ML20211A467
| ML20211A467 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 02/06/1987 |
| From: | Linville J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211A317 | List: |
| References | |
| 50-220-86-26, 50-410-86-65, NUDOCS 8702190175 | |
| Download: ML20211A467 (15) | |
See also: IR 05000220/1986026
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
86-26/86-65
Docket No.
50-220/50-410
License No.
DPR-63/NPF-54
Category B
Licensee:
Niagara Mohawk Power Corporation
301 Plainfield Road
Syracuse, New York 13212
Facility:
Nine Mile Point, Units 1 and 2
Location:
Scriba, New York
Dates:
November 17, 1986 to January 4, 1987
Inspectors:
W.A. Cook, Senior Resident Inspector
J.E. Kaucher, Resident Inspector, Limerick 2
C.S. Marschall, Resident Inspector
G.W. Meyer, Project Engineer
W.L. Schmidt, Resident Inspector
Approved by:
A
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r#Tinift e,/ Chief, Reactor
Dat'e
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rojects S tion 2C, DRP
Inspection Summary:
Inspection on November 17, 1986 to January 4, 1987
(Report No. 50-2'20/86-26 and 50/410/86-65
Areas Inspected: Routine inspection by resident inspectors of station activi-
ties (including Unit I operations and Unit 2 MSIV progress), plant tours,
surveillarce testing, safety system walkdowns, Licensee Event Reports (LERs)
review, allegation followup, review of Unit 1 Reactor Building Closed Loop
Cooling heat exchanger concerns, and a review of a 10CFR50.55(e) report.
This
inspection involved 354 hours0.0041 days <br />0.0983 hours <br />5.853175e-4 weeks <br />1.34697e-4 months <br /> by the inspectors. Two violations were identi-
fied.
Results: Unit 2 MSIV progress is discussed in section 2.a and Standby Gas
Treatment System Problems are discussed in section 2.b.
Details of a violation
involving ineffective corrective action for a SDV High Level scram are
discussed in section 2.1.
Unit 1 and 2 control room activities are discussed
in section 3.
A violation was identified at Unit I which concerns a momentary
breach of Reactor Building Integrity while in the power operating mode.
Details are provided in section 3. Unit 2 allegations concerning MSIV actuator
hydraulic fluid and Control Room HVAC are discussed in section 7.
An unresolved item regarding the Unit 1 RBCLC heat exchanger No. 13 is
discussed in section 8.
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DETAILS
1.
Persons Contacted
The inspectors interviewed and discussed station activities with various
licensee representatives and contractor personnel.
2.
Summary of Plant Events
UNIT 1
The plant operated at full power throughout the report period with power
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reductions for weekly control rod exercising and control rod pattern
adjustments.
UNIT 2
a. Main Steam Isolation Valve Review
The resident inspectors continued to closely monitor licensee's progress
in resolving Main Steam Isolation Valve (MSIV) problems. A region based
inspection was conducted the week of December 1, 1986, the results of
which are documented in Inspection Report 50-410/86-67.
Resident
inspector coverage and licensee progress are noted below:
(1) Repairs to the damaged body of MSIV 6D were completed the week of
November 17, 1986 and the valve was reassembled and subsequently leak
tested unsatisfactorily. When dissassembled, the ball showed signs
of smearing of the stellite seating surfaces and scratching of the
tungsten carbide coating. The ball stem also showed signs of
abrasion damage.
The licensee attributed both the damage to the stem
and coating to misalignment of the valve bonnet.
(2) On November 20, a newly coated ball was installed in the 60
MSIV body and the. leak test results were again unsatisfactory. A
different type of packing was used for this valve reassembly and it
became suspect as the cause of the leakage. Crosby was consulted and
a different type of packing was obtained and used. The valve was
reassembled and it passed the Type C leak rate test. The new Crosby
recommended packing was used in all subsequently reassembled valves.
(3) By the first week in December, all eight valves were reassembled and
the actuator modifications were completed. Wiring and logic testing
was then conducted which verified proper circuit response. On
December 3, a condition was discovered in the circuitry which
resulted in the paralleling of both Reactor Protective System
electrical power supplies. The event which lead to this discovery is
discussed in further detail in section 2.f.
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(4) Preoperational and surveillance testing was performed the week of
December 15 to verify proper valve operation.
Except for some minor
limit switch adjustments, all valves operated properly. All MSIVs
met the three to five second closing time requirement.
(5) On December 20, the official Type C leak rate testing was performed
on all eight valves. MSIV 6B was the only failure, with a leak rate
of 8.9 SCFH. The valve was dissassembled and the ball showed
scratching and flaking of the tungsten carbide coating, similar to
the initial failure condition, although less severe. The bonnets
were removed from valves 6C and 6D to allow inspection of the balls.
Only minor scratching of the 6C and 60 ball coatings was observed.
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The licensee conducted additional testing of the 6B MSIV ball in the
70 valve body to better quantify the failure in terms of leakage,
b.
During this inspection period, several problems have occurred which
have either caused the Standby Gas Treatment (SBGT) System to auto-
matica11y initiate or to function improperly.
(1) On November 25, the SBGT system train A automatically started
due to a low flow condition in the Normal Reactor Building
Ventilation System. At the time the event occurred, prepara-
tions were being made to conduct the monthly surveillance on the
Reactor Building Ventilation Effluent Radiation Monitor. A
jumper installed on a ventilation damper control circuit was not
securely attached and fell off. When the jumper fell off, it
shorted to ground and caused the Reactor Building Ventilation
System to isolate. Licensee Event Report (LER) No. 86-09,
submitted on December 23, documented this event.
(2) On November 27 and December 8, SBGT automatically started due to
spiking of the Reactor Building Below the Refuel Floor Effluent
Monitor.
LER No. 86-11, submitted on December 26, documented
this event.
(3) On November 28, SBGT automatically started due to a low flow
condition in the Normal Reactor Building Ventilation System.
The cause of the low flow condition was not clear. The
initiating event was a trip of the reactor building ventilation
supply fan. The operator who responded to the local ventilation
control panel did not thoroughly review the alarms on the panel
prior to resetting those alarms. The operator's observations
would have been particularly helpful since the progression of
events was uncertain.
The licensee concluded two possible causes for the low flow
condition: 1) the flow from one supply fan with two exhaust fans
running reduces the exhaust flow to below the trip setpoint, or,
2) the two running exhaust fans drew down the reactor building
pressure to 3" WG below atmospheric and then both tripped on
high reactor building differential pressure.
Review of the
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alarm printer indicated that only the ventilation low flow
condition existed prior to the fan trips.
LER No. 86-12,
submitted on December 23, documented this event.
(4) On December 7, during the performance of a surveillance on SBGT
System train B, operators observed that the heaters were not
energized, as designed.
The heaters are controlled by an
internal system flow switch. During the first phase of system
operation, reactor building air is removed to create the
required negative pressure. When proper reactor building
pressure is established, the system enters a recirculation mode
to maintain that pressure.
During the drawdown stage, the
heaters were energized.
In the recirculation mode, the heaters
deenergized due to low flow sensed by the flow switch. The SBGT
System train A exhibited the same heater control / flow switch
problem.
Licensee engineering evaluation resulted in a change
to the flow switch pressure sensing points to provide a better
indication of actual flow through the SBGT train.
(5) On December 31, a Reactor Building Ventilation Effluent Monitor
(HVR-RE14A) failed a surveillance test and was declared inoper-
able. To allow maintenance on the monitor, the monitor was
taken out of service and train A of SBGT System was started.
Train B of SBGT, which was left in standby mode, automatically
started due to a low Reactor Ballding to atmosphere differential
pressure. The licensee determined that the low reactor building
differential pressure appeared to have been caused by wind
effects on the atmospheric pressure sensing line.
(6) On December 31, while observing operation of the SBGT System,
the inspector noted that the instrument used to monitor the
differential pressure across one of the charcoal filter units
was pegged high (greater than 2" WG).
The inspector reported
his observation to the control room and determined that this
problem had been previously identified by shift operators and a
station Problem Report was generated on December 24.
All of the above automatic SBGT System actuations were reported to
the Headquarters Duty Officer via the ENS.
The resident inspectors
will review itcensee resolution of the above stated problems in a
subsequent inspection period.
c.
On 11/17, the licensee determined that some field run concrete
embedded conduit, for lighting and communications cabling, did not
contain the required fire seals. Control Rod Drive testing was
temporarily suspended, pending an engineering evaluation of the
potential impact on secondary containment integrity.
Drawings were
reviewed and inspections were conducted of the affected areas. No
secondary containment barriers were found to contain field run conduit
and control rod drive testing was then resumed.
The inspector observed
some of the conduits in the Control Building and concluded that due
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to the small diameter, the cover plates in the opennings, and the lack
of straight through penetrations, these conduits were unlikely to be a
technical problem. The inspector reviewed licensee corrective action
and determined it was both adequate and timely in addressing this
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deficiency.
LER No. 86-08, submitted on December 17, documented
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this event..
d.
On November 20, two consecutive half scrams occurred due to a loss of
power to Reactor Protection System (RPS) Channel B.
The power was
lost from the Uninterrupted Power Supply (UPS) 3B which supplies RPS
Channel B logic and trip circuits. The licensee found that in both
instances the Electrical Protection Assemblies (EPAs) downstream of
UPS 3B had tripped.
The licensee is still investigating the cause
of the EPA trips. All trip settings were tested and found within the
acceptable range.
LER No. 86-07, submitted on December 19,
documented this event. The resident inspectors will review licensee
final resolution of this event in a subsequent inspection period.
e.
On November 23, with all rods fully inserted, a Group 2 control rod
scram occurred. The Group 2 scram was a result of a loss of power to
the Group 2 RPS Channel A scram pilot solenoids, concurrent with a
half scram on RPS Channel 8 due to an Average Power Range Monitor
(APRM) surveillance test in progress. The licensee suspects the loss
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of power to the Group 2 Channel A scram pilot solenoids was caused by
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the inadvertant removal of fuses to the Group 2 scram pilot solenoid
relays, while hanging a tagout on adjacent relay fuses. The licensee
notified the NRC HQ Duty Officer of this scram via the ENS. The LER
has not been issued as of the end of this inspection period.
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f.
On December 3, while performing energized logic checks of the 70 MSIV
actuator circuits, a full scram occurred. Both the 3A and 3B UPSs
lost power, causing both RPS scram sensor busses and all scram pilot
valves to deenergize.
The licensee traced the cause of the UPS power
loss to technicians performing logic checks of the MSIV trip solenoid
power supply transfer circuits. MSIV trip solenoids are normally
powered from either the 3A or 3B UPS. When the trip solenoid's normal
power supply is lost, a transfer circuit energizes the trip solenoid
from the other UPS, thereby, preventing MSIV closure on the loss of
one UPS. During logic testing, a condition simulating the loss of
power to the trip solenoid, without actual deenergization of the UPS,
was initiated. The transfer circuit switched power to the alternate
UPS, but for an instant the two UPSs were paralleled. Because of
another unrelated problem, both power supplies were momentarily
paralleled out of phase. This transient caused both UPSs to experience
voltage and current surges which resulted in both power supplies being
electrically isolated by their respective protective devices. The
licensee has subsequently made a modification to the MSIV trip solenoid
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circuit which they consider prevents the possibility of paralleling
UPSs. This modification is currently under review by the NRC staff.
LER No. 86-15, submitted on December 23, documented this event.
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g.
On December 10 and 11, three automatic High Pressure Core Spray
(HPCS) system initiations occurred.
The HPCS pump started and went
into recirculation and the Division III diesel generator started and
ran unloaded, as designed. Water was not injected into the core
because of the high (actual) water level inje: tion valve interlock
prevented the injection valves from opening. The licensee initially
attributed the actuation signal to bumping the reactor vessel level
transmitters.
Further evaluation by the licensee determined that the
suspect reactor vessel level transmitters' sensing lines have a
flexible tubing section just outside the containment penetration.
Bomping this flexible section of sensing line duplicated the low
reactor water level HPCS start signal.
The licensee has roped off
the area around the flexible sections of sensing lines tb prevent any
further mechanical agitation.
The potential for air entrapment in
the sensing lines was discussed with licensee representatives who
committed to review this as a potentially contributing factor. The
inspectors will review licensee action in a subsequent report period.
n.
On December 16, the A train of Group 8 of the Primary Containment
Isolation System (PCIS) actuated when a testing error resulted in a
blown fuse in the power supply to the PCIS Group 8 train A relays.
During wiring checks of the Off Normal Status Panel of PCIS, a SWEC
technician erroneously connected a 125 VDC circuit to a 125 VAC
circuit. The Group 8 systems which isolated included: cooling flow
to the recirculation pumps; containment atmospheric monitoring;
drywell instrument air; and drywell equipment drains. The systems
responded as designed.
Immediate corrective action included
replacement of the fuse, restoration of the isolated systems, and
suspension of further wirinq checks.
The inspectors will review
licensee long term correctDe action in a subsequent report period.
1.
On December 15, the Scram Discharge Volume (SDV) High Level Trip was
not bypassed prior to resetting a manually inserted scram.
The mode
switch was moved from REFUEL to SHUT 00WN and the expected scram
signal was received. This scram was reset and approximately one
minute later a second scram was received due to the SDV High Level
Trip.
This event is similar to an event which occurred on November 5, when
the SDV High Level Trip was not bypassed prior to resetting a scram
and a second scram due to 50V High Level subsequently occurred.
The
November 5 event was documented in Inspection Report 50-410/86-56 and
by the licensee in LER No. 86-01.
Licensee corrective action taken
in response to the November 5 event was apparently ineffective in
preventing a recurrence.
This is contrary to the requirements of
NMPC Quality Assurance Topical Report, Section 16, Corrective Action,
and the requirements of 10CFR50, Appendix B, Criterion XVI, and is a
violation. VIOLATION (50-410/86-65-01)
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On December 18, both Division I, Low Pressure Core Spray
(LPCS) and Low Pressure Core Injection (LPCI), Emergency
Core Cooling Systems initiated and injected water into the
Reactor Vessel. The initiation signal was a spurious high
drywell pressure caused when a relay was being replaced in
the Reactor Core Isolation Cooling System.
The Division I
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diesel generator started, as designed. One of the two
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diesel room fans did not start automatically and required
manual starting from the control room. When the injection
was verified to be from a spurious signal, all systems were
returned to their normal standby status.
The inspectors
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observed no deficiences.
k.
On December 22, due to the simultaneous draining of all three fuel
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oil day tanks, all three Emergency Diesel Generators (EDGs) were
automatically disabled.
Each day tank was partially drained to its
respective storage tank in preparation to run its associated fuel oil
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transfer pump.
The transfer pump had to be run in order to draw a
representative sample for chemical analysis. When the day tank low
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level alarm was received, its respective EDG start logic locked out
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any automatic start signal.
Control room operators immediately
identified the problem and had the day tank levels restored to their
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normal level. The licensee notified the Headquarters Duty Officer,
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via the ENS, that the EDGs had been momentarily disabled. The
inspectors will review licensee analysis of this event and their
corrective action in a subsequent reporting period.
During review of this event, the inspectors noted that the logs in
each Emergency Diesel room did not indicate that a problem had
existed or that the chemistry surveillance had been performed.
The
resident inspectors discussed the adequacy of the EDG logs with the
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licensee and will monitor the logs for improvement in subsequent
reporting periods.
1.
On December 26, one of the twenty-six fire detectors which makeup the
Reactor Building 2625W Detection Zone System was found inoperable.
The detector was out of service for approximately 63 hours7.291667e-4 days <br />0.0175 hours <br />1.041667e-4 weeks <br />2.39715e-5 months <br /> and
compensatory action was not taken.
This was contrary to Technical
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Specification (TS) 3.3.7.8, which states, in part, that if a detector
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is inoperable for more than one hour, an hourly fire patrol of the
affected area is required. As provided for in 10 CFR 2, Appendix C,
Section V, a Notice of Violation is not being issued for this
licensee identified TS violation.
This TS violation was promptly
reported to the NRC by the licensee.
The violation is of minor
safety significance, in that, the loss of the single detector did not
seriously degrade the overall effectiveness of the detection system.
The licensee corrective action was timely and positive, in that, upon
identification of the inoperable fire zone detector, a fire patrol
was immediately established.
In addition, the licensee is conducting
retraining of all fire brigade personnel on the proper control of
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fire protection equipment and has initiated procedural revisions to
improve fire protection system administrative controls.
There have
been no previous events of this nature at Unit 2.
m.
On January 1, Division I and II batteries were declared inoperable,
based on an unsatisfactory surveillance test. During the performance
of the surveillance test, corrosion was noted on several terminals
and a high resistance was found on one connection. The licensee removed
the corrosion from the battery terminals and the one high resistance
connection.
Subsequent resistance checks were completed satisfac-
torily. The inspector observed that the terminals appeared to have
varying amounts of corrosion inhibiting grease applied to them. The
inspector discussed this inconsistency in grease application with
licensee representatives and the vendor. The inspector determined
that the amount of lubricant is inconsequential as long as the
terminals and connectors are completely coated.
3.
Plant Inspection Tours
During this reporting period, the inspectors made frequent tours of the
Unit I and 2 control rooms and accessible plant areas to monitor station
activities and to make an independent assessment of equipment status,
radiological conditions, safety and adherence to regulatory requirements.
The following was observed:
Unit 1
The Unit I control room atmosphere was evaluated on a frequent basis
during this reporting period. Few distractions were present and operator
knowledge of plant status was generally good, as demonstrated by an
infrequent need to refer to other sources for an accurate plant status.
As appropriate for an operational control room, noise level was low, only
personnel with official business were present, and the control room was
clean and free of extraneous material.
On December 10, 1986, during full power operations, the resident inspector
observed a security guard momentarily breach secondary containment. The
guard, who was responding from inside the reactor building to an alarm
condition for the reactor building outer airlock door, waited three to
four minutes for the outer airlock door to close. Assuming that the outer
airlock door was slightly ajar or that a malfunction had occurred in the
red light indicating that the outer door was open, the guard opened the
inner airlock door to investigate the cause of the alarm. When the guard
discovered that there were people in the airlock and that the outer door
was still open, he quickly closed the inner airlock door.
Technical Specification 3.4.0 requires secondary containment integrity during
reactor power operations.
This is a violation.
(50-220/86-26-01).
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When station management was notified of this breach of secondary contain-
ment integrity, the licensee immediately counseled the responsible
individual concerning the correct actions to be taken when responding to
an alarm at an air lock door, if the red light prevents entry. On
December 12, 1986, the licensee drafted a memo to clarify the procedure
for assessment of alarms generated at air lock doors and the proper
actions to take if entry through an air lock door is prohibited. This
memo received wide distribution in the security department. This correc-
tive action was acceptable.
Unit 2
The control room atmosphere continues to be closely evaluated. During the
initial fuel load and open vessel testing phase, the number of operator
distractions and unnecessary traffic in the control room showed improve-
ment. Since the completion of Control Rod Drive testing, this trend has
not continued. The number of people not conducting official business and
traffic through the Control Room have increased.
The inspectors observed that all channels of the Unit 2 public address
system (HEAR-HERE) are announced in the control room, regardless of their
applicability to personnel in the control room. These non essential
announcements add to the noise level in the control room and appear to be
unnecessary. This observation was discussed with licensee management, who
acknowledged the concern, but did not consider the miscellaneous
announcements to be overly distractive.
Plant readiness for initial criticality, with respect to housekeeping, has
shown some improvement.
4.
Surveillance Testing Review
The inspectors observed portions of the surveillance test procedures
listed below to verify that the test instrumentation was properly cali-
brated, approved procedures were used, the work was performed by qualified
personnel, limiting conditions for operation were met, and the system was
correctly restored following the testing.
N2-OSP-GTS-M001, Standby Gas Treatment System Functional Test,
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revision 0, August 1986, performed on December 22, 1986.
Control Rod Drive System Testing performed in accordance
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with N2-SVT-5-0V, during the week of November 17, 1986.
MSIV circuit and logic checks and preoperational testing at
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Unit 2 was periodically monitored this inspection period.
No violations were identified.
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5.
. Safety System Operability Verification
On a sample basis, the inspectors directly examined selected safety system
trains to verify that the systems were properly aligned in the standby
mode. The following systems were examined:
Unit 2
High and Low Pressure Core Spray Systems
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No violations were observed.
6.
Review of Licensee Event Reports (LERs)
The LERs submitted to the NRC were reviewed to determine whether the
details were clearly reported, including accuracy of the description of
the cause and adequacy of the corrective action. The inspectors also
determined whether the assessment of potential safety consequences had
been properly evaluated, whether generic implications were indicated,
whether the event warranted on site follow-up and whether the reporting
requirements of 10 CFR 50.72, where applicable, and 10 CFR 50.73 had been
met.
During this inspection, the following LERs were reviewed:
UNIT 1
LER ,#,
Event Date
Subject
86-23
8/1/86
Failure to Perform Testing Within
Required Interval - Fire Protection
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System and Radiation Protection
86-29
9/10/86
Failure to Perform Testing Within
Required Interval - Torus
Temperature Monitoring System
86-34
12/6/86
Loss of Stack Sample Flow Due to
Software Problem
LER 86-23 and LER 86-29 document events associated with Technical Spect-
fication violations due to failure to perform a surveillance within the
required interval. Each of these failures was identified as a result of
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the licensee's implementation of a computer based program to control
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scheduling of surveillances.
Since the violations were licensee identi-
fled, of minor significance, reported as required, immediately corrected,
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could not have reasonably been prevented by corrective action for previous
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violations, and recurrence is prevented by the computer based program
which ideritified them, no Notice of Violation is issued for these events.
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LER 86-34 describes a violation of Technical Specification 3.16.14 b which
requires continuous monitoring of radioactive gaseous process and
effluent.
LER 86-02 reported a similar event and identified a Technical
Specification conflict which requires a unit shutdown be initiated when a
loss of stack gas effluent monitoring occurs.
In the December 6, 1986
event, a technician made a judgmental error in deciding not to report the
loss of stack gas monitoring, since the actual loss of monitoring was less
than an hour in duration. When licensee management became aware of the
event, immediate action was taken to counsel the technician regarding his
responsibility to notify the Station Shift Supervisor of changes in plant
equipment status and a standing order was issued to all chemistry techni-
cians to emphasize this requirement.
In addition, the licensee has
included review of this event in the requalification training for
chemistry technicians. The amendment to Technical Specification 3.16.14b, which the licensee identified as a corrective action in
LER 86-02, revision 1 dated July 1, 1986, has not been submitted to the
NRC for review as of the end of this inspection period. Since this unique
event is of minor safety significance, was identified and reported by the
licensee, and adequate action has been taken to correct the technician's
error and prevent recurrence, no Notice of Violation is issued for this
event.
UNIT 2
LER #
Event Date
Subject
86-01
11/5/86
Upscale Trip and SDV High Level
86-02
11/4/86
All SRM Downscale
Channels Jumpered for Two hours
86-03
11/8/86
Partial Loss of Secondary
Containment Isolation Actuation
Instrumentation
86-04
11/9/86
Trip
86-05
11/5/86
Loading of fuel in the quadrant
with SRM Channel C bypassed
The violations and events described in the LERs listed above were
previously reviewed and documented in Inspection Report
50-220/86-21 and 50-410/86-56, Section 2.
An Enforcement Conference was
held on January 8, 1987 to discuss the violations.
A meeting was held with station management to discuss their overall
approach to LER preparation and review, on December 17. The inspectors
discussed three specific LERs and the problems found during their review
to illustrate their findings.
In general, the LERs had adequate details
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of the events, but the corrective actions specified lacked a proper root
cause analysis. Some technical errors were identified in the LERs which
should have been identified and corrected during the licensee's review
process, prior to submittal. The licensee plans to correct and submit
revised reports for the three LERs discussed (LER No's 86-02, 86-04, and
86-05).
In addition, to address the general concern for proper LER
preparation and review, the licensee plans to revise their LER control
procedure.
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7.
Allegation Followup
During the inspection period, the inspectors conducted interviews and
inspections in response to allegations presented to the NRC. The
inspector and licensee actions resulting from these allegations are noted
below:
UNIT 2
Allegation 86-A-121: On October 8, 1986, control room heating and
ventilation design concerns were brought to the attention of the resident
inspectors by a licensee contract employee. The employee's concerns had
been previously identified to licensee station management, however, the
alleger was not satisfied with the licensee's response and desired to have
the NRC independently review the concerns. The contract employee's
concerns were formally presented to licensee management in a NRC Region I
letter, dated October 16, 1986.
The licensee responded to the control
room ventilation concerns in a letter, dated October 24, 1986,
(NMP2L-0927). The inspector has reviewed the licensee's responses to
these allegations and found that, in general, the licensee's response
adequately resolved the concerns.
The following items refer directly to the concerns in the contract
employee's August 1,1986 letter to station management and provide the
inspector's conclusions regarding these concerns.
(a) The current design of the Nine Mile Point Unit 2 Control Room
environmental envelope meets the requirements of Regulatory Guide (RG) 1.52, Section C, paragraph 2.g.
(b) The inspector conducted an independent review of the FSAR treatment
of hazardous chemicals and the effects of their release on control
room operators. The inspector concluded that the present design
adequately addresses all credible releases of toxic chemicals and
meets the requirements of RG 1.78.
(c) The inspector reviewed the completed preoperational test and deter-
mined that it has sufficiently demonstrated the adequacy of the
design to maintain the required positive pressure in the control room
to prevent infiltration,
periodic testing, as required by Technical
Specifications, will verify continued system integrity.
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(d) The inspector concurred with the licensee's determination
that area differential pressure monitor 2HVC-PDI147 is not
required by RG 1.97 to be safety related.
(e) The inspector reviewed the preoperational test procedure
(N2-P0T-53-3, Rev.1) which was conducted to verify that the
maximum outside air flow does not exceed 1500 CFM and that
control room pressure can be maintained as required in the
FSAR. The inspector concluded that the current design
adequately achieves and maintains these design parameters.
(f) The inspector concluded that the existing design of the
control room HVAC system, coupled with the lower Technical
Specification limit of 90 degrees F in the control room,
will not result in exceeding equipment operating temperature
limits or endanger control room operators from a habitabilty
standpoint.
Allegation 86-A-143: An allegation was received concerning the
cleanliness of the hydraulic oil being used in the Main Steam
Isolation Valve (MSIV) actuators. The alleger stated that
controls on the replacement of the hydraulic oil were inadequate
and that the oil in the actuator sumps was contaminated.
MSIV actuators required modification to meet the Technical
Specification MSIV closure time requirements. To perform the
modification, the oil was drained from the actuators. After the
completion of the necessary modifications, the hydraulic oil was
replaced with new oil. The resident inspectors reviewed the
licensee's procedural controls for the MSIV hydraulic oil
replacement and discussed the most e xen+ oil change with
licensee representatives involved. The inspectors determined
that the licensee had previously addressed the quality of the
hydraulic fluid with the vendor. Oil quality specifications were
obtained from the vendor for onsite chemical analysis.
Replacement oil was sampled and found satisfactory prior to use.
Stone & Webster construction personnel, involved with the
hydraulic oil replacement, were interviewed and it was determined
that clear plastic five gallon containers were used to transport
the hydraulic fluid from the 55 gallon storage drums in the
warehouse to the Reactor Building for addition to the actuator
sumps. The inspector found this to be acceptable.
After the licensee became aware of this allegation, each MSIV actuator
hydraulic oil sump was sampled through a sump drain valve. All samples
were satisfactory and the analysis results were documented in the
licensee's Chemistry Maintenance Procedure.
Inspector review of this
procedure identified no specification for visual clarity / suspended solids.
The lack of a visual clarity check was addressed with the licensee. NMPC
had concluded that some discoloration of the oil occurs normally during
usage, and that this discoloration was acceptable.
It was determined that
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the hydraulic fluid system filter (40 microns) is designed to remove any
particulates and prevent any mechanical fouling of the hydraulic
components. One of the filters recently removed was opened for inspector
review. The inspector found the filter to be in good condition, consider-
ing it had never previously been replaced.
Inspector review of the licensee's actuator maintenance procedure identi-
fied that the procedure had not been revised to reflect the current
actuator design.
Via discussion with responsible maintenance personnel,
the inspector determined that the proposed revision will also include: how
to add oil to the actuators, if required; how to check the oil level; and,
how to remove, inspect and clean the system filter.
It was also deter-
mined that chemistry procedures will be revised to address the proper
hydraulic fluid sample frequency requirements.
Based of the inspectors' review, the concern could not be substantiated
for the MSIV actuators as currently assembled.
The pending revisions to
the maintenance and chemistry procedures will be reviewed by the resident
inspectors in a subsequent inspection report.
[
No violations were identified.
8.
Failure to Identify Inoperable Component - Unit 1
On November 21, 1986, the licensee notified the NRC, via the ENS, of
a potential loss of the Unit 1 High Pressure Coolant Injection (HPCI)
and Control Room Emergency Ventilation (CREV) due to the failure of
Reactor Building Closed Loop Cooling (RBCLC) heat exchanger No.
13. Through wall leakage had been discovered during a
hydrostatic test conducted on May 20, 1986 (during the 1986
refueling outage).
The Inservice Inspection (ISI) group which
conducted the test, requested a disposition of the heat exchanger
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from corporate engineering on June 16, 1986.
Corporate
engineering evaluated the heat exchanger, which had been leaking
since 1978, as functionally operable and recommended a method of
repair.
However, no evaluation was done of the effects of a
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seismic event on the heat exchanger or of the ability of the
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Condensate Transfer System to supply makeup to RBCLC.
In August
1986, after completion of the refueling outage, a potential 10 CFR 21 report reveiw was initiated.
The review identified that,
in a seismic event, the end of the heat exchanger could fall off
causing a complete loss of RBCLC.
This catastrophic failure
would render HPCI and CREV inoperable due to lack of cooling
water and seal water supplied by RBCLC. However, this concern
was not realized by station personnel until the week of November
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9, 1986.
The heat exchanger was isolated on November 14, 1986.
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At the end of the reporting period, the licensee had completed an analysis
to demonstrate that failure during seismic loading was not a concern. An
analysis, to demonstrate the ability of the Condensate Transfer System to
supply adequate makeup to RBCLC, is in progress. The licensee has identi-
fled their failure to recognize RBCLC as a system required to support the
operability of safety-related systems and is addressing this concern. An
additional concern, identified to the licensee by the inspectors, was the
apparent oversight by station management in promptly resolving the heat
exchanger operability question. The heat exchanger failed its hydrostatic
test in May 1986, was placed in service, inspite of this failure, and was
not properly addressed by the licensee until November 1986. This concern
remains unresolved and will be addressed in a future inspection.
Unresolved Item (50-220/86-26-02)
9.
Construction Deficiency Report Review - Unit 2
(Closed) Construction Deficiency Report (CDR) (86-00-21): Inadvertent
closure of automatic fire suppression control valve. On August 23, 1986,
three fire suppression systems for the Reactor Building were found
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inoperable due to a filled common drain header, which had closed one
automatic deluge valve and would have closed the other two deluge valves
had there been actuation signals. The drain line had a closed valve in
it, and the line had become full from the water draining into it from
numerous previous actuations of the deluge valves.
For the deluge valves
to function, an open, vented path must exist for water providing control
pressure to be continuously drained.
NMPC concluded that the proper means
to ensure operation of these deluge valves was to cut the control pressure
drain lines from the deluge valves and allow the water to drain onto the
floor. Further, NMPC reviewed the control pressure drain lines on all
other NMP-2 fire protection systems and found the drains to be open,
vented, and without valves. The inspector reviewed the NMPC final report
dated October 23, 1986, inspected the cut drain lines, and inspected a
sample of other deluge valves to ensure unobstructed paths. The inspector
concluded that the NMPC resolution was acceptable and that the CDR was
closed.
10. Exit Meetinn
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 in.pection. Based on the NRC Region I review of this report and
discussions held with licensee representatives, it was determined that
this report does not contain Safeguards or 10 CFR 2.790 information.
,