ML17056C227
| ML17056C227 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 01/05/1993 |
| From: | Larry Nicholson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17056C225 | List: |
| References | |
| 50-220-92-25, 50-410-92-29, NUDOCS 9301190052 | |
| Download: ML17056C227 (44) | |
See also: IR 05000220/1992025
Text
Report Nos.:
Docket Nos.:
License Nos.:
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
92-25; 92-29
50-220; 50-410
Licensee:
Niagara Mohawk Power Corporation
301 Plainfield Road
Syracuse,
13212
Facility:
Location:
Dates:
Nine Mile Point, Units
1 and 2
Scriba, New York
November
1 through December
12, 1992
Inspectors:
W. L. Schmidt, Senior Resident Inspector
W. F. Mattingly, Resident Inspector (in training)
. S. A. Greenlee, Reactor Engineer
P. D.
rysdale, Sen'
tor Engineer
Approved by:
Larry
. Nicholson, Chief
React r Projects Section No. 1A
Division of Reactor Projects
ate
In
ection Summar:
This inspection report documents routine and reactive inspections of
plant operations, radiological controls, maintenance,
surveillance, emergency planning,
security, and safety assessment/quality
verification activities.
Results:
See Executive Summary.
930ii900S2 930ii2
ADOCK 05000220
8
0
Executive Summary (Continued)
EXECUTIVE SUMMARY
Nine Mile Point Units 1 and 2
NRC Region I Inspection Report Nos. 50-220/92-25 I 50-410/92-29
11/01/92 - 12/12/92
Plant 0 erations
Both of the units were operated safely over the period.
Operators at Unit 2 did an excellent
job in response
to a failed reactor protection relay and in response
to the subsequent
reactor
Radiolo ical Controls
The implementation of the radiological control program was observed to be satisfactory over
the period.
Maintenance and Surveillance
Maintenance and surveillance activities conducted at both units were observed to be generally
well conducted.
The maintenance
organization responded well when a maintenance
technician removed the wrong drain plug from an emergency
diesel generator heat exchanger
causing a small contained spill of chromated coolant.
At Unit 2, a gauge with the wrong
range was installed on the 1B standby liquid control pump suction during surveillance testing.
This issue was not technically significant, since the gauge was digital and should have had
sufficient accuracy.
However, the persons verifying calibration, installing and using the
gauge did not identify and correct the problem, or did not notify the inservice testing
department and complete a procedure change as required by the surveillanc'e test. For this
reason,
and because of previous problems with the use of improperly ranged gauges during
surveillance testing, a violation was issued.
Emer enc
Plannin
During the period, the 1992 partial-participation emergency drill was conducted.
The drill
had to be suspended
for several hours to allow the site staff to respond to the reactor scram
at Unit 2.
0
Executive Summary (Continued)
En ineerin
and Technical
u
ort
Review of a 10 CFR 2.206 petition to shutdown Unit 1 was conducted with respect to a
provided list of primary containment and reactor coolant system isolation valves.
The
inspector found that the valves specified on the list were properly addressed
as not needing
testing or were being tested according to the IST plan, the technical specifications,
and the
The inspectors observed that the security force properly implemented the observed portions
of the security plan.
afet
Assessment/
ualit Verification
The post-trip review process functioned well following the November 4 reactor scram.
Plant
management
used good safety perspective and ensured that problems were addressed
prior to
plant restart.
A Safety Review and Audit Board meeting was attended and found to provide
good review and oversight of site activities.
A review of the 1992 Licensee Event Reports
(LERs) indicated that the failure to properly assess
plant impact was a common contributor to
nine separate
events.
~-
TABLEOF CONTENTS
1.0
SUMMARY OF FACILITYACTIVITIES
1.1
Niagara Mohawk Power Corporation Activities ........
1.2
NRC Activities .. ~......................
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1.2.1
NRC Receipt of Petition for Emergency Enforcement
and Request for Public Hearing on Unit 1 ~......
Action
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2.0
PLANT OPERATIONS (71707,93702)
2.1
Plant Operations Review - Unit 1
2.2
Plant Operations Review - Unit 2
2.2.1
Review of November 4 Reactor Scram....,
.
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2.2.2 Partial Loss of Offsite Power
2
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3.0
RADIOLOGICALAND CHEMISTRY CONTROLS (71707).............
5
3.1
Routine Observations - Unit 1 and Unit 2 ............ ~.......
5
4.0
MAINTENANCE(62703)
4.1
Observation of Maintenance Activities - Unit 1
4.1.1
Liquid Poison Loop 12 Pressure Tap Installation.........
4.1.2
Emergency Diesel Generator Cooling Heat Exchanger
D'isassembly
4.2
Observation of Maintenance Activities - Unit 2
4.2.1
Division II Emergency Diesel Generator Local Annunciator
Failure Troubleshooting ........................
4.2.2
Division I Emergency Diesel Generator Speed Control Failure
4.2.3
Division II Emergency Diesel Generator High Vibration Trip
.
4.2.4
High Pressure
Core Spray Valve Breaker Assembly Inspection
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5.0
SURVEILLANCE(61726)
5.1
Observation of Surveillance Activities - Unit 1
5.1.1
Average Power Range Monitor (APRM) Weekly Instrument
Channel Test.............................
5.1.2
Feedwater High Pressure
Coolant Injection Testing
5.1.3
Reactor Building Emergency Ventilation Testing ~......
5.2
Observation of Surveillance Activities - Unit 2
5.2.1
Standby Liquid Control System Surveillance Testing
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Table of Contents (Continued)
6.0
ENGINEERING AND TECHNICALSUPPORT
6..1
Unit 1
6.1.1
Preliminary Review of Primary Containment/Reactor
Coolant
System Isolation Valve Administrative Deficiencies
6..2
Unit 2
6.2.1
Temporary Modification of the Unit 2 B-Loop Recirculation
Flow Controller................. ~...........
12
12
12
13
13
7.0
SAFETY ASSESSMENT AND QUALITYVERIFICATION(40500, 71707,
92700)
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7.1
Review of Licensee Event Reports - Unit 1
7.2
Safety Review and Audit Board Meetings.... ~.............
7.3
(Open) Unresolved Item 50-220/92-24-04 and 50-410/92-28-04:
Adequacy of Corrective Actions
~ .
14
14
14
14
8.0
MANAGEMENTMEETINGS........ ~......................
17
- The NRC inspection manual procedure or temporary instruction that was used as inspection
guidance is listed for each applicable report section.
DETAI
1.0
SUMMARYOF FACILITYACTIVITIES
1.1
Nia ara Mohawk P wer
o
oration Activitie
The Niagara Mohawk Power Corporation (NMPC) operated Nine Mile Point Unit 1 (Unit 1)
safely, essentially at full power over the period.
NMPC operated Nine Mile Point Unit 2 (Unit 2) safely, essentially at full power, until a
November 4 reactor scram.
The scram resulted from the failure of a normally energized
relay in the reactor protective system (RPS).
NMPC completed their review of this event on
November 6 and restarted the unit on November 7.
Operators increased
reactor power to
100% and safely operated
the unit through the remainder of the period.
On November 15,
one of the two offsite power lines was de-energized
due to an equipment failure in its supply
breaker, located in the Scriba switchyard.
1.2
NRC Activities
Resident inspectors conducted inspection activities during normal, backshift and weekend
hours over this period.
There were 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of backshift (evening shift) and 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of deep
backshift (weekend, holiday, and midnight shift) inspection during this period.
During the week of December 7 a routine inspection of the environmental monitoring
program was conducted.
The findings of this inspection willbe documented in Combined
Inspection Report 92-28/33.
From November 3-5 the routine partial participation emergency preparedness
inspection was
conducted.
Combined Inspection Report 92-27/31 documents the observations
and findings
during the November 4 drill.
On December
1, a meeting was held with NMPC senior management
in NRC Region I to
discuss recent performance at both units.
Attachment
1 to this report provides the list of
attendees
and the presentation
material provided by NMPC.
1.2.1
NR
Recei
t of Petition for Emer enc
Enforcemen
Action and R
ue t for Public
Hearin
on Unit
1
On October 27, 1992, a petition was filed under 10 CFR 2.206, requesting that the NRC
order NMPC to immediately cease power operation at Unit 1 and place the unit in a cold
shutdown condition.
The petition further requested
that the NRC hold a public hearing
before authorizing resumption of power operation.
The basis for such an order and hearing
included concerns
that:
(1) the Unit 1 feedwater system operating in its high pressure
coolant injection (HPCI) mode does not meet NRC requirements for an engineered
safety
feature systems (ESF) grade HPCI system; and (2) 45 percent of containment isolation valves
have administrative deficiencies.
The NRC staff's initial review of this petition, documented in NRC letter dated
December 4, 1992, to the petitioner, did not identify any need for an immediate order to
shutdown Unit 1. With respect to the HPCI concern, initial staff review determined that the
emergency systems met the NRC requirements for core cooling in accordance with 10 CFR 50.46.
The feedwater system operating in its HPCI mode is not taken credit for in the 10 CFR 50, Appendix K analysis; but rather the automatic depressurization
(ADS) and core
spray (CS) systems are relied upon to depressurize
the reactor and cool the core,
respectively.
While this mode of feedwater system operation is not an ESF grade system, it
is required to be operable by technical specifications.
The inspectors reviewed and observed
portions of the quarterly surveillance testing on this system and found, as documented in
section 5.1.2 below, that it adequately
demonstrated
the operability of the system.
With
respect to the concerns on administrative deficiencies on primary containment isolation
valves, the staff found, based on the initial inspection documented in section 6.1.1 below,
that minor deficiencies exist, but that valves were being properly tested to ensure proper
operation of the isolation function.
2.0
PLANT OPERATIONS (71707,93702)
2.1
Plant 0 erations Review - Unit
1
The inspectors observed good control of plant operations by the Unit 1 operations staff.
Control room operators operated the plant safely.
NMPC took a good initiative to increase
the ability of the station shift supervisor (SSS) and the assistant
station shift supervisor
(ASSS) to supervise
the other member of the operations crews by removing walls and
rearranging their office space within the control room.
2.2
Plant 0 erations Review - Unit 2
The inspector observed good control of plant operations by the Unit 2 operations staff.
Control room operators operated the unit safely and took appropriate actions to address
problems such as the failed RPS relay discussed
below.
Operators were always aware of the
reasons for annunciated
alarms on control room panels.
2.2.1
Review f November 4 Reactor
cram
The inspector observed that the operating crew performed excellently during their response
to
the November 4 reactor scram.
The ASSS performed very well as he carried out the
emergency operating procedures
anddirected the activities of the crew.
The SSS was also
very effective at maintaining an overall assessment
of plant conditions and provided proper
oversight of the ASSS and the crew.
The reactor operators and non-licensed operators
performed well with respect to monitoring and controlling reactor vessel level and pressure
using the feedwater, reactor core isolation cooling (RCIC), safety relief valve (SRV), and
residual heat removal (RHR) systems.
While operating at 100% power, following half scram testing on the A RPS channel,
operators detected
smoke coming from one of the B RPS channel cabinets, in the back of the
control room.
The SSS opened the cabinet and observed smoke coming from what he
thought was a normally energized B RPS relay, because of its location and lack of
component identification tag.
The SSS prudently ordered that the B RPS relays be de-
energized by inserting a manual half scram of the B RPS logic. After the B RPS channel
was de-energized
the SSS determined,
through discussion with operators and instrument and
control (I&C) technicians,
that the subject relay was actually powered from A RPS (although
located in a B RPS cabinet), and thus had not been de-energized
by placing the manual scram
on the B RPS channel.
Before the SSS could order that the manual half scram be cleared from the B RPS channel
and inserted on the A RPS channel, the power supply fuse to the affected relay failed.
The
blown fuse together with the B RPS half scram caused one-quarter of the control rods to be
inserted,
as designed.
The insertion of these control rods caused reactor power to decrease
from 100% to 14%, and reactor water level decreased
due to the power transient to the low
level scram setpoint within about ten seconds.
At that point an automatic full scram occurred
and all control rods were inserted.
Operators took effective actions to control reactor vessel water level and pressure.
To limit
the plant cooldown the main steam isolation valves were shut.
Operators
used RCIC,
recirculating to the condensate
storage tank and manual opening of SRVs to control reactor
pressure,
while the steam condensing
mode of RHR was readied for operation.
Communication between the SRV operator and the other operators controlling reactor vessel
level with the feedwater system and the RCIC system was very good.
The SRV operator
noticed that one valve gave both an open and closed indication on the control panel when it
was signaled to open.
This valve was then shut and not used in the following SRV cycling
sequence.
During the SRV cycling, reactor water level changed up to 60 inches, with level
swelling as the valve was open and shrinking when the valve was closed.
These level
changes
caused
several isolations of RCIC on high level and a second low level reactor
The operations staff and plant management
exhibited very good questioning attitudes during
the post-scram review process and functioned well to ensure that issues needing resolution
were completed prior to unit restart.
The critique conducted by the reactor analyst
supervisor was very good as operators were given the opportunity to discuss their
observations
and actions.
This process
lead to the identification and resolution of several
issues that included the failure of the RPS relay, the SRV position indication problem, and
reactor water level changes during the SRV operation.
The inspector attended the pre-restart
Site Operations Review Committee (SORC) meeting and found that all the issues necessary
for restart were either dispositioned or tracked to allow disposition prior to restart.
could not determine the cause for the RPS relay failure prior to startup, but did take
thermographic pictures of the other similar relays and planned to incorporate this into a
preventive maintenance (PM) schedule.
The failed relay was replaced with an equivalent
replacement relay.
The inspector interviewed procurement personnel and reviewed the
vendor's product quality certificate, NMPC's spare parts equivalency review and the quality
control inspection reports for the replacement relay.
Alldocumentation for the replacement
relay was satisfactory.
Good discussion was observed during the review of the repair for the SRV acoustic monitor
SRV that did not have positive indication of position.
Plant management
took the necessary
actions to ensure that the monitor was operable prior to startup.
This included de-inerting
the drywell and replacing a broken acoustic pickup.
The reactor water level swings observed during SRV operation were analyzed and
determined to have been caused by actual fluctuation in the reactor level as the pressure of
the coolant was changed,
not due to gasses
coming out of solution in the reference legs of the
instruments.
The inspector reviewed the response of the RPS system to this event and found that it was
according to the design.
The reason for having RPS relays of the other division (A RPS
relays in B RPS cabinets) was for 10 CFR 50, Appendix R fire considerations,
to allow a
backup scram to occur iffire damage to one RPS channel precluded its normally energized
scram relays from opening.
NMPC submitted licensee event report (LER) 92-22, on December 4.
This LER adequately
discussed
the event and the corrective actions taken.
The LER stated that GE had provided
the industry with information on potential failures of the type of relay that failed, but that the
failure of this relay did not relate to GE's information.
The inspector considered
this LER
open pending review of the GE information and PM program on these relays.
2.2.2
Partial Loss of
ffsite Power
On November 15, with the unit operating at 100% power, offsite power line 5 was lost to
Unit 2 because its offsite supply breaker (R50) inadvertently opened.
The control room had
no knowledge of problems with the offsite breaker before it opened.
The Division I and III
(EDG) started to supply power to their busses.
Operators took
appropriate actions by parallelling the EDGs with the remaining offsite power supply and
then securing the EDGs.
Initiallyoperators could not parallel the Division I EDG with line 6
because
the operators did not have speed control of the EDG when preparing to parallel.
Operators identified a broken connector on the speed sensing probe and were able to parallel
and secure the EDG (further corrective actions on this problem are discussed
in section 4.2.2
below).
NMPC review of the R50 breaker indicated that it had tripped open on low nitrogen
accumulator pressure in its operating mechanism.
This nitrogen accumulator pressurizes
the
hydraulic operator for this breaker and is designed to trip open at a given low pressure
setpoint.
NMPC offsite maintenance determined that the shaft on the hydraulic pump, used
to keep the pressure in the nitrogen accumulator and thus the hydraulic system, had failed.
This caused the motor to run without the pressure being restored to normal.
Preventive
maintenance
on this breaker and on the other offsite power breaker (R60) had been
conducted within several weeks of this breaker failure.
This failure was similar to a previous
event that occurred when R60 opened due to low nitrogen pressure.
In that case, control
room operators
had been previously told by the offsite maintenance crew that the breaker
would not open ifnitrogen pressure
decreased.
The inspector toured the offsite switchgear and discussed
the failures of the breakers with the
offsite maintenance
personnel.
NMPC site management
directed that the independent safety
engineering group (ISEG) review the recent loss of offsite power and determine what action
needed
to be taken to limit these occurrences.
This instance was the sixth time in several
years that either a partial or complete loss of offsite power has occurred.
NMPC submitted
LER 92-23 documenting this incident on December
14, 1992.
This LER remained open
pending further inspection review of the corrective actions.
3.0
RADIOLOGICALAND CHEMISTRY CONTROLS (71707)
3.1
Routine Ob ervations -
nit 1 and Unit 2
The inspectors observed good use of radiological protection practices, proper use of
procedures,
and adherence
to postings during routine plant tours.
e
4.0
MAINTENANCE(62703)
Inspectors observed and reviewed selected activities to verify that safety-related
maintenance
was conducted in accordance with approved procedures,
technical specifications,
and
appropriate industrial codes and standards.
Observations
and reviews included verification of
the proper use of: administrative authorizations and tag outs (including lifted leads), certified
parts and materials, calibrated test equipment, proper radiological requirements,
controlled
drawings, and correctly established quality control hold points.
4.1
bservation of Maintenance Activitie -
nit 1
4.1.1
Li uid P i on
12 Pre
ure T
In
llation
The inspector observed portions of the installation of a pressure
tap between the liquid poison
pump 12 and its discharge check valve, to assist in quarterly system reverse flow testing.
Both the mechanics
and QA inspectors demonstrated
proper quality control throughout the
implementation of this simple design change.
The welding technic and post-weld inspections
were satisfactory.
The mechanics performing the maintenance
were very knowledgeable and
performed the procedure properly, using good radiological work practices and proper
cleanliness controls.
4.1.2
Emer enc
Die
1
enerator
lin
Heat Exchan er Di
sem
1
Chemistry and maintenance
technicians performed a routine quarterly inspection of EDG-102
cooling water heat exchanger 79-03.
Partial disassembly of the cooler required draining the
tube (raw water) side and removing the "floating head" at one end to gain visual access
to
the internal tubing.
The maintenance procedure directed the technicians to drain residual
water from the cooler head area by removing the drain plug on the underside of the assembly
prior to unbolting the head flange.
The procedure contained a diagram showing drain plugs
on the underside of the cooler, but did not identify the specific internal areas that could be
drained by each plug.
The technician mistakenly removed a plug on the shell side of the
cooler, draining approximately
15 gallons of potassium chromated jacket cooling water onto
surrounding equipment and floor spaces before the drain plug was reinserted.
The inspector
observed other maintenance
technicians in the diesel room respond quickly to contain the
spilled water and to prevent a release of the liquid from the building.
Environmental
protection, fire department,
operations,
and other site organizations immediately responded
to
the diesel room to assess
the potential consequences
of this spill. All maintenance work in
the diesel room was suspended
until the cause of the incident was determined and corrective
actions were taken to prevent a recurrence.
The inspector considered
the critique conducted by maintenance
to have fully addressed
the
incident and adequately identified the needed corrective actions, prior to resuming work.
The primary corrective action was to revise the maintenance procedure by clearly labelling
the different drain plugs on the heat exchanger housing.
Maintenance supervisors considered
0
that close supervisory monitoring, additional training, and detailed pre-job briefings were not
warranted for this task because of its relative simplicity. However, supervisors did advise
other personnel of the procedure change and emphasized
the specific locations of the
different cooler drain plugs.
The inspector discussed
with the system engineer potential operability consequences
related
to possible water intrusion on electrical components
near the diesel coolers.
A thorough
inspection of the diesel fuel transfer pump, the lube oil pump, and the lube oil emersion
heater was made by the system engineer and electrical maintenance
technicians.
No water
had apparently entered
these components.
Also, no additional makeup to the jacket cooling
water system was required since the expansion tank level was still in its normal band.
No
other diesel operability concerns were identified. Alladjacent surfaces on the diesel
equipment pallet were wiped to remove spilled liquid and all surrounding floor areas were
thoroughly cleaned.
The inspector considered
that the licensee's overall response
to this
event was timely and appropriate.
When heat exchanger disassembly
resumed,
the inspector observed direct supervisory
oversight in the work area.
When the cooler internals were exposed,
a site chemistry
technician performed a visual inspection of and took samples for laboratory analysis from the
internal head and tube areas.
The inspector reviewed the inspection criteria contained in the
procedure and independently verified that internal heat exchanger
surfaces on the raw water
side were in generally good condition, free from excessive corrosion and flow blockage, and
that muscle shells or fragments were not present.
Relatively small amounts of
microbiologically-induced corrosion were present on the internal surface of the cooler head,
but most of this material was removed when samples were taken.
The inspector discussed
the inspection methodology with the chemistry technician and found him to be very
knowledgeable and experienced
in this type of heat exchanger inspection.
The technician
made appropriate entries in the procedure to reflect his visual inspection.
Samples for
subsequent
laboratory analysis were properly labeled.
Overall, mechanical maintenance
technicians were knowledgeable of diesel heat exchanger
construction and disassembly/reassembly
requirements.
They demonstrated
adequate skill
and attention to procedure requirements during reassembly of the heat exchanger.
The
inspector discussed with the maintenance
supervisor the deficiency event report (DER)
written to evaluate the cooling jacket water spill and considered
that all factors associated
with the event were properly identified and documented.
4.2
ervati
n f Mainten n
Ac ivi ie -
nit 2
4.2.1
Division II Emer enc
Diesel
enerator Local Annunciator Failure Trouble hootin
The operations department and I&C technicians took conservative, timely and effective
actions to evaluate and correct a loss of power to the local Division II EDG annunciators.
During routine rounds on November 5, an operator found the local panel annunciators
0
Further investigation revealed that the isolation breaker upstream of the three
annunciator power supplies had tripped and would not reset.
The operating crew
conservatively declared the EDG inoperable and took appropriate actions in accordance with
the technical specifications (TS).
The inspector observed the annunciator troubleshooting and return to service conducted by
I&C technicians.
The technicians identified a short circuit on the output of one power supply
and properly questioned why the fuse upstream of that supply did not blow prior to the
tripping of the upstream breaker.
Further investigation identified that the three power
supplies for the annunciators
have a common output; vice supplying separate
rows of
as previously thought.
Thus, with all three power supplies feeding the fault, the
limiton the individual fuses was not exceeded,
but the combined current was enough to trip
the breaker.
The failed power supply was replaced and the Division II EDG was returned to
operable status.
NMPC initiated a DER to evaluate the adequacy of this design.
4.2.2
Divisi n I Emer enc
Diesel
enerator
S
ntr
1 Failure
The inspector determined that the operations and I&C departments
aggressively pursued
returning the Division I EDG to service following failure of the speed sensor discussed
in
section 2.2.2 above.
The inspector reviewed the work conducted and discussed
the
troubleshooting effort with the system engineer and the SSS.
A broken connector on the
speed sensor caused
the lack of control.
The connector was replaced,
the EDG was then run
to verify speed control and returned to service.
NMPC determined that the connector
apparently broke due to vibration of the wiring conduit and wrote a DER for engineering to
evaluate the mounting of the conduit.
Since the Division II EDG configuration is the same
as Division I, the evaluation willinclude the Division II EDG conduit mounting.
4.2.3
Division II Emer enc
Diesel Generator Hi h Vibration Tri
The operations and I&C departments
and the system engineer did an excellent job
troubleshooting and repairing a condition that caused
a non-emergency trip following a post-
maintenance
test of the Division II EDG.
On November 13 the EDG tripped, during its 5
minute unloaded cooldown run, on an annunciated
high vibration condition.
Troubleshooting revealed that a true high vibration condition did not cause the trip, since the
vibration trip unit was not in a tripped condition (the unit must be manually reset ifit does
trip). This trip is pneumatically actuated, with the vibration trip unit bleeding air from its
associated
pneumatic lines, lowering pressure
enough to actuate a pressure switch that
initiates an engine trip (unless an emergency signal is present).
A check valve upstream of
the vibration trip unit will normally hold sufficient pressure in the trip unit pneumatic lines to
prevent an engine trip; however, this time, it appears
that the check valve leaked enough air
to activate the vibration trip unit pressure switch.
9
I&C technicians removed, inspected,
cleaned,
and conducted a satisfactory air drop test on
the vibration trip unit pneumatic lines.
Subsequent
operation and cooldown of the diesel was
successful.
4.2.4
Hi h Pre
r
re
ra
Valve Breaker Assem
l
In
ection
The inspector observed portions of the periodic preventive maintenance
and testing on the
high pressure core spray (HPCS) suppression
pool test bypass valve, 2CSH*MOV111,
breaker assembly at the motor control center located in the Division IIIsafety-related
switchgear room.
The activity was properly performed per electrical preventive maintenance
procedure N2-EPM-GEN-V520.
Activities specifically observed included:
clean, inspect,
and test the valve open and close relays, breaker overload contacts, control power
transformer, breaker auxiliary contacts, breaker, and cubicle; and installation of the breaker
assembly into the motor control center.
Proper primary containment integrity was
maintained while 2CSH*MOV111, a primary containment isolation valve, was inoperable.
The electricians were experienced with the procedure,
knowledgeable of the breaker
assembly operation, and used proper electrical maintenance
techniques.
Electrical
maintenance supervisory involvement was good.
Based on the above observations
the
inspector concluded that the breaker assembly was in satisfactory condition.
5.0
SURVEILLANCE (61726)
The inspectors reviewed safety-related
surveillance activities by observation of testing in
progress,
interviews, and review of records and verified that:
required administrative
approval was obtained, procedural precautions
and limitations were observed,
review of test
data was accurate and timely, surveillances conformed to TS, calibrated test equipment was
used, radiological controls were observed,
and required surveillance frequencies
were met.
5.1
Observation
f urveillance Activities - Unit 1
5.1.1
Avera e Power Ran
e Monitor APRM Weekl
In trument
hannel T t
The inspector observed the weekly channel functional test on APRM 12 required by TS and
noted the following:
1) communications and coordination between the I&C technicians and
the control room operators were satisfactory;
2) the I&C technicians had an excellent
working knowledge of the procedure;
3) all required log entries were made and proper
authorization to perform the procedure was obtained; and 4) the surveillance was conducted
properly and resulted in a determination that the instrument was functioning properly.
10
5.1.2
Feedwater Hi h Pr
sure
lant In'ecti n Te tin
Operations personnel satisfactorily performed the quarterly feedwater HPCI pump and check
valve operability test following procedure N1-ST-Q3, which satisfied the periodic pump and
valve operability test required by the TS.
The test involved a reactor power reduction to
1800 MW, in order to test with two condensate
pumps in operation.
It demonstrated
that
each HPCI pump provided flow above the minimum specified at the pump differential
pressure conditions delineated by specification MDC-11, "Pump Curves and Acceptance
Criteria." The test also verified that each HPCI pump discharge check valve adequately
seated
to prevent reverse flow through an idle pump and it obtained vibration measurements
from each pump and motor as part of the plant's equipment performance trending program.
The inspector accompanied
the system engineer during the test of HPCI train 11 and
observed technicians recording flow and differential pressure
data.
The inspector
independently verified that the test data taken was as recorded and then confirmed that the
data met the acceptance
criteria specified by the procedure.
The calculations required by the
procedure using recorded test data were also verified to be correct and met specified
acceptance
criteria. All measuring and test equipment (M&TE) installed for this test was
verified to have an appropriate range for the test and was in its current calibration period.
The inspector determined that this test adequately
demonstrated
the operability of HPCI
pump 11.
The test was properly performed, and was reviewed and accepted by operations
management.
The test of HPCI train 11 was also used to provide post-maintenance
test acceptability of a
repair that was made on a pinhole leak in the 2" recirculation line from the pump to the main
condenser.
The inspector reviewed the inspection document for this repair and confirmed
that the acceptance
criteria were satisfied.
After the test of train 11, the inspector reviewed the official test results conducted the prior
week for train 12 and verified that the recorded data was acceptable for pump and check
valve operability.
5.1.3
Reactor Buildin
Emer enc
Ventilation Testin
Operators satisfactorily performed the monthly secondary containment and reactor building
emergency ventilation system operability test required by TS, over a period of several days,
according to surveillance test procedure N1-ST-M8.
One ventilation train was removed from
service for testing, while the other was kept in a standby condition.
The test involved running each emergency
fan for a minimum of ten hours, with the in-line
heaters on, while flow and d/p data was obtained to verify proper performance of the
charcoal and HEPA filters. The ability of the system to maintain a minimum -0.25 inches of
water differential pressure between the reactor building and the outside atmosphere
was also
confirmed by this test.
The inspector observed the system operating indications on the
0
0
11
control room instruments used by operators for the test.
Minor inconsistencies
in the
recorded data were noted by the inspector, but were promptly corrected by operations
personnel performing the test.
The final recorded data used for system operability were
reviewed by the inspector and were properly reviewed by site operations and technical
support personnel.
5.2
Observati
n f urveillance Activi ie -
nit 2
5.2.1
Standb
Li uid Control S stem Surveillance Testin
The inspector found that the operability and inservice testing (IST) procedure for the standby
liquid control system (SLC), adequately
met the requirements of the TS, the updated final
safety analysis report (UFSAR), and Section XI of the ASME Code.
During testing
communications between the personnel were excellent.
However, the inspector identified
that a pump suction test equipment gauge,
needed for IST data, did not meet the procedure
requirements.
Further, problems were observed with the understanding of I&C technicians
using ultrasonic flow meters and vibration instrumentation.
While observing the test, the inspector found that the M&TEpump suction pressure
had a range of 0-200 inches of water; while the procedure required the installation of a gauge
with a range of 0-100 inches of water.
Once this was identified to testing personnel the test
was secured
and declared invalid.
Review of the test procedure showed that 0-100 inch
water gauge was specified in the test equipment list, in the test equipment calibration list,
and at the installation verification step.
Further, the procedure required that ifany test
equipment was to be used that was different from that specified in the procedure the IST
department needed to be contacted and the procedure changed.
The technical significance of using the wrong pump suction pressure gauge range was low
since the gauge was digital and, therefore, should have been sufficiently accurate and
readable through most of its range; however, the inspector was concerned
that licensee
personnel failed to follow their procedures
and then subsequently
failed to note the error
themselves.
Additionally, as noted in LER 91-03, NMPC personnel have used improper
gage ranges during IST on several occasions in the past; however, the changes to the
surveillance test procedure initiated as a result of these past problems were very evident, and
should have been sufficient to prevent recurrence.
Thus, the failure by NMPC personnel to
follow the surveillance test procedure was seen as violation of TS 6.8.1 (vice ineffective
corrective actions), which requires that written procedures
be implemented for surveillance
testing (50-410/92-29-01).
Following the identification of the installation of the wrong gauge,
a 0-100 inch of water
gauge was installed and the test reperformed.
NMPC initiated a DER to resolve the gauge
installation issue.
12
During both performances of this test the inspector noted that the flow indication given by
the ultrasonic flow device increased
as the test was performed, without a change in the
system flow characteristic.
NMPC determined that the most probable cause was a drift in
the instrument's zero point, due to high background sonic energy in the pipe where the flow
was being measured
or due to an increase in the temperature of the fluid as it was circulated
to the test tank.
Following the second performance,
the flow rate was in the high alert
range.
However, once the pump was stopped (i.e., system flow was actually zero) the
ultrasonic instrument indicated some flow. NMPC initiated a DER to analyze the zero
reference drift problem.
The inspector asked the I&C technicians involved in the test about the effects on the
vibration instrument frequency response
when using the nine inch extension on the probe.
The technicians replied that the frequency response
was not changed and, thus, the probe
could be used when necessary
to get to out-of-the-way locations.
This indicated a lack of
understanding of the vibration test equipment since the use of the probe significantly effects
the frequency response.
Additionally, as indicated in LER 92-04, NMPC previously failed
to meet TS requirements
because of improper use and understanding of the nine inch probe
extension. Ifthe nine inch probe extension is used to obtain ASME Code required data on
the SLC pumps, the frequency response of the vibration instrument will not meet the
requirements.
The inspector did note that ifthe surveillance procedure was followed
correctly, the nine inch probe extension would not be used for gathering ASME Code data
and that it had not been used for this purpose during this test.
NMPC IST supervision were aware of the I&C technicians'ack of knowledge on the use of
ultrasonic flow and vibration test equipment.
They were working to reduce the number of
personnel who operate this equipment, and to increase the training for this smaller group.
The inspector had no additional questions or concerns.
6.0
ENGINEERING AND TECHNICALSUPPORT (71707, 37700)
6.i
((nit i
6.1.1
Preliminar
Review f Primar
ontainment/Reactor
oolant
tern Isolation Valve
Administrative Deficiencies
As discussed
in section 1.2.1 above, a 10 CFR 2.206 petition was received which dealt in
part with administrative deficiencies on primary containment and reactor coolant system
isolation valves.
Attachment 5 to the petition provided a list of 84 valves, and 17 associated
notes describing these deficiencies.
To ascertain ifthere were any current operability
concerns with the listed valves the inspector reviewed:
IST program plan issued on
November 2, 1992, the UFSAR, the current TS, a proposed TS amendment
dated February
7, 1992, and the numerous surveillance tests used to demonstrate operability of primary
containment and reactor coolant system isolation valves.
13
Preliminarily, the inspector found that of these 84 valves, 76 were currently in the IST
program, with appropriate testing listed including; exercise,
stroke timing, and leakage rate
testing.
Four valves were associated
with the non-safety related HPCI mode of the feedwater
system and therefore, were not in the IST plan.
Two other valves were not in the IST plan
since blank flanges had been installed upstream of the valves.
The final two valves were not
included in the IST plan since the valves did not need
10 CFR 50, Appendix J testing due to
a water seal.
With respect to differences between the TS tables and the UFSAR tables for
these valves, the inspector found that the proposed TS amendment addressed
the concerns for
valves currently considered
by NMPC to be isolation valves.
The proposed TS amendment
also clarifies the leakage rate testing requirements for valves which currently are exempted
from the requirement of 10 CFR 50, Appendix J.
Review of surveillance testing showed that
applicable testing criteria for stroke timing were being implemented. Ifa valve was
currently not in the TS tables it was being tested as appropriate with the IST plan, with
stroke times that were more conservative than those specified in the proposed TS
amendment.
The inspector also verified that valves which receive automatic closure signals
on a loss of coolant accident were properly functionally tested during the performance of the
refueling cycle loss of coolant/loss of offsite power function test.
This preliminary review did not identify any condition that would indicate that the identified
valves were not being tested to ensure their operability.
NMPC stated that this amendment
corrects all the noted problems and that once it is issued'he UFSAR will be updated.
However, the proposed TS amendment
has not been issued and is still under review by the
NRR staff.
6.2
6.2.1
Tem orar
Modification of the Unit 2 B-Loo
Recirculati
n Flow Controller
During power ascension,
following the scram on November 4, the plant experienced
significant flow oscillations on the B recirculation loop, caused by problems with the valve
stem velocity sensor for the B flow control valve.
NMPC implemented a temporary
modification to the recirculation flow controller rather than enter the drywell and repair the
sensor.
The modification, recommended
by GE, was installed and tested with a GE technical
representative
present at the site.
The most significant part of the modification consisted of
removing the velocity sensor input from the control circuit and replacing it with a signal of
constant value.
The inspector reviewed the engineering design change package and the associated
10 CFR 50.59 safety evaluation, and observed portions of the modification testing.
The inspector
found that the modification was technically sound and would allow proper operation of the
recirculation flow control valve.
Further, the safety evaluation adequately
demonstrated
that
an unreviewed safety question did not exist as a result of the modification and that TS
requirements
were not affected.
14
7.0
SAFETY ASSESSMENT AND QUALITYVERIFICATION (40500, 71707,
92700)
7.1
Review of Licensee Event Re orts - Unit I
LER 91-07, dated July 23, 1991, discussed
a reactor building emergency ventilation system
isolation due to a damaged
cable in a radiation monitor trip unit. NMPC initiallycommitted
to replace the damaged
cable during the next refuel outage; however, subsequent
engineering
evaluation determined that a permanent repair to the existing cable would be satisfactory.
The inspector agreed that the repair would be satisfactory following discussions with NMPC
personnel.
A supplement to the LER will not be issued.
7.2
Safet
Review and Audit Board Meetin
The inspector observed portions of the Safety Review and Audit Board (SRAB) meeting on
December 2, 1992, and reviewed the October 7-8, 1992, SRAB meeting minutes.
The
SRAB, composed of senior managers,
engineers,
and consultants,
technically competent in
various fields of nuclear energy, functions to provide an independent review and audit of
designated plant activities per TS 6.5.3.
Proper committee composition was present and
presentations
by various members and subcommittees
were clear and well prepared.
In-depth
discussions
were held on various safety-related
matters including:
entry into limiting
conditions for operation for planned maintenance while operating, the frequency of loss of
offsite power events at Unit 2, and engineering implementation of the software QA program.
The inspector concluded that both SRAB meetings satisfied the objectives of TS 6.5.3.
7.3
0 en
nres lved Item SO-220
2-24-04 and
0-41
2-28-04: Ad
uac
of
orrective Action
As part of the effort to assess
the adequacy of recent corrective actions, the inspectors
reviewed all of the 1992 LERs for both units.
The most common similarity between the
events was the failure of NMPC personnel to assess
adequately
the plant impact associated
with various conditions and actions.
During 1992, nine reportable events were caused,
at
least in part, by improper assessment of the potential affects of operations and maintenance
activities.
A brief summary of each event is listed below.
Any violations of regulatory
requirements
have been addressed
in previous inspection reports.
Unit 1
~Januar
10 and 22
I
2 LER
2-01
- Operators failed to take actions required by the
Unit 1 TS when portions of the turbine stop valve closure scram and the generator load reject
scram were bypassed
at greater than 45% power.
The bypass conditions occurred because of
an equipment malfunction together with an improper valve lineup.
The operators were aware
of the problem because of an annunciator indicating that the main turbine first stage pressure
was low.
0
15
The most significant cause of the operator's failure to follow the TS was that they apparently
did not fully understand
the implications of the turbine first stage pressure instrument sensing
a low pressure condition.
Further, the abnormal alarm was not logged by the operating crew
and a DER was not written.
~ Februa
21
1
2 LER
2-
- The plant was isolated from its ultimate heat sink (Lake
Ontario) for approximately five minutes.
This was a result of closing the screenhouse
forebay, with the plant in a reverse flow condition, and the subsequent inability to reopen
Gate D immediately.
Gate D was closed to test its control circuit following modification.
A contributing cause of this event was that operators
and maintenance
supervision failed to
assess
adequately
the potential impact of closing Gate D on the plant.
~
Se tember 4-5
1
2
LER
2-10
- Several instances occurred where the minimum
number of operable reactor trip system channels was less than required.
This resulted
from bypassing two intermediate range neutron monitors because of anticipated
"spiking," then subsequently placing average power range neutron monitors in bypass
for various operational and maintenance
reasons.
The most significant cause of this event was that the control room operators did not
correctly assess
the effect of concurrently placing various neutron monitors in a
bypass condition.
Unit 2
~Janua
1
1
2 LER 92-03
- An unexpected
secondary containment isolation signal was
received when workers de-energized
a reactor building ventilation system radiation monitor
(the above refuel floor monitor).
The system responded correctly to the loss of power.
The cause of this event was a failure to perform an adequate job/plant impact assessment
prior to commencing work on the radiation monitor.
~
March 2
1
2 LER
2-06
- The plant lost both 115 kV offsite power sources,
lines 5 and 6.
Line 5 was lost when technicians accidentally actuated
an over-current
relay during maintenance.
Line 6 was subsequently
lost when operators attempted to
cross-tie it to the line 5 loads.
Line 6 was isolated from the plant, by design, because
of interlocks (associated
with the over-current relay trip) that were affected when the
cross-tie was attempted.
16
The cause of this event was a failure to perform an adequate job/plant impact
assessment
prior to commencing work on the over-current relay.
Additionally,
operators compounded
the event by improperly assessing
the impact of the relay trip
on the ability of line 6 to supply line 5 loads.
~
Jul
28
1
2 LER 92-18
- The plant lost 115 kV offsite power line 6 due to failure
of its associated
offsite supply breaker; however, NMPC personnel were aware that
the breaker was experiencing problems more than thirteen hours before the trip; but
they improperly assessed
that the malfunction would not cause the breaker to trip.
A significant contributing cause of this event was a failure to perform an adequate
plant impact assessment
of the breaker malfunction.
~
Au u t 22
1
2
LER 92-17
- The reactor scrammed
on low reactor vessel water
level during an attempt by the control room operators to switch feed pumps.
The cause of this event was improper operation of the feedwater and condensate
systems.
The operators did not understand
the consequences
of some of their
manipulations of these systems.
Se tember 16
1
2 LER
2-1
- The plant experienced
an automatic isolation of
the reactor water cleanup system (an engineered
safety feature) due to a high
temperature condition in the reactor water cleanup system pump room.
The high
temperature condition was caused by an improper ventilation system configuration.
The improper configuration was established during maintenance
on the emergency
recirculation unit coolers.
The cause of this event was a failure to perform an adequate plant impact assessment
of the maintenance
on the emergency recirculation unit coolers.
e tember 2
1 92
LER
2-20
- The plant lost 115 kV offsite supply line 5 when a
crane boom, being used to place concrete,
came close to the line, and the resulting
arc through the crane to the ground caused
the line to trip.
A possible contributing cause of this event was a failure to perform a plant impact
assessment
of the work. Ifthe work had been assessed
for plant impact, and had
been coordinated with the control room, the incident might have been prevented.
The corrective actions for each event listed above have generally been good when
considering the individual event and possibly one or two past events.
The corrective actions
tended to focus on fixing or creating procedures,
letting other personnel know about the
event (via a Lessons Learned Transmittal), and conducting some specific event related
17
training.
The corrective actions have not, however, focused on the broad scope of failures to
assess
adequately
the impact of various operations and maintenance activities.
NMPC was
conducting their own analysis of past LERs for the adequacy of corrective actions.
This
unresolved item remains open pending further inspector review.
8.0
MANAGEMENTMEETINGS
At periodic intervals and at the conclusion of the inspection, meetings were held with senior
station management
to discuss the scope and findings of this inspection.
Based on the NRC
Region I review of this report and discussions
held with Niagara Mohawk representatives,
it
was determined that this report does not contain safeguards
or proprietary information.
0