ML17333A893
| ML17333A893 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/06/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17333A889 | List: |
| References | |
| 50-315-97-04, 50-315-97-4, 50-316-97-04, 50-316-97-4, NUDOCS 9705150312 | |
| Download: ML17333A893 (50) | |
See also: IR 05000315/1997004
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-315, 50-316
License Nos:
Report No:
50-31 5/97004; 50-31 6/97004
Licensee:
Indiana Michigan Power Company
Facility:
Donald C. Cook Nuclear Generating Plant
Location:
1 Cook Place
Bridgman, Ml 49106
Dates:
February 15, 1997 - March 29, 1997
Inspectors:
B. L. Bartlett, Senior Resident Inspector
B. J. Fuller, Resident Inspector
J. D. Maynen, Resident Inspector
Approved by:
Bruce L. Burgess, Chief
Reactor Projects Branch 6
9705%50312
970506
ADOCK 05000315
8
Executive Summary
D. C, Cook Units
1 and 2
NRC Inspection Report 50-315/97004, 50-316/97004
This inspection included aspects of licensee operations, maintenance,
engineering, and
plant support.
The report covers a 6-week period of resident inspection and includes the
follow-up to issues identified during previous inspection reports.
~rien
Licensed operators failed to include all control room instrumentation in their routine
scans of the control room panels.
This Ied to three of four over power recorder
pens being inoperable for four to seven days until identified by the NRC inspectors.
In addition, the operating crews and ILC were aware of the poor operating history
of the recorder pens yet action was not taken until prompted by the NRC
inspectors.
The failure to have chart recorders capable of recording overpower
transients was a deviation from a commitment in the UFSAR. Section 01.2
The Unit 1 down power and shutdown to enter the Unit 1 refueling outage was
performed in a professional and appropriate manner.
Effective command and
control was maintained by the operating staff. Section 01.3
An inadequate
procedure was used during a reactor trip recovery activity and
resulted in an inadvertent ESF actuation when the TDAFP was reset too close to
the SG low low level setpoint.
This was considered
an example of a violation.
The failure to implement adequate corrective actions to prevent the reoccurrence of
a failure of a Taylor Mod 30 controller was an example of a violation. Section 01.4
The licensee took immediate, comprehensive
corrective action to restore and
maintain the flowpath for water to reach the recirculation sump.
The licensee's
safety assessment
had shown that in the event of a loss of coolant accident while
shutdown, the sump was important to maintaining the unit in a safe shutdown
condition.
Section 01.5
The startup following the Unit 2 unplanned reactor trip proceeded well. The
inspectors noted effective command and control was maintained, and that
communications were excellent during the pre-job briefing and during the approach
to criticality. In addition, there was a low, manageable
number of personnel
present and control room distractions were minimized.
Section 01.6
M i
Plastic shields installed in the control room in order to keep snow out of the backs
of the control panels were not recognized as a temporary modification.
Even
though the licensee has made significant progress in the improvement of temporary
modifications, unrecognized temporary modifications may remain installed in the
plant. The installation of a temporary modification without the proper evaluations
was a violation. Section M2.1
~
A poorly worded TS surveillance requirement concerning the turbine driven auxiliary
feedwater pump (TDAFWP) was identified by the inspectors.
The licensee
recognized these problems and agreed to initiate the appropriate TS change
requests.
Section M3.1
The inspectors noted that the licensee',s procedure for testing the containment
evacuation alarm was inadequ'ate, the coverage of the horns inside containment
was inadequate,
and that when informed. of an inoperable horn that the Unit
Supervisor failed to initiate an action request.
In addition, the procedures covering
use of the containment evacuation alarm were inconsistent in requiring a plant
announcement.
Section M3.2
The licensee failed to adequately remove the spiral wound gasket material from the
RHR system following the second spiral wound gasket failure on 1-IRV-311,
identified on January 31, 1996, resulting in this material entering several
components
in the RHR system and also entering the reactor coolant system.
This
was considered
a violation. The failure to address
ECCS check valve operability is
an unresolved item. Section M4.1
~
The failure to install the cage spacers after refurbishing 1-QRV-114 and 1-NRV-163
were two cases of contractor personnel failing to follow procedure.
These were
two examples of a violation. Section M4.2
~
The technicians working within the FMEZ next to the refueling cavity did not
consistently apply the practices established to keep foreign material out of open
systems.
The failure to follow FME procedures was a violation. Section M4.3
~En ini~rin
The licensee conservatively expanded the scope of their inspection to Unit 2 after
identifying cracks in Unit 1 flood-up tubes.
Following the identification of flaws in
two Unit 2 flood up tubes, the licensee declared, the affected equipment inoperable
and made a required report to the NRC.
The environmental qualification of equipment associated with cracked flood-up
tubes was an unresolved issue.
A violation was identified when the licensee failed
to make a timely report to the NRC concerning equipment that had been identified
as inoperable due to the cracked flood up tubes in Unit 1. Section E2.1
~
The inspectors raised questions concerning the licensee's testing configuration for
the coritrol room emergency ventilation system.
After promptly performing a test
to verify there were no operability concerns the licensee initiated a procedure
change request in order to better control the test configuration.
Section E3.1
Pl n
~
Routine observations were made by inspectors with no discrepancies
noted.
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Unit 1 main'ransformer temperature limitations forced operation of the Unit at 92 percent
to 94.7 percent power during the beginning of the inspection period.
On February 15,
1997, power was reduced as part of the "coastdown" into the refueling outage.
On
February 27, 1997, reactor power was stabilized at 51% in order to perform steam
generator code safety valve testing.
On March 1, 1997, the Unit was shutdown and
entered the refueling outage.
Unit 2 was at full power at the beginning of the inspection period.
On February 8, 1997,
power was reduced to 55 percent in order to perform corrective maintenance
on the East
Main Feedpump.
The Unit was returned to full power on February 17, 1997.
On March
11, 1997, the Unit tripped from full power when a feedwater regulating valve failed
closed.
The valve failed closed when its controller failed. The Unit was returned to full
power on March 18, 1997, following repairs to various controllers and the replacement of
a circulating water pump discharge valve.
r
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01
Conduct of Operations
011
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7 7 7
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
The conduct of operational activity that was observed
was generally good.
Specific events and noteworthy observations
are detailed in
the sections below.
012
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717
7
During routine control room observations the inspectors identified that three of four
nuclear instrumentation power range recorders were malfunctioning.
The
inspectors performed routine follow-up to the licensed operators'ailure to identify
the malfunctioning recorders.
b.
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Fin in
During routine control room observations
on February 25, 1997, the inspectors
observed that the recorder pens recording power level for nuclear instrumentation
power range channels N-41, N-42, and N-43 were not accurate.
The four nuclear
instruments were recorded on two chart recorders.
Each of the two chart recorders
had a range of from 0 percent to 200 percent in order to record any large scale
overpower excursions.
The inspectors observed that on the two chart recorders
the pens were showing the values given below:
N
l
0
Nuclear Instrument Channel
Chart Recorder Reading
Reactor Power Level
N-41
Recorder 1-SG-13
N-42
Recorder 1-SG-14
N-43
Recorder 1-SG-13
N-44
Recorder 1-SG-14
92%
86%
'92%
78%
78%
78%
78%
78%
The inspectors questioned the two reactor operators
(ROs) and determined they
were not aware that the three overpower nuclear instruments were showing
incorrect values.
I
Unit 1 reactor power was being reduced. at a rate of 2 percent per day as part. of
the end of cycle power reduction., This meant that the meters stuck on 92 percent
had been inoperable for approximately one week and that the meter stuck on 86
percent had been inoperable for approximately four days.
Interviews with randomly selected
ROs revealed that,the chart recorders had a
history of sticking.
Chart recorder 1-SG-13 had an action request (AR) written
against it since December 2, 1996, saying that the pens were sticking. The AR
was wntten by IRC personnel following a surveillance test.
Following the inspectors'.identification of the sticking recorder pens, the RO opened
the recorder covers and reset them to the correct, power level.
In addition, the RO
wrote an AR for the stuck recorder that did not already have an existing AR.
UFSAR Chapter 7, Instrumentation and Control, section 7.4.1 stated, "The power
range channels are capable of recording overpower excursions up to 200 percent of
full power." Even though there were other meters which monitored overpower
transients up to 200 percent of full power; these were the only pens which would
record postulated overpower transients.
The inspectors determined that:
H
~
The reactor operators, unit supe'rvisors,
and shift supervisors were not
including these recorders in their scans of the control boards.
~
The chart re'corders had a history of operability problems.
Licensee
personnel informed the inspectors that since June of 1991, the failure rate
was such that the percent pen unavailability average was 14.9 percent.
The
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'noperability of the recorders was a deviation from the licensee's
commitment to have chart recorders capable of recording overpower
transients (50-315/97004-05
(DRP)).
The low reliability/availability rate combined with the lack of use for
operations or surveillances had apparently led to the licensed operators
giving these pens a negligible "scan rate."
No operations or surveillance procedures
used these chart recorders.
When
changing power levels the operators used recorders/meters
with a fine scale,
so these recorders were not used.
Corrective actions by the licensee following the identification of this issue by the
inspectors consisted of:
~
Informing the operating crews to include these chart recorders in their scans
of the control room instrumentation.
Instructing the operating crews to scan the entire control room and to ensure
that all degraded instrumentation was identified and corrected in a timely
manner.
Performing a modification to remove these chart recorders and to record
these channels on other chart recorders.
This modification had been in the
planning stages prior to the inspectors'oncerns
being identified. This
modification was in progress on Unit 1 at the end of the report period and
was being planned for Unit 2 during its next refueling outage.
Performing a one time special review of control room instrumentation to
ensure that all degraded instruments were identified and were scheduled to
be repaired on a timely basis.
nl in
Licensed operators failed to include all control room instrumentation in their routine
scans of the control room panels.
This led to three of four over power recorder
pens being inoperable for four to seven days until identified by the NRC inspectors.
In addition, the operating crews and l&C were aware of the poor operating history
of the recorder pens yet action was not taken until prompted by the NRC
inspectors.
The failure to have chart recorders capable of recording overpower
transients was a deviation from a commitment in the UFSAR.
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01.3
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Auxiliary Power Transfer Test Surveillance
Procedure,
Revision 7
The inspectors observed licensee personnel perform the shutdown of Unit 1. The
shutdown was performed to enter the Spring 1997 refueling outage.
Licensee
procedures
observed included:
01-OHP-4030.STP.026
~
'1-OHP 4021.055.004
Removing a Main Feedpump and Feedpump
Turbine From Service, Revision 6
01-OHP 4021.001.003
Power Reduction, Revision 12
"" 01-OHP 4021.002.005
RCS Draining, Revision 20, to half loop
conditions
"" 01-OHP 4021.001.004
Plant Shutdown from Hot Standby to Cold
Shutdown, Revision 29
b.
On the evening of March 1, 1997, the inspectors observed the licensee perform a
routine shutdown from power to enter a refueling outage.
The inspectors observed
that effective command and control was maintained by the Unit Supervisor and the
Shift Supervisor.
This command and control was challenged; however, by the
relatively large number of personnel present to support the shutdown.
At various
times there were between 25 and 35 operators, lhC technicians, managers,
and
other personnel in the Unit 1 control room.
C.
nl in
-The Unit 1 down power and shutdown to enter the Unit 1 refueling outage was
performed in a professional and appropriate manner.
Effective command and
control was maintained by the operating staff.
01.4
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On March 11, 1997, Unit 2 tripped from 100.percent power as a result of a failed
feed regulating valve corItroller. This caused
a low level in its associated
steam
generator (S/G). All equipment functioned as expected with the following
exceptions:
the main turbine turning gear motor failed, a main feedwater pump
8
turning gear failed to engage,
and the turbine driven auxiliary feedwater pump
(TDAFWP) experienced
an inadvertent ESF actuation.
The inspectors reviewed the
licensee's response to the trip.
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The Unit 2 reactor trip was initiated by low steam generator level coincident with a
steam flow/feed flow mismatch, as a result of failure of the controller for feed
regulating valve, 1-FRV-210.
The Balance of Plant (BOP) operator, in preparation for a surveillance on steam
generator number
1 level instrument, attempted to place the controller in manual
mode.
The controller face went blank when he touched the face plate.
The failure
of the controller resulted in the feed regulating valve going shut:
The controller, a Taylor Mod 30, was known to be susceptible to electrostatic
discharge effects (see NRC.inspection report 50-315/316-96004
(DRP)).
Beginning in March 1996, problems with electrostatic discharge sensitivity of
Taylor Mod 30 controllers were identified as a result of a controller failure leading to
8 Unit 1 reactor trip. Four other controllers in Units
1 and 2 exhibited similar
sensitivity.
Failure of a controller'in Unit 1 caused
a halt in unit power escalation in
June 1996.
Determination of a root cause was undertaken.
Corrective actions
were enacted to prevent recurrence of the controller failure. The corrective actions
included: increasing control room humidity, instructing operators to ground
themselves
prior to operation of Taylor Mod 30 controllers, installation of static
grounding mats, verification that control room carpeting was anti-static, installation
of ground wires and verifying connection of static drain clips in the controllers.
Some controllers, including the controller for 1-FRV-210, had not yet been modified
to the optimal configuration, because
of the operating status of the unit.
The BOP operator had taken'the required precautions,(grounding
himself against the
control panel, and standing on the static grounding mat), but the controller
exhibited the characteristic electrostatic discharge failure. A violation of Criteria
XVI of 10 CFR Part 50 Appendix B was identified in that inadequate corrective
actions to prevent the reoccurrence of controller failures were taken by the licensee
(50-31 6/97004-02a
(DRP)).
During the post-trip shutdown, the licensee replaced the controller with a controller
modified to be less susceptible to the'effects of electrostatic discharge.
Additional
corrective actions included requiring operators to wear static control heel grounding
assemblies
on their shoes, procurement of low static electricity chairs for the
control room cr'ew,.and directing the operators to ground themselves to bare metal
prior'to touching the controller
faceplate.'he
operators secured the TDAFWP, as allowed by 02-OHP 4023.ES-0.1,
Reactor
Trip Response, to minimize the cooldown of the reactor coolant system.
Steam
generator (S/G) level oscillations near the low-low level TDAFWP start setpoint
generated
a second start signal as S/G levels were being increased during post-trip
9
0
recovery actions.
Procedure
ES-0.1 did not contain guidance for the operators
concerning where to maintain S/G levels in order to avoid a restart of the TDAFWP.
The licensee considered this to be an operator knowledge item, which was covered
during operator training. The quality of the procedure ES-0.1 was not of a type
appropriate to the level of knowledge of the operator. This was a violation of 10 CFR Part 50, Appendix 8, Criterion V (50-315/316/97004-01a
(DRP)).
After the main turbine tripped, the motor for the main turbine. turning gear failed.
The cause for the failure was worn/damaged
bearings which allowed the rotor to
drop down in contact with the stator causing arcing and smoke.
The motor was
replaced and the turbine was placed on the turning gear.
C
An inadequate
procedure was used during a reactor trip recovery activity and
resulted in an inadvertent ESF actuation when the TDAFP was reset too close to
the SG low low level setpoint,
This was considered
a violation.
The failure to implement adequate
corrective actions to prevent the recurrence of a
failure of a'Taylor Mod 30 controller was a violation.
01.5
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Ma erial in
ntainmen
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717
7
On March 11, 1997, the licensee stopped fuel movement operations due to the lack
of a flow path to the emergency core cooling system (ECCS) recirculation sump in
lower containment.
The inspectors performed routine followup to the.licensee's
resolution of the issue
as the inspectors had identified the debris at about the same time as licensee
management.
In addition to the followup, the inspectors reviewed licensee
procedure, OHI-4100,'Outage Technical Advisor Risk Assessment,
Revision 0.
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During a routine containment tour, the inspectors identified a large accumulation of
bagged material in the area directly in front of the grates at the entrance to the
ECCS recirculation sump in lower containment.
The materials consisted of
scaffolding, S/G'eddy current inspection equipment and a large amount of bagged
insulation removed in preparation for S/G inspections.
The licensee had
independently identified that transient material had;been allowed to accumulate and
was in the process of taking action to.remove the material.
'I
OHI-4100 Attachment 3, Inventory - IVlode 68, required maintaining one loop of
residu'al heat removal (RHR) operable with a flowpath from the reactor coolant
system (RCS) and recirculation sump.
As the material in front of the recirculation
sump screens could block water from reaching the sump in the event of a refueling
10
cavity seal failure, the licensee conservatively declared the recirculation sump
inoperable..With the sump inoperable, the licensee entered
a red path for shutdown
risk, which by licensee procedures required immediate compensatory'action.
Core alterations were suspended
in accordance with OHI-4100 while actions were
taken to restore the flowpath. The actions included a concentrated
cleanup effort
which involved restowing and securing items that would float. Plant Manager'
Standing Order (PMSO) 179, Transient Materials in Containment While the Unit is
Shutdown, Revision O,.was issued to provide guidance for control of transient
materials in containment during reactor shutdown conditions.
Core alterations were
restarted after completion of the cleanup.
gJLClliM
I
The licensee took immediate, comprehensive
corrective action to restore and
maintain the flowpath for water to reach the recirculation sump.
The licensee's
safety assessment
had shown that in the event of a loss of coolant accident while
shutdown, the sump was important to maintaining the unit in a safe
shutdown'ondition.
01.6
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of h Lien 'e
rn
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2
a.
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717
7
On March. 16, 1997, the licensee started up the Unit 2 reactor following the reactor
trip. The inspectors observed all or part of the following activities and procedures:
~ ""02-OHP 4021.001.002
- Reactor Start-Up, Revision 18
~ ""02-OHP 4021,001.006
1
~ ""02-OHP 4021.050.001
Power Escalation, Revision 15
Turbine Generator Normal Startup and
Operation, Revision 9
~ 02-OHP 4021.01 3.005
~ 02-OHP 4024.210
Visual Audio Count Rate Channel (NIS),
Revision 4
Annunciator ¹210 Response:
Flux Rod,
. Revision 6
~ ""12 EHP 6040 PER.370
Estimation of Critical Position, Revision
1
~ Technical Data. Book
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The inspectors observed that licensed reactor operators complied w'ith their
procedures and maintained effective command and control during the startup.
The
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inspectors also observed that the operators, were attentive during their pre-job brief
before the pull to criticality. Comments made to the operators by a member of
operations management
concerning repeat backs resulted in significant increase in
the us'e of three point communications.
During a review of the startup procedures
in use, the inspectors'oted
that alarm response
procedure 02-OHP 4024.210
Revision 6, CS-2, Drop 29, listed a deleted technical specification as a reference;
however, this did not affect the actions required by the procedure.
The, unit
supervisor was notified of the discrepancy,
and the procedure was revised.
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The startup following the Unit 2 unplanned reactor trip proceeded well. The
inspectors noted effe'ctive command and control was maintained, communications
were excellent during the pre-job briefing and during the approach to criticality. In
addition, there was a low, manageable
number of personnel present and control
room distractions were minimized.
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Conduct of Maintenance
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Refueling Surveillance, Revision 14
Portions of the following maintenance
job orders, action requests,
and surveillance
activities were observed or reviewed by the inspectors:
~ 01-0HP 4030.STP.037
~ ""12-EHP 4030.STP.229
~ C0040106
~ 01-OHP-4030.STP.026
.
Auxiliary Power Transfer Test Surveillance
Procedure,
Revision 7
Control Room Emergency Ventilation System,
Revision 2
~ "" 01-EHP 4030 STP.2'17B
Diesel Generator
1 AB Load Sequencing
and ESF
Testing, Revision. 3
Fisher V100 Vee-Ball Control Valve
Maintenance,
on 1-IRV-310, using "," 12 MHP
5021.001.102
~
.
~ R0022763
Foreign Material Exclusion (FME), inspection of
.
~ Unit 1 Refueling Water Storage Tank using 12
PMP 2220.001.001
12
~ R0049426
Pressurizer
Pressure Transmitter Calibration,
using "" 01 IHP 6030.IMP.363
~ R0049473
Leak test'of valve 1-ICM-129; using "" 12 EHP
4030.STP.242
~ R0051820
Darling S-350W-SC Swing Check Valve
Maintenance,
on 1-Sl-166-02 using "" 12 MHP
5021.001
~ 1 1 6
b.
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The inspectors found'the work performed under these activities to be generally of
good quality with procedures
present and in use.
Comments for specific work
activities are discussed
in further detail below.
M2
Maintenance and IVlaterlaI Condition of Facilities and Equipment
M21
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sem
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On March 6, 1997, at 3:30 a.m., licensee personnel identified a plexiglass.
rain/snow cover located just below the return air duct to the Unit 2 control room.
This cover had the potential to affect the operability of the Unit 2 control room
emergency ventilation system (CREVS). 'Both trains of the Unit 2 CREVS were
declared inoperable and TS 3.0.3 was entered.
Shortly afterwards the cover was
removed and TS 3.0.3 was exited.
The inspectors performed follow up to the
event.
Licensee documents reviewed, included:
.
~
Condition Report 97-0590
~
Plant Managers. Procedure,
PMP 5020.RTM.001, Revision 0, Restraint of
Transient Material.
~
UFSAR 9.10, Control 'Room, Ve'ntilation System
~
Drawing OP-2-5149-29, Flow Diagram Control Room Ventilation Unit No. 2
~
PMP 5040.MOD.001, Revision 5, Temporary Modification
~
Action Requests C0034756, C0034755, R064539, R064538
13
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Findin
During the routine testing of the Unit 1 engineered safety features actuation
system, the CREVS for both Unit 1 and Unit 2 would actuate as designed.
During
one of the Unit 1 tests, the Unit 2 control room operators observed
a plexiglass
rain/snow cover causing pressure fluctuations in the Unit 2 control room. The
operators observed the cover moving up, partially blocking the return air duct and
then falling away.
As blockage of the return air duct could interfere with the proper operation of the
CREVS, the. operators declared one train of CREVS inoperable.
Shortly thereafter,
discussions with a licensing engineer determined that since the duct was common
to both trains of CREVS, calling both trains of CREVS inoperable would be
appropriate and entry should be made into TS 3.0.3.
The need to enter TS 3.0.3
was.recognized
at 4:10 a.m., the plastic shields were removed, and TS 3.0.3 was
exited at 4:35 a.m.
As required by 10 CFR 50.72 the licensee made a one hour report to. the NRC for
the discovery of a condition outside the design basis for Unit 2. A plastic shield
was also. installed under the Unit 1 return air duct, however it had been restrained
differently than the Unit 2 plastic shield.
Thus, the Unit 1 plastic shield did not
interfere with the proper operation of the Unit 1 CREVS.
The licensee's investigation showed that the shields were installed to prevent snow
from entering the backs of the control room panels.
At the time of installation,
some licensee personnel questioned whether the plastic shields were temporary
modifications.
A review resulted in a licensee determination. that the plastic shields
were not temporary modifications but were housekeeping
items. This
determination was in error as the plastic shields could interfere with the proper
operation of the CREVS.
Even though the plastic shields were not deemed to be temporary modifications,
the personnel who wrote the work instructions recognized the need to restrain the
shields.
Accordirigly, the job orders contained work instructions to fasten the
plastic shields in a manner to prevent them from being sucked up against the inlet
ducts.
This was done for Unit 1 however, the Unit 2 plastic shield was not
properly restrained,
This licensee change to the facility as described in the UFSAR without following
plant procedures governing temporary modifications and without a required written
safety evaluation, which provides the bases for the determination that the change
does not involve an unreviewed safety question is a violation of 10 CFR Part 50.59
(50-31 5/31 6-97004-04(DRP)).
Temporary modifications have been the subject of previous NRC inspection reports.
Reports 50-315/316-96002
and 96014 discussed
examples of poor safety
evaluations.
Report 50-315/316-96011
discussed
a violation for implementing a
change to the facility but not recognizing that it was a temporary modification.'n
14
response to the issues discussed
above, the licensee has spent considerable effort
in training personnel in the understanding
of and the proper 'use of temporary
modifications.
Since these corrective actions have been implemented, the
inspectors have noted a marked increase in the quality and use of temporary
modifications.
C.
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Plastic shields installed in the control room in order to keep snow.out of the backs
of the control panels were not recognized as a temporary modification.
Even
though the licensee has made significant progress in the improvement of temporary
modifications, unrecognized temporary modifications may remain installed in the
plant.
The installation of a temporary modification without the proper evaluations
was a violation.
M3
Maintenance Procedures
and Documentation
M3.1
e
ions Concernin
urveill n e Tes s of h
T rbin
Driven A xiii r
F
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P m
TDAFWP
B
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During a routine review of licensee surveillance tests the insp'actors questioned
whether the TDAFWPs were being tested in accordance with technical specification
requirements.
The inspectors reviewed the licensing basis of the TDAFWPs,
reviewed completed surveillance tests, interviewed licensee personnel,
and held
telephone conferences with NRR p'ersonnel in order to evaluate the licensee's
surveillance procedures for verifying TDAFWP operability.
Documents reviewed by the inspectors included:
~
Design Basis. Document DB-12-AFW, Auxiliary Feedwater System Design
Basis Document
""01(2)-OHP 4030.STP.017T,
Turbine Driven Auxiliary Feedwater System
Test, Revisions 9, 10, and 11.
~
Licensee Technical Specification Clarification 61, Auxiliary Feedwater
System Surveillance Requirements,
dated April 21, 1994
'I
~
Technical Specification Amendments 203 to license number DPR-58 and
188 to license number DPR-74
~
UFSAR'Chapters
14.'1, 14.2; 14.3, and 10.5
~
Licensee letter AEP:NRC:0969AM, Donald C. Cook Nuclear Plant - Unit 1
Pump Inservice Test Program
1.5
rv
ion
nd Findin
Technical Specification (TS) surveillance requirement 4.7.1.2.b stated, in part,
"Each auxiliary feedwater pump shall be demonstrated
OPERABLE when tested
pursuant to Specification 4.0.5 by:... Verifying that the turbine driven'auxiliary
feedwater pumps'eveloped
head at the test flow point is greater than or equal to
the re'quired developed head. when the secondary steam supply pressure
is greater
than 310 psig.
The provisions of Specification 4.0.4 are not applicable for entry
into MODE 3."
The licensee routinely performed the surveillance test at a secohdary side pressure
of between 500 psig and 900 psig.
The inspector's concerns centered
on the
question of whether the licensee was required to perform the surveillance test at
just greater than 310 psig (e.g., 311 psig).
The licensee informed the inspectors that their interpretation of the TS surveillance
requirement differed in that they thought the test could be performed at any
pressure greater than 310 psig.
Since 500 to 900 psig was greater than 310 psig,
the licensee thought that the test was being properly performed.
When questioned
as to the basis for greater than 310 psig the licensee performed a review of the
license basis and determined that there appeared to be no technical justification for
the specific value of 310 psig. The licensee also stated that in 1994, they had
attempted to run the surveillance at 310 psig, but the pump was not capable of full
rated speed, flow, or discharge pressure at such a low secondary side pressure.
The TS surveillance requirement had been changed
on October 17, 1995, by
amendment 203 to the Unit 1 TSs.'he inspectors review of the previous TS
surveillance, requirement identified that it did require a pump discharge pressure
and
flow rate that the TDAFWP was incapable of while at a secondary side pressure of
greater than 310 psig. The licensee disagreed with the inspector's conclusions and
stated that the TDAFWP was never expected to perform at a high discharge
pressure
and flow rate at low secondary side pressures.
'I
NRC,internal discussions confirmed the inspectors'inding that the previous TS
requirements were clear and that the TDAFWP had been required to perform at the
higher rated discharge pressure
arid flows. However, the inspectors review of the
design basis and. licensing basis of the TDAFWP confirmed the licensee's statement
that the TDAFWPs were not taken credit for in any accident analysis at the
secondary side pressure of 310 psig. Therefore, even though the surveillance
procedures
did not meet the previous TS surveillance requirement they did comply
with the present TS surveillance requirements
and at all times had complied with
the licensing basis.
The inspectors identified several other licensee documents which appeared to show
the TDAFWP'was capable of high discharge'pressures
and flows at a low
secondary side pressure.
The licensee stated th'at these statements
were in error
and would be corrected.
16
The ins'pectors completed their assessment
of this issue and had no operability
concerns with the present surveillance*requirements.
The licensee stated that a TS
change request would be submitted to clarify the existing surveillance requirements.
C.
n
i'
A poorl'y worded TS surveillance requirement concerning the turbine driven 'auxiliary "
feedwater pump (TDAFWP) was identified by the inspectors.
The licensee
recognized these problems and agreed to initiate the appropriate TS change
requests.
M4
Maintenance Staff Knowledge and Performance
M4.1
ir IW
n
k
M
ri iin h
R
a
r
I n
V
I
ni
m
n
h
R
r
a.
n
On March.12, 1997, during core off-load, the licensee found spiral wound gasket
material on the bottom nozzles of three fuel assemblies.
Additional material was
found on the lower core plate.
During inspections of the emergency core cooling
systems
(ECCS), spiral wound gasket material was found in accumulator discharge
check valves 1-Sl-166-2 and 1-SI-166-3.
The loop 4 safety injection (Sl) and
residual heat removal (RHR) cold leg check valve, 1-SI-161-L4, also contained a
piece of spiral wound gasket material.
The inspectors followed the licensee's
investigation into the possible sources of the material, the scope of the problem,
and the corrective actions.
In addition, the following documents were reviewed:
~ C0040106
"" 12 MHP'5021;001.102,
Fisher V100 Vee-Ball Control
Valve Maintenance, Revisiori 1, on 1-IRV-310
~ R0022763
12 PMP 2220.001.001,
Foreign Material Exclusion (FME),
Revision 0, inspection of Unit 1 Refueling Water Storage Tank
I
~ R0051820
"" 12 MHP 5021.001.116,
Darling S;350W-SC Swing Check
Valve Maintenance,
Revision 1, on 1-SI-166-02
~
NRC Inspection Report 50-315/316-95010
b.
~
NRC Inspection Report 50-315/316-96002
i n
n
Fin in
The licensee's investigation identified several possible sources of the spiral wound
gasket material which was found in the ECCS'and reactor vessel.
Residual heat
removal (RHR) heat exchanger outlet valves, 1-IRV-310 and 1-IRV-320, each
contained two spiral wound gaskets.
A similar valve, the RHR heat exchange'r
bypass valve, 1-IRV-311, had two earlier spiral wound gasket failures, but its
1'7
gaskets were replaced with compressed
fiber gaskets following the second failure.
These failures were discussed
in NRC Inspection Reports 50-315/316-95010
and
50-315/316-96002,
respectively.
Additionally, the spiral wound gaskets were
found separated
and missing some material on'-QRV-114, the reactor coolant
excess letdown to excess letdown heat exchanger shutoff valve, and 1-NRV-163,
the pressurizer spray control valve.
Both 1-IRV-310 and 1-IRV-320 were inspected,
and approximately 21 total feet of
spiral wound gasket material was missing from these two valves.
Additionally, the
licensee speculated that some spiral wound gasket material may have remained, in
the RHR system from the earlier gasket failures of 1-IRV-311. The loop 4 Sl and
RHR cold leg check valve, 1-SI-161-L4, failed an "as found" leak rate test in Mode
4. Subsequent
inspection of this valve and two other check valves, 1-SI-166-2 and
1-SI-166-3, accumulator discharge check valves, revealed spiral wound gasket
debris in all three. valves.
Additional inspections for spiral wound gasket material
were performed on the refueling water storage tank (RWST), the ECCS suction
header from the RWST, and the lower reactor vessel.
The lower reactor vessel was
found to contain some spiral wound gasket material, but no spiral wound gasket
material was found in either the RWST or the ECCS suction header.'he
failure to
adequately remove the spiral wound gasket material from the RHR system and RCS
was a significant condition adverse to quality in which corrective action was not
taken to prevent recurrence.
This failure was a violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action (50-315/316/97004-02b
(DRP)).
The licensee concluded that any gasket material from 1-QRV-114 was captured in
the excess letdown heat exchanger and did not enter the RCS.
The spiral wound
gasket material missing from 1-NRV-163 was determined to have remained either in
the pressurizer spray line or in the pressurizer due to low flow rates and had not
entered the reactor vessel.
The gasket failures of 1-QRV-114 and 1-NRV-163 are
discussed
in section M4.2;
An operability evaluation performed after the second failure of the gasket on 1-IRV-
311 determined that the ECCS systems.remafned
operable, even with some
material left in the system.
This operability evaluation discussed
pump operability
and fuel damage potential from spiral wound gasket material; however, it did not
address
ECCS valve operability. The failure to address
ECCS valve operability is an
Unresolved Item (50-315/97004-06
(DRP)) pending the'esults of the ECCS testing
and evaluation of check valve operability.
/
/
k
The licensee conducted flushes of the RHR 'and connected
ECCS systems in order
to dislodge any spiral wound gasket material in the piping and collect it in the
defueled reactor vessel for removal.
The licensee planned to perform an additional
test of the ECgS pressure isolation valves prior to returning Unit 1 to full power.
'I
The licensee failed to adequately'remove
the spiral wound gasket material from the
RHR system following the second spiral wound'gasket failure on 1-IRV-311,
18
h'l,
'f
/
II
identified on January 31, 1996, resulting in this material entering several
components in the RHR system and also entering the reactor coolant system.
This
failure constituted a violation.
The failure to address check valve operability is an.unresolve'd
item pending the
results of the ECCS testing and evaluation of check valve operability.
M4 2
i
in
r
n 1-NRV-1
n
1- RV-114
i
1
a.
I
i n
27
On March.11, 1997, during refurbishment of valve 1-QRV-114, the reactor coolant
excess letdown to excess letdown heat exchanger shutoff valve, the spiral wound
cage gasket was found to be separated
and broken in pieces.
On March 13, 1997,
during disassembly for corrective maintenance
on valve 1-NRV-163, the pressurizer
spray control valve, the spiral wound cage gasket was found to be damaged with
some material missing.
Both valves were found to be missing cage spacers,
an
internal valve part designed, in part, to compress the cage gasket. The evaluation of
the missing gasket material is discussed
above in section M4.1. The inspectors
followed the licensee's corrective actions and reviewed the following documents:
~ ""12 MHP 5021.001.126
Copes-Vulcan Bellows Seal Control Valve
Maintenance,,Revision
1
~ ""12 MHP 5021.001.057
.
Copes-Vulcan Isolation Valve Maintenance,
Revision
1
~ R0020879
~ R0020974
Refurbishment of 1-NRV-163 during the Unit 1
1995.refueling outage
Refurbishment of 1-QRV-114 during the Unit 1
1994 refueling outage
b.
b
rv
i n
n
Fin in
The licensee's investigation into the missing cage spacer identified previous
refurbishments in 1994 for 1-QRV-114 and in 1995 for 1-NRV-1'63 as the most
likely times when the cage spacer was not installed.
The licensee stated that the
missing cage spacer was the most likely reason that 1-NRV-163 was inoperable
during all of the most recent fuel cycle. The licensee also stated that the missing
cage spacer on 1-QRV-114 was got noticed earlier because the valve was
infrequently operated.
Step 7.3.2 of ""12 MHP 5021.001.126,
Copes-Vulcan Bellows Seal Control Valve
Maintenance,
Revision 1, required tha't the cage spacer be installed during valve
reassembly.
Step 6.3.2 of "" 1.2 MHP 5021.001.057,
Copes-Vulcan Isolation
Valve Maintenance, also required that the cage spacer be installed during valve
19
t
reassembly.
Job Order Activity(JOA) R0020879 required the use of "" 12 MHP
5021.001.126,
and JOA R0020974 required the use of ""12 MHP 5021.001.057.
In both cases,
a valve contractor performed the maintenance work. The licensee
speculated that the contract workers may not have been familiar with Copes-Vulcan
valves.
The failure to install the cage spacers after refurbishing'-QRV-114 and 1-
NRV-163 were two cases of contractor personnel failing to follow procedure.
The
failure to follow procedure "" 12 MHP 5021.001.057 was one example of a
violation (50-315/97004-01c
(DRP)). The failure to follow procedure "" 12 MHP
5021.001.126 was another example of a violation (50-315/97004-01d
(DRP)).
For
the current refueling outage, the licensee used a different valve contractor than was
used dunng the earlier valve refurbishments.
The valves were reassembled,
all of the parts were installed, and.successfully
tested.
Two mock up Copes-Vulcan valves for training on proper disassembly and
reassembly. were obtained, and the licensee planned to revise the procedures to
more 'clearly state how these valves are to be reassembled.
nl in
The failure to install the cage spacers after refurbishing 1-QRV-114 and'1-NRV-163
were two examples of contractor personnel failing to follow procedure.
These
failures were two examples of a violation for failure to follow procedures..
M4.3
F rei nM
rialEx
I
i nPr
i
ni
1
a.
n
'
27
On March 23, 1997, during core barrel former bolt work in Unit 1 containment, the
inspectors observed contractor; personnel working in a foreign material exclusion
zone.
The contractors were'reparing
a camera for use in machining prior to
installation of:a new former bolt. After the inspectors left the area, they reviewed
the licensee's
procedures concerning FME and developed questions concerning
procedural adherence.
4
The inspectors reviewed licensee procedure 12 PMP.2220.001.001,
Foreign
Material Exclusion, Revision 0.
b.
b
rv
i n
n
Fin in
The contractor'echnicians
prepared
a camera assembly by attaching two camera
modules and a light to a frame.
The work was performed in the area directly
adjacent to the refueling cavity near the location of the core barrel. This area had
been established
as a Foreign Material Exclusion Zone (FMEZ) in accordance with
PMI 2220, Foreign Material Exclusion.
12 PMP 2220.001.001,
Foreign Material Exclusion, step 5.2.7 required, in part,
that light hand tools be secured to the person using them by a lanyard or, tagline.
20
l
> II
The technicians used tools such as open end wrenches, needle-nosed
pliers and
lock-wire pliers to attach and captivate the assembly.
Each of the tools used had
an attached lanyard to secure the tool to the person.
In several instances, the
inspectors observed that the person using the tool did not attach the lanyard to his
arm while the tool was in use.
The inspector's subsequent
review of the licensee's
procedures
led to the questioning of this practice.
12 PMP 2220.001.001,
Foreign Material Exclusion, step 5.2.8 required in part, that
tools shall not be left laying loose within the FMEZ. All such tools shall be
.
restrained in an appropriate manner to prevent their introduction into any open
equipment or system.
The workers used the temporary bridge over the cavity.as
their tool laydown area.
When a tool was needed, the technician would obtain it
from the laydown are'a.
In several instances, the inspectors observed that tools
were left loose on the tarp covering the work area instead of returned to the
laydown area.
The inspector's subsequent
review of the licensee's
procedures
led
to also questioning this practice.
Licensee senior management
had performed tours of the turbine and auxiliary
buildings and upper and lower containment on each shift for the entire outage.
Their post-tour observations reviewed by'the inspectors, repeatedly stated that
worke'rs 'needed to clean up their areas.
Licensee management
informed the
inspectors that FME awareness
and compliance were not at the level desired.
These failures to follow procedures were an example of a violation of Technical Specification 6.8.1. (50-315/97004-.01b
(DRP)).
ncl
i n
The technicians working within the.FMEZ next to the refueling cavity did not
consistently apply the practices established to keep foreign material out of open
systems.
The failure to follow FME procedures was a violation.
E1
Conduct of Engineering
During the resident inspection activities, routine observations were conducted in the
areas of engineering using Inspection Procedure 37551.
Engineering personnel
were observed,to promptly respond to plant issues and to perform good
evaluations.
E2
Engineering Support of Facilities and Equipment
E2.1
D m
FI
-
T
R
ir
ForEnvir nm
n
I
lifi
i n
fEI
ri
I
Wir
B
h
i
The electrical penetrations for containment are located below the calculated
containment flood-up level following a loss of coolant accident (LOCA). Because
safety related cables had not been qualified for submergence
in water, they were
contained inside, stainless steel tubes which provide a barrier 'between the cable and
the water in containment during postulated post-accident conditions.
The licensee had previously identified some moisture in a flood-up tube.
As a
'esult,
the licensee had made an internal commitment to inspect about one-third of
the flood-up tubes in each unit during the. next three refueling outages.
Inspection
of flood-up tubes in Unit 1, was performed in March, 1997.
The inspection
revealed some'tubes with moisture but also identified cracks, flaws, or arc strikes
in nine tubes. 'hese flaws would provide a pathway for water to enter the tubes
following a postulated accident.
A condition report was initiated an'd the equipment
associated with these flood-up tubes was declared inoperable.
Licensee personnel
decided to evaluate the actual operability of Unit 1 equipment after performing an
immediate inspection of Unit 2 for flawed flood-up tubes.
The licensee conservatively decided to perform an inspection of flood-up tubes in
Unit 2,'instead of waiting for its next scheduled refueling outage.
Th'e inspection
was performed on March 23, 1997 and identified cracks in two tubes.'
condition
report was initiated and the equipm'ent associated with these flood-up tubes was
declared inoperable.
The power cable for containment recirculation fan 2-HV-CEQ-1 was located in one
of the cracked tubes.
Operability of the fan could not be guaranteed with water in
the tube after a LOCA. The licensee could not determine when the cracks
developed in the tube; but believed that the flaws in the tubes in both units h'ad
been present since the tubes were originally installed.
This meant that the flaws
had been present for many years and that the equipment had been inoperable for
many years.
The licensee made a one hour notification to the NRC in accordance with 10 CFR 50.72(b)(1)(ii)(A) for Unit 2 once this condition was identified. This was due to the
other train of containment recirculation fan being inoperable for maintenance
periodically in the past.
This meant that periodically both trains of recirculation fans
were inoperable.
This necessitated
an entry into TS 3.0.3 due to Unit 2 being in an
However, the licensee did not also report that the
inoperability of.2-HV-CEQ-1 exceeded the allowable outage time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> as
specified in the action statement of Tet;hnical Specification 3.6.5.6, which also
would have placed the Unit in TS 3.0.3.. This failure to report under this additional
reporting requirement was minor in nature as the condition had already been
reported.
I
The inspectors also identified a violation,of 10 CFR 50.72(b)(2)(i) reportability
requirements for Unit 1. The licensee had the same information available for Unit 1
that was available'or Unit 2. Unit 2 equipment was declared inoperable and a
timely report to.the NRC was made, however, the licensee failed to make a timely
report for equipment identified after the inspection in Unit 1. The required report to
22
the NRC for Unit 1 was made at 1205 on March 27, 1997, following the inspectors
notification to the licensee that the failure to report was a violation (50-315/97004-
03'(DRP)).
Environmental qualification of equipment is necessary to ensure equipment will
perform its intended function when exposed to the environment- resulting from
postulated accidents.
Flood-up tubes perform an environmental qualification
function for electrical conductors not qualified for submergence
in water after a
LOCA. The licensee was still evaluating what flood-up tubes were affected and
what effects tube cracking had on e'quipment operability.
The environmental
qualification of equipment associated with cracked flood-up tubes is an unresolved
issue (50-31 5/31 6-97004-07(DRP)).
The licensee conservatively expanded the scope of their inspection to Unit 2 after
identifying cracks in Unit 1 flood-up tubes.
Following the identification of flaws in
two Unit 2 flood-up tubes, the licensee declared the affected equipment inoperable
and made a required report to the NRC.
The environmental qualification of.equipment associated with cracked flood-up
tubes was an unresolved'issue.
A violation was identified when the licensee failed
to make a timely report to the NRC concerning equipment that had been identified
as inoperable due to the cracked flood-up tubes in Unit 1.
E3
Engineering Procedures
and Documentation
E3.1
fi
i
nrlfr
in
f h
nrlR
V
il
i
a.
In
i n
7
1
During the follow-up to a regional request for information the inspectors questioned
the control of the test boundary for the CREVS. The inspectors interviewed
licensee personnel and reviewed the licensee's testing procedure, ""12-EHP
4030.STP.229,
Revision 2, Control Room Emergency Ventilation System.
b.
rv
i n
n
Fin
During routine follow-up to a regional request for information the inspectors began
questioning the control of the test bouridary for the CREVS. The inspectors
observed that the status of the auxiliary building emergency exhaust system
(referred to as the AES fans) was not controlled during testing of the CREVS.
/
The control room pressure envelope included an opening to the control room cable
vault. The cable vault directly communicates with the auxiliary building ventilation
23
(
f 'I
t f
fl
system.
Even though the cable vault door was closed with a hatch, the inspectors
were concerned that enough air could flow between the rooms that the cable vault
could reduce the positive pressure
in the control room.
During routine plant operations only one AES fan is operating,'however,
following a
safety injection signal all AES fans operate.
This significantly changes the negative
pressure
in the auxiliary building which could reduce the positive pressure
in the
control room.
The licensee's
CREVS test procedure did not address the status of
the AES fans.
Thus during most testing, only'one AES fan was operating.
Following the inspectors'concerns
with the testing configuration, the licens'ee
performed a test of the.CREVS with all AES fans operating.
No difference could be
observed in the CREVS positive pressure between one AES fan and all AES fans
operating.
Subsequently,
the licensee initiated a procedure change to add the AES
fan.configuration to the testing procedure.
C.
nl in
The inspectors identified questions concerning the licensee's testing procedure for
the control room emergency ventilation system.
After promptly performing a test
to verify there were no operability concerns the licensee initiated a procedure
change request in order to better control the test configuration.
R1
Radiological Protection and Chemistry Controls (71750)
During the resident inspection activities, routine observations were conducted in the
areas of radiological proteqtion and chemistry controls using Inspection Procedure 71750.
No discrepancies
were noted.
S1
Conduct of Se'curity and Safeguards Activities (71750)
During normal resident. inspection activities, routine observations were conducted in
the areas of security and safeguards activities using Inspection Procedure 71750.
No discrepancies
were noted.
F1
X1
Control of Fire Protection Activities (71750)
During normal resident inspection activities, routine observations
w'ere conducted in
the area of fire protection activities using Inspection Procedure 71750.
No
discrepancies
were noted.
Exit Meeting
The inspectors presented the inspection results to members of the licensee
management at the conclusion of the inspection on March 29, 1997.
The licensee
requested additional information on several of the findings presented.
24
I
, There was considerable discussion between the NRC inspectors and the
licensee personnel present concerning Section M3.1, "Questions Concerning
Surveillance Tests of the Turbine Driven Auxiliary Feedwater Pump."
Specifically, licensee personnel disagreed with the NRC position that the
previous TS surveillance required that the TDAFWP be able to achieve 700
gpm at full discharge pressure with any secondary side steam pressure of
greater than 310 psig (e.g., 311 psig).
Licensee personnel stated that the
TDAFWPs were not required to. provide full flow at SG pressures
below 550
psig.
The inspectors stated that it was the NRC's position that the. previous
TS surveillance requirement did require full rated flow at 310 psig SG
pressure.
Licensee personnel stated that they would agree to disagree.
~
During discussions concerning the licensee's failure to report following the
identification of flawed Unit 1 flood-up tubes, the inspectors stated that it
appeared that the licensee had not recognized the need to make a report.
In
response,
licensee personnel stated that they had been.evaluating
the need
to report but had been slow in reaching a conclusion.
PARTIAL LIST OF PERSONS CONTACTED
¹IVI. Ackerman, Manager Nuclear Licensing
¹J. Allard, Maintenance Superintendent
¹G. Arent, Operations Procedure Supervisor
¹K. Baker, Manager Production Engineering
¹P. Barrett, Director Performance Assurance
¹A. Blind, Site Vice President
¹S. Brewer, Manager Regulatory Affairs
¹M. Depuydt, Licensing Coordinator
¹S: Farlow, Supervisor
I&C Engineering
¹M. Finissi, Supervisor Electrical Systems.
¹R. Gillespie, Operations Superintendent.
¹C. Golden, System Engineer
¹D. Hafer, Manager Plant Engineering
¹S. Hodge, Manager Work Control
.
¹J. Kobyra, Manager Nuclear Engineering
¹D. Londot, Environmental
¹D. Loope, Training Manager
¹A. Lotfi,'Performance
Engineer
¹D. Morey, Chemistry Superintendent
¹D. Noble, Radiation Protection Superinteiident
¹F. Pisarsky, Supervisor, Component Engineering
¹T. Postlewait, Site Engineering Support Manager
¹T. Quaka, Project Management 5 Inst. Services
¹P.'ussell,
Plant Protection Superintendent
¹J. Sampson,
Plant Manager
~
¹P. Schoepf, Manager Safety-Related Systems
25
C
0
¹L. Smart, Licensing Coordinator
¹D. Spencer, Performance Engineering'
¹M. Stark, Supervisor Performance Testing
.
¹A. Verteramo, Supervisor Reactor Engineering
¹J. Wiebe, Manager Engineering and Analysis
¹Denotes those present at.the March 27, 1997 exit meeting.
26
C
'NSPECTION PROCEDURES USED
IP 60710
IP 62703
IP 71750
On-site Engineenng
Refueling Outage
Surveillance Observations
Maintenance Observation
Plant Operations
Plant Support Activities
ITEMS OPENED and CLOSED
Qggnnn.
50-316/97004-01 a(DRP)
Inadequate
Procedure resulted in
Inadvertent ESF Actuation
50-31 5/97004-01 b(DR P)
50-31 5/97004-01c,d(DRP)
50-315/316/97004-02a(DRP)
50-31 5/31 6/97004-02b(DR
P)
Failure to Follow Procedures
(FME
Practices)
Failure to Follow Procedures
(Missing
Cage Spacers)
Failure to Implement Adequate Corrective
Action (Taylor Mod 30 Controller Failure)
Failure to Implement Adequate Corrective
Action (Spiral Wound Gasket Material in
RCS)
50-31 5/97004-03(DR
P)
50-31 5/31 6/97004(DRP)
50-31 5/97004-05(DR
P)
50-31 5/97004-06(DR
P)
50-31 5/31 6-97004-07(DR
P)
GhmC
None
Failure to Make Timely 50.72 Report
. Failure to Perform 50.59 Evaluation
(Ventilation Catch Basin in CR Panels)
DEV
Overpower Chart Recorder Pen
Inoperability
Failure to Address Check Valve
Operability
Environmental Qualification of Equipment
Associated with Cracked Flood-up Tubes
27
l
AEP
CFR.
CR
FMEZ
gpm
JOA
LER
MHP
NRC
OHP
PMI
PMSO
Pslg
S/G
TDAFWP
TS
US
List of Acronyms
American Electric Power
Action Request
Balance of Plant
Code of Federal Regulations
Condition Report
Control Room Emergency Ventilation System
Division of Reactor Projects
Engineered Safety Features
Foreign Material Exclusion Zone
gallons per minute
Job Order Activity
Licensee Event Report
Loss of Coolant Accident
Motor Driven Auxiliary Feedwater Pump
Maintenance Head Instruction
Maintenance Head Procedure
Nuclear Regulatory Commission
Operations Head Procedure
Public Document Room
Plant IVlanager's Instruction
Plant'Manager's
Procedure
Plant Managers Standing Order
Pounds per Square Inch Gage
Regulatory Guide
Reactor Operator
Refueling Water Storage Tank
Safety Injection
Shift Supervisor.
Turbine Driven Auxiliary Feedwater Pump
Technical Specification
Updated Final Safety Analysis Report
Unit Supervisor
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