ML17059B443
| ML17059B443 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 02/21/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17059B441 | List: |
| References | |
| 50-220-96-14, 50-410-96-14, NUDOCS 9703050278 | |
| Download: ML17059B443 (54) | |
See also: IR 05000220/1996014
Text
U.S. NUCLEAR REGULATORY COMIVIISSION
REGION I
Docket/Report Nos.:
50-220/96-14
50-410/96-14
License Nos.:
NPF-69
Licensee:
Niagara Mohawk Power Corporation
P. O. Bex 63
Lycomihg, NY 13093
Facility:
Nine Mile Point, Units
1 and 2
Location:
Scribe, New York
Dates:
December 1, 1996- January
11, 1997
Inspectors:
B. S. Norris, Senior Resident Inspector
T. A. Beltz, Resident Inspector
R. A. Skokowski, Resident In'spector
Approved by:
Lawrence T. Doerflein, Chief
Projects Branch
1
Division of Reactor Projects
9703050278
97022i
ADOCK 05000220
8
4
TABLE OF CONTENTS
page
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EXECUTIVE SUMMARY ........................................~.
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SUMMARY OF ACTIVITIES
Nia'gara Mohawk Power Corporation (NMPC) Activities ...-.............
Nuclear Regulatory Commission (NRC) "Staff Activities
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I ~ OPERATIONS
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Conduct of Operations .'.....,...............
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01.1'eneral
Comments
01.2
Unit 2 Power Reduction for Feed Water Pump Exchange ..
01.3
Unit 2 Missed UFSAR-Required
CRD Housing Support Gap
Inspections .............................,....
07
Quality Assurance
in Operations ................'........
07.1
Unit 1 Housekeeping
08
Miscellaneous Operations Issues........................
08.1
(Open)
LER 50-220/96-11:
Reactor Scram Caused
by the
Main Generator Lockout Relay Trip
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II. MAINTENANCE ..........................:.....
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M1
Conduct of Maintenance
M1.1
General Comments
M1.2
Unit 1 Liquid Poison Pump and Check Valve Operability
il
Surveillance Test
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M1.3
Maintenance
Rule Evaluation of Unit 2 NonSafety-Related
Switchgear-003...................,...........
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III. ENGINEERING...'......... ~...............
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E2
Engineering Support of Facilities and Equipment.......... ~....
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E2.1
Hot Shorts Vulnerability of Unit 2 Shutdown Cooling Valves ..
E2.2
Potential Overpressurization
Concerns
Relative to NRC Generic
96 06
etter 96 06 .. ~... ~..... ~.....
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E8
Miscellaneous
Engineering
Issues
E8.1
(Closed)
LER 50-220/96-09:
Potential Overstressed
Pipe
Supports. Caused by Design Deficiency
E8.2
(Closed)
Special Report:
Inoperability of Unit 1 ¹11
Containment Hydrogen Monitoring System
E8.3
(Closed) URI 50-220/95-25-01:
Emergency Cooling System
Material Deficiencies '................. ~.... ~.....
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E8.4
(Closed)
URI 50-410/95-12-01:
Temporary Scaffolding
Erected Around Unit 2 Liquid Poison Tank for Extended
Period
with no Engineering Evaluation ...,.... ~.......... ~...
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Table of Contents (cont'd)
IV. PLANT SUPPORT
R4
Staff Knowledge and Performance
in Radiological Protection......
R4.1
Repeat Failure to Properly Secure
a Unit 1 High Radiation Area
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V. MANAGEMENTMEETINGS
X1
Exit Meeting Summary.... ~.......................
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X3
Management
Meeting Summary
ATTACHMENT
17
18
18
'19
19
19
Attachment 1-
PARTIALLIST OF PERSONS CONTACTED
INSPECTION PROCEDURES USED
ITEMS OPENEO, CLOSED, AND UPDATED
LIST OF ACRONYMS USED
EXECUTIVE SUMMARY
Nine Mile Point Units 1 and 2
50-220/96-14
8c 50-410/96-14
December 1, 1996 - January 11, 1997
This integrated inspection report includes reviews of licensee operations,
engineering,
maintenance,
and plant support.
The report covers
a 6-week period of resident inspection.
PLANT OPERATIONS
. The December 5, 1996, power reduction at Unit 2 to exchange
operating feedwater pumps
was completed
in accordance
with approved procedures.
The pre-evolution briefing
contained
an appropriate
level of detail for the plant conditions, and discussions
by the
~ operators indicated a thorough understanding
of the upcoming evolution.
t
The licensee demonstrated
good safety perspective
by shutting down Unit 2 upon
identification of the missed Updated Final Safety Analysis Report (UFSAR) required control
rod drive (CRD) housing support gap verifications.
The licensee's inspection revealed
out-'f-tolerance
gaps on 19 of 185 CRDs.
Their engineering supporting analysis, which
determined that the out-of-tolerance gaps did not affect the operability of the system, was
considered technically sound by the inspectors.
Subsequent
changes to the applicable
procedure
appear adequate to ensure the future gap verification.
However, the failure to
completed the UFSAR-required gap verifications was classified as,a Non-Cited Violation.
The inspectors identified an open polyethylene
bag adjacent to the Unit
1 spent fuel pool
that was not properly controlled with respect to foreign material exclusion accountability
due to inattention by personnel.
This was classified as a Non-Cited Violation.
At Unit 1, the inspectors identified several examples of improperly stored ladders.
The
recurring failure to appropriately store and/or secure ladders located near safety-related
and
other important equipment was considered
a weakness.
MAINTENANCE
Unit
1 Operations Department conducted
a liquid poison system quarterly surveillance in a
controlled manner.
Coordination and communications
between Operations
and lnservice
Testing (IST) personnel were very good.
Operations
and IST personnel
knowledge
regarding the evolution was good.
The test data was complete and received
a timely
review.
Unit 2 appropriately included the non-safety-related
electrical switchgears within the scope
of the Maintenance
Rule, and evaluated the risk associated
with on-line maintenance
for
'the switchgear.
IV
Executive Summary (cont'd)
ENGINEERING
Niagara Mohawk Power Corporation (NMPC) notified the Nuclear Regulatory Commission
(NRC) that Unit 2 may have operated
outside its design basis due to the potential for a 10 CFR 50, Appendix R, fire-induced hot short condition that could result in damage to three
shutdown cooling valves.
The licensee took appropriate immediate corrective actions to
address the concern.
NMPC appropriately notified the NRC of potential conditions outside design basis identified
during their review of Generic Letter (GL) 96-06.
The licensee's review identified several
. drywell penetrations
at both units that could potentially exceed the design pressure
during
an accident due to thermal expansion of entrapped
water.
The operability determinations
were adequate
and in accordance
with the guidance provided in GL 96-06; the operability
.
determinations for the Unit 1 core spray high point vent and post-accident
sampling lines
were particularly appropriate
and conservative.
The licensee issued
a voluntary Licensee Event Report concerning potential overstressed
pipe supports for the reactor building closed-loop cooling system.
The supports could
become overstressed
due to.thermally induced longitudinal expansion.
The root cause
evaluation and corrective actions were appropriate.
NMPC evaluation and corrective actions to NRC-identified emergency cooling system
discrepancies
appeared
appropriate.
However, the licensee's failure to implement the
existing technical guidance to ensure adequate
valve packing gland nut thread engagement
was classified as a Non-Cited Violation.
The failure to follow plant procedures
resulted in the installation of temporary scaffolding
around the Unit 2 standby liquid.control (SLC) syste'm tank for an extended
period without
proper engineering
analysis.
This was classified as a Non-Cited Violation.
PLANT SUPPORT
On two occasions,
the inspectors identified the same high radiation area access gate to be
unlocked.
The corrective actions to the first occurrence were ineffective, and the
inspectors considered this a recurring failure of procedural adherence.
(VIO 96-14-03)
REPORT DETAILS
Nine Mile Point Units 1 and 2
50-220/96-14
8L 50-410/96-14
December 1, 1996 - January 11, 1997
SUMMARYOF ACTIVITIES
Niagara Mohawk Power Corporation (NMPC) Activities
Unit 1
Nine Mile Point Unit 1 (Unit 1) started the inspection period at full power.
On December
24, Unit 1 experienced
a failure of ¹11 circulating water pump.
This resulted in a
reduction of power to 78% for approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
Full power operation resumed
and
continued to the end of the report period.
Unit 2
Nine Mile Point Unit 2 (Unit 2) started. the inspection period at full power.
On December 5,
power at Unit 2 was reduced to approximately 55% to support
a feed water pump (FWP)
exbhange.
Unit 2 was returned to full power 38 hou'rs later.
On December 19, Unit 2
conducted
a reactor shutdown to perform control rod drive (CRD) housing support gap
inspections.
The reactor was started up on December 23, and the unit achieved full power
on December 26. The unit maintained essentially full power for the remainder of the
inspection period.
Or anizational Chan
es
On December 1, 1996, Messrs. Martin McCormick and Carl Terry exchanged
responsibilities within the Nine Mile Point nucleai organization.
Mr. McCormick became the
Vice President - Nuclear Engineering
and Mr. Terry became the Vice President - Nuclear
Safety Assessment
and Support.
Nuclear Regulatory Commission (NRC) Staff Activities
Ins ection Activities
The NRC conducted
inspection activities during normal, backshift, and deep backshift
hours.
The results are contained in the applicable sections of this report.
U dated Final Safet
Anal sis Re ort
UFSAR Reviews
A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR
description highlighted the need for additional verification that licensees were complying
with UFSAR commitments,
While performing the inspections discussed
in this report, the
inspectors reviewed the applicable portions of the UFSAR related to the areas inspected.
The inspectors verified that, with the exception of the Unit 2 CRD housing support gap
inspections described
in Section 01.3, the UFSAR wording was consistent with the
observed plant practices, procedures
and/or parameters.
2
I. OPERATIONS
01
Conduct of Operations (71707)
'1,1
General Comments
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
In general, the conduct of operations was professional
and safety-conscious;
specific events and noteworthy observations
are detailed in
the sections below.
01.2
Unit 2 Power Reduction for Feed Water Pum
Exchan
e
a.
Ins ection Sco
e
On December 5, 1996, a planned power reduction of the Unit 2 reactor was
completed to allow the B FWP to be removed from service due to excessive
seal
leakage.
The inspectors observed
portions of the power reduction because
the B
reactor recirculation system
(RCS) pump was experiencing
higher than normal
tfibration that could have been aggravated
during the evolution,
In addition to
observing the power reduction, the inspectors observed the pre-evolution briefing,
and reviewed applicable plant procedures.
b.
Observations
and Findin s
The inspectors observed
portions of the Unit 2 power redu'ction completed on
December 5, 1996.
Power was lowered to remove the B FWP from service
because
of excessive
seal leakage.
Control rods were inserted until power was
reduced to 90%, then reactor recirculation flow was decreased
until power reached
55%.
The power reduction was preformed in accordance
with approved
Procedure
N2-OP-101D, "Power Changes,"
Revision 3.
The inspectors observed the reactivity manipulation pre-evolution briefing provided
to the crew performing the reactor recirculation flow decrease.
This briefing was
completed in accordance
with Procedure
N2-ODP-OPS-0110, "Reactivity
Management
Program," Revision 7. Since the B RCS pump was experiencing
higher
than normal vibration, which could be aggravated
during the flow decrease,
the
briefing included a review of the emergency downpower actions.
During the
briefing, discussions
by the operators indicated their understanding
of the upcoming
evolution.
Before the power reduction, the RCS pump vibrations were higher than
normal but within the manufacturer's
limits. Before and during the power reduction,
NMPC monitored and trended additional parameters for indication of pump
degradation;
no indications of RCS pump degradation
were observed.
Topical headings such as 01, MS, etc., are used In accordance withthe NRC standardized reactor inspection report
outline.'ndividual
reports are not expected to address
all outline topics.
The NRC inspection manual procedure
or temporary
Instruction that was used as inspection guidance Is listed for each applicable report section.
3
w
During the evolution, management
oversight was provided by the Operations
Manager, who was present in the control room during a majority of the power
reduction.
The power reduction was completed without incident, and Unit 2 was
returned to full power on December 7.
C.
Conclusion
The December 5, 1996, power reduction at Unit 2 for the removal of the B FWP
was completed in accordance
with approved procedures.
The pre-evolution briefing
was thorough, with an appropriate
level of detail for the plant conditions; discussion
by the operators indicated a thorough understanding
of the upcoming evolution.
01.3
Unit 2 Missed UFSAR-Re uired CRD Housin
Su
ort Ga
Ins ections
a I
Ins ection Sco
e
On December 19, the licensee commenced
a shutdown of Unit 2'from 100%
power, as required by technical specification (TS) 3.1.3.8, due to a failure to
perform an UFSAR-required gap inspection of the CRD housing supports (commonly
referred to as>the "shoot-out steel" ). Unit 2 was shutdown and the required
inspections were completed; adjustments
were made to restore the CRD housing
support gap back within specification; and Unit 2 was subsequently
restarted.
The inspectors reviewed the applicable deviation event/reports
(DERs), engineering
supporting analysis, UFSAR sections, TS and plant procedures.
The inspectors also
observed portions of the plant shutdown; visually inspected the CRD housing
support; and reviewed the gap inspection results.
b.. Observations
and Findin s
n
As part of the corrective actions associated
with a previous event, NMPC was
conducting
a review of the UFSAR to validate that necessary
programs and
procedures'were
in place
The review identified that the UFSAR requirement to
inspect the CRD housing support after reinstallation, with particular attention to
maintaining the correct gap between the CRD flange and the housing support, was
not contained in the Unit 2 procedures;
and thus, had not been performed since
initial startup.
The CRD housing supports prevent a significant nuclear transient in the event a
drive housing breaks or separates
from the bottom of the reactor vessel
~ Unit 2 TS 4.1.3.8, "Control Rod Drive Housing Support," requires
a visual inspection to
ensure that the CRD housing support is in place following disassembly.
However,
UFSAR Section 4.6.3.2 states:
"When the support structure is reinstalled, it is
inspected for correct assembly with particular attention to maintaining the correct
gap between the CRD flange lower contact surface and the grid." The gap, as
described
in the UFSAR, Section 4.6.1.2.3, is approximately 1-inch between the
contact surface of the CRD flange and the support grid. This gap allows the CRD
housing support to accomplish its intended function, while providing sufficient
0
clearance to prevent contact stresses
caused by theimal expansion.
Although the
TS-required visual inspections of the CRD support housing were being performed,
the gap w'as not verified to be acceptable.
On December 19, 1996, while Unit 2 was operating at 100% power, NMPC notified
the NRC in accordance
with Title 10 of the Code of Federal Regulations
(CFR),
Part 50.72, that a shutdown of Unit 2 had commenced
in accordance
with TS 3.1.3.8, due to a failure to perform a UFSAR-required inspection.
The failure to
perform the required gap inspections placed the unit in a potentially unanalyzed
condition.
The inspectors observed portions of the plant shutdown and determined
it to be performed in accordance
with Procedure
N2-OP-101C, "Plant Shutdown,"
Revision 11.
While shutdown, the licensee inspected the CRD housing support gap in accordance
with Work Order (WO) 96-16814-00.
They identified that 19 of the 185 CRDs had
gaps that were slightly outside the vendor
recommended
tolerance of 1 inch 2
0.12 inches.
The smallest measured
gap was 0.828 inches, and the largest gap
was 1.190 inches.
The gaps on all CRDs were adjusted back within tolerance.
Unit 2 was restarted on December 23 and the unit achieved full power on
December 26.
Subsequent
to the plant restart, the licensee completed
an
engineering
analysis and determined that the CRD housing support had always been
This analysis was supported
by General Electric (GE) analysis, and
evaluated both extremes of the as-found inspection results.
Specifically, the largest
gap would not have resulted in an impact load on the housing support that would
exceed the allowable stress.
Therefore, the support would have prevented
any
significant nuclear transient in the event a drive housing broke or separated
from the
bottom of the reactor vessel.
Additionally', the smallest gap still provided sufficient
clearance to prevent contact stresses
caused by thermal expansion.
The licensee
changed
Procedure
N2-MMP-RDS-670, "CRD Support Steel Removal 5 Installation,"
'evision
02, to ensure proper gap verification'would be performed in the future.
The inspectors performed an independent
visual inspection of the CRD housing
support.
The inspe'ctor also reviewed the method used by the licensee to verify the
gap between'the
CRD and the housing support.
No concerns. were identified. The
inspectors'also
reviewed the NMPC engineeiing analysis and the GE supporting
analysis and considered them technically sound.
However, the failure to include the
UFSAR-required CRD housing support gap verification in plant procedures
is a
violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures,
and
Drawings."
This licensee-identified
and corrected violation is being treated as a
Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.
The Unit 1 UFSAR also refers to a 1-inch gap for the CRD support housing;
however, no verification was required.
Previous maintenance
activities at Unit 1
had not required adjustment of the CRD housing support nuts (the nuts used to set
the gap); therefore, NMPC determined that the original gap was maintained.
After
the end of this inspection period, Unit 1 inspected the CRD housing support gaps
during Forced Outage 97-01 (January
17 through 19, 1997).
All gaps were found
within tolerance.
Unit 1 was still evaluating changes to their procedures to ensure
future gap verification.
C.
Conclusion
07
Upon identification of the missed UFSAR-required CRD housing support gap
verification, NMPC shut down Unit 2. The licensee demonstrated
a good safety
perspective
by shutting down the unit instead of attempting to perform an
engineering
evaluation to justify continued operation. 'he licensee's
inspection
revealed out-of-tolerance
gaps on 19 of 185 CRDs.
Their engineering
analysis,
which determined that the out-of-tolerance
gaps did not affect the operability of the
system, was considered technically sound,
Subsequent
changes to the applicable
procedure were adequate to ensure the future gap verification.
Quality Assurance in Operations (71707, 40500)
07.1
Unit 1 Housekee
in
at
Ins ection Sco
e
hc
On November 29, 1996, the inspectors toured Unit 1 reactor and turbine buildings.
Several housekeeping
discrepancies
were identified. The inspectors reviewed the
applicable plant procedures
and discussed
the issues with the Station Shift
Supervisor (SSS) and Unit 1 management.
b.
Observations
and Findin s
Inade uate Control of Forei
n Material Exclusion
FME Areas on the Refuel Floor
During a tour of the Unit 1 refuel floor, the inspectors noted
a large yellow
polyethylene
(poly) bag located approximately one foot from the edge of the spent
fuel pool (SFP).
FME controls were in effect surrounding the SFP.
The bag was
open and contained smaller yellow bags, tags, and trash.
There was no indication
that any contents of the bag fell into the SFP.
No activity was in progress
on the
refuel floor. However, recent activities included new fuel inspection and movement
of n'w fuel bundles into the SFP.
At the time, the area surrounding the SFP was being controlled as a Level 2
cleanliness
local work zone and posted as such.
An FME Material Accountability
Log was present on the refuel floor. The inspectors reviewed the log for the area
surrounding the SFP; however, no log entry for the bag was identified.
The
inspectors informed an operator performing rounds of the poly bag, who then
notified radiation protection
(RP) personnel
and the SSS.
RP directed the operator
to remove the bag and contents from within the FME boundary.
The inspectors discussed
the concern with the Reactor Engineering Supervisor.
The
supervisor stated that the bag originated from work on the refueling bridge.
The
bag had been appropriately recorded
in the Material Accountability Log for. the
0
refueling bridge, and logged out upon removal
~ The inspectors confirmed the log
entries.
The technician who removed the bag from the refueling bridge, however,
placed it within the FME boundary for the SFP area, without logging the bag into
that area.
Although the area surrounding the SFP was conspicuously
posted, the
technician stated he was unaware of this area being FME controlled.
NMPC Procedure
GAP-HSC-02, "Local Work Zones and System Cleanliness
Controls," Revision 05, establishes
administrative controls for maintaining local
work zones.
Section 3 4.3 of GAP-HSC-02 requires
a Material Accountability Log
,to ensure material accountability within Level 1, 2 and 3 work zones.
Plant
management
re-emphasized
the importance of FME controls with the staff.
However, the failure to adhere to Procedure
GAP-HSC-02 is a violation of TS 6.8.1
regarding procedures.
This failure constitutes
a violation of minor'significance and
is being treated as a Non-Cited Violation, consistent with Section IV of the NRC
Re etitive Occurrence of Unsecured
Ladders Ad'acent to Safet -Related
E ui ment
Unsecured
ladders have been occasionally identified in both units by NRC
inspectors.
In Unit 1, the inspectors discovered unsecured
10-foot A-frame ladders
adjacent to safety-related
components,
such as hydraulic control units and scram
discharge volume vent and drain valves (on August 28, 1996) and containment
spray pump ¹121 (on October 2, 1996).
On November 14, 1996, the inspectors
identified an unsecured
ladder adjacent to the operating feedwater pump.
Although
not safety-related, the feedwater pumps are used for high pressure coolant
injection. The ladders were not in use at the time of discovery, nor. did it appear that
any activity had recently taken place.
On November 29, 1996, the inspectors observed
a 10-foot A-frame ladder adjacent
to the ¹15 reactor recirculation pump (RRP) motor generator
(MG) set.
Although
the RRP MG set is not safety-related,
damage to the MG set would potentially result
in an unanticipated
plant transient.
The inspectors discussed
the issue with the SSS and Plant Manager.
In each case,
actions were taken by the licensee to secure the ladders.
Conclusions
Due to personnel inattention to postings, material accountability controls were
violated on the Unit 1 refuel floor in that an open poly bag was left inside the FME
area arou'nd the SFP.
Also, after use, ladders were occasionally left unsecured
in
the vicinity of safety-related
and other important equipment.
The ladders falling
could potentially render necessary
emergency equipment unavailable or cause
a
plant transient.
The licensee took appropriate corrective action for the
. discrepancies
identified during this inspection.
The above examples were identified by the NRC. The recurring failure to properly
store material is indicative of weak management
oversight with respect to housekeeping.
t
,
7
08
Miscellaneous Operations Issues (90712)
/
0~.1
0 en
LER 50-220 96-11:
Reactor Scram Caused
b
the Main Generator Lockout
~Rela
Tri
The inspectors reviewed the subject Licensee Event Report (LER) and determined
that it satisfactorily described the event.
However, the assessment
of the root
cause analysis and corrective actions will remain open pending the enforcement
conference
related to the reactor overfill event associated
with the reactor scram.
A detailed. review of the issues detailed in this LER is contained
in NRC Inspection
Report 50-220/96-13, Section 02.3.
II. MAINTENANCE
'1
Conduct of Maintenance (61726, 62707)
M1.1
General Comments
/
Using NRC Inspection Procedures
61726 and 62707, the inspectors periodically
'bserved the licensee perform plant maintenance
activities and conduct various
surveillance tests.
In general, maintenance
and surveillance activities were
conducted
professionally, with the WOs and necessary
proceduies
in use at the
work site, and with the appropriate focus on safety.
Specific activities and
- observations
are detailed below.
The inspectors reviewed procedures
and/or
observed
portions of the following maintenance/surveillance
activities:
~ WO-93-31 1 9-00
~ N2-EPM-GEN-5Y555
~ N1-ST-Q8
~ N1-OP-12
~ N1-ST-M1
~ N1-0DP-IIT-01 01
~ N1-0DP-IIT-01 02
~ N1-ITP-01
~ N1-ITP-02
~ N2-MMP-RDS-670
Repair parallel interlock
GE 13.8 kV [kilo-Volt]'Magna-Blast Breaker and
Associated Motors
. Liquid Poison Pump and Check Valve Operability Test
Liquid Poison Sy'tem
Liquid Poison Pumps Operability Test
Establishment of IST [Inservice Testing] Pump and
Valve Acceptance Criteria
Analysis and Trending of IST Results
Ultrasonic. Flow Test
Vibration Measurement
CRD Support Steel Removal 5 Installation
Surveillance activities are Included under "Maintenance."
For exampie, a section involving surveillance observations might
be Included as a separate sub-topic under M1, "Conduct of Maintenance."
8
Unit 1 Li uid Poison Pum
and Check Valve 0 erabilit
Surveillance Test
!ns ection Sco
e
On December 30, 1996, Unit
1 Operations
and Inservice Test (IST) personnel
performed
a quarterly surveillance test of the liquid poison system to verify the
operability of the pumps and associated
discharge check valves.
The inspectors
reviewed applicable licensee procedures
and TSs; observed equipment setup and
testing for one train of,the system; reviewed completed surveillance tests
conducted within the last year; and discussed
the surveillance test results with the
Assistant SSS (ASSS) and IST Supervisor.
Observations
and Findin s
The inspectors observed the surveillance test locally in the reactor building.
Face-
to-face and remote communications were very good and the transfer of information
. went well ~ The inspectors noted good control of'valve manipulations,
and
independent
verifications were adequately performed.
Operator knowledge
regarding certain procedural steps and anticipated system response
appeared
adequate.
The IST technician appeared
very knowledgeable with respect to test
equipment installation and operation.
All test equipment was within current
calibration cycle.
The inspectors verified proper system restoration upon completion
of the surveillance test.
The inspectors reviewed the completed surveillance test procedure.
The test results
received a timely review and evaluation by the ASSS.
The recorded data was
complete and within allowable specification.'owever,
the licensee identified that
one vibrational data point on pump ¹12 was in the "Alert Range."
Although the
pump was still operable,
an increased surveillance'requency
was instituted, in
accordance with NMPC Procedure
N1-ODP-IIT-0101, based upon American Society
of Mechanical Engineers
Code,Section XI requirements.
The inspectors reviewed prior surveillances
and noted that liquid, poison pump ¹12
had exhibited similar vibration in July 1996.
Since July however, the pump
vibrational data had been in the acceptable
range.and
was taken off an increased
surveillance frequency in November 1996, in accordance
with the plant procedure.
The inspectors discussed
the ¹12 liquid porson pump vibration issue with the IST
supervisor, who stated that a definitive cause for the vibration was not known at
this time.
Conclusions
The inspectors observed
a quarterly surveillance test of the Unit 1 liquid poison
system; overall, the inspectors determined that the test was conducted
in a well
controlled manner.
Coordination and communications
between Operations and IST
personnel were very good.
Personnel
knowledge regarding the surveillance was
also good.
The surveillance test data received
a timely review.
Higher than normal
t
c
9
vibration identified on one pump was appropriately trended; although
a definitive
cause
had not yet been determined.
M1.3
Maintenance
Rule Evaluation of Unit 2 NonSafet -Related Switch ear-003
a.
Ins ection Sco
e
The inspectors observed
Unit 2 operators transfer a nonsafety-related
switchgear
(2NPS-SWG003) to the alternate power source in preparation for preventive and
corrective maintenance.
The inspectors evaluated the on-line maintenance
activities
with respect to the Unit 2 Maintenance
Rule Procedures.
The inspectors reviewed
portions of applicable plant procedures,
the WO and holdouts.
(A holdout is a
component tagging process
used to provide protection for personnel
and/or
equipment during operation, maintenance
and modification activities, which is
commonly referred to as tagout within the industry.)
b.
Observations
and Findin s
On January 3, 1997, Unit 2 performed preventive and corrective maintenance
on
circuit breaker 2NPS-SWG003-14, the 13.8 kilovolt (kV) normal feed to nonsafety-
related switchgear 2NPS-SWG003.
Switchgear SWG003 provides power to large
balance-of-plant
loads, including one FWP, three circulating water pumps,
a
condensate
pump and a booster pump, and several nonsafety-related
load centers.
Loss of this equipment could potentially result in a plant scram.
The inspectors observed the pre-evolution brief, and considered the review of
operator actions in the event of a loss of switchgear SWG003 to be appropriate.
The inspectors observed the transfer of switchgear SWG003 to its alternate power
source.
The transfer was completed in accordance
with Procedure
N2-OP-71A,
"13.8 kV AC [Alternating Current] Power Distribution," Revision 2. The WO and
holdout were developed
and approved
in accordance
with the appropriate
procedures.
After maintenance
was completed, switchgear SWG003 was returned
to its normal power source.
Discussions with the SSS indicated appropriate precautions were taken during the
preparation of the holdouts.
The inspectors verified that switchgear SWG003 was
appropriately contained
in the scope of Maintenance
Rule (10 CFR 50.65) and
controlled by Unit 2 Procedure
N2-MRM-REL-0104, "Maintenance
Rule Scope,"
Revision 00.
Discussions with the SSS indicated that Unit 2 appropriately evaluated
the risk associated
with the transfer for switchgear SWG003.
c.
Conclusion
Unit 2 appropriately included nonsafety-related
switchgear SWG003 within the
scope of the Maintenance
Rule, and evaluated the risk associated, with on-line
maintenance
for the switchgear.
t
~
10
III. ENGINEERING
E2
Engineering Suppo< of Facilities and Equipment (37551, 40500)
E2.1
Hot Shorts Vulnerabilit
of Unit 2 Shutdown Coolin
Valves
a0
Ins ection Sco
e
On December 17, 1996, NMPC notified the NRC that Unit 2 was potentially outside
the design basis for 10 CFR Part 50, Appendix R, with respect to shutdown cooling.
A hot short condition could have caused motor operated valves (MOVs) in the
.
residUal heat removal (RHR) system to be driven closed and mechanically damaged,
preventing remote shutdown capability.
The inspectors reviewed the applicable
DER, engineering supporting analysis, and NRC Information Notice 92-18, "Potential
for Loss of Remote Shutdown Capability during a Control Room Fire," and discussed
the issue with the Unit 2 design engineering
and operations staff. The inspectors
-also assessed
the adequacy of the licensee's short term corrective actions.
b.
Observations
and Findin s
During review of a Unit 1 issue related to Appendix R fire-induced hot shorts in
MOVs, NMPC design engineering staff discovered
a similar concern at Unit 2.
In
particular, several MOVs were susceptible to mechanical damage if the hot short
bypassed
the torque switch causing spurious operation and a valve stall condition.
The concern was applicable to 32 of 45 MOVs that would be controlled at the
remote shutdown panel during a control room fire, Appendix R shutdown.
Of the
32 susceptible
MOVs, 28 were part of redundant trains.
Thus, failure of one
redundant MOV would not prevent remote shutdown capability.
However, four
MOVs were determined not to have adequate
redundancy.
The four valves (2RHS" MOV112, 113, 142, and 149) determined to be susceptible
were documented
on DER 2-96-3379, and the licensee made a 1-hour notification
to the NRC in accordance with 10 CFR 50.72.
As. part of their immediate corrective
actions, NMPC closed three of the valves (RHS" MOV112, 142 and 149) and
disconnected
the valves from the power supply such that a control room fire could
not damage these valves and disable. the safe shutdown function.
The fourth valve
(RHS" MOV113) is normally closed and de-energized
to preclude
a fire-induced loss-
of-coolant accident (LOCA) at the high/low pressure interface location.
MOVs 112 and 113 are isolation valves in the RHR suction path for the shutdown
cooling mode, and are required for plant cold shutdown from the control room or
the remote shutdown panel.
MOVs 142 and 149, RHR discharge to radiological
waste isolation valves, are required'to be operable from the remote shutdown panel
prior to and after initiation of RHR system shutdown cooling mode to flush the
stagnant water in the shutdown cooling piping.
Valves
RHS "MOV112, 142, and 149 are normally closed.
Procedural controls were
established,
through the use of a holdout, to preclude spurious operation of the
r
11
valves and possible mechanical damage.
The inspectors verified that the valves
were deenergized,
and that the appropriate procedural controls were in place.
This
remains an unresolved
item pending the completion of the licensee's
analysis and
subsequent
NRC review.
(URI 50-410/96-14-01)
c.
Conclusions
The licensee's identification and immediate corrective actions to address three
shutdown cooling valves potentially susceptible to damage during a 10 CFR 50
Appendix R fire-induced hot short condition were appropriate.
E2.2
Potential Over ressurization
Concerns
Relative to NRC Generic Letter 96-06
a.
Ins ection Sco
e
~ NMPC engineering staff's preliminary evaluations of NRC Generic Letter (GL) 96-06,
"Assurance of Equipment Operability and Containment Integrity during Design-Basis
Accident Conditions," identified specific piping that could potentially be
overpressurized
during a design-basis
LOCA. The overpressure
conditions could
result in piping exceeding the allowable stresses
in several systems; the following
drywell penetrations
have been identified by NMPC:
~ core spray high point vent lines (Unit 1)
~ post-accident
sampling line (Unit 1)
~ shutdown cooling system lines (Unit 1)
~ drywell equipment and floor drain lines (Unit 1)
~ drywell unit cooler lines (Unit 2)
~ reactor recirculation pump seal cooler lines (Unit 2)
As a result, NMPC determined that both units were potentially outside the design
basis and notified the NRC in accordance
with 10 CFR 50.72., To determine the
adequacy of the licensee's
immediate corrective actions, the inspectors reviewed
the applicable DERs, engineering supporting analyses
and GL 96-06, and discussed
the concerns with NMPC engineering
and operations
personnel.
b.
Observations
and Findin s
Unit 1
Unit 1 engineering staff determined that the core spray (CS) high point vent lines
and the post-accident
sampling (PAS) line could potentially overpressurize
and
exceed allowable stresses
during a design basis'OCA.
During a design basis
LOCA, the potential existed for water trapped between the containment isolation
valves (CIVs) to heat up and thermally expand, to the point where piping integrity
was not assured.
On December 13, 1996, NMPC notified the NRC, in accordance
with 10 CFR 50.72, that Unit 1 was potentially in a condition outside the design basis.
~
~
12
additionally'issued
DER 1-96-3350 to internally document the concern.
considered
both the CS and PAS systems operable, through use of administrative
controls.
Specially, the piping between the CIVs for both systems was drained
every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to maintain an adequate
expansion volume.
NMPC determined that following a postulated
design basis LOCA, the thermal
expansion of the fluid'trapped between the normally closed shutdown cooling.(SDC)
CIVs could potentially result in internal pressure
exceeding
allowable stresses.
The
fluid temperatures
within the SDC piping penetrations
were "hot" as a result of
valve seat and packing leakage.
NMPC's preliminary engineering
evaluation
determined that the already elevated'fluid temperature would reduce the net thermal
expansion
during a design basis LOCA, such that the peak pressure was within the
design basis rating for the pipe.
NMPC design engineering
analyses identified potential overpressure
concerns
associated
with the lines for the drywell equipment drains (DWED) and drywell floor
drains (DWFD). The DWED and DWFD inside and outside CIVs were normally open
and the piping not normally filled with water.
However, the piping would contain
water during pump-down oper'ations.
During the design basis LOCA, the CIVs
would automatically close and could potentially trap water between the CIVs.
Thermal expansion of the trapped fluid could potentially exceed allowable internal
stresses
for the pipes.
Based on the design of the DWED and DWFD outboard
CIVs, NMPC preliminarily determined that the valve disc would unseat at
approximately 150 pounds per square inch (psi), thus providing pressure
relief to
maintain the piping within design basis pressure.
P
On December 20, 1996, NMPC notified the NRC, in accordance
with 10 CFR 50.72, that Unit 1 was potentially in a condition outside the design basis.
issued
DER 1-96-3419 to internally document the concern.
Both the SDC and
DWED/DWFD systems were. considered
operable based upon present system
configuration.
The potential overpressure
conditions identified at Unit 1 during the licensee's
review of GL 96-06 remains an unresolved item pending the completion of the
.
NMPC's.evaluation to determine if this condition was outside the design basis and
subsequent
NRC review.
(URI 50-220/96-14-02)
Unit 2
NMPC identified four penetrations
at Unit 2 that could potentially exceed the design
pressure
during an accident due to thermal expansion of entrapped water between
the inboard and outboard CIVs. The penetrations
allow reactor building closed loop
cooling (RBCLC) water to flow into and out of the drywell for drywell unit coolers
and reactor recirculation pump seal coolers.
NMPC documented
the concern in DER
2-96-3427.
On December 20, 1996, NMPC notified the NRC on the condition in
accordance
with 10 CFR 50.72.
13
The engineering
supporting analysis associated
with the DER 2-96-3427 based
continued operability of the equipment on projected valve leakage.
With leakage
considered,
the calculated maximum pressure
expected
during thermal expansion
would not exceed the allowed pressures.
The inspectors reviewed the engineering
analysis and deemed the basis for operability to be consistent with guidance
provided in GL 96-06.
However, this item remains unresolved
pending the
completion of NMPC's evaluation to determine ifthis condition was outside the
design basis and subsequent
NRC review.
(URI 50-410/96-14-02)
C.
Conclusions
NMPC appropriately notified the NRC in accordance
with 10 CFR 50.72 of potential
conditions outside design basis identified during their review of GL 96-06.
The
licensee's review identified several drywell penetrations
at both units that could
potentially exceed the design pressure
during an accident due to thermal expansion
of entrapped
water.
The inspectors determined that the operability determinations
were adequate
and in accordance
with the guidance provided in GL 96-06.
The
operability determinations for the Unit 1 CS high point vent and PAS lines were
particularly appropriate
and conservative.
Miscellaneous Engineering Issues (90712, 92700, 92903)
E8.1
Closed
LER 50-220 96-09:
Potential Overstressed
Pi
e Su
orts Caused
b
Desi
n Deficienc
Ins ection Sco
e
The inspectors reviewed the Unit 1 voluntary LER related to the potential for reactor
building closed loop cooling (RBCLC) system pipe supports within containment to be
overstressed
in the event of a LOCA coincident with a loss of offsite power (LOOP).
The inspectors discussed
the issue and conclusions with Unit 1 Engineering
management
and staff, and evaluated the licensee's root cause determination and
corrective actions.
b.
Observations
and Findin s
On October 21, 1996, during the review of an engineering
analysis related to the
RBCLC system pipe supports,
Unit 1 plant management
determined that the
supports within containment could be overstressed
in the 'event of a LOCA
coincident with a LOOP. The deficiency was identified as the result of an
engineering
evaluation performed in response to similar industry operating
experience
(a LER issued by Haddam Neck Nuclear Station on July 22, 1996).
The
performance of the engineering
evaluation appeared
prudent.
The licensee determined that, in the event of a LOCA with a LOOP, the temperature
of the RBCLC water and piping within containment could increase before power and
flow were restored, resulting in thermally induced longitudinal expansion
and
potential overstressing
and failure of some U-bolt supports.
Ho'wever, the licensee
determined that this deficiency did not result in a significant safety concern as the
piping would remain intact and operable even considering
a subsequent
seismic
event.
The licensee also determined that the plant was not in a condition outside
the design basis.
Particularly, the engineering evaluation determined that the design
basis load combinations for RBCLC, as described
in the UFSAR, did not address
accident loads because
the system was not safety-related.
However, good
engineering practice would have included the accident loads, particularly thermal
stresses
resulting from accident conditions.
The licensee evaluated the RBCLC piping inside containment and identified thirteen
8-inch piping supports
and thirteen 4-inch piping supports requiring modification.
Work requests for repair and/or modification were generated
and added to the work
scope for Refueling Outage
(RFO) 14, scheduled for March 1997.
The inspectors discussed
the LER with the Engineering Manager and a structural
engineer.
NMPC issued the voluntary LER due to the generic implications of the
situation, which was similar'to that discussed
in GL 96-06.
The L'ER satisfactorily
described the event.
The causes
and the corrective actions are detailed and
appropriate.
The inspectors
had no further questions.
c.
Conclusions
The licensee'performed
an engineering evaluation of Unit 1 in response to industry
operating experience
and determined that RBCLC system pipe supports within
containment could be overstressed
in the event of a LOCA coincident with a LOOP;
performance of the engineering
evaluation appeared
warranted and prudent.
The
root cause evaluation and corrective actions to prevent similar occurrence
were
appropriate.
E8.2
Closed
S ecial Re ort:
Ino erabilit
of Unit 1 ¹11 Containment
H dro en
Monitorin
S stem
On November 14, 1996, with Unit 1 operating at 100% reactor power, ¹11
Containment Hydrogen Monitoring System (HMS) was removed from service for
calibration.
During the calibration, a toggle switch failed, delaying completion of the
surveillance until the switch was replaced.
The ¹12 HMS was operable
and in
calibration.
The ¹11 HMS was returned to an operable status on November 16
following toggle switch replacement
and system calibration.
NMPC initiated DER 1-96-3100 to evaluate the toggle switch failure and to
determined corrective actions.
NMPC concluded that frequent use of the toggle
switch resulted in mechanical failure. The toggle switch was a momentary contact,
spring return switch, actuated extensively during monthly calibrations, and did not
impact the safety-related function of the system.
The inspectors'iscussion
with
the system engineer indicated that the associated
toggle switches were recently
installed as part of a modification during RFO13 in 1995.
E
15
Within the past year, numerous toggle switches of this type have failed and were
subsequently
replaced.
NMPC was evaluating the availability of replacement
switches of different design.
NMPC will continue to monitor toggle switch
performance
and replace failed switches, as required.
The licensee found a different
design switch which was being evaluated
as a replacement; they intend to replace
the balance of the switches in the near future.
In addition, NMPC is reviewing the
repetitive failures of the toggle switches for possible 10 CFR 21 reporting
consideration.
NMPC submitted
a special report to the NRC within 14 days, as required by Unit 1
TS 3.6.11-1, Action Statement Table 3.6.11-2 (4a).
The inspectors reviewed the
special report and confirmed that all required information was provided.
Closed
URI 50-220 95-25-81:
Emer enc
Coolin
S stem Material Deficiencies
Ins ection Sco
e
In January 1996, NRC resident inspectors performed
a walkdown of all accessible
areas of the Unit '1 emergency cooling (EC) system and identified two material
condition concerns.
Specifically, several
EC system drain valve packing gland nuts
appeared
to have insufficient thread engagement;
and secondly, supports for the
fire water header connection to the ¹11 EC makeup tank appeared to exceed the
maximum allowable span between supports permitted by NMPC internal standards.
0
The inspectors reviewed the licensee
DERs to assess
corrective actions and
discussed
the results with members of the engineering staff.
Observations
and Findin s
Packin
Gland Nut Thread En
a ement
NMPC documented
the packing gland nut thread engagement
issue on DER 1-96-
0130.
NMPC Standard
Design Specification Procedure,
SDS-006, "Bolt-Torque
Requirements for Unit 1 and Unit 2," Revision 1, provided general guidance for
'hread
engagement.
However, in practice, NMPC did not apply this requirement to
packing gland nuts, even though there was no exception stated within the
procedure.
Maintenance staff were trained to adjust packing so that a valve could
be operated without binding and no packing leakage existed.
NMPC stated that
vendor manuals could be used as guidance, but most vendor manuals did not
specifically address
packing gland nut thread engagement.
Procedure SDS-006, Section 6.1.C, stated that " ..
~ the minimum thread
engagement
for a fastener will be one thread beyond the top of the nut,... [and
that for] any fasteners that do'not obtain thread engagement
greater than one
thread beyond the top of the nut, approval by design engineering
is required."
The
failure to follow Procedure SDS-006, is a violation of TS 6.8.1 regarding procedural
adherence.
This failure constitutes
a violation of minor significance and is being
16
treated as a Non-Cited Violation, consistent with Section IV of the NRC
NMPC discussed
the packing gland thread engagement
concern with vendors and
other licensees,
and concluded that good maintenance
practice was to ensure
one
thread visible beyond the nut.
SDS-006 was revised to reinforce compliance with
Section 6.1.C. with respect to packing gland nut thread engagement.
Packing
gland nuts currently with insufficient thread engagement
were to be evaluated for
operability on a case-by-case
basis.
Fire Water Header Pi in
Su
orts to ¹11 EC Makeu
Tank
gl
C.
NMPC issued
DER 1-96-0102 to document the potential operability concern
regarding the lack of fire water header piping supports to ¹11
EC makeup tank.
Design Engineering determined that the supports for ¹11
EC makeup tank fire water
supply were adequate for the applied loading and for system operability; however,
a
support was added mid-span as a system enhancement.
The inspectors verified the
support installation and that the engineering drawing represented
the current plant
configuration.
Conclusions
NMPC evaluation and corrective actions to NRC-identified EC system discrepancies
appeared
appropriate..However,
the failure to implement technical guidance to
ensure adequate
valve packing gland nut thread engagement
was a violation of
procedures.
Closed
URI 50-410 95-12-01:
Tem orar
Scaffoldin
Erected Around Unit 2
Li uid Poison Tank for Extended
Period with no En'neerin
Evaluation
ar
Ins ection Sco
e
In April 1995, during an inspection of the Unit 2 reactor building, the inspectors
identified that the temporary scaffolding around the standby liquid control (SLC)
storage tank did not appear to have been inspected recently.
In addition, the
inspectors questioned
whether an engineering
analysis had been performed
considering the potential safety risk associated
with temporary scaffolding near
safety-related
equipment.
The. Unit 2 Independent
Safety Engineering Group (ISEG)
initiated an investigation after the inspectors
raised the concern.
b.
Observations
and Fihdin s
The inspectors reviewed the associated
ISEG report, dated May 15, 1995.
The
report identified that the attached scaffold tag (¹93-231) indicated the scaffold had
been erected or last inspected sometime in 1993.
Also, ISEG noted that no analysis
had ever been performed.
Scaffold Procedure
N2-MAP-MAI-0301, required an
evaluation of scaffolds in safety-related
areas that were installed for greater than
~
'
17
60 days.
The ISEG report stated that the scaffold was scheduled to be replaced
with a permanent structure by August 31, 1995, in accordance
with a simple
design change
(SDC 2-0398-91).
The ISEG concluded that the engineering
evaluation should have been performed when it was recognized that the scaffold
was to be installed for long term.
The licensee initiated a DER (2-95-2093) after the NRC identified the issue.
determined the root cause to be a combination of factors:
inadequate
procedure
adherence;
engineering judgement used in lieu of calculation; management
did not
budget resources
after approving the design change;
and engineering
did not
properly disposition
a May 1992 DER (2-92-2132).,
DER 2-95-2093 also noted that
a modification was requested
in September
1986 to install a permanent
ladder and
platform over the SLC tank, and that the temporary scaffolding was initially installed
in September
1989.
Immediate corrective actions included a seismic evaluation of the scaffolding until
the permanent structure could be installed.
NMPC reviewed all iristalled scaffolds
and identified two others that exceeded
the 60-day requirement;
one at Unit 1 and
another at Unit 2. Both were evaluated for seismic considerations
and found
acceptable.
Actions to preclude recurrence included a review of the associated
maintenance
and engineering procedures,
and emphasis
on procedural adherence.
The inspectors verified that the scaffolding around the SLC tank had been replaced
with a permanent
ladder and work platform.
However, the failure to perform
evaluations of scaffolding erected for greater than 60 days is a violatio'n of Unit 2
Procedure N2-MAP-MAI-0301, Section 5:5.1b.
This failure constitutes
a violation
of minor significance and is being treated as a Non-Cited Violation, consistent with
Section IV of the NRC Enforcement Policy.
c.
Conclusion
The failure to follow plant procedures
resulted in the installation of temporary
scaffolding'around the Unit 2 SLC tank for an extended
period without proper
engineering
analysis.
IV. PLANT SUPPORT
using Inspection Procedure 71750, the inspectors routinely monitored the
performance of activities related to the areas of radiological controls, chemistry,
s'ecurity, and fire protection.
Minor deficiencies were
discussed with the appropriate management,
significant observations
are detailed
below,
4
0
0'
18
Staff Knowledge and Performance in Radiological Protection (71750)
Re eat Failure to Pro erl
Secure
a Unit 1 Hi h Radiation Area Gate
Ins ection Sco
e
At the end of the previous inspection period, the inspectors toured the Unit 1
turbine building and identified that the gate to the turbine deck, a posted high
radiation area, was unlatched.
The inspectors continued inspection of this issue
during this inspection period.
The issue was discussed
with the SSS,
supervision, the Operations Manager, and the Plant Manager.
Observations
and Findin s
On November 29, 1996, the inspectors identified that on the 300 foot elevation. of
the turbine building, the east gate to the turbine deck was not properly latched
and locked, allowing access to the turbine deck and adlacent reheater rooms,
During power operations, the gates to the turbine deck are normally locked and
posted
as "High Radiation Areas." RP and the SSS were notified and the gate was
subsequentlpshut
and latched.
NMPC initiated DER.1-96-3217 to address the
issue.
Reactor power at the time was 100%.
Subsequent
radiation surveys
indicated the highest localized radiation levels (measured
at 30 centimeters) were
approximately 300 millirem/hour (mrem/hr) on the turbine deck and 800 mrem/hr in
the reheater rooms.
The highest on contact readings were 380 mrem/hr and 1000
mrem/hr on the turbine deck and in the reheater rooms, respectively.
Previously, on September
17, 1996, the inspectors identified the same gate not
properly latched and locked.
Subsequently,
and only following further discussion
with the inspectors,
NMPC initiated DER 1-96-2301
on September
27 to address
the issue.
NMPC noted the apparent
cause
as inadequate
work practices,
in that
personnel failed to verify gate closure.
The corrective actions were to (1) counsel
shift personnel with regard to ensuring lockable barriers remained latched, and (2)
repair the gate, which had considerable
"play" and was known to not always latch
upon closure:
The Plant Manager and RP Manager informed the inspectors that the gate being
unlatched did not meet their expectations.
The inspectors
noted that corrective
actions to the September
17 event were ineffective, in that personnel
again failed to
verify proper gate latching upon exiting the area.
Subsequent
to the November 29
event, counselling of shift personnel was again conducted.
An already open work
order to repair the "play" in the gate was immediately initiated upon identifying the
repeat event.
NMPC Procedure
GAP-RPP-08, "Control of High, Locked High, and Very High
Radiation Areas," Revision 03, Section 3.1.3 states that "~.. when practicable, High
Radiation Areas should be locked."
Additionally, Section 3.6.1 requires personnel
to maintain positive access control to High, Locked High, and Very High Radiation
Areas.
The procedure specified that barriers are to remain closed and locked after
t
0'
19
each entry, and that the barriers be checked closed by shaking.
The failure to
ensure that the east gate to the Unit 1 turbine deck, a posted High Radiation Area,
remained locked was not in accordance
with Procedure
GAP-RPP-08 and is a
violation of Unit 1 TS 6.11.
TS 6.11 requires that written procedures
be approved,
maintained and adhered to for all operations involving personnel
radiation exposure.
(VIO 50-220/96-14-03)
c.
Conclusions
On two occasions,
the inspectors identified the same high radiation area access
gate to be unlocked.
The inspectors considered this a recurring failure of procedural
adherence
and attention to detail.
Furthermore, the corrective actions to the first
occurrence were ineffective.
V. MANAGEMENTMEETINGS
X1
Exit Meeting Summary
At periodic intervals, and at the conclusion of the inspection period, meetings were
held with senior station management to discuss the scope and findings of this
inspection,
The final exit meeting occurred on January 27, 1997.
Based on the
NRC Region
I review of this report, and discussions
'with NMPC representatives,
it
was determined that this report does not contain safeguards
or proprietary
information.
X3
Management Meeting Summary
On January 6, 1997, a meeting between the NRC and NMPC management
was held
at the NRC headquarters.
This meeting was requested
by NMPC to present their
bases for disagreeing with the Level IV violation regarding the failure to report the
condition of the Unit 1 blow out panels being outside the design basis when it was
identified in October 1993 (NRC Inspection Repo'it 50-220/96-05).
Results of this
meeting will be provided to NMPC in a separate
correspondence.
This meeting was
open to the public.
0'
'
ATTACHMENT
PARTIALLIST OF PERSONS CONTACTED
Nia ara Mohawk Power Cor oration
R. Abbott, Vice President & General Manager, Nuclear
J. Aldrich, Maintenance
Manager, Unit 1
M. Balduzzi, Operations Manager, Unit 1
D. Barcomb, Radiation Protection Manager, Unit 2
C. Beckham, Manager, Quality Assurance
.J. Burton, Director, ISEG
G. Correll, Chemistry Manager, Unit 1
J. Conway, Plant Manager, Unit 2
K. Dahlberg, General Manager, Projects
R. Dean, Engineering Manager, Unit.2
A. DeGracia, Work Control & Outage Manager, Unit 1
G. Helker, Work Control & Outage Manager, Unit 2
M. McCormick, Vice President, Nuclear Engineering
L. Pisano, Maintenance
Manager, Unit 2
N. Rademacher,
Plant Manager, Unit 1
R. Smith, Operations Manager, Unit 2 ~
P. Smalley, Radiation Protection Manager, Unit 1
K. Sweet, Technical Support Manager, Unit 1
R. Sylvia, Executive Vice President & Chief Nuclear Officer
C. Terry, Vice President,
Nuclear Safety Assessment
& Support
K. Ward, Technical Support Manager, Unit 2
C. Ware, Chemistry Manager, Unit 2
D. Wolniak, Manager, Licensing
W. Yaeger, Engineering Manager, Unit.1
INSPECTION PROCEDURES USED
- IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 90712:
IP 92700:
IP 92903:
On-Site Engineering
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
" Surveillance Observations
Maintenance
Observation
Plant Operations
Plant Support
In-Office Review of Written Reports of Nonroutine Events at Power
Reactor Facilities
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Followup - Engineering
f
OPENED
50-41 0/96-1 4-01
50-220 5.
50-41 0/96-14-02
50-220/96-14-03
50-220/96-1
1
CLOSED
50-41 0/95-1 2-01
50-220/95-25-01
'0-220/96-09
UPDATED
None
ITEMS OPENED, CLOSED, AND UPDATED
URI,
Hot Shorts Vulnerability of Shutdown Cooling Valves
Potential Overpressurization
Concerns
Relative to NRC Generic Letter 96-06
Repeat Failure to Properly Secure High Radiation Area Gate
LER
Reactor Scram Caused
by the Main Generator Lockout Relay
Tnp
Temporary Scaffolding Erected Around Unit 2 Liquid Poison
Tank for'Extended
Period with no Engineering Evaluation
Emergency Cooling System Material Deficiencies
LER
Potential Overstressed
Pipe Supports Caused
by Design
Deficiency
LIST OF ACRONYMS USED
ASSS
CFR
DER
DWED
DWFD
EC
FWP
GL
HMS
ISEG
kv
LER
mrem/hr
NRC
PAS
ps l
Assistant Station Shift Supervisor
Code of Federal Regulations
Containment Isolation Valve
Control Rod.Drive
Deviation/Event Report
Drywell Equipment Drains
Drywell Floor Drains
Emergency Cooling
Feedwater Pump
Generic Letter
Hydrogen Monitoring System
Independent
Safety Engineering
Group
Inservice Testing
kilo-Volt
Licensee Event Report
Loss of Coolant Accident
Motor Generator
Motor Operated Valve
millirem/hour
Niagara Mohawk Power Corporation
Nuclear Regulatory Commission
Post-Accident Sampling
pounds per square inch
'
RF0
TS
Reactor Building Close Loop Cooling
Reactor Recirculation System
Refueling Outage
Radiation Protection
Spent Fuel Pool
Station Shift Supervisor
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Violation
Work Order