ML17056B578
| ML17056B578 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/02/1991 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17056B576 | List: |
| References | |
| 50-220-91-23, 50-410-91-23, NUDOCS 9112260023 | |
| Download: ML17056B578 (34) | |
See also: IR 05000220/1991023
Text
Report Nos.:
Docket Nos.:
License Nos.:
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
91-23; 91-23
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
October 6 through November 9, 1991
Inspectors:
W. L. Schmidt, Senior Resident Inspector
R. A. Laura, Resident Inspector
R. R. Temps, Resident Inspector
R. J. Summers, Project Engineer
Approved by:
Donald R. Haverkamp, Chief
Reactor Projects Section 1B
Division of Reactor Projects
Date
IM "w
"
p
d
"
"
""
d
" '"I
"
f
plant
operations,
radiological
controls,
maintenance,
surveillance,
security,
and
safety
assessment/quality
verification activities.
~Riltg See Executive Summary.
p~gpg g Pi i
ADOCK 0500
Nine Mile Point Vnits 1 and 2
NRC Region I Inspection Report Nos. 50-220/91-23 & 50-410/91-23
October 6 - November 9, 1991
Plant
erati
NMPC continued to operate both units safely. Good operator performance was indicated in their
response at both units to challenging events, such as the leaking feedwater heater at Unit 1 and
the loss of condenser
vacuum at Unit 2.
However, inattention to detail by operators at both
units caused notable operational problems.
Unit 1 was required to be taken sub-critical during
a startup because an operator failed to complete a startup prerequisite step properly, and.at Unit
2 a loss of condenser
vacuum was caused by operators who did not perform or verify proper
performance of a preventive maintenance activity.
R
i I
ical
nr
Radiological control activities at both units generally were observed to have been conducted
properly during the period.
However, the inspector identified a violation (410/91-23-01) of
station frisking requirements at Unit 2. Specifically, several individuals failed to complete the
required two-minute frisk with a hand-held frisker before leaving a radiologically controlled
ai'ea.
Maintenance
The maintenance activities observed indicated continued good performance in this area.
5
~
The surveillance activities observed during the period indicated continued good performance.
Inspector review of NMPC's actions to address
a previously unresolved item on the installation
and use of temporary
on the core spray systems
at Unit
1 was upgraded
from an
unresolved
item to a violation (220/91-23-02);
the NRC determined
that NMPC did not
adequately review and approve the procedure for installation and use of the gauges
so as to
assure the continued operability of the core spray system.
ecurit
Observations of security activities and tours of the plant indicated continued good performance
in this area.
Executive Summary (Continued)
f t
A
nt/
u li
V riTi ti n
Routine review of several
licensee event reports indicated that in-depth reviews were being
completed and that corrective actions were taken commensurate with the safety significance of
the issues.
An unresolved item was opened (410/91-23-03), pending further NRC assessment
ofthe appropriateness ofNMPC's actions followinginspector identification ofa cable separation
issue on a reactor core isolation cooling system valve.
Based on the Unit 1 violation discussed
above and on continued deficiencies identified with
temporary
modifications,
there
continues
to be
a problem
with the
general
employee
understanding of plant configuration changes and how they should be controlled, including the
use of required safety reviews when such configuration changes potentially affect equipment or
system operability.
As a result of a Rosemount transmitter failure, the licensee has initiated a root cause analysis.
The licensee has agreed to provide the results to the NRC when complete.
11
TABLE
F
NTK
1.0
SUMMARYOF FACILITYACTIVITIES
1.1
Niagara Mohawk Power Corporation Activities ...........
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NRC Activities
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2.0
PLANTOPERATIONS.............................
2.1
Routine Plant Operations Review - Unit 1
2.2
Routine Plant Operations Review - Unit 2
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3.0
RADIOLOGICALAND CHEMISTRY CONTROLS ..................
5
3.1
Routine Observations - Unit 1 and Unit 2 ....................
5
4.0
MAINTENANCE .... ~..................................
6
4.1
Routine Observation of Maintenance Activities .................
6
5.0
SURVEILLANCE
5.1
Routine Observation of Surveillance Activities - Unit 1
5.2
(Closed) Unresolved Item 91-20-01
Inadequate
Controls During Core
Spray Testing - Unit 1
e
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6.0
EMERGENCY PREPAREDNESS ............................
10
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~6.1
Declaration of an Unusual Event at Unit 2 ...................
10
7.0
SECURITY AND SAFEGUARDS ............................
10
8.0
SAFETY ASSESSMENT AND QUALITYVERIFICATION...........
8.1
Routine Review of Licensee Event Reports (LERs) and Special Reports
8.2
Reactor Core Isolation Cooling Cable Separation - Unit2.........
8.3
Temporary Modifications Implementation Weaknesses
- Unit 2
8.4
Safety Review and Audit Board (SRAB) Meeting of October 23 and 24
11
11
11
12
13
9.0
MANAGEMENTMEETINGS...............................
13
- The NRC inspection manual procedure or temporary instruction that was used as inspection
guidance is listed for each applicable report section.)
111
DETAILS
1.0
SVMMARYOF FACILITYACTIVITIF8
11
i
Mh
kP
r
ratinA
ii't
the beginning of the period, the Niagara Mohawk Power Corporation (NMPC) maintained
Unit 1 in cold shutdown following the September 26, 1991 automatic reactor scram caused by
a failed generator
current transformer.
Plant startup commenced
on October
10 following
replacement of the current transformer.
After reaching rated pressure,
operators identified that
second stage feedwater heater valves had been mispositioned during pre-startup valve lineups.
The unit was taken sub-critical to resolve the issue.
Once the mispositioned valve issue was
resolved, the unit startup was recommenced.
The unit achieved fullpower on October 15 and
operated
there until October
16, when one of the three high pressure
heaters
developed a tube leak.
The affected heater string was isolated and reactor power was lowered
to within the known capacity of the remaining heaters
strings (approximately 80%).
performed a safety evaluation and conducted a special test which determined that the maximum
power level achievable with only two heater strings was approximately 94%. The unit operated
at that power level through the end of the period.
NMPC operated Unit 2 at fullpower throughout the report period except for October 23, when
operators reduced power to 54% to prevent a low condenser vacuum scram.
Vacuum was being
lost, because an operator error during the performance ofa preventative maintenance procedure
on the condenser air removal pumps caused the air ejectors to be isolated.
Shortly following
unisolation of the air ejectors and recovery ofvacuum, an Unusual Event was declared because
of a hydrogen gas release into the turbine building. The release, from a broken generator sight
glass, was identified and isolated by an operator.
The Unusual Event was terminated, following
ventilation and sampling of the turbine building, and the unit was returned to 100% power,
where it operated for the remainder of the period.
1.2
N~R
An electrical distribution system functional inspection (EDSFI) was conducted at Unit 1 from
October 9 through 25.
The findings of this team inspection willbe documented in inspection
report 50-220/91-81.
Resident inspectors conducted inspection activities during normal, backshift and weekend hours
over this period.
There were ten hours of backshift (evening shift) and
14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of deep
backshift (weekend, holiday, and midnight shift) inspection during this period.
2.0
PLANT OPERATIONS
2.1
R
in
Pl nt
n Rviw-
ni
1
The inspector assessed
that routine plant operations generally were performed properly. During
the inspection period the inspectors
observed control room activities including operator shift
turnovers, shift crew briefings, panel manipulations,
and response to alarms.
The number of
lit annunciators remained low and operator response to alarming annunciators
was observed to
be proper.
Routine safety and auxiliary system operations generally were conducted in accordance
with
approved operating procedures
and administrative guidelines, except for the mispositioning of
the
second
stage
heater
low load
valves
discussed
below.
The
inspectors
independently verified safety system operability by review of operator logs, system markups,
control panel walkdowns and component
status
verifications in the field.
Operator
logs
contained a sufficient level of detail.
Specifically, the mispositioned second
stage feed water
valve and the leaking feedwater heater were both properly logged. Two markups were reviewed
and were found to provide satisfactory isolation for personnel and equipment protection.
The
inspector performed a control room panel and in-plant component alignment verification for the
core spray and liquid poison systems and no discrepancies
were identified.
erat r In tenti n
De il Re
1
in V 1v
fP iin
NMPC management took conservative actions, during plant startup, when operators identified
that second
stage feedwater heater valves had been mispositioned due to inattention to detail.
Specifically, a control room operator observed a mismatch between reactor power and reactor
pressure
and identified by control room indication that the heater light load pressure control
valves 8-31 and 8-36, were open vice shut, as required by a prerequisite
step in the startup
procedure (OP-43). The valves were subsequently shut and operations management directed that
the reactor be taken sub-critical while a reverification of the OP-43 prerequisites
was made.
This review revealed no other discrepancies
and reactor startup was recommenced.
Inspector review determined that the chief shift operator (CSO), a licensed reactor operator, who
signed offthe prerequisite step off, failed to read and perform the entire step.
The CSO closed
the valve but did not ensure that the valve controller was in manual.
Placing the controllers in
manual was in the body of the procedural step, but the sign-off sheet only reflected that the
valves were shut.
This allowed the valves to open automatically during the startup process.
NMPC investigation of this event yielded the same results as the inspector's review. Operations
management
discussed this event with all members of the operations staff emphasizing the need
for attention to detail.
The step in OP-43 was revised to improve the human factors aspect of
the sign-off. The operations manager counseled the CSO involved in the event.
The inspector
concluded that, although the event was caused by operator inattention to detail, the discrepancy
was identified by an operator which was indicative of careful attention to plant operation, and
operations management took prompt and effective corrective actions.
0
2.1.2
F
w
r H
r
R
r
On October 16, an attentive control room reactor operator noticed a step change in feedwater
flow with no power change in progress.
Investigation determined that the number 135 high
pressure feedwater heater had developed a tube leak. The steam and feedwater sides of the heat
exchanger were isolated.
The inoperability of the heater rendered its respective heater string
unavailable, thus leaving two heater strings in service.
Reactor power was lowered to 80%, the
previously set limitfor two feedwater heater strings.
NMPC performed a safety evaluation and
wrote a special
test procedure,
which allowed increasing
reactor power to determine
the
maximum achievable level with the two heater strings in operation.
The inspector reviewed
these documents and found them to be comprehensive
and to reflect a good safety perspective.
Reactor power was slowly increased to approximately 94% power before reaching the operating
limitations of the two feedwater heater strings.
The inspector determined that the tube rupture
was identified by an attentive operator at the panels.
Further, site management performed a safe
and cautious increase of power with the two remaining heater strings in service.
2.2
Routine Plant
in Rview-
ni 2
During the inspection period, the inspector observed
that control room operations generally
reflected a safety conscious approach to operations.
Turnovers in the control room were
properly conducted with good exchange ofinformation between station shift supervisors (SSS),
the assistant
SSS (ASSS), and the shift crews.
Shift briefings were generally well attended by
operations and other departmental personnel, and were conducted in a professional atmosphere.
Operations management
presence at turnover shift briefings was noted on numerous occasions.
Panel
manipulations
and alarm
response,
and routine safety
system
and auxiliary system
operations were conducted in accordance with approved operating procedures and administrative
guidelines.
The inspectors
independently verified safety system operability by review of operator logs,
system
markups, control panel walkdowns, and component
status verifications in the field.
Discussions were held with operators and technicians in the field to assess their familiaritywith
current system status and personnel response to events during the inspection period.
2.2.1
R utinePl ntT
r
Throughout the inspection period, the inspector conducted
routine tours of the plant.
The
inspector identified three concerns during these plant tours, as described below:
On October 8, the inspector identified a cable separation concern which was brought to
the attention of Unit 2 management
on October 9. The concern was with the separation
of the limit switch cabling for the reactor
core isolation cooling (RCIC) system
condensate
storage tank suction valve and non-divisional wiring for a space heater.
This
concern is discussed in section 8.2.
The inspector identified four air-operated valves in RHR pump room 'B'hich had air
leaks in their air regulators.
The condition was identified to the control room operators
and investigated
by operation personnel.
Work requests
were issued
and the leaks
repaired.
Two floor drains in the diesel generator building were noted to be taped over and
identified to the control room personnel.
NMPC uncovered the floor drains and wrote
DER 2-91-Q-1243 to track the issue.
This issue is discussed
further in section 8.3.
2.2.2
Partial Loss of Condenser Vacuum
On October 23, a non-licensed operator did not properly followand control room operators did
not provide proper oversight of a preventive maintenance
procedure,
which led to a loss of
condenser
vacuum and nearly resulted in an automatic reactor scram.
Specifically, a non-
licensed operator performing N2-PM-BM1, "Periodic Operation of the Condenser AirRemoval
Pumps," lined up the "B" condenser air removal pump, 2ARC-P1B, in preparation for running
the pump.
Although the operator had the procedure in the field, he failed to perform and sign
offseveral key steps which required repositioning ofcontrol room panel switches.
As a result,
when pump 2ARC-P1B was started from the control room, an interlock caused
the steam air
ejector isolation valve, 2ARC-AOV104, to close thus causing
condenser
vacuum to start
lowering. Had the missed procedural steps been performed, the interlock would not have been
activated.
Control room operators noticed the decreasing
vacuum and took immediate actions
to reduce reactor power to about 54% (from 100%).
Valve 2ARC-AOV104 could not be
reopened
from the control room, so'operators
were dispatched
to the field. While they had
difficulties, operators eventually reopened the valve locally allowing the air ejectors to restore
proper condenser vacuum before an automatic plant trip on low vacuum could occur.
The inspectors
determined
that the operators
responded
properly to the decreasing
vacuum.
However, as noted by NMPC and inspector followup to this event, the failure of the operator
to follow the procedural
steps
and the control room operator
starting
the pump without
understanding
the consequences
of his actions were deficiencies.
Further, NMPC determined
that it would have been more appropriate to have a licensed operator perform this procedure.
The following actions were implemented by operations
management
in response
to this and
previous recent personnel errors:
The non-licensed
operator was disciplined for failing to implement the procedure
as
written.
All operations personnel were directed to read the site administrative procedure (AP)
governing procedural
usage
and to sign a statement
acknowledging
they read
and
understood the AP. Also, this incident and the rules ofprocedure usage were reviewed
with all operators at shift briefings by operations department managers.
To increase supervisory oversight, the ASSS's duty station was moved out of the SSS
office into the control room floor area and his job duties were redefined to provide
greater oversight and control of operations related activities, and better interface with
other work groups.
The inspectors determined that the actions taken were appropriate.
However, the error in this
case is an additional example of recent attention-to-detail and procedural adherence problems at
the site, indicating that continued attention by NMPC management
is warranted.
2.2.3
nc ntrolled Relea
f
H
r
n
h T r in
B il in
On October 23, operators properly responded
to a hydrogen leak in the turbine building by
declaring an Unusual Event and by taking actions to isolate the leak and monitor for explosive
mixtures of hydrogen.
Shortly after the event described in section 2.2.2 above,
a diligent
operator, investigating a hissing sound, identified a shattered
main generator liquid detector
(sight glass) leaking hydrogen gas into the turbine building. The operator isolated the leak and
notified the control room.
An Unusual Event was declared due to the uncontrolled release of
flammable gas. At about the time the sight glass was isolated, a control room alarm (indicative
of a 25% explosive mixture of hydrogen in air) monitoring an area of the turbine building
momentarily alarmed.
Sustained alarms were not received nor were concentrations greater than
25% explosive mixture detected during manual sampling in the turbine building.
NMPC technicians
sampled
the turbine building for hydrogen pockets,
and plant managers
evaluated methods for ventilating the building. While this was going on, all activities that had
potential for igniting hydrogen pockets were suspended.
Unit2 generator hydrogen pressure fell
from a nominal 70 psig to 30 psig indicating that an estimated
10,000 standard cubic feet of
hydrogen was released.
No explosive pockets were found and the roof vents were opened to
allow ventilation of the building.
The Unusual Event was exited following the sampling and
ventilation of the turbine building.
NMPC investigation revealed that the root cause for the sight glass shattering was that it was
the wrong thickness
glass,
0.1 inches versus
the required 0.24 inch thick glass.
determined that a work request (WR) was issued before initialunit startup in 1986 to replace the
sight glass, which was broken, but the WR was later voided.
Operations personnel interviewed
remembered
the broken sight glass being repaired, however, no documentation exists for this
action.
The inspector assessed
that this incident was not indicative of a current maintenance
program weakness.
3.0
RADIOLOGICALAND CHEMISTRY CONTROLS
3.1
ine
erv
n -
ni
nl 2
During plant tours the inspector observed proper radiological postings and generally good use
of radiological practices at both units.
However, during plant tours at Unit 2 the inspector
identified deficiencies in frisking practices,
discussed
below, and continued problems with
temporary modifications by chemistry personnel to sample water systems,
discussed in section
8.3.
3.1.1 Fil r
Mee R
i
1
i IP
n
R
uirem n -
ni 2
On November 6, the inspector observed that individuals exiting a radiologically controHed area
were not properly performing the whole body frisk required prior to entering the unrestricted
(clean) area of the plant.
Specifically, personnel leaving the auxiliary boiler room at Unit 2
performed whole body frisks (hand held frisker) in significantly less time than the minimum two-
minute frisk required by the radiological posting at the step-off-pad.
After observing one
person,
which he believed
had not completed
the required two-minute frisk, the inspector
reviewed the security logs for the appropriate door to determine ifthe individual could have
properly frisked. The inspector reviewed the security logs and confirmed by the computer time
logs that the individual observed and other personnel could not have completed the frisk in the
required two minutes.
In the 30-minute time period around the inspector's field observation,
the security log indicated that eight of nine individuals failed to properly perform the frisk in
accordance with posted requirements.
This was a violation of the site s Administrative Procedure 3.3.3, Radiation Worker Conduct,
section 6.2.6 which requires in part that radiation workers follow proper radiological work
practices,
which includes observing radiological postings and step-off-pad requirements
(50-
410/91-23-01).
The inspector determined that this finding was not indicative of a programmatic
breakdown on the part of the radiation protection department,
as proper radiological controls
were in place.
This was indicative of a failure on the part of individuals to comply with a site
administrative requirement.
Whileoflow safety significance, this violation was cited due to past
NRC-identified instances of poor radiation work practices
at Unit 2 ( failure to adhere to
radiological postings while working on a control rod drive hydraulic control unit and failure of
an individual to perform a frisk when leaving a radiologically controlled area) and due to recent
problems at Unit 2 with personnel inattention to routine administrative requirements
(such as
failure to follow the markup procedure
controls
and other examples of poor procedural
adherence).
4.0
MAINTENANCE
4.1
R
ine
bservati
n fM in
n n
A
vi
'he
inspector observed and reviewed selected portions ofpreventive and corrective maintenance
to verify adherence
to regulations,
use of administrative
and
maintenance
procedures,
conformance with codes and standards,
proper QA/QC involvement, and proper equipment
alignment and retest.
The following activities were observed:
WR 197131, Investigate and repair the number 11 reactor water cleanup pump vibration
inside the bearing end ofthe motor. The inspector observed a portion ofthe maintenance
in progress
and reviewed the associated
work package.
The work in progress
sheet,
work request,
radiation work permit request,
and troubleshooting plan were reviewed
with no discrepancies
identified.
The electrical maintenance
technicians identified that
the vibration was due to a cap screw that loosened and fell out between the end bell and
shield inside the motor.
The cap
screw
was replaced.
The inspector
found the
technicians were experienced
and competent.
4.1.2
gni~2
The inspector observed troubleshooting and repair activities associated with the Division
I emergency
diesel generator
(EDG).
On October
10, the machine
was declared
inoperable as a result ofit failing to achieve its required output frequency within the TS
required time.
This testing was being conducted at an increased
frequency because of
previous failures to achieve rated frequency in the required time. Initialtroubleshooting
efforts narrowed the problem down to the fuel rack mechanism which was not operating
quickly enough during the EDG start sequence.
The air cylinder which operates the fuel
rack assembly was replaced, but under retest the EDG still failed to come up to rated
frequency in the required time.
Subsequent
troubleshooting
determined
that an air-
operated relay, that allows operating air to the air cylinder, was sticking, thus causing
the delay in the startup sequence of the EDG. Following replacement of the relay, the
inspector observed the maintenance department retest of the EDG. Review of traces in
the control room showed satisfactory results.
The EDG was then satisfactorily retested
by an operations surveillance procedure, N2-OSP-EGS-M001, and the EDG was declared
The inspectors determined that the corrective and testing actions were proper
and timely.
5.0
SURVEILLANCE
5.1
R utine
ervation of Surveill n
A tivi i
-
nit 1
The inspector
observed
and reviewed
portions of completed
surveillance
tests
to assess
performance in accordance
with approved procedures
and Limiting Conditions of Operation,
removal and restoration of equipment, and deficiency review and resolution.
'
5.1.1
nit 1
Nl-ST-Q8, Liquidpoison pump and check valve operability test. The inspector observed
the performance of N1-ST-Q8 for subsystem
11.
The subsystem failed the test due to
lower than required flow at rated pressure,
was immediately declared inoperable and a
seven-day
limiting condition
for operation
was
entered
per
A
deficiency/event report was generated
to troubleshoot the problem and the number 12
subsystem
tested immediately to demonstrate operability per TS surveillance 4.1.2.c.
NMPC investigation determined the ultrasonic flow measuring device used during N1-
ST-Q8 for subsystem
11 was yielding inaccurate data.
The surveillance was run again
per N1-ST-Q8T which determined flow by measuring the rate of water level change in
the test tank with a calibrated measuring stick. Satisfactory results were obtained using
this method and the number
11 liquid poison subsystem
was declared operable.
The
inspector determined that the operations staff properly implemented the TS requirements
and took the appropriate corrective actions to resolve the test methodology deficiency.
5.1.2
gni~2
Quarterly surveillance test of the Division IIIemergency diesel generator (EDG) fuel oil
transfer pumps.
The test was run in accordance
with procedure N2-OSP-EGF-0001,
Revision 3, Diesel Generator Fuel Oil Transfer Pump and Valve Operability Test.
The
inspector determined that the procedure was being used in the field and that it was being
followed with appropriate
signoffs made.
Good coordination
was
noted
between
operations personnel, who ran the test and recorded pump flow and differential pressure
data, and instrumentation and control (1&C) technicians, who obtained pump vibration
data per procedure N2-IMP-GENE-28.0. The inspector verified that all gauges and test
equipment used were in calibration.
The inspector assessed
this activity to be properly
performed.
'I
Calibration of air-start system pressure
gauges on the Division IIEDG.
The inspector
determined that this activity was properly conducted.
5.2
I
~nit
1
nre
lved I
m
1-2 -
1
n
l Drin
r
During the previous inspection report period the inspector identified three concerns with the
process that NMPC used to install test gauges to the bottom of pressure control valves (PCV)
in the core spray system.
Specifically, gauges were installed on the PCVs which control the
cooling water supplies to the core spray pump and core spray topping pump.
The maintenance
department installed the gauges, using a special maintenance instruction (SMI), so that setpoint
data could be obtained and adjustment made to the PCVs, ifrequired, while the system was run
during a normal quarterly surveillance
test Nl-ST-Q1A and B, Rev. 00.
However,
the
installation of the gauges and test methodology of the PCVs was never added to the surveillance
and was performed instead by a special maintenance instruction which was not an approved test
procedure.
The inspector reviewed the dispositions ofthe three deviation/event reports that were
written to address
the three concerns associated
with this matter.
The first concern
was that installation of the test gauges
was not adequately
reviewed or
evaluated by an appropriate level of plant management
and thus was an unauthorized change to
the facility. The inspector determined that the gauges were not installed and removed within an
approved
station procedure or some other acceptable
administrative control process,
and no
safety review was performed before the gauges were installed into the core spray system.
The
Unit 1 plant manager agreed with the inspector's determination and stated that the installation
of the test gauges and test methodology should have been incorporated into the surveillance test.
Specifically, AP 2.0, "Procedure Use and Control" step 3.2 states that surveillance procedures
willbe implemented to ensure the orderly, safe and efficient testing of safety related equipment
with sufficient administrative controls to provide equipment configuration control, assessment
of plant impact, and personnel
and equipment protection. If a procedure
change
had been
completed,
an evaluation would have been required to determine the safety significance of the
installation.
The second concern was that, as a result of the failure to adequately review and evaluate the
facility change, NMPC had not determined its effect upon the operability of the core spray
system when the plug from the test fittingin the bottom ofthe PCVs was removed to install and
remove the test gauges.
Specifically, the inspector questioned NMPC management
regarding
the operability of the core spray system, and whether the operation of the PCV was degraded
during that time had a core spray initiation occurred.
NMPC reviewed
this concern by
calculation S14-81-F026.
This calculation, performed by site and corporate engineering,
was
detailed and concluded that the core spray pump motor cooler flow and the core spray topping
pump bearing box cooler flow would have been adequate with the .25 inch orifice left when the
plug was removed from the test fittingon the bottom of the PCVs. The inspector reviewed this
calculation and found the overall conclusions to be acceptable.
Some minor deficiencies were
identified, apparently due to miscommunication between site engineering, corporate engineering
and the vendor, and were discussed with engineering.
Engineering stated that a change would
be issued to the package to make the necessary
minor corrections.
The third concern was that no markup (isolation) was used when the test gauges were installed
in the PCVs.
NMPC initial review of this issue concluded that no requirements
existed to
prepare
and issue a markup to support the surveillance test of the core spray system.
The
inspector took exception to this disposition because the gauges were installed and utilized under
the SMI, not the surveillance
test.
The disposition did not clearly address
the inspector's
concern.
This was discussed with the general supervisor of operations support who agreed and
re-evaluated the disposition.
Operations management determined that it was prudent to provide
the operations planning group with additional guidance on decision making related to markups.
Specifically, when a breach is made to a system that is radioactive or that could experience
pressure,
then a markup should be issued for personnel and equipment protection.
This final
resolution addressed
the inspector's concerns.
0
10
In summary, the inspector determined that NMPC had not properly reviewed and evaluated the
installation of these test gauges,
and as a result, the effect on the operability of the system was
not reviewed until after it was questioned by the inspector.
The installations of the test gauges
and testing of the PCVs were changes
to the facility and to facility procedures
that were not
adequately reviewed and evaluated
as required generally by 10 CFR 50.59 and specifically by
NMPC AP 2.0, which is considered a violation (210/91-23-02).
The actual safety significance
ofthis violation was low because the core spray system would have performed its safety function
ifcalled upon, as verified by review of the calculation package and disposition to DER 1-91-0-
11-23. The installation and removal of the gauges in the PCVs without the use of a markup was
a poor practice.
These
observations
reflected poorly on the operations
and maintenance
departments.
During review of this issue, the inspector attempted to obtain a safety evaluation, which NMPC
management
stated existed for a similar condition which arose on the containment spray system.
The inspector subsequently determined that a safety evaluation had not been performed.
Based
on followup discussions,
the inspector concluded that the operations managers
and regulatory
compliance supervisor failed to verify the validity of information from their subordinates prior
to discussions
with the inspector when they told the inspector about the evaluation.
The
providing of this erroneous
information appeared
to be inadvertent
and did not affect the
inspector's findings and NRC staff actions, as all aspects of this surveillance testing issue were
reviewed.
The need to provide complete information was discussed with the Unit 1 and Unit
2 plant managers.
Both managers
agreed with the concern and stated
that their intent was
always to provide complete and accurate information.
The inspector had no further questions
regarding this concern.
6.0
6.1
Declaration of an
nu
al Event at
nit 2
As discussed in section 2.2.3 above, an Unusual event was declared on October 23. This event
was appropriately classified and handled by the control room operators and the site management.
7.0
SECURITY AND SAFEGUARDS
During the period, the inspectors conducted plant tours and observed security guards performing
their duties, and no deficiencies were noted. Further, the inspectors conducted a perimeter fence
walkdown and noted no deficiencies.
11
8.0
SAFETY ASSESSM<24T AND QUALITYVERIHCATION
8.1
Routine Review of Licensee Even
R
ERs
and
ial Re
8.1.1
iinit 1
The following LER was reviewed and found satisfactory:
LER 91-12,
Reactor scram caused by main generator trip due to a failed current transformer.
The licensee root cause investigation determined that the failure was a short in the
current transformer windings caused by high localized ambient temperature in the
area.
The failed current transformer and two others on the phase two neutral side
were replaced.
Licensee
testing
and evaluation
determined
that immediate
replacement
of other current
transformers
was
not required.
Long term
corrective
actions
include
the
development
of a
periodic
thermographic
surveillance ofcurrent transformer in operations to identify degrading conditions.
The inspector
determined
that the root cause
and
corrective
actions
were
appropriate.
8.1.2
+nit 2
~
~
~
The following LER was reviewed and found satisfactory:
LER 91-20,
High pressure core spray (HPCS) system inoperable due to a failed instrument.
This LER documented
the failure of HPCS level transmitter 21SC*LT10D, a
Rosemount manufactured transmitter.
Problems with the transmitter was detected
during performance ofTS required 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> channel check surveillances on ECCS
actuation instrumentation.
Subsequent
troubleshooting identified the transmitter
was
defective.
The failed unit was
sent
to the vendor for specification
determination of the failure mode, however, preliminary indications are that the
transmitter suffered from a loss offilloil which is a generic problem encountered
throughout the industry with specific models of Rosemount
transmitters.
The
inspector
determined
that NMPC's program
for identifying and
replacing
detectors which suffer from this syndrome was adequate
and that the corrective
actions taken were appropriate.
NMPC has sent the affected transmitter to the
manufacturer for root cause determination.
Licensee management
has agreed to
provide NRC with the results of this evaluation when it is complete.
8.2
React r
re I
I '
lin
I
tin-
ni 2
As discussed
in section 2.2.1, the inspector identified a concern regarding the separation of
RCIC valve cabling from non-divisional power cabling. Specifically, on October 9 the inspector
identified to NMPC what appeared
to be inadequate separation between a Division I cable for
valve
2ICS*MOV129
and
non-divisional
cables.
Although
identified
on
that
date,
deviation/event report (DER) 2-91-Q-1301, describing this concern, was not issued until October
15 at which time RCIC was declared inoperable pending resolution and correction of the cable
separation
concern.
Inspector review of site procedure NMP2-SPEC-EO61A,
Appendix I,
12
indicated that a ten-inch separation
was required in this case, however, the cables were found
to be eight inches apart.
To correct this, the procedure allowed installation of a protective wrap
(Siltemp) for cases when ten-inch separation
cannot be achieved.
The inspector verified that
Siltemp was applied to the non-divisional power cables
as resolution to this problem.
This
action corrected the technical deficiency.
However, at the end of this inspection period, the
inspector was continuing the NRC review of some specific aspects of the NMPC followup to the
original concern, including why it took a week to initiate the DER and what effect the deficiency
had on the operability of the RCIC.
The inspector was still reviewing the safety significance
of this issue with respect to operability of the system and was concerned with the time it took
for the DER to be processed
and corrective actions taken.
This is an unresolved item (410/91-
23-03), pending further NRC review of the NMPC followup actions.
8.3
Tem
ra
Modifiicati n Im lemen
i n W
kn
-
ni 2
During plant tours the inspector identified two temporary modification issues, which had not
been previously identified by NMPC in their efforts to review temporary modification controls
at Unit 2.
Specifically:
Temporary Modification 89-78 initiated the addition oftubing and a temporary sampling
valve to facilitate sampling of the service water system by chemistry personnel.
The
inspector identified the following concerns to plant management:
The temporary
sampling
valve,
designated
2SWP*V1097
was
not
added
to the
appropriate SW piping and instrumentation diagram (P&ID) until eighteen months after
implementation of the TM. Further, the addition of this valve and its operation was not
reflected on the SW operating procedure valve lineup section (N2-OP-11) nor was it
called out for by valve number in the chemistry sampling procedure N2-CSP-SV.
Valve 2SWP*V912A,'pstream of valve 2SWP*V1097, required to be open while
sampling, was routinely opened and left in the open position without the knowledge of
operations personnel and contrary to its required closed position as specified in N2-OP-
11.
NMPC initiated actions to remove the TM after identification of these discrepancies,
because it was no longer needed.
NMPC also initiated action to perform a review of all
TMs to ensure that any repositionings or additions ofvalves by TMs were recognized in
prints and/or in procedures.
A DER was initiated to document the finding for corrective
actions and remained open at the end of the report period.
The inspector identified that several floor drains were taped in the diesel generator and
control building.
NMPC personnel
had
toured
this area
previously looking for
unauthorized TMs, but had not identified this issue.
Initial NMPC review considered
that the condition was not in accordance with the temporary modification procedure, AP 6.1, since the two floor drains did not have documentation supporting their being taped
over.
13
Each of these issues was of minor safety significance, and has been corrected.
However, they
do indicate that continued NMPC management attention is needed in response to the temporary
modifications concerns and inspection findings discussed in Inspection Report 91-17.
8.4
fe Rviw
A
i
r
RAB M
'n
f
r2
24
The inspector attended the SRAB meeting conducted October 23 and 24 and verified the SRAB
composition met the TS requirements.
Committee reports and audit activity reports were clearly
presented
and provided good assessment
of performance in the areas reviewed.
Open items
listed in the committee reports and audits were aggressively discussed at the meeting to ensure
proper identification of root causes
and the adequacy of proposed corrective actions. Further,
SRAB findings appeared
consistent with NRC assessment
and inspection findings, especially in
the area of human performance problems.
9.0
MANAGE<'ENTMEETINGS
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 Ireview of this report and discussions held with Niagara Mohawk representatives, itwas
determined that this report does not contain safeguards or proprietary information.