ML20040G910
| ML20040G910 | |
| Person / Time | |
|---|---|
| Site: | Zion File:ZionSolutions icon.png |
| Issue date: | 01/26/1982 |
| From: | Hayes D, Kohler J, Waters J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20040G904 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.4, TASK-2.F.1, TASK-2.F.2, TASK-2.K.3.09, TASK-TM 50-295-81-29, 50-304-81-27, NUDOCS 8202160607 | |
| Download: ML20040G910 (14) | |
See also: IR 05000295/1981029
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No.:
50-295/81-29; 50-304/81-27
Docket No.:
50-295; 50-304
License No.:
Licensee:
Commonwealth Edison Company
P. O. Box 767
Chicago, IL 60690
Facility Name:
Zion Nuclear Power Station, Units 1 & 2
Inspection At:
Zion, IL
Inspection Conducted: December 1, 1981 through January 15, 1982
J.5. Gtupw
[ - 2 0 ^8 2_
Inspector (s):
J. E. Kohler
. $. Y[
J. R. Waters
/ - 2.C - 8 2-
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Approved By:
I.
y s, Ch
Reactor Projects Section IB
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Inspection Summary
Inspection on December 1, 1981 through January 15, 1982 (Report No. 50-295/81-29;
50-304/81-27)
Areas Inspected: Routine unannounced resident inspection of licensee action on
previous inspection items, reactor trips, removal of battery and charger 112 from
service, Fischer Porter transmitters, inadvertent PORV opening, primary to secondary
leakage, auxiliary feedpump inoperability, 2B reactor trip breaker, ASCO valve
sticking, NUREG-0737 items, operational safety verification, monthly maintenance
observation, monthly surveillance observation and Licensee Event Reports. The
inspection involved a total of 286 hours0.00331 days <br />0.0794 hours <br />4.728836e-4 weeks <br />1.08823e-4 months <br /> onsite by two NRC inspectors including
33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> onsite during off shifts.
Results: Of the areas inspected one item of noncompliance (battery and charger
112 removed from service paragraph 4) was identified.
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8202160607 820127
PDR ADOCK 05000295
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1.
Persons Contacted
- K.
Graesser, Station Superintendent
- E.
Fuerst, Assistant Station Superintendent,0perations
- G.
Plim1, Assistant Station Superintendent, Administrative
and Support Services
R. Budowle, Unit 1 Operating Engineer
J. Gilmore, Unit 2 Operating Engineer
L. Pruett, Assistant Technical Staff Supervisor
P. LeBlond, Assistant Technical Staff Supervisor
- A. Miosi, Technical Staff Supervisor
B. Schramer, Station Chemist
F. Ost, Health Physics Engineer
C. Silich, Technical Staff Engineer,ISI
- B.
Harl, Quality Assurance Engineer
T. Lukens, Quality Control Engineer
- B. Kurth, Master Instrument Mechanic
- Denotes those present at the exit of January 15, 1982
2.
Summary of Operations
Unit 1 operated at power levels up to 100% throughout the inspection interval.
No reactor trips were experienced.
Unit 2
The following reactor trips occurred during the inspection interval:
Date/ Time
Power Level
Occurrence
December 1, 1981
28%
Unit 2 was tied to the grid at 12:20
3:20 AM
AM December 1, 1981 for the first time
since commencing a refueling outage
September 11, 1981. At 3:20 AM the same
day the unit tripped from 28% power. The
trip resulted from the rupture of the 2D
feedwater regulating valve operating dia-
phragm. This caused a steam flow / feed
flow mismatch coincident with low level
in the Steam Generator. The valve was
repaired, the unit made critical and re-
stored to the grid at 1:25 PM December 1,
1981.
December 6, 1981
90%
The reactor tripped on low low stean gener-
3:55 AM
ator 2C level. The low low level condition
was initiated when a motor control center
that supplies power to the E.H.C. oil pump
tripped.
This caused the turbine governor
valves to drift closed causing a shrink
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condition in the steam generators. The
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redundant E. He C. oil pump
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Date/ Time
Power Level
Occurrence
December 6, 1981
did not auto-start and was started
(con;t)
manually. However, it failed to develop
sufficient E.H.C. oil pressure due to a
problem with the unloader valve setting.
After the trip was received, the 2B auxiliary
feedwater pump failed to start automatically
as designed.
Subsequent maintenance inves-
tigation found nothing that would indicate
the cause of the starting problems and the
pump successfully passed a surveillance test
to prove operability (See paragraph 9 for
details regarding auxiliary feedwater pump
starting problems).
December 11, 1981
90%
The unit returned to power on December 7,
1981. Reactor tripped due to a main genera-
tor trip-turbine trip. The generator tripped
on a ground fault which resulted from a tube
leak in a hydrogen cooler. The tube leak
introduced vs ter into the main generator
which caused a current path to ground to
develop in the T-1 bushing.
After the reactor trip was received, neither
the 2B or 2C motor driven auxiliary feedwater
pumps (AFW) started automatically as designed.
The 2A AFW pump was out of service at the time.
Both 2B and 2C pumps were able to be started
manually from the control room.
Because the failure of AFW pumps to start as
designed following a reactor trip was a re-
petitive occurrence (See Unit 2 reactor trip
of December 6, 1981), the NRC issued a con-
firmatory letterwhich required Unit 2 to re-
main shutdown until a definitive resolution
of the AFW pump starting problems could be
achieved (See paragraph 9 for details of AFW
pump starting problems).
The confirmatory shutdown letterwas lifted by
the NRC on December 21, 1981 after repairs
were made and the unit was on-line at 2:35 AM
on December 22, 1981.
December 22, 1981
50%
Reactor trip from low low Steam Generator C
2:35 AM
level. The low low level condition was caused
by a blown diaphragm in the 2C feedwater regu-
lating valve.
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Date/ Time
Power Level
Occurrence
After the trip was received, the AFW pumps
s tarted as designed af ter repairs were made
a s a result of the reactor trip on Decem-
bar 11, 1981.
Upon resetting safeguards following recovery
from the reactor trip, the 2B reactor trip
breaker opened for unknown reasons and would
not close immediately. The breaker was removed
and inspected but nothing was found and a
surveillance test to prove operability was
successfully passed.
The unit was returned to power at 6:25 PM on
December 22, 1981.
December 22, 1981
50%
Reactor trip from opening of train B reactor
8:33 PM
trip breaker at power. The opening of the
trip breaker was related to the reactor trip
of December 22, 1981 (See paragraph 10 for
details of reactor trip caused opening of 2B
reactor trip breaker).
The unit was placed back on line at 6:15 AM on
December 23, 1981.
January 4, 1982
22%
On January 1, 1982 a shutdown on Unit'2 was
1:30 AM
commenced to repair condenser tube leaks.
When the unit had been ramped down to zero
percent power as indicated by the EHC system the
generator was still producing 49 MW.
Tha
operators tripped the turbine knowing that a
turbine trip / reactor trip would result. On
January 3, 1982 the unit was taken to hot
standby in anticipation of the completion of
condenser repairs.
January 5, 1982
< 2%
On January 5, 1982 at 1:25 PM the reactor
1:25 PM
tripped from hot standby when instrument
mechanics tripped the P-13 bistable thus
enabling the at power trips. The trip signal
came from the reactor trip / turbine trip logic.
The reactor was made critical again at 4:45 PM
January 5, 1982.
January 6, 1982
< 2%
On January 6, 1982 at 12:39 AM, the reactor
12:39 M4
tripped on low inw level in the D Steam Gen-
erator. The MSIV's were being open in prepara-
tion for placing the unit on line. When the
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Date/ Time
Power Level
Occurrence
D MSIV was opened the downstream drain valve
failed to close automatically. The resultant
steam off dropped the Steam Generator level
below the trip point. The reactor was made
critical again at 4:05 January 6, 1982.
January 6, 1982
- ( 2%
At 4:53 AM January 6, 1982 the unit tripped on
4:54 AM
steam flow / feed flow mismatch coincident with
low level in the A Steam Generator. The trip
resulted from an excessive rod pull which
caused Steam Generator relief valves to open
at the same time the operator was opening the
MSIV bypass valves. The condition was aggra-
vated by g steam flow set point which was high
by 0.4x10 pph and an initial Steam _enerator
level near the low level point. The reactor
was made critical again at 12:45 PM and tied
to the grid at 10:15 PM on January 6, 1982.
3.
Licensee Action on Previous Inspection Items
(closed) Unresolved Item (50-304/81-16-01) Slow Closure of Containment Isolation
Valves. The licensee submitted an updated LER which attributed the slow valve
closing time to an ASCO solenoid valve in the instrument line which failed to vent.
The failure to vent was attributed to oil in the instrument air lines (See paragraph
11 for details regarding containment isolation valves sticking due to oil in the
instrument air lines).
4.
Removal of Battery and Charger 112 from Service
On December 12, 1981 modification work on Unit i that required isolation of Battery
112 and Charger 112 from D.C. bus 112 was presented to shift management (shift
engineer S.E. and shift control room engineer S.C.R.E.).
Management reviewed
Technical Specification Section 3.15.2.E and 3.15.2.F and determined that the
battery and charger isolation were permitted by the above referenced Technical
Specification as long as the work was completed within twenty-four hours.
They
noted that the isolation should be acceptable since the temporary configuration
would be the same as that presently authorized procedurally to place a battery
on routine equalizing charge, whereby both battery and charger are also divorced
from the D.C. bus.
Management did not realize that such an isolation was in
violation of Technical Specification 3.15.2.H when performed on an operating unit.
As a final check prior to making the battery isolation, the Operating Engineer
(0.E.) was consulted, but he erroneously thought the work was being performed
on Unit 2 which was in hot shutdown, and agreed with the shift management's
conclusion to initiate the isolation. The work was authorized, bus 112 and 212
cross connected, and the 112 battery and charger isolated at about 10:20 AM
December 12, 1981.
The work was completed and the lineup returned to normal
about 6:30 PM December 12, 1981. The Operating Engineer realized the next day
that the work had been done on the operating unit in violation of Technical
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Specification 3.15.2.H and initf'ted a deviation report. The senior resident
inspector was notified about a
AM December 14, 1981 and a telegram sent to
Region III at 11:30 AM Decemb.
14, 1981.
The safety significance of the occurrence was that a_ degree of independence
112 remained energized from a power source that
between units was lost. *
was as reliable as its . zaal source.
Technical Specification Sections 3.15.2.E and 3.15.2.F describe operation with
an. inoperable battery and battery charger respectively. Technical Specification Section 3.15.2.H states:
If more than one of the conditions _specified in
3.15.2.A, 3.15.2.B, 3.15.2.C
3.15.2.D
3.15.2.E, 3.15.2.F and 3.15.2.G occur
concurrently, the reactor of the affected unit shall be brought to the hot
shutdown condition immediately.
Contrary to the above, from 10:20 ..M
to 6:30 PM December 12, 1981 Unit I was
operated with both the 112 battery and 112 battery charger isolated from bus
112 in violation of Technical Specification 3.15.2.H.
This violation was licensee
identified and is considered an item of noncompliance.
The resident inspectors consider the cause of this event to be personnel error
due to difficulties encountered in comprehending Technical Specification 3.25.2
and its eight subsection. The inspectors noted that the written structure-
of the specification is complex and has lead to items of noncompliance in the
past (NRC Inspection Report 295/79-01; 304/79-01 and 295/79-08; 304/79-09).
The licensee was requested to submit ~a revision to Technical Specification 3.15.2 which would clarify its meaning, particularly with respect to Technical Specification 3.15.2.H.
The change should include a provision to allow both
battery and charger to be isolated from a D.C. bus provided that bus was supplied
power from the opposite unit.
This item is open pending completion of corrective action and is designated
295/81-29-01 and 304/81-27-01.
5.
Investigation
The senior resident inspector interviewed licensed personnel regarding Commonwealth
Edison Management Director 1-0-17 as part of a separate NRC investigation.
No items of noncompliance were identified.
6.
Zero Shift of Fischer Porter Transmitters
LER 304/81-26 identifies a repetitive problem involving zero shift on Fischer-
Porter transmitters resulting in nonconservative safety settings. The licensee
has undertaken a program to improve transmitter setpoint stability by replacing
transmitters used in environmentally qualified applications with transmitters
of another manufacturer. The replacement program will be ongoing.
For transmitters that do not require environmental qualification, a setpoint
change study has been prepared with the intent of introducing a conservative
bias into the setpoint to offset any drift. The setpoint change study is under
review.
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No items of noncompliance were identified.
7.
Inadvertant PORV's Opening
The resident inspector was requested by NRC Headquarters to reinspect NUREG 0737 requirement II.K.3.9 regarding the P.I.D. controller for the power operated
relief valves (PORV's). The re-inspection only concerned plants using Foxboro
type controllers for the PORV's.
The inspector determined that Zion Station
does not use Foxboro type equipment in the P.I.D. application.
No items of noncompliance were identified.
8.
Unit 1 Primary to Secondary Leakage
The licensee has continued to monitor the unit primary to secondary leakage.
Previous leak test results are documented in Inspection Reports 50-295/81-09,
-14, -20 and -26.
The lesk test results for this inspection period are as
follows:
Date
Leak Rate in GPD
1B S/G
1 C S/G
December 1, 1981
374
56.1
December 4, 1981
218
10.3
December 11, 1981
300
7.97
December 17, 1981
264
25.5
Decamber 23, 1981
367
37.7
December 30, 1981
375
54.0
January 7, 1982
387
27.5
January 14, 1982
431
12.5
FortheDecember4,1981angsubsequentleakratesthelicenseeusedare-
calculated value of 4.65x10 cc for the volume of water in the steam generator.
Previous leak rates were based on a steam generator volume of 6.13x10
cc.
The calculated leak rates were thus reduced by a factor of 0.74 using the new
value.
The inc reasing activity in the steam generator has increased the activity of the
air ejet*or exhaust. The set point of the air ejector rad monitor has been
raised from 600 cpm to 14,000 cpm.
Several areas'in the turbine building
including the Unit I high pressure turbine enclosure, the Unit 1 steam tunnel,
the area around the Unit 1 air ejectors, the secondary sample room and the
auxiliary boiler room have been roped off due to radioactive contamination.
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On December 3, 1981 the licensee held a meeting to discuss the past history,
current status and anticipated actions reParding the Unit 1 primary to secondary
leakage. The following major conclusions were reached by the licensee:
a.
The probable locations of the leaking tube (s) are row 1 and row 2,
and those adjacent to anti-vibration bars,
b.
An early shutdown for refueling is not feasible due to excess reactivity
remaining in the undischarged assemblies.
c.
The reduction in leak rate achieved by a load reduction would be small.
d.
Industry data for series 51 Westinghouse steam generators would predict-
the leakage to be from several faults rather than one large one.
c.
Unit I will continue to operate until the 500 gal / day Technical Specification
limit is reached or the February 1982 scheduled refueling outage commences.
f.
Leak rate calculations will continue on a weekly basis.
No items of noncompliance were identified.
9.
Auxiliary Feed Pumps Inoperability
In recent months the auxiliary feedwater pumps have been subject to three different
problems which resulted in their failure to respond to automatic initiation
signals.
On September 14, 1981 during a normal cooldown on Unit 2, Steam Generator level
was allowed to fall below the 10% low low level resulting in an auto start signal
to the auxiliary feedpumps. The operators placed the auxiliary feedpump control
switches in the pull-to-lock position as allowed by procedure, to avoid excessive
cooldown. The pumps tripped as required. Subsequently the operators were unable
to restart either motor driven auxiliary feedpump. After racking out the breaker
and then returning it to service, one pump was successfully started. The failure
of the motor driven pumps to start was later found to be caused by a " sneak path"
resulting from an earlier modification to the Westinghouse W-2 control switches.
This occurrence was the subject of a special I.E. Report No. 50-295/81-22, 50-304/81-18
in which one item of noncompliance was issued to the licensee.
On November 26.-1981 the Unit 2 motor driven feedpumps failed to start in response
to operator action while the unit was in hot standby. The operators found that by
throttling shut the discharge valves, the pumps could be started. Once the pumps
were running, the discharge valves could be re-opened to their normal positions
and the pump would continue to operate.
It was later determined that the pumps
were tripping off on low suction pressure. This was the result of an improper
set point modification on the suction pressure instrument. The modification had
been performed on the 2A, 2B and 2C auxiliary feedpump instruments during the
Unit 2 refueling outage of September 11-November 24, 1981. The modification had
also been completed on the 1C auxiliary feedpump instrument April 10, 1981. All
four instrument aet points were returned to their previous setting.
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On December 6, 1981 Unit 2 tripped from power Operation. Auxiliary feedpump_
2B_ failed to start in response to an automatic initiation signal. The pump was
checked out. mechanically and electrically but no cause for the failure to start
was found. An operational test was performed satisfactorily on the pump and
Unit 2 was returned'to operation.
On December 11, 1981 Unit 2 again tripped from power-operation. The 2A auxiliary
feedpump was already out of service and the 2B and 2C auxiliary feedpumps failed
to start. The operator was able to start the 2B pump manually on the first attempt
but the 2C pump required two tries before it started. A Confirmatory letter was
issued by NRC Region III confirming that Unit 2 uould not be restarted until the
cause of the auxiliary feedpumps failure to operate was found and corrected.
Subsequent investigation determined that the pumps were tripping on momentary
low suction pressure which occurred during simultaneous start with each pump-
lined up to a separate discharge header. This split header arrangement is used
whenever the steam driven auxiliary feedpump is out of service. This mode of
operation was instituted in September of 1979 in response to an NRC request
resulting from the accident at Three Mile Island and required that two separate
auxiliary feed flow paths to the steam generators be maintained.
The licensee installed time delays that block the low suction pressure trip for a
short time after the pump starts to allow the momentary low suction pressure to
clear. This modification has been cempleted on Unit 2.
For Unit 1, a standing
order has been issued to alert the operators that the motor driven auxiliary
feedpumps may trip during a simultaneous pump start with the discharge headers
split. The order instructs them to manually restart the pumps if this occurs.
This order will remain in effect until the time delay modification _can be completed
on Unit 1.
The_ difficulty experienced when starting the 2C auxiliary feedwater
pump manually during the event was found to be caused by a problem in the pump
switch. That switch was replaced.
Unit 2 tripped from power December 22 and 23, 1981. On both occasions both motor
driven auxiliary feedpumps started and operated satisfactorily even though the
discharge headers were split. This demonstrated the adequacy of the time delay
modification.
The improper setting of the suction pressure trips and the inoperability of the
pumps in the split header mode are being inspected by the NRC Region III Division
of Engineering and Technical Inspection. A separate report will be issued on
these subjects.
This item is open pending completion of the special NRC inspection and is designated
Open Item 295/81-29-02; 304/81-27-02.
10.
Opening of the 2B Reactor Trip Breaker
Zion Un'2 2 was placed on the line at 6:25 PM on December 22, 1981 following
startup from a reactor trip of December 21, 1981 due to a blown diaphragm in a
feedwater regulating valve. At 8:35 PM on December 22, 1981 Unit 2 tripped from
approximately 40% power.
fhe cause of the trip was the opening of train B
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reactor trip breaker. All safety systems operated as designed and the unit was
placed back on the line at 6:15 AM on December 23, 1981.
The cause of the train B safeguards actuation was a power loss to the undervoltage
coil associated with the Westinghouse DB-50 reactor trip breaker.
After recovery from the trip, the 2B reactor trip breaker would not close upon
resetting safeguards. This was similar to that experienced after recovery from
the reactor trip on December 22, 1981. Upon investigation it was determined that
the two parallel reactor trip relays associated with the 2B steam generator low
low level trip had failed in the safe direction by opening which resulted in
opening train B reactor trip breaker and a subsequent reactor trip.
The relays that failed open are BFD type 22S relays, which are similar to relays
identified in previous NRC Bulletins on BFD relays (type 48S, 84S). The licensee
inspected Unit 1 and found one failed relay. The failed relays in both units
were replaced with spare BFD type 22S relays.
As a long range program to improve BFD relay reliability,.new relays, type NBFD
have been ordered, in addition to improved coils to modify type 22S relays.
No items of noncompliance were identified.
11.
ASCO Solenoid Air Valves Sticking Due to Oil-in the Instrument Air System.
Zion Station has had a history of air operated valves failing to stroke because
the solenoid valve which releases the operating air has stuck. The licensee
has determined that oil in the instrument air system interacts with the Buna N
seals in the solenoid valve at elevated temperature and causes the valve stem
to stick. The source of the oil appears to be the service air system via the
cross connect to instrument air. Cross connection of the two systems is necessary
when less than two instrument' air compressors are operable. The instrument air
system is not sampled for oil on a routine basis.
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The licensee has taken the following actions in response. to the sticking solenoid
problem:
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a.
A third air compressor has been installed in the instrument air system-
in order to increase the instrument air system reliability and reduce
the frequency of cross tie's to the service air system.
b.
A modification has nearly been completed to replace the Buna N seals
in the ASCO solenoids with Viton seals. Approximately 99% of the Unit I
and 95% of the Unit 2 ASCO's have undergone this modification. The modi-
fication has been halted in anticipation of a new modification to replace
the installed ASCO's with a new environmentally qualified model,
c.
Surveillance of containment isolation valve operability has been increased
by instituting Procedure TT-300.
This procedure verifies the operability
of all (53 per unit) ASCO controlled containment isolation valves monthly.
Prior to implementing TT-300 these valves would be tested no more frequently
than quarterly.
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The -licensee has' implemented a program ~ to. improve the L reliability of-
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the instrument air compressors. The program-includes application of a
vibration analyser and balancing of the compressors. Detailed records
are not available, but the licensee. believes.the instrument-service air
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cross connect time has been reduced from several days to a few hours per
year.
The effectiveness of the licensee's action is illustrated by the reduction
in reportable containment isolation valve malfunctions:
Year
No. of Occurrences
1977
7
1978
7
1979
2
1980
1
1981
2
In view of the results achieved by the licensee's actions and the redundancy
of the isolation valves, the licensee's response to the sticking ASCO problem
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appears to be adequate.
No items of noncompliance were identified.
12.
NUREG 0737 Items
The following NUREG 0737 Action Items were complated by the licensee for both
Unit i and Unit 2.
Item
Title
II.B.4
Training for Mitigating Core Damage
II.F.1-4
Containment Pressure
II.F.1-5
Containment Water Level
II.F.2.-3B
Reactor Vessel Level
No items of noncompliance were identific3.
13.
Operational Safety Verification
The. inspector observed control room operations, reviewed applicable logs and
conducted discussions with control room operators during the months of
December and January. The inspector verified the operability of selected
emergency systems, reviewed tagout records and verified proper return to service
of affected components. Tours of the auxiliary building and turbine building
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were conducted to observe plant equipment conditions, including potential
fire hazards, fluid leaks, and excessive vibrations and to verify that main-
tenance requests had been initiated for equipment in need of maintenance. The
inspector by observation and direct interview verified that the physical security
plan was being implemented in accordance with the station security plan.
The inspector observed plant housekeeping / cleanliness conditions and verified
implementation of radiation protection controls
During the month of December,
the inspector walked down the accessible portions of the auxiliary systems to
verify operability.
These reviews and observations were conducted to verify that facility operations
were in conformance with the requirenents established under Technical Specifications,
10 CFR, and administrative procedures.
No items of noncompliance were identified.
14.
Monthly Maintenance Observation
Station maintenance activities of safety related systems and components listed
below were observed / reviewed to ascertain that they were conducted in accordance
with approved procedures, regulatory guides and industry codes or standards
and in conformance with Technical Specifications.
The following items were considered during this review: The limiting conditions
for operation were met while components or systems were removed from service;
approvals were obtained prior to initiating the work; activities were accomplished
using approved procedures and were inspected as applicable; functional testing
and/or calibrations were performed prior to returning components or systems to
service; quality control records were maintained; activities were accomplished
by qualified personnel; parts and materials used were properly certified;
radiological. controls were implemented; and, fire prevention controls were
implemented.
Work requests were reviewed to determine status of outstanding jobs and to assure
that priority is assigned to safety related equipment maintenance which may affect
system performance.
The following maintenance activities were observed / reviewed:
a.
Modification of auxiliary feedpump suction pressure instruments
b,
Following completion of maintenance on the O diesel generator, the
inspector verified that these systems had been returned to service
properly.
No items of noncompliance were identified.
15.
Monthly Surveillance Observation
The inspector observed Technical Specifications required loop functional
surveillance testing and verified that testing was performed in accordance
with adequate procedures, that test instrurentation was calibrated, that
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limiting conditions for operation were met, that removal and restoration of
the affected components were accomplished, that test results conformed with
Technical Specifications and procedure requirements and were reviewed by
personnel other than the individual directing the test, and that any deficiencies
identified during the testing were properly reviewed and resolved by appropriate
management personnel.
No items of noncompliance were identified.
16.
Licensee Event Reports Followup
Through direct observations, discussions with licensee personnel, and review
of records, the following event reports were reviewed to determine that re-
portability requirements were fulfilled, immediate corrective action was
accomplished, and corrective action to prevent recurrence had been accomplished
in accordance with Technical ( 'cifications:
Unit 1
LER NO.
DESCRIPTION
81-46
Non-representative Sample From Off Gas Monitor
81-47
Failure of ORT-PR-10C
81-48
Failure of IRE-0011 and IRE-0012
81-49
Failure of Power Range Channel N-42
81-50
Battery and Charger 112 Taken Out of Service
Unit 2
LER NO.
DESCRIPTION
81-25
Missed Shiftly Grab Samples
81-26
2A S/G Feedwater Flow Loop High
81-27
Vessel Level Leak in Containment
81-28
Blower Tripped for Rad Monitors
81-29
2C S/G Channel Failed liigh
81-16 Update
Failure of 2A0V-SS9356B to Close
Regarding LER 304/81-25, this will be designated a licensee identified item of
noncompliance in which no citation will be issued.
Regarding LER 304/81-26, the zero shift of Fischer Porter transmitters is
described in paragraph 6 of this report.
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Regarding LER 50-304/81-16 (Failure of 2A0V-SS9356B to close), the subject valve
did not operate because the ASCO solenoid failed to vent the air off the
operator of the A0V. The licensee believes this was due to the ASCO valve
sticking caused by residual oil in the instrument air system interacting with
the Buna N seals. This problem has existed with sol'enoid air valves at least
as far back as 1976 and has been well documented via LER's.
A further discussion
of this problem is contained in paragraph 11.
17. Meetings, Offsite Functions
The inspectors attended the following meetings and offsite functions during
the inspection period:
J. R. Waters
December 10, 1981
Zion Probalistic Risk Seminar NRC Headquarters
Bethesda, Maryland
December 16-18, 1981 Resident Inspector Seminar
NRC Region III
Headquarters
Glen Ellyn, Illinois
J. E. Kohler
November 30-
December 18, 1981 American Nuclear Society
Meeting
San Francisco, California
December 17, 1981
Commonwealth Edison
Corporate Office
Chicago, Illinois
December 18, 1981
Resident Inspector's Seminar
NRC Region III
Headquarters
Glen Ellyn, Illinois
18.
Unresolved Items
Unresolved items are matters about which more information is required in order
to ascertain whether they are acceptable items, items of noncompliance or
deviations. Two unresolved items (paragraphs 4 and 9) were disclosed during
this inspection.
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19.
Exit Interview
The inspector met with licensee representatives (denoted in paragraph 1)
throughout the month and at the conclusion of the inspection on January 15,
1981 and summarized the scope and findings of the inspection activities.
The licensee acknowledged the inspector's comments.
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