ML17312B129
| ML17312B129 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/05/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17312B127 | List: |
| References | |
| 50-528-96-16, 50-529-96-16, 50-530-96-16, NUDOCS 9612110028 | |
| Download: ML17312B129 (30) | |
See also: IR 05000528/1996016
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
'ocket
Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By;
50-528
50-529
50-530
NPF-51
50-528/96-1 6
50-529/96-1 6
50-530/96-1 6
Arizona Public Service Company
Palo Verde Nuclear Generating Station, Units 1, 2, and 3
5951 S. Wintersburg Road
Tonopah, Arizona
October 6 through November 16, 1996
K. Johnston,
Senior Resident Inspector
J. Kramer, Resident Inspector
D, Garcia, Resident Inspector
D, Carter, Resident Inspector
Dennis F. Kirsch, Chief, Reactor Projects Branch F
ATTACHMENT: Supplemental
Information
'P612f i0028 961205
ADQCK 05000528
G
~ ~
l
I
EXECUTIVE SUMMARY
Palo Verde Nuclear Generating Station, Units 1, 2, and 3
NRC Inspection Report 50-528/96-16; 50-529/96-16; 50-530/96-16
~Oerations
~
A loss of the operating instrument air (IA) compressor occurred in Unit 1, while it
was in Mode 6, as a result of an incomplete review of work by the work control
senior reactor operator (SRO).
Operations personnel
responded
appropriately to the
event; however, operations
personnel
exhibited weakness
in attention to detail in
that the shift supervisor did not ensure that the event was properly documented
in
control room logbooks or the corrective action programs (Section 01.1).
~
Refueling personnel demonstrated
good communications
and a formal
safety-conscience
approach when performing refueling operations.
The refueling
senior reactor operator (LSRO) directing the core load during its latter stages
used
improved monitoring equipment
and handling techniques.
Operations showed good
judgement in stopping upper guide structure (UGS) installation operations when
LPSI flow indications could not be verified (Section 01.2).
~
The Unit 1 operations midloop team did not ensure proper completion of all
prerequisites
prior to initiating the drain down of the reactor coolant system
(RCS)
to reduced inventory. After it was identified that the lineup was incorrect, auxiliary
operators
(AOs) (initial positioner and verifier) reperforming the valve lineup failed to
identify an incorrectly positioned valve.
This is a violation of requirements to follow
procedures.
Both of these issues are repeat events from previous violations of the
same procedure.
The resolution of the draining discrepancies
by the operators
and
subsequent
management
response
was very good (Section 04.1).
Maintenance
~
Maintenance work observed was well performed.
Technicians were experienced
and knowledgeable of their assigned tasks and demonstrated
good communications
between work groups.
Additionally, maintenance
personnel exhibited strong
knowledge of the reactor vessel multistud tensioner and stud insertion process
(Section M1.1).
~En ineerin
~
Licensee Event Report (LER) 528/95007, Revision 1, was incomplete in that it did
not address
significant aspects of problems with letdown isolation valves which
individually could not have isolated full RCS pressure,
Additionally, the initial LER
and first revision did not fully address the safety implications of the as-found
condition of these valves (Section E8.3).
~
An unresolved
item was identified concerning the degraded
flexible covers for the
reactor coolant pump lubrication oil collection system (Section F2.1).
e
~ 4
Re ort Details
Summar
of Plant Status
Unit 1 began this inspection period defueled.
On October 29, following completion of a
39 day refueling outage, the unit commenced
a reactor startup and power ascension.
On
November 6, the unit reduced power from 90 to 25 percent to repair a steam leak
downstream of a main turbine control valve.
Following the repair, the unit returned to
100 percent power and remained there for the duration of the inspection period.
Units 2 and 3 operated at essentially 100 percent power for the duration of the inspection
period.
I. 0 erations
01
Conduct of Operations
01.1
Loss of IA Com ressor
B Unit 1
ao
Ins ection Sco
e 71707
The inspector observed operations'esponse
to the loss of IA Compressor
B, a
nonsafety related component,
which resulted from a unexpected
power loss during
a maintenance
activity. The inspector discussed
the event with the shift supervisor,
operations director, unit department
leader, and electrical maintenance
department
leader.
b.
Observations
and Findin s
On September 29, electrical maintenance
technicians obtained approval from the
work control senior reactor operator (SRO) to perform work on the 480 volt Circuit
Breaker NHNM0219 using Work Order (WO) 770890.
The electrical maintenance
technicians de-energized
Circuit Breaker NHNM0219, which removed power to
Distribution Panel NHN-D02. One load supplied by Distribution Panel NHN-D02 was
control power for IA Compressor
B. IA Compressor
B was in operation with IA
Compressors
A and C in standby.
After control power was removed, IA
Compressor
B tripped and IA Compressor A and C both started.
IA Compressor A
subsequently
tripped on low oil pressure.
An AO responded to the area and
restarted
IA Compressor A.
The inspector, who was in the control room at the time the event occurred,
observed that control room personnel took appropriate actions to restore an
IA compressor to service.
The event did not have a significant impact on the plant,
which was in Mode 6 at the time.
The shift supervisor briefed the entire operations crew and the site shift manager on
the initial lessons
learned from the event.
The shift supervisor stated that the work
control SRO failed to perform a proper review of WO 770890, by not evaluating
-2-
electrical prints to determine which loads would be affected by de-energizing
Circuit
Breaker NHNM0219.
On October 3, the inspector noted that the event had not been documented
in
either the unit or the control room logbooks and it had been not documented
in the
licensee's corrective action program in that a condition report/disposition request
(CRDR) had not been initiated.
The inspector discussed
concerns that the details of
the event had not been documented
in the control room logbooks or captured by
the corrective action program with the unit department
leader.
The unit department
leader did state that he had been independently tracking this issue; however, he
agreed that the shift supervisor should have ensured it was adequately
addressed
without his involvement.
The inspector noted that once the inspector identified concerns were brought to the
attention of management they were appropriately addressed.
C.
Conclusions
A loss of the operating IA compressor occurred as a result of an incomplete review
of work by the work control SRO.
Operations personnel
responded
appropriately to
the event; however, operations
personnel exhibited weakness
in attention to detail
in that the shift supervisor did not ensure that the event was properly documented
in control room logbooks or the corrective action program.
01.2
Fuel Movement UGS Installation
Unit 1
Ins ection Sco
e 71707 and 60710
The inspector observed refueling operations
and the installation of the UGS using
the following procedures:
78OP-9FX01, Refueling Machine Operations
Section 9.0, Filling and Draining the Refueling Pool Using the
40OP-9ZZ12, Mode 6 Operations
31MT-9RC33, Reactor Vessel UGS Removal and Installation
b.
Observations
and Findin s
On October 16, 1996, the inspector observed
Unit 1 refueling operations.
The
LSRO directed all fuel transfers from the refueling bridge.
Allfuel movement was
coordinated with the control room and logged in accordance
with
-3-
Procedure 72IC-9RX03, "Core Reloading."
Good communications were observed
between the LSRO, the fuel pool bridge crane operator,
and the control room.
The inspector observed the latter portions of the fuel load.
It was during this stage
in fuel loading during the 1995 Unit 1 refueling outage that a fuel assembly was not
properly positioned on the core support plate.
The licensee attributed this, in part,
to weaknesses
in their fighting and ability to use video cameras
as the vessel was
filled. The inspector observed that, during this core load, the licensee had
implemented corrective actions which enabled them to,more closely monitor the
latter portion of core load.
Additionally, the LSRO used proper techniques to verify
the last fuel assemblies
were properly set.
The inspector observed proper radiological protection practices while the camera
cabling was removed from the refueling pool and proper foreign material control
inventory practices.
The inspector also observed
good use of safety harnesses
for
personnel frequenting the refueling cavity and while walking across the bridge
crane.
On October 17, the inspector observed the lifting, transfer, and insertion of the UGS
into the reactor vessel.
The licensee demonstrated
good communications
and
oversight in the movement of the UGS.
Radiation protection personnel continuously
monitored and kept operators informed of dose rates in manned areas,
The
licensee's
use of remote underwater cameras greatly aided the alignment and
insertion of the UGS into the reactor vessel.
After the UGS was lowered into the vessel the inspector observed the licensee
unlatch all the control element assembly self-latching mechanisms
in preparation for
lowering the control element assembly support plate.
During this time, the control
room was lining up the LPSI system to lower refueling pool water level.
The control
room informed the LSRO of LPSI flow problems and UGS installation was halted.
Control room personnel
concluded
LPSI flow detector SIN-Fl-300 was not providing
reliable information.
The licensee corrected the flow indication problem prior to
resuming the UGS installation.
The inspector determined this action to be
appropriate.
Conclusions
Refueling personnel demonstrated
good communications
and a formal
safety-conscience
approach when performing refueling operations.
The LSRO
directing the core load during its latter stages
used improved monitoring equipment
and handling techniques.
Operations showed good judgement in stopping UGS
installation operations when LPSI flow indications could not be verified.
-4
04
Operator Knowledge and Performance
04.1
RCS Reduced Inventor
and Midloo
0 erations
Unit 1
a.
Ins ection Sco
e 71707
On October 20, 1996, in the process of reducing the RCS level for midloop
operations,
operators identified that their drain path was not properly established.
In addition, during a subsequent
valve lineup walkdown, AOs failed to identify that
a valve, required to be open, was locked closed.
The inspector reviewed the
licensee's
response
to these problems,
b.
Observations
and Findin s
Missed Prere
uisite for Drain Ali nment
On October 20, 1996, shortly after they initiated draining the RCS, the operations
midloop team did not receive the expected
level change for the refueling water
tank (RWT) and identified an unexpected
level change
in the holdup tank (HUT).
The midloop team subsequently
identified that Appendix Q of
Procedure 400P-9ZZ16, "RCS Drain Operations," did not reflect current plant
configuration in that three valves were not in their correct lineup to align the drain
path to the RWT.
The licensee investigation determined that the following sequence
of events
contributed to the valve lineup problem.
On October 17, following core reload, the
oncoming control room night shift continued the drain of the refueling cavity to the
RWT, an activity that was initiated on day shift. Concurrent with cavity drain
operation, the crew lowered the reactor vessel level approximately 2 inches in
accordance with Procedure 40OP-9ZZ16, "RCS Drain Operations."
Operators
had
changed the drain path, documented
in Appendix Q to the procedure, to drain the
RCS to HUT. Subsequently,
the operators misplaced the paperwork for the revised
Appendix Q lineup, and, therefore, the revised lineup did not replace
a previously
existing Appendix Q lineup, which showed the drain path established to the RWT.
The operators completed both drain evolutions at approximately 11:30 pm.
The licensee determined that during the draining evolutions on October 17, the
midloop control room supervisor
(CRS) was preparing for the upcoming drain to
midloop and was not directly involved with the crew's activities.
However, the
midloop CRS was peripherally aware that the crew had performed
a drain of the
RCS to the RWT. The next day, the midloop team was temporarily disbanded
due
to outage delays that affected the midloop schedule.
On October 19, the midloop team reconvened
for night shift and prepared to drain
the RCS to reduced inventory condition by draining the RCS to the RWT. The
midloop team did not reperform Appendix Q because they were confident that they
-5-
had an established
drain path to the RWT based
on the completed Appendix Q
demonstrating
a drain path to the RWT and the midloop CRS's previous
understanding
of draining operations to the RWT on October 17.
The team
subsequently
performed
a drain of the RCS in preparation to enter a reduced
inventory condition.
After draining approximately
1 ft of level from the RCS, the
midloop CRS identified that there was a slight level increase
in the HUT rather than
the RWT. The midloop team halted further drain operations until an investigation
was completed,
k'he
licensee's investigation determined that the midloop CRS failed to ensure the
drain path was aligned in accordance
with Appendix Q prior to draining the RCS.
The inspector concluded that the failure of the CRS to perform the prerequisites was
a violation for failure to follow Procedure 40OP-9ZZ16.
The inspector noted that the midloop CRS did not ensure completion of Appendix Q
and relied on communications that were overheard when reviewing paperwork.
The
inspector determined that this event was similar to a midloop event on
November 28, 1994, where the CRS relied on discussions
between the control
room staff and assumed that makeup flow path alignments had been performed.
This event was identified as a failure to follow procedure violation in NRC Inspection
Report 50-530/94038.
The inspector concluded that it was reasonable
to expect
that the corrective actions taken following the November 1994 event should have
prevented the October 1996 event.
Inade
uate Valve Positionin
and Verification
After the midloop team initially halted the RCS drain on October 20, the midloop
CRS dispatched two AOs to perform and independently verify the Appendix Q valve
alignment.
The AOs identified two open valves that Appendix Q required to be
closed and, subsequently,
closed the valves.
These actions isolated the drain path
to the HUT. However, the AOs did not identify that locked closed
Valve CHN-V495, which established
a drain path to the RWT, was required to be
open.
The midloop crew recognized that diverting letdown water from the volume control
tank would provide a performance verification of the drain path alignment without
reducing RCS level. The crew initiated a divert and noted that the drain path was
still not properly aligned.
The midloop CRS informed the AOs of the problem and
directed them to recheck the Appendix Q valve lineup.
The AOs subsequently
identified that Valve CHN-V495 was locked closed and opened the valve to align
the drain path.
The failure of the AOs to place Valve CHN-V495 in the open
position is the second example of the failure to follow Procedure 40OP-9ZZ16.
The inspector noted that on October 17, 1995, Unit 3 operations
personnel
attempted to lower the RCS level by draining to the RWT. Operators were unable to
drain the RCS and, subsequently,
discovered that Valve CHN-V495 was closed.
-6-
The licensee had identified that AOs failed to initially position and independently
verify the position of Valve CHN-V495. This event was documented
as a noncited
procedure violation in NRC Inspection Report 50-528,529,530/95018.
The
inspector concluded that it was reasonable
to expect that the corrective actions for
the October 1995 event should have prevented this October 1996 event.
The two failures of the operations staff to follow procedure
is a violation of
Technical Specification (TS) 6.8.1 (50-528/96016-01).
Problem Resolution
After the midloop team identified Valve CHN-V495 had been mispositioned, they
suspended
the performance of the reduced inventory preparations to reperform all
drain down prerequisites
and evaluate the events.
The licensee subsequently
recommenced
the drain down evolution and completed the midloop operations
without incident. 'In addition, the licensee initiated CRDRs and human performance
evaluations to assess
personnel performance issues.
The inspector found that the midloop teams had been prompt in identifying that the
lineup had not been properly established.
In addition, once the initial walkdown
was completed, the midloop team's actions to test the lineup demonstrated
conservative action.
The licensee's evaluation of the event was questioning
and
thorough.
C.
Conclusions
-The midloop team did not ensure proper completion of all prerequisites
prior to
initiating the drain down of the RCS to reduced inventory.
After it was identified
that the lineup was incorrect, AOs (initial positioner and verifier) reperforming the
valve lineup failed to identify an incorrectly positioned valve.
Both of these issues
are repeat events from previous violations of the same procedure.
The resolution of
the draining discrepancies
by the operators
and subsequent
management
response
was very good.
08
Miscellaneous Operations Issues (92901)
08.1
Closed
Violation 50-529 96005-01:
failure of a reactor o erator to follow a
rocedure
in reali nin
ower sources
and
Closed
LER 50-529 96002:
ina
ro riate work
ractice results in an en ineered safet
feature actuation of the
Train B emer
enc
diesel
enerator.
This event was discussed
in Inspection Report 50-528,529,530/96-05.
The
inspector verified the corrective actions described
in the licensee's
response
letter,
dated May 22, 1996, to be reasonable
and complete.
In addition, no new issues
were revealed
in the LER.
-7-
08.2
Closed
Violation 50-530 95025-02:
failure to follow the prescribed operability
evaluation.
This violation concerned
an incident where an operability detern ination
had not been performed by operations
personnel when credit for manual actions
were taken to compensate
for a degraded
condition found on the Unit 3 Essential
Chiller 8 as determined
by engineering
personnel.
The inspector verified the corrective actions described
in the licensee's
response
letter dated March 25, 1996, to be reasonable
and complete.
II. Maintenance
NI1
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:
e
WO 752667:
replace gasket on 1B Emergency
Diesel Generator
B fuel oil
discharge filter (Unit 1)
~
WO 770205:
replace manifold on Emergency Diesel Generator
B (Unit 1)
~
WO 771959:
evaluate/test
reactor coolant pump rotorbars (Unit 3)
~
31MT-9RC30: reactor vessel head removal and installation (Unit 1)
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.
The
inspector concluded that maintenance
personnel
exhibited strong knowledge of the
reactor vessel multistud tensioner and stud insertion process.
M1.2
General Comments on Surveillance
Activities
a.
Ins ection Sco
e 61726
The inspectors observed
all or portions of the following surveillance activities:
~
control room air handling unit airflow capacity and
pressurization test (Unit 1)
-8-
~
auxiliary feedwater pump A inservice test (Unit 2)
The inspectors found these surveillances were performed acceptably and as
specified by applicable procedures.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
Leakin
Bod -to-Bonnet Seal on Shutdown Coolin
Isolation Valve SIB-652
Unit 1
a.
Ins ection Sco
e 62707
During restart activities in Unit 1, the licensee discovered that shutdown cooling
isolation Valve SIB-652, the first of two isolation valves for the RCS, had a leaking
body-to-bonnet
seal.
In response to the licensee's
decision to not repair the valve
prior to restart, the inspector reviewed the basis for this decision and reviewed
work performed on the valve during the outage.
Two conference
calls were held
with the licensee involving the NRC's Region IV office and the NRR projects,
manager.
b.
Observations
and findin s
During the refueling outage, the licensee installed modifications to Valves SIB-652
and SIA-651 to provide pressure relief in these double wedge gate valve bonnets to
prevent the development of pressure
locking under design basis accident conditions.
To accomplish this modification, the licensee had to disassemble
the valves and
subsequently
replace the body-to-bonnet
seal during valve reassembly.
The seal
installed was prepared with a surface of silver, which was designed to improve
valve sealing.
The modification was done with the core off loaded and the
shutdown cooling loops drained.
During the subsequent
flood up, the licensee
observed that the seal leaked.
They concluded that the leakage was not
unexpected
since, in their experience,
the valve seals tended to seal better as RCS
pressure
increased.
However, in Mode', with the RCS at normal operating temperature
and pressure,
the valve was found to leak at approximately 0.08 gallons per minute (gpm).
Maintenance
engineering
evaluated
and allowed mechanics to increase
body-to-bonnet
bolt torque.
This activity did not decrease
the leakrate.
Maintenance
engineering
also allowed mechanics to use the manual handwheel
on
the actuator to apply additional seating pressure to establish
a better seal at the
upstream valve seat.
They stipulated that the seating pressure
be relieved to the
original seating force.
This activity reduced the body-to-bonnet
leak to around 0.03
gpm.
-9-
Licensee engineering
subsequently
performed an evaluation which concluded that
this amount of leakage was acceptable for the duration of the operating cycle.
The
licensee evaluated;
The susceptibility to corrosion of valve components
exposed to the boric
acid environment.
The I(censee found that under the environmental
conditions, the valve components,
which were mostly stainless steel with a
few carbon steel components,
would not be subject to significant corrosion.
The exposure of the system piping to thermal stratification.
They determined
that existing evaluations remained valid as long as the leak remained below
0.1 gpm.
The ability to monitor the teak.
They installed a video camera to allow
control room operators to monitor the general condition of the leak.
In
addition, they planned to enter containment twice per week to measure
system leakage and assess
valve condition.
The licensee constructed
a stainless steel drip catch with a hose draining through a
floor drain to the containment sump. At the end of the inspection period, the
licensee was evaluating additional actions that could reduce leakage,
After roughly
'two weeks at full power, the leak rate had decreased
slightly.
The inspector reviewed the licensee's evaluation of continued operations with the
leak and found that it adequately
addressed
the technical issues of boric acid and
thermal stratification exposure.
Additionally, the evaluations to support the
activities performed to reduce the leak were appropriately reviewed.
The inspector
found that the installed drip catch was well constructed
and performed as designed.
The licensee's monitoring activities to date have demonstrated
concern for changes
in leak rate.
C.
Conclusion
The licensee has performed adequate
actions to address
a leaking body-to-bonnet
seal in a reactor coolant pressure
boundary valve.
M8
Miscellaneous Maintenance Issues (92902)
M8.1
Closed
Violation 529 95010-01:
use of an uncalibrated boronometer.
LER 529/94008, submitted on February 7, 1995, identified that Unit 2 operators
had used an uncalibrated boronometer to comply with the compensatory
action
requirements of TS 3.1.2.7, which applied when a startup channel was out of
service.
The inspector reviewed the LER and the associated
CRDRs and found
weaknesses
in the evaluation of the cause of this event and with the corrective
actions.
Inspection Report 50-529/95010 included a Notice of Violation (NOV) for
failure to use a properly calibrated instrument to meet TS requirements.
Although
-10-
licensee identified, the violation was cited because the licensee had not
implemented adequate
corrective actions.
The licensee responded
to the NOV in a letter dated July 27, 1995.
They stated
that corrective actions would be implemented to:
Revise procedures for controlling preventive maintenance
and preventive
maintenance
activities to require notification of the shift supervisor when a
preventive maintenance
task is waived.
Revise procedures to require notification of the shift technical advisor or
other appropriate
engineering
personnel when out-of-tolerance results are
found during surveillance testing.
Require the shift technical advisor or appropriate engineer to perform a
documented
evaluation of the significance of the problem or deficiency and
ensure that when appropriate
a corrective action document
is generated.
Issue a night order to all three units outlining the actions to be taken if the
boronometer
is not available, including initiating a "control room discrepancy
log" entry to make the status of the boronometer obvious to control room
personnel.
Review the event in the operator training.
The inspector reviewed the corrective actions described
in the licensee's
response
and found them to appropriately address the cause of the violation.
In particular,
the corrective actions to highlight deficiencies with an operations impact to
operators
addressed
the cause of this event.
The inspector noted that operators
have done a more thorough job of highlighting deficiencies with controlled
temporary notes and control room discrepancy
log entries.
M8.2
Closed
LER 50-529 95006:
failure to perform TS surveillance
requirement 4.5.2.e.4, inspection of all emergency core cooling systems outside
containment
and verify total leakage
is less than
1 gpm.
The inspectors
documented
the event and initial licensee response
in NRC Inspection Report 50-
528,529,530/95-14.
The licensee initiated an investigation to identify the cause
and corrective actions
for the event.
The licensee noted that sections of the surveillance were performed
in two midcycle outages
and documented
as full performance
on the surveillance
test package review sheets
(STPRS) although the test log clearly indicated only
partial performance.
The licensee identified that the cause of the event included
both procedure
and personnel
weaknesses.
-1 1-
The licensee revised the STPRS forms and provided training to operations
and
maintenance
personnel,
on the revised form, in industry events training.
In
October 1995, the test program users group performed
a human factors review of
the revised STPRS form, concluded that the STPRS form was less than adequate,
and identified further enhancements
to the form.
In February 1996, the licensee
performed an assessment
of the effectiveness of the corrective actions similar to
the initial investigation and concluded that the corrective actions were effective.
The failure to perform the surveillance requirement is a violation of the TS.
The
inspector reviewed condition report/disposition request
(CRDR) 2-5-0252 and found
the licensee's investigation to be thorough and their corrective actions to be
thorough.
This licensee-identified
issue is being treated as a noncited violation
consistent with Section Vll of the NRC Enforcement Polic
(50-529/96016-02).
III. En ineerin
E8
Miscellaneous Engineering Issues (92903)
E8.1
Closed
LER 50-529 95001;
TS 3.0.3 entry until TS limiting condition for
operation
(LCO) 3.4.9 Action B was met by isolating the Charging Pump A, On
April 12, 1995, Unit 3 was in Mode
1 operating at approximately 100 percent
power when an AO identified a leak through
a cracked weld in the piping system
near the Charging Pump A suction drain valve.
Control Room personnel
entered
TS
LCO 3.0.3 following a determination that Action B for TS LCO 3.4.9 could not be
met.
Within nine minutes, operations isolated the Charging Pump A which
established
compliance with TS LCO 3.4.9 Action B, and exited TS LCO 3.0.3.
The licensee determined that this was an isolated failure which had resulted from a
defective weld, most likely from original fabrication," They concluded that the failure
was accelerated
because
of material fatigue as a result of the vibration of the
charging pump suction line. The licensee performed walkdowns of the remaining
charging pumps in Units 1, 2, and 3 and did not identify any additional material
nonconformance
or leakage.
On April 18, 1995 the Unit 3 Charging Pump A was
repaired and returned to service.
The inspector found the licensee's
response
to
this event to be appropriate.
E8.2
Closed
Violation 50-528 95025-03:
failure to leak test the essential chiller
system.
This violation addressed
the licensee's failure to establish testing required
to demonstrate that the essential chilled water system could perform satisfactorily
in that they had not identified and performed tests incorporating the requirements
and acceptance
limits for the allowable system leakage.
-1 2-
The inspector reviewed the licensee's response'to
the violation dated March 25,
1996.
The licensee discussed
the following corrective actions:
~
Engineering revised the calculation which established
the maximum allowed
system leakage.
These changes
were reflected in the associated
design
basis manual.
~
Operator rounds were revised to provide leakage measurements
and the
results were to be reviewed by engineering.
~
Maintenance
personnel were briefed on the importance of observed
leaks on
the chiller and the chilled water pump.
In addition, the licensee stated in the NOV response that they had established
a
June 30, 1996, schedule for completion of the design basis project for the heating,
ventilation, and air conditioning systems.
The inspector reviewed the licensee's
planned coriective actions and determined
that they addressed
the weaknesses
identified. The inspector reviewed revisions to
the calculation for acceptable
leak rate and the procedure to test for leakage and
found that they established
a reasonable
leak rate and an acceptable
method to test
for this leakage.
The inspector noted that the CRDR also included actions to have
maintenance
perform weekly checks of the essential chiller pumps for leakage and
found this action to be prudent.
E8.3
0 en
LER 50-528 95007
Revision 1: adverse affect of low bench set on Fisher
air o crated letdown containment isolation valves
Observations
and Findin s
In September
1994, as documented
in NRC Inspection Report
50-528;529;530/94031,
the inspector noted that Unit 1 Valve CHB-515, the
.
letdown to regenerative
heat exchanger isolation valve, had a caution tag indicating
that the valve leaked at a rate of 41 gpm when closed at normal operating pressure
and could not be used to isolate the letdown line. Although this condition had
existed since late 1992, the inspector identified that the licensee had not performed
an adequate
review of the deficiency and had missed an opportunity to fix the valve
during a 1993 refueling outage.
Subsequently,
the licensee performed an
operability determination and concluded that, in its existing condition, the valve
could perform its design functions.
The inspector subsequently
identified that the
valve was required to close as part of the licensee's control room fire mitigation
strategy and initiated Unresolved Item 528/9431-01.
The licensee took
compensatory
actions to provide additional fire mitigation strategies,
reperformed
the operability determination and determined that the valve could perform its design
functions.
This action was documented
in LER 528/94009, issued on March 2,
1995.
The licensee submitted
LER 528/95007 (dated June 9, 1995) and
-13-
LER 528/95007, Revision
1 (dated April 6, 1996), to document that a design
deficiency had contributed to the problems with Valve CHB-515, that this was
applicable to downstream letdown line containment isolation Valves CHA-516 and
CHB-523, and that it had impacted
a number of design basis functions of these
valves.
The inspector reviewed LER 528/95007, Revision 1, and associated
evaluations
and calculations.
The three letdown isolation valves are air to open, spring to close, 2-inch globe
valves.
The seating force of the spring, established
during a bench set, should be a
function of the spring force necessary to close the valve against system pressure
and friction forces and the air pressure
available for the air operator.
The licensee
identified, in LER 95007, Revision 1, that the letdown valve operators were
undersized for their application and that this was attributed to the absence
of a
detailed design basis for these air operated valves.
Valve service engineering determined that in order to close under design basis
conditions, the letdown isolation valves required
a bench set of at least 38 pounds
per square inch gage (psig).
The valves, as originally procured and installed, were
provided a bench set of between 22 and 38 psig,
The licensee determined that the
Nuclear Steam Supply System vendor had procured the valves and had not
established
an adequate
design basis for the air operated valves.
The licensee
initiated the following corrective actions:
~
Evaluations were performed for all air-operated valves of a similar design.
Valve services engineering
calculated appropriate
bench set requirements for
each of the valves and determined that all these valves had been set
appropriately.
~
The air operators for all of the letdown isolation valves were replaced during
the past round of refueling outages.
~
Valve services engineering
established
an air-operated valve program to
establish air operator valve setpoint, diagnostic testing, maintenance,
and
testing programs.
The licensee planned to implement this program for
air-operated valves in priority systems.
The inspector noted that in addition to having procured undersized
valve operators,
licensee as-found test results on all nine letdown isolation valves were below the
22 psig originally specified as the minimum for the valves.
The as-found bench sets
for the valves were between 10 and 20.6 psig.
The as-found results were not
addressed
in either LER 50-528/94009 or LER 50-528/95007,
Revision 1.
In
addition, the licensee had not evaluated this problem in any of the CRDRs
associated
with this issue.
The inspector discussed
this issue with maintenance
personnel.
They determined
that the set point changes
probably were the result of not ensuring that the valve
-14-
stroke length was maintained when the actuator and valve stem were recoupled
following maintenance
activities.
Routine activities which would have required
decoupling the valve stem from the actuator included valve repacking and actuator
diaphragm replacement.
They also determined that vendor instructions should have
been adequate to ensure that valves were properly reassembled.
Independent
of
this issue, the licensee's
air operated valve program has been improved to ensure
that these valves are properly set up and that design bench sets are maintained.
Conse
uences of Leakin
Letdown Isolation Valve:
In LER 528/95007, Revision 1, the licensee determined that the following design
basis functions were impacted by low letdown isolation valves bench sets:
~
The containment isolation function of Valves CHA-516 and CHB-523
~
The mitigation of a letdown line break outside containment (functions of
Valves CHB-515 and CHA-516) as described
in the Updated Final Safety
Analysis Report (UFSAR) Chapter 15
The isolation of a high energy line break of the letdown line break in the
auxiliary building (function of Valves CHB-515 and CHA-516)
1
The isolation of the letdown line for reactor coolant inventory control for
10 CFR Part 50, Appendix R, fire scenarios
(all three valves)
~
The isolation of letdown upon the receipt of a safety injection actuation
signal (Valves CHB-515 and CHA-516).
LER 528/95007, Revision 1, documented
the analysis performed by the licensee to
determine the impact of having a bench set as low as 22 psig on each of these
functions.
The analysis concluded that there would be adequate
isolation for all
scenarios
as long as two letdown isolation valves close.
Additionally, for the,
letdown line break scenarios
in which only one valve could be credited, the licensee
determined that offsite dose, auxiliary building environment,
and loss of RCS
inventory would be increased,
but within design basis limits.
The inspector noted that the evaluation in LER 528/95007, Revision 1, did not
consider the as-found valve bench sets which would have resulted in greater
leakage in the case where only one valve was available to close.
However, portions
of this evaluation were performed in Calculations 13-MA-CH-954 13-NC-ZY-249.
As discussed
in the LER, the letdown valves, with a minimum bench set of 22 psi,
would have to be closed with a differential pressure
across the valve of 1878 psi,
which would be achieved 27 minutes into the event.
According to
Calculation 13-MA-CH-954, the lowest as-found valve would not have fully closed
until the differential pressure
across the valve was 1120 psi approximately 85
minutes into the event.
The LER indicated that the resultant thyroid dose at the
-15-
exclusionary boundary would be 7.2 rem, while Calculation 13-NC-ZY-249 found
the dose to be 21.45 rem.
The LER also stated that only one valve could have been assumed to close for some
fires outside the control room.
Although the LER described compensatory
measures
that were put into place until the air-operated
valves could be replaced, it did not
describe the consequences
of having only one valve closed.
After questioned
by the inspector concerning the as-found data, the licensee
performed an evaluation to determine the impact of the as-found bench sets on their
ability to achieve safe shutdown.
The licensee informed the inspector that they
determined that they could have achieved safe shutdown with the as-found bench
sets despite calculated valve leakage.
In response to these findings, the licensee proposed to submit a second revision to
This item willremain open pending review of the revised LER.
b.
Conclusions
LER 528/95007, Revision 1,,was incomplete in that it did not address significant
aspects of problems with letdown isolation valves which individually could not have
isolated full RCS pressure.
Additionally, the initial LER and the first revision did not
fully address the safety implications of the as-found condition of these valves.
EBA
Closed
Violation 50-530 95025-01:
failure to identify significant changes
in chiller
refrigerant as a condition adverse to quality. This violation involved maintenance
personnel correcting a deficiency in essential chiller refrigerant levels identified by
the inspector without documenting the problem as required by the corrective action
program.
The licensee missed opportunities for determining the potential impact on
system performance
and operability.
The inspector verified the corrective actions described
in the licensee's
response
letter dated, March 25, 1996.
The inspector reviewed the evaluation response to
CRDR 9-6-0135 that was initiated to addresses
the weaknesses
identified by the
NRC, and found it acceptable.
In addition to a self-assessment
that was performed
by engineering
personnel, the licensee contracted
an independent
assessment
to
compare their chiller performance
issues to current industry standards.
The
inspector determined that the licensee took appropriate actions to address the
violation.
E8.5
Closed
Ins ection Followu
Item 50-530 96012-02:
departure from nucleate
boiling ratio (DNBR) uncertainties,
This item was opened pending the licensee's
completion of corrective actions concerning core operating limit supervisory system
addressable
constant change
and reportability of the DNBR uncertainty issue.
-16-
The nuclear fuels director issued
a memorandum to all nuclear fuels management
personnel emphasizing management's
expectations that all changes
require an
independent
review and section leader review prior to implementation.
In addition,
the licensee discussed
their expectations with all nuclear fuels management
personnel.
On October 18, Combustion Engineering issued 10 CFR Part 21
notification alerting the industry of the potential nonconservatism
in the DNBR limits
previously identified by the licensee.
E8.6
Closed
Followu
Item 50-528 95016-02:
history of ground fault relay failures.
This followup item concerned
a history of failures of General Electric ground fault
relays (GFRs) in safety and nonsafety related 480 volt motor control center
breakers.
The licensee had evaluated
GFR failures in a CRDR written in 1994.
In
Inspection Report 50-528,529,530/95016,
the inspector identified the following
concerns
regarding the licensee's
actions in response to the failures:
An analysis of the failure rates for these GFRs had not been performed.
The licensee had developed
a schedule for the replacement of GFRs which, if
they failed, could place the plants in a TS action statement.
However, the
licensee had not applied risk insights nor enlisted significant operation and
engineering support in assessing
what additional GFRs needed to be
replaced.
At the time of the inspection, none of the GFRs had been replaced according
to the schedule that was established to close the 1994 CRDR.
The licensee initiated CRDR 9-5-1021 to address the inspector's concerns.
The
licensee concluded
in their evaluation of the CRDR that the frequency of GFR
failures matched the vendor's expected failure rate.
Additionally, the licensee found
, that there was no trend to the GFR failure rate.
Based on this analyses, the licensee
determined that a root cause of failure evaluation, which would have been difficult
for this solid state device,'as not warranted.
The licensee did assess
the additional contribution of the GFR failure data on
conclusions.
For purposes of the evaluation, the
licensee established that a contribution to core damage frequency of greater than
10'ere candidates for replacement,
The inspector noted that in the past year the
licensee has improved the failure data collection process
and questioned
whether
this may have had an impact on any failure rate calculations,
The inspector
reviewed the failure data for GFRs over the past year and found that the failure rate
was consistent with previous data.
The inspector reviewed work history over the past year and determined that, as of
November, 1996, the licensee had replaced
61 of 66 GFRs in safety-related
applications.
Additionally, the licensee had established
a plan to replace the General
Electric GFRs in nonsafety-related
breakers which could initiate a plant transient.
-17-
The inspector determined that the licensee had taken adequate
actions in response
to this issue.
IV. Plant Su
ort
F2
Status of Fire Protection Facilities and Equipment
F2.1
Reactor Coolant Pum
Lubrication Oil Collection S stem
Unit 1
a.
Ins ection Sco
e 71750
On October 25, the inspector performed a walkdown of the Unit 1 RCP oil collection
system and reviewed the licensee's commitment to comply with Section III.O of
Appendix R to 10 CFR Part 50.
b.
Observations
and Findin s
The inspector observed that the Unit 1 RCP oil collection system contained the
required oil collection devices as indicated in the UFSAR. The system contained
one welded high pressure
pipe connection on each RCP that did not have a
protection device around it; however, the licensee was not required to have the
welded connection protected.
During the walkdown with the system engineer, the inspector noted that the
condition of the flexible covers (silicon treated glass cloth shields) for the RCP oil lift
system were tom and improperly secured.
The licensee initiated a work request to evaluate and repair the flexible covers on all
four RCPs,
The licensee subsequently
replaced two of the covers, repaired the
remaining two covers, and ensured
all the Unit 1 covers were properly fastened.
In
addition, the licensee performed 31FT-9RC01
"RCP Lubrication Oil Collection
System Inspection," to reverify the status of the complete oil collection system prior
to entering Mode 4.
On October 21, four days prior to the inspector's walkdowns, maintenance
personnel
had performed 31FT-9RC01
as a prerequisite for mode change.
The
procedure included an inspection of the covers and maintenance
personnel,
performing this inspection, concluded that the covers were in good condition and
properly installed.
The licensee initiated CRDR 9-6-1247 to evaluate the flexible cover deficiencies.
The licensee planned to evaluate whether the flexible cover condition existed during
the initial performance of 31FT-9RC01 and why they were determined acceptable,
to develop
a basis for acceptability for future performance of 31FT-9RC01, and to
assess
human performance
and procedural adequacy.
In addition, the licensee
-18-
planned to evaluate the transportability of the as-found condition of flexible covers
to Units 2 and 3.
The inspector will review the licensee's
evaluation, conclusions,
and corrective
actions during'
future inspection (Unresolved Item 528/96016-03).
F8
Miscellaneous Fire Protection Issues
F8,1
RCP Lubrication Oil Collection S stern
Unit 1
a.
Ins ection Sco
e 71750
The inspector performed
a walkdown of the RCP oil collection system and reviewed
the applicable sections of the design basis manual for the fire protection system
pertaining to RCP oil collection.
'b.
Observations
and Findin s
The inspector noted that each of the two tanks in the oil collection system is
capable of holding 110 percent of the lubrication oil from two RCPs.
The inspector
noted that the tanks were equipped with a local gage glass level indication and
were not equipped with a remote level indication or level alarm.
During the walkdown, the inspector identified a potential condition where the RCP
lubrication oil collection system tanks would not be capable of collecting and
holding the lubrication oil from two RCPs.
It appeared that if nuclear cooling water
supplied to the RCP developed
a leak it could be captured by the oil collection
system, fillthe collection tank, and, therefore, not provide the necessary
capacity
for the collection of RCP oil. The inspector noted that there was a flange
connection
in the nuclear cooling water line within the area of the RCP oil collection
system.
Since the tank level has no alarm capability and level can only be checked
from inside containment,
a loss in collection tank capacity could go undetected.
The licensee initiated a CRDR to evaluate the inspector's concern.
The inspector
will review the licensee's evaluation and conclusions during a future inspection
(Inspection Followup Item 528/96016-04).
V. Mana ement IVleetin s
X1
Exit Meeting Summary
The inspectors presented
the inspection results to members of licensee management
at the conclusion of the inspection on November 13, 1996.
The licensee
acknowledged
the findings presented.
-1 9-
The inspectors
asked the licensee whether any material examined during the
inspection should be considered
proprietary.
No proprietary information was
identified.
e
SUPPLEMENTAL INFORMATION
ATTACHMENT
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
F. Riedel, Department Leader, Operations
C. Seaman,
Director, Emergency Services
M. Shee, Director, Radiation Protection
D. Smith, Director, Operations
J. Taylor, Department Leader, Operations
M. Windsor, Section Leader, Mechanical Maintenance
Engineering
C. Zell, Department Leader, Operations
INSPECTION PROCEDURES USED
71707
60710
92901
62707
61726
92902
92903
71750
Plant Operations
Refueling Activities
Followup- Plant Operations
Maintenance Observations
Surveillance Observations
Followup-Maintenance
Followup-Engineering
Plant Support Activities
II
(
1
(
I
ITEMS OPENED
CLOSED AND DISCUSSED
~Oen ed
50-528/9601 6-01
failure to follow RCS drain down procedure
line up
requirements
50-528/96016-03
degraded
RCP oil collection system
50-528/9601 6-04
IFI
potential for nonsafety-related
nuclear cooling water to leak
into RCP oil collection system
Closed
50-529/96005-01
failure of a reactor operator to follow a procedure
in
realigning power sources
50-529/96002
LER
inappropriate work practice results in an engineered
safety
feature actuation of the Train B emergency diesel generator
50-530/95025-02
529/95010-01
50-529/95001
LER
failure to follow the prescribed operability evaluation
use of an uncalibrated boronometer.
TS 3.0.3 entry until TS LCO 3.4.9 Action B was met by
isolating the A charging pump.
50-528/95025-03
failure to leak test the essential chiller system
50-530/95025-01
50-528/9501 6-02
IFI
50-530/9601 2-02
IFI
failure to identify significant changes
in chiller refrigerant as
a condition adverse to quality
history of GFR failures
DNBR uncertainties
50-529/95006
LER
failure to perform TS surveillance requirement 4.5.2.e.4
50-529/96016-02
failure to perform TS surveillance requirement 4.5.2.e 4
Discussed
50-528/95007
LER
adverse affect of low bench set on Fisher air operated
letdown/containment
isolation valves
(
4
~ ~
LIST OF ACRONYMS USED
CRDR
GFR
gpm
HUT
LCO
LER
LSRO
pslg
STPRS
TS
UGS
auxiliary operator
condition report/disposition request
control room supervisor
departure from nucleate boiling ratio
ground fault relay
gallons per minute
high pressure safety injection
holdup tank
instrument air
limiting condition for operation
licensee event report
low pressure safety injection
refueling senior reactor operator
pound per square inch gage
reactor coolant pump
refueling water tank
senior reactor operator
surveillance test package review sheets
Technical Specifications
Updated Final Safety Analysis Report
upper guide structure
work order
1
E
qr
vl
I