
In addition, calculations
showed the system tended, with minor exceptions, to respond better to seismic and
thermal movement.
The inspectors
asked if this condition had been caused
by weaknesses
in either the
work instructions or the specification, or had it been caused by weaknesses
in their
application.
The licensee determined that both the work instruction, which included
a step requiring the verification that the hanger was free-to-slide, and the
specification, which included specific verification methods, were adequate.
They
also determined that all six trains were in similar configurations with the pipe in
contract with the hanger and no means available to determine if the pipe was free
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to slide.
The failure to perform the verifications required in the specification was an
example of failure to implement work instructions in violation of 10 CFR Part 50,
Appendix B, Criterion V (Violation 50-528/96017-02; 50-529/96017-02;
50-530/9601 7-02).
c.
Conclusion
Workers installing a piping modification to the EW system did not ensure that the
modification was installed according to design specifications and may have added
unanticipated
stress to the piping and hanger.
In addition, workers installing the
piping had not had all requisite training in pipe installations.
E5
Engineering Staff Training and Qualification
E5.1
Trainin
and Qualification of Workers Performin
EW Modifications
Section E1.1 discussed
weaknesses
in the training and qualification of workers
performing the installation of EW modifications.
Miscellaneous Engineering Issues
E8.1
Closed
Violation 50-529 94031-03: two examples of inadequate
corrective
actions.
The violation discussed
failure of the licensee to take adequate
corrective
actions for degraded
battery cells and for spurious tripping of the Train N AFA
pump.
As part of their corrective actions the licensee replaced the degraded
battery cells,
corrected the cause of the spurious tripping of the Train N AFA pump, and improved
the administrative directions for evaluation of technical problems.
The inspectors
reviewed the licensee's
program for monitoring individual battery cells and
determined that the licensee was trending individual cell data in sufficient detail to
predict individual cell degradation.
This violation had highlighted weaknesses
in the licensee's corrective action
program to resolve longstanding
equipment deficiencies.
The inspectors reviewed
the administrative changes
made by the licensee associated
with the CRDR program
and determined that the administrative directions had been improved in the area of
facilitating development of adequate
corrective actions.
Based on this review, the
inspectors concluded that the licensee had adequately
resolved this item.
-20-
E8.2
0 en
LER 50-528 93011-02:
potential safety-related
equipment problems due to
degraded
grid voltage.
a a
~Back round
Revision 2 of this LER, dated June 17, 1996, added two new potential conditions,
Scenarios
3 and 4, which could lead to double sequencing
of safety-related
equipment during a loss of coolant accident, concurrent with low offsite (grid)
voltages and described administrative controls that were put in place to maintain
operability of offsite power and safety-related
equipment.
In addition, subsequent
to issue of the LER, the licensee identified a potential
unreviewed safety question associated
with their offsite power arrangement,
A
new power line, not associated
with Palo Verde, had recently been installed which
crossed over two (Westwing) of the five total offsite power lines providing offsite
power to Palo Verde, although the UFSAR addresses
four offsite power sources.
Thus, a single failure of the new line, dropping across the two existing Westwing
lines could cause loss of these two lines to Palo Verde.
The licensee's
existing
analysis considered
the loss of only a single line, of the total four provided, reducing
the offsite sources to three,
a condition equivalent to loss of both Westwing lines.
On July 11, 1996, members of the licensee's staff met with the NRC staff to
provide an update of the degraded
voltage and double sequencing
issue identified
by Palo Verde.
On August 2, 1996, the licensee responded to questions raised by
the NRC in a docketed memorandum to the staff.
On September
18, 1996, members of the licensee's staff again met with the NRC
staff in Rockville, Maryland, to provide a second update for the NRC staff. A
summary of this meeting was issued on November 13, 1996.
b.
Ins ection Sco
e
The inspectors reviewed Revision 2 of the LER, the results of information Palo
Verde supplied the staff associated
with the July 11 and September
18 meetings,
the current status of Palo Verde actions associated
with offsite power, and selected
technical documents which supported
Palo Verde determinations that their offsite
power remained operable with existing administrative controls.
Observations
and Findin s
Palo Verde studies and calculations concluded that offsite power to the site would
remain operable
as long as the grid voltage level was maintained at 100 percent or
above.
This conclusion was based
on computer modeling of the grid from a model
provided by the Western States Coordinating Council (WSCC).
The licensee had
not done any software validation of the model
~ The Palo Verde offsite power
operability study did not include any uncertainty for the modeling and inquired
-21-
whether the model had been validated by modeling any of the recent grid
disturbances
in the western area and comparing the model results to what actually
happened.
The licensee found one study which modeled
a local disturbance for
short term dynamic response.
The model results were similar to the actual event,
but voltage levels after the disturbance
were not included.
The first new potential problem, added by Revision 2 of the LER, called Scenario 3,
concerned
potential uncontrolled AFA flow to intact and/or ruptured steam
generators
during a secondary
line break.
The scenario assumed
double sequencing
and no operator intervention.
The licensee administrative controls to block transfer
of nonsafety busses
adequately
addressed
this scenario.
The second new potential problem, added by Revision 2 of the LER, called Scenario
4, concerned
operators potentially overloading
a startup transformer when one of
the three transformers was out of service.
Scenario 4 appeared to be the same
technical issue identified by the NRC in NRC inspection Report 50-528/90-42;
50'-529/90-42; 50-530/90-42.
The licensee's
response to this finding was to
establish administrative controls to preclude potentially overloading the startup
transformers.
The inspectors questioned the licensee concerning the difference
between Scenario 4 and the previous NRC finding and found that they were the
same and the licensee had failed to maintain their administrative controls.
Licensee
engineering
personnel
had noted that licensee procedures
could allow overloading
the startup transformers
in March 1996.and
had initiated CRDR 9-6-0273.
A
preliminary review of CRDR 9-6-0273 indicated that the CRDR was closed without
addressing
several issues, including the root cause of how the licensee lost
administrative control of the potential for overloading the startup transformers.
Revision 2 of the LER appeared to be incomplete, in that it did not indicate that the
root cause of Scenario 4 was recent failure of the licensee to maintain committed
administrative controls, in lieu of licensee engineering identifying a new problem
with the existing design.
The inspectors
also considered that CRDR 9-6-0273
appeared to have been closed without adequately
addressing
the issue.
The inspectors noted that NRC inspection Report 50-528/96-16;529/96-16;
530/96-16, Section E8.3, identified that LER 528/95007, Revision 1, was
incomplete.
Other weaknesses
in the licensee's
evaluation of CRDRs are discussed
in Section M1.3
The inspectors discussed
this consideration with the licensee.
The licensee initiated
CRDR 961355 to evaluate the acceptability of the closing of CRDR 9-6-0273.
This
new CRDR indicated that the licensee planned to issue Revision 3 to the LER to
address the root cause inconsistency noted by the inspectors.
The inspectors determined that the licensee administrative controls to block transfer
of nonsafety busses
adequately
addressed
Scenario 4.
-22-
This LER will remain open pending:
Submittal of the information concerning
loss of the two Westwing lines to
the staff and staff approval.
Inspector review of the conservatism
used by Palo Verde to offset the
unknown accuracy of the WSCC modeling program.
Inspector review of offsite power studies which include lines out of service.
Inspector review of the results of the licensee's investigation of the
adequacy of LER Scenario 4 and CRDR 9-6-0273 (CRDR 9-6-1355).
d.
Conclusions
The licensee was proactive in addressing
problems with offsite power and keeping
the staff informed.
The inspectors
also concluded that the licensee administrative
actions were acceptable to maintain offsite power operable.
However, the
inspectors concluded that Revision 2 of the LER and CRDR 9-6-0273 were
incomplete,
in that they did not address the root cause of the problem.
IV. Plant Su
ort
P3
Procedures
and Documentation
P3.1
Licensee Onshift Dose Assessment
Ca abilities
TI 2515 134
a.
Ins ection Sco
e
Using Temporary Instruction 2515/134, the inspectors gathered
information
regarding:
~
Dose assessment
commitments in the emergency
plan
~
Onshift dose assessment
emergency
plan implementing procedure
~
Onshift dose assessment
training
b.
Observations
and Findin
s
On December 16, 1996, the inspectors conducted
an in-office review of the
emergency plan and implementing procedures to obtain the information requested
by the temporary instruction.
The inspectors conducted
a telephone interview with
the licensee on December 17, 1996, to verify the results of the review.
Based on
the documentation
review and the licensee interview, the inspectors determined
that the licensee had the capability to perform onshift dose assessments
using
V,
-23-
real-time effluent monitor and meteorological data and that the process was
described
in the emergency
plan and implementing procedures.
C.
Conclusion
The process for performing onshift dose assessments
was described
in the
emergency
plan and implementing procedures.
S4
Security and Safeguards Staff Knowledge and Performance
S4.1
Loss of Visitor Control
Unit 2
80
Ins ection Sco
e 71750
During a routine tour of the EDG room, the inspectors observed
a contract
employee, performing escort duties, not maintaining control of a visitor. The
inspectors discussed the observation with the supervisor present at the scene, the
licensee, and contractor management.
b.
Observations
and Findin s
On November 22, the inspectors observed
a contract employee cleaning the floor in
the Unit 2 Train A EDG control cabinet room.
Although the employee possessed
an
escort badge, the inspectors did not observe
a visitor. The escort's supervisor,
also
present in the room,
indicated that the visitor was in the adjacent engine room
paintirig the floor. The supervisor subsequently
obtained possession
of the escort
badge and gave it to another employee working in the vicinity of the visitor. The
inspectors determined that the visitor had been out of visual sight of the escort in
the control cabinet room.
Procedure
20AC-OSK04, Revision 17, "Protected/Vital Area Personnel
Access
Control,",step 3.7.5.4 required that escorts maintain positive control of visitors at
all times while in the protected/vital area, and step 3.7.6.2 required that visitors
shall remain in the line of sight and in positive control of their escort.
The failure of
the employees to follow procedure
and maintain positive control of the visitor within
a vital area was a violation of TS 6.8.1 for failure to follow procedures
(50-529/9601 7-04).
The inspectors questioned the escort about the duties and responsibilities of an
escort.
The escort indicated that there was only one exit out of the EDG room and
that the visitor could not get out of the EDG room without going past the escort.
The inspectors noted that the escort failed to realize that the visitor was already in a
vital area; in addition, there was another exit out of the room.
The inspectors
also
noted that the supervisor knew the location of both the escort and visitor and had
allowed them to become separated.
-24-
The inspectors informed security of the event.
Security personnel
responded
to the
scene, obtained personnel statements,
and reminded the personnel
involved of their
escort responsibilities.
Security contacted the SS and the SS dispatched
an
operator to verify the status of the EDG. The operator identified no discrepancies
to
the EDG. Another badged individual, who had been working with the visitor in the
EDG room; subsequently
stated that the visitor had been within his sight for the
duration.
The inspectors discussed
the event with the contract project manager.
The project
manager indicated that on the day of the event, the contractor stopped
all work in
the EDG room and performed
a training session
on escort duties.
In addition,
separate
counseling was performed for the escort and visitor. The following day,
the contractor performed prejob briefings to discuss the duties of an escort.
The
project manager indicated that the contractor planned to develop
a computer based
interactive training program on escort responsibilities by early 1997.
The inspectors discussed
the event with the Director of Emergency Services.
The
director planned to issue news flashes and flyers to reinforce the requirement of
escort responsibilities,
and that a security department
leader would meet with the
new classes of employees
and explain security requirements.
The inspectors found
these actions to be thorough.
c.
Conclusions
An escort, visitor, and supervisor failed in their responsibilities to prevent an
unescorted
visitor from gaining unrestricted access to an area containing vital safety
equipment.
The corrective actions performed by the licensee and contractor were
thorough.
V. Mana ement Meetin s
X1
Exit Meeting Summary
The inspectors presented
the inspection results to members of licensee management
at the
conclusion of the inspection on December 30, 1996.
The licensee acknowledged
the
findings presented.
The inspectors asked:the
licensee whether any material examined during the inspection
should be considered
proprietary.
No proprietary information was identified.
ATTACHMENT 1
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Flood, Department Leader, System Engineering
R. Fullmer, Director, Nuclear Assurance
J. Hesser, Director, Design Engineering
W. Ide, Vice President,
Engineering
D. Kanitz, Engineer, Nuclear Regulatory Affairs
A. Krainik, Department Leader, Nuclear Regulatory Affairs
D. Mauldin, Director, Maintenance
R. Myrick, Department Leader, Mechanical Maintenance
G. Overbeck, Vice President,
Nuclear Operations
M. Powell, Department Leader, Civil/Mechanical Design Engineering
C. Seaman,
Director, Emergency Services
G. Shanker, Department Leader', Nuclear Assurance
Maintenance
D. Smith, Director, Operations
J. Taylor, Department Leader, Operations
M. Windsor, Section Leader, IVlechanical Maintenance
Engineering
C. Zell, Department Leader, Operations
t
Others
L. Gourley, Project Manager, Fluor Daniel
INSPECTION PROCEDURES USED
37551
61726
62707
71707
71750
92901
92902
92903
Onsite Engineering
Surveillance Observations
Maintenance
Observations
Plant Operations
Plant Support Activities
Followup- Plant Operations
Followup-Maintenance
Followup-Engineering
Licensee Onsite Dose Assessment
Capabilities
0 g
e'
'e
Sl
J
on
e
'J
-2-
I
ITEMS OPENED
CLOSED AND DISCUSSED
~Oened
50-528;
50-529/9601 6-01
50-528; 50-529;
50-530/9601 7-02
VIO
failure to.follow procedures
by operators with three
different examples
J
failure to follow written procedures
in the maintenance
area
with two different examples
50-528; 50-529;
50-530/9601 7-03
50-529/9601 7-04
VI0
inadequate
tests of main steam and feedwater isolation
valve air operating systems did not insure operability in
violation of TS 4.0.5
failure to follow security procedure visitor control
requirements
Closed
50-528/95011-01
LER
inadequate
main steam and feedwater isolation valve
operating air inservice tests in all three units
50-529/94031-03
Discussed
50-528/9301 1-02
two examples of inadequate
corrective actions
LER
Potential safety-related
equipment problems due to
degraded
grid voltage
V,
~
g45N,~ ~
-3-
LIST OF ACRONYMS USED
AFA
CRDR
CRDL
EC
auxiliary operator
condition report/disposition request
control room deficiency log
essential chilled water
EW
GTGs
LER
SESS
TS
WSCC
engineering
evaluation request
essential cooling water
gas turbine generators
high pressure safety injection
licensee event report
reactor coolant pumps
shift supervisor
safety equipment status system
Technical Specifications
Updated Final Safety Analysis Report
work order
Western States Coordinating Council
~ ~
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