ML17059B312
| ML17059B312 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 10/08/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17059B310 | List: |
| References | |
| 50-220-96-07, 50-220-96-7, 50-410-96-07, 50-410-96-7, NUDOCS 9610150256 | |
| Download: ML17059B312 (68) | |
See also: IR 05000220/1996007
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket/Report Nos.:
50-220/96-07
50-410/96-07
License Nos.:
NPF-69
Licensee:
Niagara Mohawk Power Corporation
P, O. Box 63
Lycoming, NY 13093
Facility:
Nine Mile Point, Units
1 and 2
'ocation:
Scriba, New York
Dates;
June 2, - July 27, 1996
Inspectors:
B. S. Norris, Senior Resident Inspector
T. A. Beltz, Resident Inspector
L. A. Peluso, Radiation Physicist
D. M. Silk, Senior Emergency Preparedness
Specialist
R. A. Skokowski, Resident Inspector
Approved by:
Lawrence T. Doerflein, Chief
Reactor Projects Branch
1
Division of Reactor Projects
96iOi50256 96i008
ADQCK 05000220
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EXECUTIVE SUMMARY
Nine Mile Point Units 1 and 2
50-220/96-07
8E 50-410/96-07
June 2, - July 27, 1996
This integrated inspection report includes reviews of licensee operations,
engineering,
maintenance,
and plant support.
The report covers a 6-week period of resident inspection;
it also includes the results of inspections conducted
by regional inspectors
in the areas of
radiological environmental monitoring and meteorological monitoring, and emergency
preparedness.
The report also contains
a review of the NRC Integrated Performance
Assessment
Process
(IPAP) team inspection report.
During the IPAP report review, the
inspectors identified violations, unresolved
items, and inspection followup items, a
summary of which is provided in Attachment A to this report.
PLANT OPERATIONS
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The Unit 1 operators acted appropriately and completed actions in accordance
with
procedures
during the June 6, 1996, feedwater heater level transient.
The root cause
in the deviation/event report (DER) was accurate,
and appropriately supported.
NMPC's
review to identify potential damage was good, and included structural, fuel, and core
shroud analyses.
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During the review of an October 1994 Unit 2 LER, the inspectors determined that there
were several missed opportunities for the shift management to identify the correct
technical specification (TS) action statement when authorizing concurrent work on
multiple hydraulic control unit accumulators.
In addition, the work control/planning
organization could have aided the operations staff by including the potential plant
impact as part of the work package.
Nonetheless,
once identified, the shift crew took
prompt action to ensure the plant was in compliance with the TS. This was identified
as a non-cited violation.
MAINTENANCE
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In general, maintenance
and surveillance work was conducted
professionally, with the
necessary
procedures
at the work site, and with the appropriate focus on safety.
As
necessary,
the proper radiation protection work practices were implemented.
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The Unit
1 operations
personnel
perform'ed well on all aspects of a routine emergency
diesel generator surveillance, accomplished the evolution without incident, and
appeared to understand
the scope of the surveillance.
Communications between the
operators
in the turbine building and the control room were adequate.
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As a result of corrective actions associated
with earlier LERs, NMPC discovered
additional surveillances that had not been performed as required.
Unit
1 failed to
calibrate one of the instruments for the containment leakage detection system during
the last two refueling outages;
and Unit 2 did not test several valves in the reactor core
0
Executive Summary (cont.)
isolation cooling system prior to reactor system pressure
exceeding
150 psig. The root
causes were different, and each was identified as a non-cited violation.
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Unit 2 maintenance
technicians performed receipt inspections of new fuel appropriately
and in accordance
with the procedure.
Storage and handling activities associated
with
the shipping crates and the fuel assemblies
on the refuel floor were verified to be in
accordance
with licensing conditions.
ENGINEERING
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The check valves for the service water system to the unit cooler in the Unit 2 high
pressure
core spray (HPCS) switchgear room failed the forward and reverse flow tests
during a routine surveillance, resulting in the HPCS system being inoperable longer than
expected.
The inspectors noted that the licensee's
past corrective actions to address
this issue have not been fully effective.
Additional management
attention to this issue
is warranted.
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A Unit 1 LER identified that the TS limitfor the power to flow ratio was exceeded
for
about 5.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> due to the reactor recirculation flow instruments being recalibrated
using a new methodology.
The new method resulted in a indicated flow reading higher
than actual flow if the transmitter was isolated.
After the last refueling outage, the unit
restarted with one recirculation loop isolated.
The cause of the event was an
inadequate
understanding
of the new method and the potential impact on plant
operations.
This was identified as a non-cited violation.
PLANT SUPPORT
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NMPC continued to implement an effective overall radiological environmental
monitoring program and meteorological monitoring program including management
controls, quality assurance
audits, and quality assurance
of analytical measurements.
The offsite dose calculation manual was properly implemented.
Audits were effective
in assessing
program strengths
and weaknesses.
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A review of revisions to the emergency
plan and implementing procedures
determined
that the revisions did not reduce the effectiveness of the emergency
plan and were
acceptable.
TABLE OF CONTENTS
page
EXECUTIVE SUMMARY
TABLE OF CONTENTS
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IV
SUMMARY OF ACTIVITIES
1
Niagara Mohawk Power Corporation (NMPC) Activities
Nuclear Regulatory Commission
(NRC) Staff Activities ~......
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1
I. OPERATIONS
2
01
Conduct of Operations...
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2
01.1
General Comments
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Operational Status of Facilities and Equipment
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02.1
Unit 1 Loss of One String of Feedwater Heating
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Quality Assurance
in Operations ........ ~..........., ~......
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07.1
Review of INPO Evaluation .........
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08
Miscellaneous Operations
Issues
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08.1
(Closed) LER 50-410/95-12 and LER 50-410/95-12, Supplement
1:
Automatic Actuation of Standby Gas Treatment System Because of
Inadequate
Corrective Action for Snow Plugging of Filters..... ~.....
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08.2
(Closed) LER 50-220/96-04:
Reactor Scram Caused by Turbine Trip Due
to Feedwater Oscillations ........... ~.........
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08.3
(Closed) LER 50-410/94-06:
Technical Specification Violation Resulting
from a Missed Action Statement
Caused by Inadequate
Work Practices
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08.4
(Closed) Unit 1 Special Report:
¹11 Suppression
Chamber Water Level
Monitoring System Inoperable .................... ~,...,,
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II. MAINTENANCE
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M1
Conduct of Maintenance
M1.1
General Comments
M1.2
Unit 1 EDGs and Power Board 102/103 Operability Testing.....
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M2
Maintenance
and Material Condition of Facilities and Equipment ..
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M2.1
Receipt Inspection of Unit 2 New Fuel (60705)
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M8
Miscellaneous Maintenance
Issues .............,.,
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M8.1
(Closed) LER 50-220/95-03, Supplement
1: Technical Specification
Surveillance Tests not Performed at the Required Frequency
Because of
Cognitive Error
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M8.2
(Closed)
LER 50-410/96-05:
Surveillance Requirement Not Performed Per
Technical Specifications Due to Inadequate Work Practices..........
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M8.3
(Closed) LER 50-410/96-07:
Technical Specification Violation Due to
Inadequate
Work Organization/Planning .....
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III. ENGINEERING .................
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E2 Engineering Support of Facilities and Equipment......................
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E2.1
Unit 2 HPCS Inoperable due to Failed Service Water Surveillance.....
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IV
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Table of Contents (cont'd)
E8 Miscellaneous
Engineering
Issues
E8.1
(Closed) LER 50-220/96-03:
Power to Flow Technical Specification
Violation due to Ineffective Change Management
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IV. PLANT SUPPORT...
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R1 Radiological Protection and Chemistry (RP&.C) Controls ..
R1.1
Implementation of the Radiological Environmental Monitoring
(84750)
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R1.2
Meteorological Monitoring Program (84750)
R6 RP&C Organization and Administration
R6.1
Organization Changes
and Responsibilities (84570)
R6,2
Annual Environmental Operating Report (84570)
R7 Quality Assurance
in RPSC Activities
R7.1
Quality Assurance Audit Reports (84750)
R7.2
Quality Assurance of Analytical Measurements
(84750)
P3 EP Procedures
and Documentation
P3.1
In-Office Review of Changes to the E-Plan (82701)
V. Management Meetings........
X1
Exit Meeting Summary....
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X3
Management
Meeting Summary
X3.1
Regional Drop-In Visit by Executive Vice President
Program
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PARTIALLIST OF PERSONS CONTACTED .... ~.... ~.......
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INSPECTION PROCEDURES USED....
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ITEMS OPENED, CLOSED, AND UPDATED....
LIST OF ACRONYMS USED
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ATTACHMENT
ATTACHMENTA -
RESULTS OF THE REVIEW OF NRC IPAP IR 50-220/96-201
AND
50-410/96-201: LIST OF VIOLATIONS, UNRESOLVED ITEMS, AND
INSPECTOR FOLLOW ITEMS
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REPORT DETAILS
Nine Mile Point Units 1 and 2
50-220/96-07
8( 50-410/96-07
June 2- July 27, 1996
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 June 6,
power was reduced to 80% to repair the ¹12 feedwater heater string; power was returned
to 100% on June 11.
On July 19, power was reduced to 45% to allow cleaning of the
north condenser water box.
On July 21, the ¹13 shaft driven feedwater pump would not
engage,
limiting reactor power to 45% to the end of the period.
Unit 2
Unit 2 maintained essentially full power throughout the period.
On June 15, power was
reduced to 50% to allow for a shift of feedwater pumps, power was returned to 100% on
June 16.
On July 19, power was reduced to 78% for a control rod pattern adjustment,
full power was restored on June 20.
Nuclear Regulatory Commission (NRC) Staff Activities
lns ection Activities
The NRC resident inspectors conducted
inspection activities during normal, backshift, and
weekend hours.
There was one specialist inspection conducted
during this period in the
area of radiological environmental monitoring and meteorological monitoring; also, an in-
office review was performed regarding changes to the emergency
plan and the associated
procedures.
The results of the inspection and the review are contained
in this report.
During this period, the resident inspectors reviewed the report of the NRC Integrated
Performance Assessment
Process
(IPAP) team inspection conducted from March 4 through
22, 1996 (NRC Inspection Report 50-220/96-201
and 50-410/96-201).
By charter, the
NRR IPAP team inspections do not evaluate their findings with respect to enforcement;
therefore, the inspectors reviewed the IPAP report to identify violations, unresolved items,
and inspection follow items.
Some items identified by the IPAP team had been previously
identified or addressed
in earlier NRC inspection reports.
A summary of the issues
identified is provided in Attachment A to 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
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inspectors reviewed the applicable portions of the UFSAR related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the observed
plant
practices, procedures
and/or parameters.
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, operations were conducted
professionally and
with the proper focus on safety; specific events and noteworthy observations
are
detailed in the sections below.
02
Operational Status of Facilities and Equipment (71707)
02.1
Unit 1 Loss of One Strin
of Feedwater
Heatin
a.
Ins ection Sco
e
The inspector reviewed the details associated
with the June 6, 1996, feedwater
heater level control transient at Unit 1. The review included the applicable portions
of the chief station operator (CSO) and station shift supervisor (SSS) logs for the
event, and a discussion of the event with membeis of the operating crew and Unit
1 plant management.
The inspectors walked down areas of the plant effected by
the transient.
The inspectors also reviewed the deviation/event report (DER) written
to address the event, and the applicable portions of the Unit
1 UFSAR and Technical
Specifications (TSs).
b.
Observations
Findin s
At 4:02 a.m. on June 6, 1996, while at 100%, Unit 1 experienced
a level transient
in feedwater heating string ¹12.
Control room operators reduced power to 98.5%,
and attempted to restore water level for feedwater heaters ¹123 and ¹122 (third
stage heater and second stage heater, respectively, in string 12).
Operators noted
that the ¹122 feedwater heater piping had moved, due apparently to water flashing
to steam within the system.
At 4:40 a.m., operators reduced power below 80%
and isolated feedwater heater string ¹12.
Operators acted appropriately and
completed necessary
actions in accordance
with procedures.
'opical headings such as 01, M8, etc., are used in accordance withthe NRC standardized reactor inspection report outline.
Individual 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.
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To assess
the significance of operating with a loss of a feedwater heater string, the
inspectors reviewed the applicable portions of the Unit 1 UFSAR and TS. At Unit 1,
are part of the flow path for the high pressure coolant
injection (HPCI) system.
The UFSAR states that HPCI is not an engineering
safeguards
system nor is it considered
in any loss of coolant accidents
analyses.
However, according to the TS, HPCI ensures
adequate
core cooling in the event of
a small reactor coolant line break.
The inspectors verified that only one of the three
feedwater heater strings are required for HPCI operability.
Later, on June 6, the inspectors, with Unit
1 personnel,
walked down portions of
the ¹12 feedwater heater string, including the heaters
and the associated
feed and
steam piping, to assess
the damage.
A piping support for extraction steam to
feedwater heater ¹122 was found disengaged
from the concrete wall, with some
damage to the concrete.
Three other pipe supports for feedwater heater ¹122 were
found bent.
Other components
associated
with the feedwater heater were also
found damaged.
NMPC determined the root cause to be a failure of the level control valve for
feedwater heater ¹122.
To evaluate the effect of the transient, NMPC performed
the following: an analysis to verify that system integrity was not structurally
comprised;
an analysis to verify no adverse affect to the reactor or fuel; and an
assessment
to verify no affect on the core shroud.
The results of the evaluations,
as well as the root cause analysis of the event, were described
in DER 1-96-1389.
The Station Operations Review Committee (SORC) reviewed and approved the
proposed
repairs and related evaluations associated
with the event.
Repairs to the
system were completed on June 10; feedwater heater string ¹12 was returned to
service and the plant was returned to full power on June 11.
The inspectors considered the root cause described
in the DER to be accurate,
and
appropriately supported
by the physical evidence of the valve condition and
computer data for the feedwater heater string ¹12 drain cooler flows.
C.
Conclusion
The inspectors found that the Unit
1 operators acted appropriately and completed
actions in accordance
with procedures
during the June 6, 1996, feedwater heater
level transient.
The root cause described
in the DER was accurate,
and
appropriately supported with physical evidence and computer data.
NMPC's review
to determine the potential damaged
cause by the transient was good, as evidenced
by the completion of the structural, fuel and core shroud analysis.
07
Quality Assurance in Operations (71707)
07.1
Review of INPO Evaluation
The inspectors reviewed the report from the Institute of Nuclear Power Operations
(INPO) evaluation conducted from January 29 through February 9, 1996.
The
evaluation examined the overall operation of the Nine Mile Point site, and was
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performed by peer evaluators from other nuclear facilities. The report identified no
issues that the NRC was not already aware of, and no additional followup by the
NRC is warranted.
08
Miscellaneous Operations Issues (90712, 90713, 92700)
08.1
Closed
LER 50-410 95-12 and LER 50-410 95-12
Su
lement 1: Automatic
Actuation of Standb
Gas Treatment
S stem Because of Inade
uate Corrective
Action for Snow Plu
in
of Filters
On December 11, 1995, with Unit 2 operating at 100% power, the standby gas
treatment system (GTS) automatically initiated and the normal reactor building
ventilation systems isolated.
Heavy snowfall and gusty winds caused snow to
accumulate
on the inlet filters for the normal reactor building ventilation.
The
purpose of the inlet filters was to remove dust, dirt, and insects, to protect the
ventilation cooling coils.
During the winter months, the cooling coils are not in
service and the system could be operated without the filters.
The shift operators were aware of the decreasing
air flow and dispatched
personnel
to remove the filters from service.
However, before the filters could be removed
from service, the reactor building ventilation isolated with a concurrent automatic
initiation of GTS, due to a low exhaust air flow. Subsequently,
the filters were
removed, and ventilation was returned to normal.
Licensee Event Report (LER) 50-410/95-12 was first reviewed in NRC Inspection
Report (IR) 50-410/96-01; it identified the root cause as being inadequate
corrective
actions to previously identified problems.
Particularly, NMPC noted that similar
ventilation degradations
had been experienced
in the 1980's, caused
by snow
plugging of the filters. The LER was not closed during the initial review because the
listed corrective actions only addressed
preventing the inlet filters from again
clogging with snow, not the root cause.
Therefore, as discussed
in IR 50-410/96-
01, the licensee agreed to submit a supplement to the LER that described
completely the corrective actions to address
all root causes.
To address the root cause of inadequate
corrective actions,
LER 50-410/95-12,
Supplement
1, was issued to provide additional information regarding enhancements
that had already been made to the NMPC problem resolution process.
The process
for problem resolution was contained
in procedure
NIP-ECA-01, "Deviation Event
Reports," and included increased oversight of problem evaluations,
assignment
of
trend codes and more stringent requirements for root cause evaluations.
The
inspectors considered the corrective actions appropriate to address the root cause.
08.2
Closed
LER 50-220 96-04:
Reactor Scram Caused
b
Turbine Tri
Due to
Feedwater Oscillations
On May 20, 1996, Unit 1 experienced
a turbine trip and reactor scram from 100%
power.
The turbine trip was due to a high reactor vessel water level, caused by a
failure of the ¹13 feedwater flow control valve.
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The description of the event in the LER, including the root cause analysis and
corrective actions, was consistent with the inspectors'eview
of the event, as
documented
in NRC IR 50-220/96-06.
08.3
Closed
LER 50-410 94-06: Technical S ecification Violation Resultin
from a
Missed Action Statement
Caused
b
Inade
uate Work Practices
a.
Ins ection Sco
e
This LER describes
an event which happened
in October 1994, but the LER had not
been reviewed previously due to an administrative oversight.
The inspectors
reviewed the details of the event and the associated
LER, the applicable portions of
the CSOs and SSS logs for the event, and discussed
the event with Unit 2 plant
management.
The inspectors
also reviewed the applicable portions of the Unit 2
TSs.
b.
Observations
Findin s
During the work control planning process,
Unit 2 scheduled two control rod drive
(CRD) hydraulic control unit (HCU) accumulators to be worked the same day.
The
affected departments
(maintenance,
work control/planning,
and operations)
had
agreed to work the HCUs sequentially,
and had noted this in an attachment to the
weekly work schedule.
However, the agreed upon schedule was not included in the
plant impact section of the individual work packages.
Subsequently,
on October
24, 1994, with Unit 2 operating at 90% power, shift management
allowed two
HCU accumulators to be made-inoperable
without'implementing the required TS
action statements.
Specifically, per TS 3.1.3.5, when an accumulator is inoperable, the associated
control rod is also inoperable.
Ifthe control rod is inoperable for reasons other than
being immovable due to friction or binding, then per TS 3.1.3.1.b, two options
exist:
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insert the control rod and disarm the associated
directional control valves; or
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if the control rod is withdrawn, verify it is separated
from all other inoperable
control rods, and insert the control rod at least one notch using normal drive
water pressure.
TS 3.1.3.5, action statement a.2.a, states that with more than one accumulator
and the associated
control rods withdrawn, immediately verify at least
one CRD pump operating by inserting at least one control rod at least one notch.
If
a pump is not running, start a CRD pump within 20 minutes and insert at least one
control rod one notch, or place the reactor mode switch in the shutdown position.
When the station shift supervisor (SSS) reviewed and approved the first HCU work
package, the SSS and the assistant
SSS (ASSS) recognized that the control rod was
required to be declared inoperable.
When the second
HCU work package was
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reviewed and approved, the SSS knew that a withdrawn control rod needed to be
inserted at least one notch to verify CRD pump operability, but failed to inform the
ASSS of the additional requirement due to the second control rod accumulator being
inoperable at the same time. The chief shift operator (CSO) questioned the
appropriateness
of having multiple accumulators out of service; the ASSS reviewed,
but misinterpreted, the TSs.
The second control rod was declared inoperable ten
minutes after the first. The ASSS again reviewed the TSs while logging the above
into the SSS log. At this point, he recognized that they had not complied with the
requirement for inserting a control rod one notch.
Twenty-five minutes after the
second control rod was inoperable,
a different control rod was inserted one notch;
meeting TS requirements.
The root cause was an inadequate
review by the SSS and ASSS; contributing
causes were poor verbal communications
between the SSS and ASSS, and poor
work coordination that allowed both HCUs to be worked at the same time.
Corrective actions included counseling of all SSSs and ASSSs, emphasis
on TS
implementation during licensed operator requalification training, and enhancements
to the work control process.
The inspectors verified that the LER description of the event was consisted with the
sequence
of events as documented
in the control room logs; the inspectors
also
discussed
the LER with Unit 2 operations management.
The failure to take the
required actions as detailed in the limiting condition of operation for multiple
as described
above,
is a violation of the Unit 2
Technical Specifications, Section 3.1.3.5.a.2.a.
However, because this licensee
identified event occurred almost two years ago, and the corrective actions appear to
have prevented recurrence, this violation is being treated as a Non-Cited Violation,
consistent with Section VII.B.1 of the NRC Enforcement Policy,
C.
Conclusion
The inspectors
noted that there were several chances for the shift management to
identify the correct TS action statement;
during the initial review of the work
packages
by the SSS and ASSS, and when questioned
by the CSO.
In addition, the
work control/planning organization could have aided the operators by including the
potential plant impact as part of the work package.
Nonetheless,
once identified,
the shift crew took prompt action to ensure the plant was in compliance with the
TS.
In addition, NMPC management
took adequate
corrective actions to prevent
recurrence.
Closed
Unit 1 S ecial Re ort: ¹11 Su
ression Chamber Water Level Monitorin
S stem lno erable
On July 11, 1996, with Unit 1 at 100% power, NMPC removed the ¹11
suppression
chamber water level (SCWL) monitoring system from service for
troubleshooting
of an erroneous
high level alarm.
Technicians recalibrated the
transmitter and adjusted the alarm setpoint, and returned the system to operable the
same day.
The redundant train of SCWL remained operable.
NMPC submitted
a
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special report to the NRC within 14 days, as required by the Unit 1 Technical
Specificationl (TS) 3.6.11-1, action statement 4.a;
The inspectors reviewed the
special report, and confirmed that all required information was contained
in the
report.
II.
MAINTENANCE'1
Conduct of Maintenance
M1.1
General Comments
Using Inspection Procedures
61726 and 62703, the inspectors observed
plant
maintenance
activities and the performance of various surveillance tests.
In
general, maintenance
and surveillance activities were conducted
professionally, with
the work package
and necessary
procedures
at the work site and in use, and with
the appropriate focus on safety.
As necessary,
the proper radiation protection work
practices were implemented.
Specific activities and noteworthy observations
are
detailed in the sections below.
The inspectors observed
all or portions of the
following maintenance
and surveillance activities:
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N2-ISP-NMS-W@001
Unit 2 - APRM Channel Functi
M1.2
Unit
1 EDGs and Power Board 102 103 0 erabilit
Testin
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N1-ST-M4
EDGs/PB 102 and 103 Operability Test
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N1-ISP-083-001
Drywell Liquid Waste Flow Meters
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N2-MMP-FHP-099
Receiving, Inspecting, and Storage of New Fuel
'onal Test
a.
Ins ection Sco
e
On July 22, 1996, the inspectors observed operator performance of surveillance
procedure
N1-ST-M4, Revision. 24, "EDGs/PB [Emergency Diesel Generators/Power
Board] 102 and 103 Operability Test."
Specifically, Section 8.3, "Diesel Generator
103 One Hour Performance
Run," of the reference procedure was observed.
b.
Observations
and Findin s
The inspectors observed operations staff performing the surveillance locally in the
Unit 1 Turbine Building. The operators performed the following evolutions:
/
~
hand-jacking of EDG 103 and integrity check of 20 cylinder test valves
~
EDG operability checks prior to load run
~
remote starting of EDG 103 and verification that the EDG obtained proper speed
and voltage in allowable time
Surveillance activities are included under "IVlalntenance." For exemple. a section involving surveillance observations might
be Included as a separate sub.topic under M1, " Conduct of Maintenance."
0
~
load run
Communications
between the operators
in the turbine building and the control room
were adequate.
The inspectors
also observed the markup of the EDG for
performance of the hand-jacking evolution, and noted conformance with plant policy
concerning independent
verification of the markup and subsequent
valve
restoration.
No concerns were identified.
Starting of the EDG and subsequent
load
run were monitored by the inspectors, with no identified concerns.
c.
Conclusions
The inspectors noted that operations
personnel performed all aspects
of the EDG
surveillance test well. The inspectors determined that the staff appeared
to'nderstand
the scope of the surveillance and accomplished the evolution without
incident.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
Recei t Ins ection of Unit 2 New Fuel 60705
The inspectors observed the inspection of new fuel for the upcoming refueling
outage at Unit 2. Technicians completed the inspections
in accordance
with
procedure
N2-MMP-FHP-099, Revision 2, "Receiving, Inspection, and Storage of
New Fuel." The inspectors verified that the receipt/inspection
activities complied
with the Unit 2 licensing conditions associated
with fuel storage and handling.
The
inspectors concluded that the new fuel handling activities were appropriately
completed.
MS
Miscellaneous Maintenance Issues
M8.1
Closed
LER 50-220 95-03
Su
lement 1: Technical S ecification Surveillance
Tests not Performed at the Re uired Fre uenc
Because of Co nitive Error
On June 13, 1996, as a result of corrective actions associated
with LER 95-03,
NMPC discovered
an additional instrument and control (ISC) surveillance procedure
had not been performed within the frequency required by TSs.
Specifically, TS
surveillance requirement
(TSSR) 4.2.5.b.(1) required performance of an instrument
calibration on each containment leakage detection system once each refueling
outage.
The TS bases discussed
three subsystems
for containment leak detection:
rate of rise leak detection; timer leak detection; and integrated flow rate.
These
three leak detection systems
are independent
and utilize separate
surveillance
procedures for performing functional testing and instrument calibration.
The rate of rise and timer leak detection system instrument functional tests and
calibrations were performed during refueling outages
12 and 13 (RFO-12 and RFO-
13).
The integrated flow rate instrument functional test and calibration was
accomplished
by surveillance procedure N1-ISP-083-001, "Drywell Liquid Waste
Flow Meters".
NMPC identified this surveillance had been completed satisfactorily
0
during quarterly surveillance prior to, and subsequent
to, RFO-12 and RFO-13.
However, the refueling outage TSSR was not performed during either RFO-12 or
RFO-13.
Since this was another example of a surveillance test not being performed
during the refueling outage as required, NMPC issued Supplement
1 to LER 95-03
on July 13, 1996.
LER 95-03 was originally discussed
and closed as part of NRC IR 50-220/95-16.
The inspectors reviewed the LER Supplement
and determined that it satisfactorily
described the event, the root cause evaluation, and corrective actions to prevent
similar occurrences
in the future.
The failure to perform the calibration at the
required periodicity is a violation of TSSR 4.2.5.b(1); based on the corrective
actions and low safety consequence,
this licensee identified violation is being
treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC
M8.2
Closed
LER 50-410 96-05:
Surveillance
Re uirement Not Performed Per Technical
S ecifications Due to Inade
uate Work Practices
On April~15, 1996, while Unit 2 was operating at approximately 100% power,
control room operators discovered that during the performance of Division 3 service
water operability testing, the Division 3 EDG had not been declared inoperable
as
required by TS. This resulted in the failure to perform TS SR 4.8.1
~ 1, verification of
breaker alignment and power availability, within one hour as required by TS 3.8.1.1.
The failure to declare the Division 3 EDG inoperable was identified by the control
room operators approximately three hours after the beginning of the service water
testing, when the ASSS was informed that a check valve failed its reverse flow
test. At this time, the ASSS and SSS recognized that the EDG should have been
declared inoperable at approximately 12:45 p.m. when the surveillance testing
began.
The SR was satisfactorily completed at approximately 3:45 p.m. ~
The root cause of the event, as described
in the LER, was inadequate
work practice
by the ASSS.
During the ASSS's review of the service water surveillance test, he
identified that the EDG would become inoperable.
However, instead of consulting
the TS to determine the applicable action statement requirements,
he continued his
review of the surveillance for other plant impacts.
This resulted in the failure of the
ASSS to declare the EDG inoperable and subsequent
failure to met the TS action
statement requirement.
NMPC identified two contributing factors:
the operator
performing the surveillance did not understand
management's
expectation
regarding
the procedure step to discuss the plant impact with the SSS and CSO, therefore the
discussion was not in the depth intended.
Secondly, the surveillance procedure
did
not direct the performance of the TS required actions for this short duration LCO.
The corrective actions for this event, as described
in the LER, included counseling
the SSS and ASSS regarding the need to fully read, comprehend
and initiate
compensatory
action for all TS requirements
prior to allowing work to commence.
Also, clarification was provided to all operators with respect to the requirement to
discuss the plant impact statement during the work approval process.
Additionally,
10
NMPC'planned to evaluate station procedures
to determine which should include
steps for completing applicable TS required actions.
The inspectors reviewed the LER and determined that it satisfactorily described the
event, the root cause,
and corrective actions to prevent similar occurrences
in the
future.
Based on the adequate
corrective actions and low safety consequence
this
licensee identified violation is being treated as a Non-Cited Violation, consistent
with Section VII.B.1 of the NRC Enforcement Policy.
Closed
LER 50-410 96-07:
Technical S ecification Violation Due to lnade
uate
Work Or anization Plannin
Unit 2 identified additional historical violations of TS surveillance requirement 4.0.4
as a result of the corrective actions associated
with Unit 2 LER 96-02.
Specifically,
on May 20, 1996, NMPC identified that several valves in the reactor core isolation
cooling (RCIC) system were not tested prior to reactor system pressure
exceeding
150 psig.
TS 3.7.4 requires the RCIC system be operable when reactor steam
pressure
is greater than 150 psig; TS surveillance 4.7.4.b requires that the RCIC
pump develop
a minimum flow of 600 gpm when steam pressure
at the turbine is
935-1035 psig.
Because steam pressure
is required to test the RCIC pump, TS 4.0.5 [inservice inspection (ISI) and inservice testing (IST)] allows the test to be
performed up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after adequate
steam pressure
is available.
The associated
surveillance test procedure (N2-OSP-ICS-05002,
"RCIC Pump and
Valve Operability Test and System Integrity Test and ASME XI Functional Test" )
also tests several RCIC system valves on the water (discharge)
side of the pump.
The pump must be running to test the valves; accordingly, the valves also cannot
be tested until steam pressure
is adequate.
However, NMPC identified that three of
the valves in the procedure do not need the RCIC system to be in operation.
Therefore, because
TS 3.7A requires the valves to be operable, the surveillance
test for those three valves must be completed prior to exceeding
150 psig.
determined that these valves had not been tested within the required time frame of
three occasions
(April 1, 1989, January 24, 1991, June 17, 1992).
determined the cause to be inadequate
work organization and planning, because
several surveillance requirements were incorporated into one procedure without
accounting for different scheduling criteria.
No immediate corrective actions were required.
The actions planned to prevent
recurrence
included revising the IST program plan to identify which RCIC valves can
be delayed for testing, and revising the RCIC surveillance procedure to identify
which valves must be tested prior to exceeding
150 psig.
The inspectors noted that this was identified as a result of a previous event, which
heightened
the awareness
to the requirement of TS 4.0.4; and to ensuring that
required surveillance are performed at the proper frequency.
Based on adequate
planned corrective actions and low safety consequence
this licensee identified
violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1
of the NRC Enforcement Policy.
11
III. ENGINEERING
E2
Engineering Support of Facilities and Equipment
E2.1
Unit 2 HPCS Ino erable due to Failed Service Water Surveillance
a 0
Ins ection Sco
e
On July 8, 1996, check valves in the service water system to the high pressure
core spray (HPCS) switchgear unit cooler failed to meet the forward and reverse
flow as required by the surveillance test.
The inspectors reviewed the operating
logs, the associated
work packages,
related DERs and the engineering'valuation.
The inspectors
also reviewed the surveillance history of the valves, and had
discussions
regarding recurring surveillance failures with the system engineer and
Unit 2 plant management.
b.
Observations
Findin s
On July 8, 1996, Unit 2 personnel conducted
a surveillance test
(N2-OSP-SWP-0005,
"Division 3 Service Water Operability. Test" ) of the service
water system associated
with the HPCS system.
During performance of this
procedure, the check valve to the HPCS unit cooler failed to meet the acceptance
criteria for both forward and reverse flow. After several attempts to clean the
system and repair the valves, the reverse flow portion of the N2-OSP-SWP-Q005
surveillance test was completed satisfactorily.
Engineering was able to provide a
lower minimum acceptance
criteria for forward flow, and the surveillance test was
completed satisfactorily on July 12.
The inspectors review of the operating logs, the associated
work packages,
and the
engineering evaluation identified no problems.
However, the inspectors noted that
each time the quarterly surveillance test has been performed since the beginning of
the year, the same valves have caused the HPCS system to become inoperable
(January 23-25, April 16-19, and July 8-12).
Furthermore,
in IR 50-410/95-24, the
inspectors documented
failures of the same surveillance and that Simple Design
Change SC2-0034-94 was ineffective in that it required additional design changes
to corrected the recurring surveillance test failures.
In Spring 1995, SC2-0034-94
was installed, which replaced the original piston check valves with nozzle check
valves. During the evaluation of a failed surveillance completed on October 30,
1995, NMPC recognized that the clearance between the plug and the seat of the
new valves was too narrow for the maximum expected
mussel size (1/8 inch) to
pass through.
In February 1996, NMPC changed the internals of these valves to
provide a larger clearance.
However, this February change was also ineffective as
evidenced by the continuing surveillance test failures.
When HPCS was inoperable in April, Unit 2 management
informed the resident
inspectors that one option being considered was removal of the unit cooler check
valves.
The inspectors consider the delay in finding a final resolution for the
12
problem with the unit cooler check valves is causing the HPCS system to be
unnecessarily
When discussing this concern with the Unit 2 Plant
Manager, it was brought to the inspector's attention that a DER (DER 2-96-1598)
had been initiated on July 8 to document both the current failed surveillance and the
repetitive failures.
The inspector reviewed the DER and the attached
engineering operability
determination checklist.
The DER listed the apparent cause
as due to fouling and
corrosion of small bore piping, some of it due to the treatment for clams in the
service water system (Clam-Trol) ~ A contributing cause was the failure to revise the
inservice testing (IST) acceptance
criteria after the earlier failures.
Each time the
valves failed the surveillance,
an operability determination was completed to accept
the values for that specific surveillance, but the IST database
was never changed.
The corrective actions include the issuance of a design document change
(DDC) to
change the IST database
and the associated
surveillance procedure.
In addition,
engineering will process the safety evaluation to support removal of the check
valves from the system; the valves are scheduled to be removed by the end of the
year.
C.
Conclusion
The inspectors considered the delay in finding a final resolution for the problems
associated
with the unit cooler check valves was causing the HPCS system to be
unnecessarily
Additional management
attention is warranted to ensure
future corrective actions are effective.
E8
Miscellaneous Engineering Issues
E8.1
Closed
LER 50-220 96-03:
Power to Flow Technical S ecification Violation.due to
Ineffective Chan
e Mana ement
The inspectors reviewed the LER, which discussed
the identification, by Unit 1
management
on May 9, 1996, that the TS limitfor power to flow ratio (PFR) had
been exceeded
for about 5.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> on April 8-9, 1995.
During the last Unit 1
refueling outage,
Spring 1995, the recirculation flow instruments were recalibrated
using a new methodology because
of lessons
learned from the reactor recirculation
pump runback on February 1, 1995.
The new method incorporated parameters that
resulted in an indicated reactor coolant flow reading higher than actual flow if the
transmitter was isolated or equalized.
After the outage, the plant restarted using
only 4 of the 5 recirculation loops; the idle loop transmitter was isolated, per the
operating procedure.
The combination of the new calibration method, and the
isolated transmitter resulted in an incorrect indicated flow in the idle loop of two
million pounds mass per hour (2E6 Ibm/hr) instead of 0 Ibm/hr.
About one week after startup, the system engineer identified the problem and the
transmitter was unisolated and placed in service, providing an accurate indication of
loop flow. Initial evaluation by NMPC, ba'sed on a review by engineering
and the
vendor, determined that the error did not cause the total recirculation flow to be
13
exceeded,
but the affect on the PFR correction factor was uncertain.
On May 7,
1996, after additional information became available,
a re-evaluation was performed;
this evaluation indicated that the PFR had been exceeded.
NMPC performed an
analysis of the event and verified that no fuel limits had been exceeded,
and
therefore, no cladding or fuel damage occurred.
The cause of the event was an
inadequate
review and understanding
of the new calibration methodology and the
potential impact on plant operations.
The inspectors reviewed the LER and determined that it satisfactorily described the
event, the root cause,
and corrective actions.
Completed and planned corrective
actions appear adequate to prevent similar occurrences
in the future.
However,
exceeding the PFR is a violation of TS 3.1.7.d, "Power Flow Relationship During
Operation".
This licensee identified violation is being treated as a Non-Cited
Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.
IV. PLANT SUPPORT
R1
Radiological Protection and Chemistry (RPRC) Controls
R1.1
Im lementation of the Radiolo ical Environmental Monitorin
Pro ram 84750
'ns
ection Sco
e
The inspectors observed
and assessed
the licensee's capability to implement the
radiological environmental monitoring program (REMP), The inspectors reviewed the
REMP procedure manual, visited selected sampling locations to confirm that
samples were being obtained from the locations specified in the Offsite Dose
Calculation Manual (ODCM), witnessed licensee and contractor personnel
exchange
air filters and charcoal canisters, examined the air samplers to determine operability
and calibration status, and reviewed the results of the Land Use Census.
The above
areas were inspected against specific TS requirements
Sections 3/4.6.20, 3/4.6,21,
3/4.6.22 for Unit 1 and Sections 3/4.12.1, 3/4.12.2, and 3/4.12.3 for Unit 2, the
b.
Observations
and Findin s
The environmental protection group, part of the Licensing/Environmental
Department at Nine Mile Point, has the responsibility to implement the REMP in
cooperation with the J. A. FitzPatrick Radiological Environmental Services
Department.
Environmental samples were collected by licensee and contractor
personnel
(Ecological Analysts Science and Technology) and were analyzed at the
FitzPatrick Environmental Laboratory (JAFEL).
The sampling stations included air samplers for airborne iodines and particulates,
a
composite water sampling station (control station), a milk farm, vegetation
locations, and several thermoluminescent
dosimeter (TLD) stations for measurement
of direct ambient radiation.
The inspectors witnessed the weekly exchange of
14
charcoal cartridges and air particulate filters at selected sampling stations.
All
observed
air sampling equipment was operational and calibrated at the time of the
inspection.
The TLDs were placed at the designated
locations as specified in the
ODCM. Milk and vegetation samples were obtained from the locations specified in
the ODCM. Sample collection was performed according to the appropriate
procedures.
The REMP procedures
contained
all the guidance necessary to collect and prepare
environmental sample media.
The procedures
included air, milk, water sampling
methods, dry gas meter calibration calculations for the air samplers,
and a method
for conducting the Land Use Census.
The procedures
were of good technical
content, concise,
and provided the required direction and guidance for implementing
an effective REMP.
C.
Conclusions
Based on the above review, direct observations,
discussions with personnel,
and
examination of procedures,
the inspectors determined that the licensee continued to
effectively implement the REMP in accordance
commitments.
R1.2
'eteorolo
ical Monitorin
Pro ram 84750
Ins ection Sco
e
The inspectors observed
and evaluated the licensee's meteorological monitoring
program (MMP) to determine w'hether the instruments
and equipment were
operable, calibrated, and maintained.
The MMP was inspected against TS
requirements Section 3/4.7.3 for Unit 2, Section 2.3 of the UFSAR, and Regulatory
Guide 1.23.
b.
Observations
and Findin s
The Meteorological Services group continued to have oversight for the MMP; and
the ISC department continued to maintain all sensors at the main, backup, and
inland towers for the Nine Mile Point/FitzPatrick site and perform calibrations in
accordance
with Unit 2 TS requirements.
The calibration procedures
were available
and implemented for wind speed, wind direction, temperature
sensors,
and other
related components.
The inspectors reviewed the most recent semi-annual
calibration results for the above parameters
and noted that the calibrations were
adequately performed in accordance
with the appropriate IKC procedures.
All
reviewed calibration results were within the licensee's
acceptance
criteria. The
FitzPatrick INC department calibrated the strip chart recorders
in accordance
with
the licensee's calibration schedule.
The results were within the licensee's
established
acceptance
criteria.
The inspectors observed the sensors
and the associated
outputs in the computer
building, as well as the outputs in the Nine Mile control room and Technical Support
15
Center.
Accurate meteorological data were available't each location using digital
display from the system computer and analog strip chart recorders.
Conclusion
Based on the above review, direct observations,
discussions with personnel,
and
examination of procedures
and records for calibration of equipment, the inspectors
determined that the licensee continued to effectively implement the MMP in
accordance
with the Unit 2 TS, UFSAR commitments,
RP&C Organization and Administration
Or anization Chan
es and Res
onsibilities 84570
Ins ection Sco
e
The inspectors reviewed any organization changes
and the responsibilities relative to
oversight of the REMP and MMP since the previous inspection conducted
in June
1995, to verify the implementation of the TS requirements.
Observations
and Findin s
The inspectors identified changes
in the organizations
responsible for the REMP and
MMP.
In October 1995, the Environmental Protection-Radiological;
Technical
Services Branch was transferred to the Licensing Branch and subsequently
renamed
the Licensing/Environmental
Branch.
The Environmental Protection-Meteorological;
Technical Services Branch was relocated to the Emergency Preparedness
Department and subsequently
renamed Meteorological Services.
The Environmental
Protection Coordinator-Radiological
continued to implement the REMP and report to
the Supervisor,
Environmental Protection, who reports to the Manager,
Licensing/Environmental
Branch.
Meteorological Services continued to have
oversight of the MMP. The Meteorological Services Coordinator reports to the
Director, who reports to the Manager, Nuclear Training
Branch.
Conclusion
Based on the above review, the inspectors did not identify any negative impact on
the'implementation of the REMP and MMP and confirmed that the responsible
personnel
in these programs essentially remained the same.
Annual Environmental 0 eratin
Re ort 84570
Ins ection Sco
e
The inspectors reviewed the Annual Environmental Operating Report to verify the
implementation of the TS requirements
Section 6.9.1.d. for Unit 1 and Section
6.9.1.7 for Unit 2.
16
Observations
and Findin s
The inspectors reviewed the Annual Radiological Environmental Operating Report for
timely reportability and the results of the routine analysis of REMP samples
and
quality assurance
results.
The Annual Radiological Environmental Operating Report
for 1995 provided a comprehensive
summary of the analytical results of the REMP
around the Nine Mile Point site and met TS reporting requirements.
No obvious
omissions,
anomalous data or trends were identified.
c.
Conclusion
Based on the above review, the inspectors determined that the licensee maintained
good management
control to implement the TS requirements with respect to the
Annual Radiological Environmental Operating Report.
R7
Quality Assurance in RP5C Activities
R7.1
Qualit
Assurance Audit Re orts 84750
a.
Ins ection Sco
e
The inspectors reviewed the Quality Assurance
(QA) audit report against criteria
contained in TS requirements,
Section 6.5.3.8.i for both units.
b.
Observations
and Findin s
The nuclear QA audit 95019, "Environmental Protection/REMP and Radioactive
Effluents," was performed December 4-8, 1995, and included an assessment
of the
REMP and MMP. The audit was conducted
by the nuclear QA audit group and
technical specialists.
The scope and technical depth of the audit were good and
effectively assessed
the programs for strengths
and weaknesses.
The audit scope
also included an assessment
at the JAFEL.
Few findings and recommendations
were identified.
The responsible
departments
responded
to these findings and
recommendations
in a timely manner.
C.
Conclusions
Based on the, above review, the inspectors determined that the licensee conducted
an audit of sufficient technical scope and depth to adequately
assess
the quality of
the REMP and MMP, as required by the regulatory requirements.
R7,2
Qualit
Assurance of Anal tical Measurements
84750
Ins ection Sco
e
The inspectors reviewed the licensee's
QA program for analytical measurements
of
radiological environmental samples including the Interlaboratory Comparison
Program
(EPA Cross-check
Program) required by the TS and ODCM.
17
Observations
and Findin s
The quality control (QC) program for analysis of environmental samples was the
responsibility of the FitzPatrick Radiological and Environmental Services
(RES)
Supervisor at the JAFEL, located in Fulton, N.Y. The laboratory maintained internal
QA programs including environmental split samples,
spike samples,
and blind
samples.
Control charts for the gamma spectroscopy
counter, liquid scintillation
counter, and low background
counters were well maintained and calibrations were
performed as scheduled.
QA samples were analyzed according to the schedule.
The laboratory supplied reports of QC results to the Nine Mile Environmental
Protection Coordinator for data review and analysis.
When discrepancies
were
found, the Coordinator consulted with the RES Supervisor.
Reasons for the
discrepancies
were investigated
and resolved.
The inspectors reviewed the JAFEL
Quality Assurance
Reports for 1994 and 1995 which contained the results of the
QA programs.
All reviewed results were in agreement.
The laboratory participated in the EPA cross-check
Program.
The inspectors
reviewed the cross-check results for 1995 and noted that results were within the
EPA's acceptance
criteria.
In 1996, the licensee started to use a vendor laboratory
(Analytics, Inc.) to continue the interlaboratory comparison program since the EPA
stopped providing this service after December 1995.
The inspectors reviewed the
cross-check
results for the first quarter 1996, and noted that the results were
within the established
acceptance
criteria. The inspectors
also determined that the
program is equivalent to the EPA cross-check
Program.
JAFEL plans to use
Environmental Management
Laboratory (EML) to supplement the Analytics Program.
This program is expected to be implemented
in September
1996.
Since JAFEL also obtained calibration standards
from Analytics Inc., the inspectors
questioned if the samples provided for the intercomparison
program are independent
from the calibration standards.
Review of the Analytics Inc. program revealed that
independence
was assured
since Analytics Inc. established two separate
and
independent
programs, one for the calibration standards
and the other for the
intercomparison
program.
The inspectors observed
a chemistry technician prepare routine environmental milk
samples for counting.
The technician followed the procedure
and used good
laboratory practices.
The inspectors also reviewed the analytical results for 1996
(January - July) and noted that there were no anomalous
results.
Conclusion
Based on the above reviews and discussions,
the inspectors determined that the
licensee continued to implement a good quality assurance
program in accordance
with regulatory requirements.
P3
EP Procedures
and Documentation
18
P3.1
In-Office Review of Chan
es to the E-Plan
82701
A emergency
preparedness
specialist inspector conducted
an in-office review of
revisions to the emergency
plan and implementing procedures
(EPIPs) submitted by
the licensee.
The specific revisions reviewed follows. The inspectors determined
that the revisions did not reduce the effectiveness
of the emergency
plan and were
acceptable.
Procedure
No.
Title
Revision No.
EPIP-EPP-01
EPIP-EPP-02
EPIP-EPP-04
EPIP-EPP-05
EPIP-EPP-07
EPIP-EPP-08
EPIP-EPP-09
EPIP-EPP-1 0
EPIP-EPP-1 2
EPIP-EPP-13
EPIP-EPP-1 6
EPIP-EPP-1 7
EPIP-EPP-20
EPIP-EPP-22
EPIP-EPP-23
EPIP-EPP-24
EPIP-EPP-27
EPIP-EPP-30
Site Emergency Plan
Classification of Emergency Conditions
't
Unit 1
Classification of Emergency Conditions
at Unit 2
Personnel
Injury or Illness
Station Evacuation
Downwind Radiological Monitoring
Off-Site Dose Assessment
and Protective
Action Recommendation
Determination of Core Damage Under
Accident Conditions
Security Contingency Event
Re-Entry Procedure
Emergency Response
Facilities Activation
and Operation
Environmental Monitoring
Emergency Communications
Procedure
Emergency Notifications
Damage Control
Emergency Personnel Action Procedures
Nuclear Transportation Accidents
Emergency Public Information Procedure
Prompt Notification System Problem Response
34
6
2
1
2
6
3
1
5
1
5
1
2
1
V. Management Meetings
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 resident inspector's final exit meeting occurred on August 30,
1996.
NMPC did not dispute any of the inspectors findings or conclusions.
The
preliminary exit for the radiological environmental monitoring and meteorological
monitoring inspection was conducted
on July 26, 1996.
19
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
X3.1
Re ional Dro -In Visit b
Executive Vice President
On July 16, 1996, Mr. B. Ralph Sylvia, NMPC Executive Vice President and Chief
Nuclear Officer, met with Mr. T. Martin, Regional Administrator, Mr. W. Kane,
Deputy Regional Administrator, and Mr. R. Conte, Chief, Reactor Projects Branch
No. 5, at the NRC Region
I offices in King of Prussia, Pennsylvania.
The topics
discussed
were the status of the "Power Choice Option" for the state of New York,
in which power companies would individually compete in an open market for the
sale of electricity; and the NMPC response
to the NRC Notice of Violation and
Proposed
Imposition of Civil Penalty (dated June 18, 1996).
Mr. Sylvia also
provided a copy of the response
at that meeting.
20'ARTIAL
LIST OF PERSONS CONTACTED
Nia ara Mohawk Power Cor oration
R. Abbott, Vice President 5 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
H. Christensen,
Nuclear Security Manager
J. Conway, Plant Manager, Unit 2
K. Dahlberg, General Manager - Projects
A. DeGracia, Work Control/Outage
Planning, Unit 1
R. Dean, Engineering Manager, Unit 2
G. Helker, Work Control/Outage
Planning, Unit 2
J. Jones,
Director, Emergency Preparedness
M. McCormick, Vice President - Nuclear Safety Assessment 5 Support
L. Pisano, Maintenance
Manager, Unit 2
N. Rademacher,
Plant Manager, Unit
1
P. Smalley, Radiation Protection Manager, Unit 1
R. Smith, Operations Manager, Unit 2
B. Sylvia, Executive Vice President - Nuclear
K. Sweet, Technical Support Manager, Unit 1
C. Terry, Vice President - Nuclear Engineering
R. Tessier, Nuclear Training Manager
K. Ward, Technical Support Manager, Unit 2
D. Wolniak, Licensing/Environmental
Manager
W. Yaeger, Engineering Manager, Unit 1
New York Power Authorit
- J. A. FitzPatrick
N. Avrakotos, Emergency Planning Manger
J. McCarty, Quality Assessment
Supervisor
A. McKeen, Radiological and Environmental Services Manager
21
INSPECTION PROCEDURES USED
IP 37551:
IP 40500:
IP 60705:
IP 61726:
IP 62703:
IP 71707:
IP 82701:
IP 84750:
IP 90712:
IP 92700:
IP 92901:
IP 92902:
IP 92903:
IP 92904:
On-Site Engineering
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
Problems
Preparations
for Refueling
Surveillance Observations
Maintenance Observation
Plant Operations
Operational Status of the Emergency Preparedness
Program
Radioactive Waste Treatment, and Effluent and Environmental Monitoring
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 - Operations
Followup - Engineering
Followup - Maintenance
Followup - Plant Support
OPENED
50-41 0/96-07-01
50-410/96-07-02
50-41 0/96-07-03
50-410/96-07-04
50-410/96-07-05
50-41 0/96-07-06
50-220/96-07-07
50-220/96-07-08
50-410/96-07-08
50-220/96-07-09
50-410/96-07-09
50-41 0/96-07-10
50-220/96-07-1
1
50-410/96-07-1
1
50-220/96-07-1 2
50-410/96-07-1 2
50-41 0/96-07-1 3
50-220/96-07-1 4
50-410/96-07-1 4
50-410/96-07-1 5
50-220/96-07-1 6
50-220/96-07-1 7
50-410/96-07-1 7
50-220/96-07-1 8
50-410/96-07-1 8
50-220/96-07-1 9
50-41 0/96-07-1 9
CLOSED
NONE
22
ITEMS OPENED, CLOSED, AND UPDATED
The mechanical seal on a feedwater pump was replaced
without a procedure.
No incoming survey for a radioactive material shipment.
IFI
Weaknesses
in the DER proc'ess.
IFI
-
ISEG responsibilities associated
with the review of NRC
issuances.
IFI
Weaknesses
in the 50.59 safety evaluation process.
IFI
IFI
IFI
IFI
Long standing hardware problems uncorrected.
Unit 1 is unable to parallel the EDGs with offsite for
restoration after a loss of offsite power.
MIC control systems installed as temporary modifications
over 4 years ago.
Material conditions in several areas of the plant were poor.
IFI
Weaknesses
in the Emergency Preparedness
program.
The functions of the ISEG are not described
in written
procedures.
Two examples were identified of inadequate
procedures for
related to the EDG lube oil and fuel oil duplex strainers.
A UFSAR drawing for the core spray system was changed
without performing a 50.59 safety evaluation.
Determine if the temporary change process was used to
change the intent of an operability test procedure.
A procedure
included in a PMT package was changed after
issuance
of the work package, without changing the PMt.
DERs identified several examples of inadequate
restoration of
systems after maintenance
or testing.
Configuration control concerns due to DCRs were not in the
database.
Post-job critique information was not incorporated into the
WC Mosse database.
Several examples of lubrication program problems.
UPDATED
NONE
23
LIST OF ACRONYMS USED
CFR
CGID
cps
DER
dp
ft'E
GEMS
GTS
IKC
IN
IR
ISEG
LCO
LER
MMP
NRC
psia
pslg
As Low As Reasonably
Achievable
Average Power Range Monitor
Boiling Water Reactor
Boiling Water Reactor Owners Group
Code of Federal Regulations
Commercial Grade Item Dedication
counts per second
Control Rod Drive
Deviation/Event Report
Dynamic Learning Activities
Department of Transportation
differential pressure
Environmental Protection Agency
Fire Brigade
Feedwater Control Valve
square feet
Gaseous
Effluent Monitoring System
Instrument and Controls
Information Notice
Institute of Nuclear Power Operations
Inspection Report
Independent
Safety Engineering Group
In-Service Inspection
Limiting Condition of Operation
Licensee Event Report
Local Power Range Monitor
Minimum Critical Power Ratio
Meteorological Monitoring Program
Non-Cited Violation
Niagara Mohawk Power Corporation
Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
Offsite Dose Calculation Manual
Position Indicator Probes
pounds per square inch absolute
pounds per square inch gage
Quality Assurance
Rod Block Monitor
24
LIST OF ACRONYMS USED
(continued)
RPRC
SFC
SORC
SRAB
TSSR
VDC
Program
equire ment
Radiologically Controlled Area
Reactor Recirculation System
Radiological Environmental Monitoring
Refueling Outage
Radiation Protection
Radiation Protection and Chemistry
Radiation Protection Manager
Radiation Work Permit
Safety Evaluation
Spent Fuel Pool Cooling
Service Information Letter
Special Inspection Team
Station Operations Review Committee
Safety Review and Audit Board
Source Range Monitor
Station Shift Supervisor
Shift Technical Assistant
Thermoluminescent
Dosimeter
Technical Specification
Technical Specification Surveillance
R
Update Final Safety Analysis Report
Unresolved Item
Volts Direct Current
Violation
Work Order
ATTACHMENTA
RESULTS OF THE REVIEW OF NRC IPAP
IR 50-220/96-201
AND 50-410/96-201:
LIST OF VIOLATIONS,
UNRESOLVED ITEMS, AND INSPECTOR FOLLOWUP ITEMS
'
The review of the results of the NRC Integrated Performance Assessment
Process
(IPAP)
Inspection Report 50-220/96-201
and 50-410/96-201
identified violations (VIO) and
unresolved items (URI). Some items identified by the IPAP were previously identified or
addressed
earlier inspection reports and are annotated
as such.
The details are contained
in the IPAP inspection report (IR), below is a summary of the issues identified for further
review:
1
~
(IR Section
1
~ 1) The responsibilities of the independent
safety engineering
group
(ISEG) are specified in the Unit 2 TSs.
The functions of ISEG are described
in the Unit
2 UFSAR, which discusses
that the establishment
of the ISEG is in response to the
requirements of NUREG-0737.
However, the team identified that there were no
procedures for the implementation of ISEG activities.
This is a violation of TS 6.8.1.b,
which requires written procedures
be established
and implemented to cover the
activities that implement the requirements of NUREG-0737.
(VIO 50-410/96-07-01)
2.
(IR Section 2.4) At the time of the inspection,
a procedure
upgrade program was in
progress at Unit 2 to address
problems identified in operations procedures.
The team
identify the following discrepancies:
~
The Division I and II EDG turbo lube oil duplex filter was aligned to the "BOTH"
position, based on the vendor technical manual guidance; this was in accordance
with the procedure (N2-OP-100A, Revision 5, "Standby Diesel Generators" ).
However, the team identified that the alarm response
portion of procedure
N2-OP-
100A for annunciator "Lube Oil Low Pressure Turbo" directed the operator to
swap over to the standby filter. With the filter aligned to "BOTH", there would be
no standby filter available; thus, the alarm response
procedure action could not be
performed.
~
The Division II EDG fuel oil duplex strainer was aligned such that both strainer
elements were in service.
The operating procedure
(N2-OP-100A) stated that
operation with the selector lever in the "MID"or "BOTH" position should only be
considered
if the EDG would otherwise be inoperable.
However, the selector lever
in the "BOTH" position while the EDG was operable.
Furthermore, the valve line-
up in the procedure
noted that the position of the selector lever should be "as
selected."
These represent
a violation of the Unit 2 TS, Section 6.8.1, in that procedures
were
not adequately
established
or implemented.
In addition, the above are examples of
conflicting requirements within procedures
and are indicative of an inadequate
procedure review process.
(VIO 50-410/96-07-02)
3.
(IR Section 3.3)
Unit 1 design change (SC1-0056-91) required a revision to UFSAR
Figure X-6 to change the position of the service water system screen wash pump
header inter-tie valves from normally open to, normally closed and to delete an
incorrectly shown valve.
No safety evaluation was performed because,
in the
preliminary evaluation (No. D93-113), the responsible
engineer documented that the
UFSAR was not affected because
descriptions
in the UFSAR were not changed.
The
team ascertained
that the engineer incorrectly characterized
this as an editorial change
A-1
to the UFSAR figure. The preliminary evaluation was not in compliance with
licensee's
procedure
NIP-SEV-01, "Applicability Reviews and Safety Evaluations,"
which di'd not allow minor configuration changes to UFSAR figures to be considered
as
editorial corrections.
The failure to complete the safety evaluation as required for
changes
in the facility as described
in the UFSAR is a violation of 10 CFR 50.59.
(VIO
50-220/96-07-03)
(IR Sections 2.1 and 2.2) During a review of DER 1-95-0957, the team noted that
temporary changes
were made to a Unit 1 procedure
(N1-ST-Q1B, Revision 4, "Core
Spray Loop 12 Pumps and Valves Operability Test" ) as a part of modification N1-90-
041.
This item is unresolved
pending further NRC review to determine if the
temporary changes
altered the intent of the procedure.
(URI 50-220/96-07-04)
(IR Section 2.2)
DER 1-95-1945 documented
that a procedure for post-maintenance
test (PMT) of the reactor building track bay door was revised after the work package
was issued, the revised procedure deleted some testing requirements for the door.
The operations
personnel performing the PMT were not aware of this revision.
This is
an URI pending an evaluation to determine the adequacy of the PMT performed for the
reactor building track bay door, and to evaluate the work control process for
appropriate barriers in place to prevent recurrence of similar problems.
(URI 50-220/96-07-05)
(IR Sections 2.3 and 4.2) The review of Unit 2 DERs indicated work control problems
involving restoration of systems
and components following maintenance
or testing.
For example:
an RHR pump minimum flow valve was inadvertently left shut following
a surveillance
(DER 2-94-1612); an isolation cooling system steam line drain pot level
switch variable leg isolation valve was incorrectly left shut following repacking
(DER
2-95-0237); and one train of suppression
chamber spray was disabled due to failure
to properly restore the correct valve line up following a leakage test (DER 2-95-1854).
Furthermore, the team reviewed 87 recent work packages,
and noted that mechanical
work packages
did not include a sign-off step at the end of the package to confirm
that configuration control was maintained, nor was restoration clearly documented
and
signed off in the text. This is an URI to evaluate the issues described
in the subject
DERs, whether the corrective actions taken to address
each DER were appropriate,
and to evaluate the adequacy of NMPC's controls for configuration restoration
following maintenance
or testing.
(URI 50-410/96-07-06)
(IR Section 3.2)
DERs 1-95-2051
and 1-95-1075 documented
configuration control
concerns
in electrical drawings, because
design change requests
(DCRs) initiated
several years ago were not entered
in the configuration control database.
Also,
drawings in other disciplines were noted as being affected.
This is an URI to
determine the significance of the configuration control issues documented
in the
DERs, to review the timeliness and adequacy of the corrective actions identified in
each DER.
(URI 50-220/96-07-07)
(IR Section 4.1)
The team identified that the information from post-job critique forms
was not consistently entered into the work control database
(W C Mosse).
This is an
A-2
URI to determine the procedural requirements
associated
with the post-job evaluation
and the incorporation of the critique information into the WC MOSSE database.
(URI 50-220/96-07-'08 & 50-4'I0/96-07-08)
9.
(IR Sections 2.2 and 4.3)
Lubrication program problems continued to occur at both
units:
DER 1-95-2181 documented
an error made in adding oil to Unit 1 CRD pump
¹12 bearing; DER 2-95-2848 documented
several instances of delays in preventive
maintenance
lubrication of pumps and motors at Unit 2; and DER 1-96-0739
documented that SDC pumps ¹11 and ¹13 had the motor bearing oil added to the
pump bearing and vice versa.
This is an URI to evaluate the adequacy of the
lubrication programs; the adequacy of corrective actions to address
previously
identified lubrication concerns;
and if the specific issues have been corrected,
(URI 50-220/96-07-09 & 50-410/96-07-09)
10.
(IR Section 4.5)
The mechanical seal replacement for the Unit 2 feedwater pump was
performed without a procedure,
although the work was done by a specially trained
maintenance
crew. This is an URI to determine if this practice is allowed by NMPC
procedures.
(URI 50-410/96-07-10)
(IR Section 5.2.1)
NMPC failed to conduct an incoming survey on a radioactive
material shipment.
This is an URI to determine if the failure to conduct the survey
violates NMPC procedures.
(URI 50-220/96-07-11
& 50410/96-07-11)
In addition to the violations and unresolved
items noted above, the IPAP report noted
several weaknesses.
These are listed below with an inspector follow item (IFI) number to
facilitate administrative tracking to closure.
12.
(IR Sections
1.2, 1.3, 2.2, and 4.2) Weaknesses
in the DER process were identified in
the areas of trending, root cause analysis, adequacy of corrective actions to prevent
recurrence,
and root cause analysis training. Also, the implementation of corrective
actions associated
with self-assessments,
ISEG, and QA recommendations
was not
verified sufficiently to assure that the required actions were effective,
For DER
2-95-1850, the root cause was a re-statement of the problem, the corrective actions
only narrowly addressed
the condition and did not address the cause.
(IFI 50-
220/96-07-1 2 & 50-410/96-07-1 2)
13.
(IR Section 1.1) The team identified that the ISEG responsibilities of reviewing NRC
issuances
(generic letters, bulletins, and information notices) was being performed by
other groups.
Except for issues of high interest, ISEG did not systematically review
NRC issuances
nor performed technical audits of their implementation by line
organizations.
(IFI 50-410/96-07-13)
14.
(IR Section 1.2) The team concluded that weaknesses
exist in the safety evaluations
completed by the licensee.
(IFI 50-220/96-07-14 & 50-410/96-07-14)
15.
(IR Section 3.2)
The team noted long-standing
hardware problems at Unit 2, such as
the loose parts monitoring.system, emergency
diesel generator air start system, and
A-3
The loose parts monitor issue was previously
identified as URI 50-410/95-25-02.
(IFI 50-410/96-07-15)
16.
(IR Section 2.4)
Due to the plant design, Unit 1 cannot perform a parallel transfer of
loads from the EDG to the offsite power source.
This will remain an IFI pending NRC
evaluation of the design adequacy.
(IFI 50-220/96-07-16)
t
17.
(IR Section 3.2) The temporary modification, at one of the units, for the
microbiologically induced corrosion control system for the service water system was
installed four years ago.
The temporary modification is still in service.
THE NRC
needs to evaluate the basis for the extended
installation period for the temporary
modification and plans to remove or make the modification permanent.
(IFI 50-220/96-07-17 & 50-410/96-07-17)
18.
(IR Sections 2.2 and 4.3)
Material condition discrepancies
were identified in the
rooms for the Unit 2 EDGs, the Unit 2 chilled water pumps, and the Unit 1 SDC
pumps.
(IFI 50-220/96-07-18 & 50-410/96-07-18)
19.
(IR Sections 5.3.3)
Many of the weaknesses
in the emergency preparedness
program
were related to changes
made in the EP program some time ago.
(IFI 50-220/96-07-
19 & 50-410/96-07-19)
20.
(IR Section 2.1)
LER 95-06 for Unit 2 reported the inadvertent disabling of a residual
heat removal (RHR) system suppression
chamber spray loop due to mispositioning of a
manual block valve.
During the time period that the loop was disabled, two mode
changes were made in violation of Technical Specification 3.0.4.
The LER was
reviewed in IR 50-410/95-23, and was identified as a non-cited violation.
21.
(IR Section 3.2) The IPAP team noted that DER completion dates for the corrective
and preventive actions were revised without justification. This issue was previously
identified as URI 50-410/95-25-03.
22.
(IR Section 5,3,1)
The IPAP team noted continuing incidents where personnel
had not
adhered to site radiological work control procedures
and practices.
This issue was
previously identified as VIO 50-220/96-06-05, 50-410/96-06-05."
23.
(IR Section 5.3.2)
The licensee had implemented appropriate corrective actions for
weaknesses
in the performance of security functions, such as unintentional disclosure
of safeguards
information in.a public document and a visitor entering the protected
area without a proper escort.
These issues were previously identified as URI 50-
220/94-13-03, 50-410/94-15-03
and VIO 50-410/94-18-02.
A-4