ML20214V625
| ML20214V625 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 11/28/1986 |
| From: | Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20214V579 | List: |
| References | |
| 50-373-86-40, 50-374-86-40, IEB-86-003, IEIN-86-072, NUDOCS 8612090762 | |
| Download: ML20214V625 (16) | |
See also: IR 05000373/1986040
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No: 50-373/86040(DRP); 50-374/86040(DRP)
Docket Nos: 50-373; 50-374 Licenses No. NPF-11; NPF-18
Licensee: Commonwealth Edison Company
Post Office Box 767
Chicago, IL 60690
Facility Name: LaSalle County Station, Units 1 and 2
Inspection At: LaSalle Site, Marseilles, IL
Inspection Conducted: October 8 through November 17, 1986
Inspectors: M. J. Jordan
R. Kopriva
J. Mueller
D. Bulter /
Approved By: 1
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Reactor Projects Section 2C Date
Inspection Summary
Inspection on October 8 through November 17. 1986 (Reports
No. 50-373/86040(DRP): 50-374/86040(DRP))
Areas Inspected: Routine, unannounced inspection conducted by resident
inspectors of licensee actions on previous inspection findings; operational
safety; surveillance; maintenance; training; Licensee Event Reports; licensee
action on an IE Bulletin; followup of 10 CFR 50.54(f) request for information;
Part 21 followup; general site emergency plan (GSEP) drill; regional request;
and temporary instruction TI 2515/75.
Results: In the area of surveillance, the verification by two individuals
that a valve was open, when in fact it was closed, is considered poor
performance. The corrective action to this event was extensive and considered
good. The performance in remaining areas was considered to be adequate.
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8612090762 861202
PDR ADOCK 05000373
G PDR
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DETAILS
1. Persons Contacted
- G. J. Diederich, Manager, LaSalle Station
- R. D. Bishop, Services Superintendent
- J. C. Renwick, Production Superintendent
D. Berkman, Assistant Superintendent, Work Planning
W. Huntington, Assistant Superintendent, Operations
- P. Manning, Assistant Superintendent, Technical Services
T. Hammerich, Assistant Technical Staff Supervisor
W. Sheldon, Assistant Superintendent, Maintenance
J. Atchley, Operating Engineer
R. W. Stobert, Quality Assurance Supervisor
- M. H. Richter, Assistant Tech Staff Supervisor
- Denotes personnel attending the exit interview on November 17, 1986.
2. Licensee Action on Previous Inspection Findings (92701)
(Closed) Violation (374/86020-01(DRP)): An operator failed to withdraw a
control rod in accordance with the approved rod sequence provided by the
nuclear engineer. Corrective actions taken were: (1) the control rod
was immediately reinserted to the required position, the nuclear engineer
reviewed the event, and the operator was reprimanded for his lack of
attention to detail; (2) station procedures were revised; and (3) all
shift personnel were trained on the event.
(Closed) Violation (374/86020-02(DRP)): The operator failed to demand
the required process computer printouts and failed to consult the nuclear
engineer prior to returning the mispositioned control rod to its correct
in-sequence position. Corrective actions taken were: (1) the event was
immediately reviewed with a nuclear engineer; (2) the event was reviewed
with the reactor operator involved and the importance of adhering to the ;
procedures was emphasized; and (3) procedure LOA-RD-03 has been revised. )
(Closed) Open Item (373/83049-08(DRP)): This item concerned isolation
response time of primary containment vent and purge valves. Safety '
EvaluationReport(SER) item 373/81-00-93 and TMI action item II.E.4.2
which also tracked this open item were closed in Inspection Report
373/86035. This item is considered closed.
(Closed) Open Items (373/86018-02;374/86017-01(ORP)): These items '
tracked the inspector's two concerns with the fire door surveillance
system. First, the fire door surveillance was performed by the security
force as part of the security supervision system. However, if a door ,
failed the surveillance, neither the Shift Engineer nor the Fire Marshall
were required to be notified. Without the Fire Marshall or the Shift
Engineer being notified, the action required by the Technical
Specification to be accomplished within one hour may not have been
accomplished.
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The licensee revised the security force's LaSalle Post Order (LPO) 121,
" Fire Door Check,"-to instruct the security personnel who were
performing the fire door surveillance to inform their supervision, who,
L in turn, informs the Shift Engineer. This concern is adequately
!- addressed.
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The inspector's second concern related to the revision process for
i fire-related post orders which appeared not to have the onsite review
! and control system required by Technical Specification section 6.0,
" Administrative Controls."
The licensee has revised LAP-900-14 " Fire Protection Program," to
require the concurrence of the Station Manager, Tech Staff Supervisor,
and Fire Marshall prior to revising LPO-105, " Fire Watch," LPO-112,
i' " Roving Fire Watch Patrol," and LPO-121, " Fire Door Check." The licensee
has also' referenced Technical Specification 4.7.6.2.d. in these LPO's.
This adequately addresses the inspector's concern.
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The inspector has confirmed that these revisions have been implemented.
These items are considered closed.
(Closed) Unresolved Item (374/86008-03(DRP)): This unresolved item
tracked the inspector's concern regarding a change to a modification for
Environmental Qualification (EQ) of level and flow instrumentation,
specifically M-1-2-84-136. The change deleted the need for replacement
of four Unit 2 Reactor Vessel High Water Level 8 switches: HPCS level
switches 2B21-N100A and 2B21-N100B, RCIC level switch 2B21-N101A, and
RCIC flow switch 2E51-N002. The station was verbally informed by the i
Station Nuclear Engineering Department (SNED) in March 1985 that these
four switches did not require EQ.
In early March 1986, upon reanalysis after completion of the changed
modification, SNED could not justify why three of the four switches were
not required to have EQ. The licensee subsequently requested their
architect / engineer to reanalyze the switches environment during accident
conditions. The reanalysis confirmed that these switches would be in a
harsh environment and, therefore, required EQ. The unit had been
operating for approximately eighty days (12/22/85 through 3/12/86).
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In late March 1986, the architect / engineer reanalyzed the switches and
determined that the existing HPCS and RCIC level switches were
environmentally qualified for their location and minimum post-accident
operating time; the RCIC flow switch does not require EQ because it does
not have to function while exposed to a harsh environment nor is it
needed for post-accident monitoring.
The inspector was concerned that the licensee had not environmentally
qualified the four switches prior to the 10 CFR 50.49 deadline of
November 30, 1985 as was originally planned'in the modification package.
The licensee was unsure of whether or not the switches were required to
l have EQ since the justification for the March 1985 SNED verbal approval
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of their deletion from the modification package was not sufficiently
documented by SNED nor by the station.
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.The inspector confirmed by review of training records that the licensee
has since trained the technical staff emphasizing that, in all
situations, appropriate documentation is required to change portions of
a modtfication package. The inspector's concerns have been adequately
addressed. This unresolved item is considered closed.
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3. Operational Safety Verification (71707) ,
The inspector observed control room operations, reviewed applicable
, logs and conducted discussions with control room operators during the
inspection period. The inspector verified the operability of selected
emergency systems, reviewed tagout records, and verified proper return
to service of affected components. Tours of Units 1 and 2 reactor
buildings and turbine buildings were conducted to observe plant equipment
l conditions, including potential fire hazards, fluid leaks and excessive
vibrations and to verify that maintenance requests had been initiated
l for equipment in need of maintenance. The inspector by observation and
direct interview verified that the physical security plan was being
l implemented in accordance with the station security plan.
l The inspector observed plant housekeeping / cleanliness conditions and
verified implementation of radiation protection controls.
During the month of October 1986, the inspector walked down the
accessible portions of the following systems to verify operability:
Unit I and 2 Residual Heat Removal (RHR) System
! Unit I and 2 Diesel Fire Pump System
Unit 1 and 2 Diesel Generators
i 4. Monthly Surveillance Observation (61726)
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The inspector observed Technical Specification required surveillance
testing and verified for actual activities observed that testing was
performed in accordance with adequate procedures, that test
instrumentation was calibrated, that limiting conditions for operation
were met, that removal and restoration of the affected components were t
accomplished, that test results conformed with Technical Specification '
l and procedure requirements and were reviewed by personnel other than the
l individual directing the test, and that any deficiencies identified
during the testing were properly reviewed and resolved by appropriate
I management personnel.
! The inspector witnessed portions of the following test activity:
l LIS-MS-403 Unit 2 Main Steam Line High Radiation Scram and MSIV
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Isolation Functional Test
LIS-NB-1-1 Unit 1 Reactor Vessel Low Water Level Scram and Primary
l Containment Isolation Calibration
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On October 17, 1986 the licensee notified the Senior Resident Inspector
(SRI) that on Unit 1, while at approximately 88% power, after performing
surveillance test LIS-RH-312, " Unit 1 Residual Heat Removal (Shutdown
Cooling Mode) High Suction Flow Isolation Functional Test", the Group 6
Division II reactor high pressure (135 psi) isolation instrument
PS-1833-N018B had been left valved out of service with two signatures
verifying the instrament was valved in service. The surveillance was
performed on the high flow isolation instrument, but the procedure also
required the isolation of the high pressure isolation switch for the
Residual Heat Removal (RHR) System. Discussions with the individuals
involved, in the presence of the SRI, revealed that the instrument was
valved out by accident and lockwired by the instrument mechanic (IM)
performing the test. The independent verifier stated he was instructed
to " verify the instrument was back in service". He verified the drain
valve from the instrument closed and also verified the instrument stop
valve closed without concentrating that the instrument stop valve should
be verified open. The lockwire had no detrimental affect on verifying
the valve positions. The instructions in the surveillance required
prepressurizing the 135 lbs. high pressure switch (PS-1833-N0188), then
prepressurizing the high flow switch (DPS-1E31-N012BA), then returning
the high pressure switch to service, and finally returning the high flow
switch to service. The IM performing the surveillance felt that he may
have gotten confused when swapping back and forth between the two
switches and failed to valve the one switch back into service. He
verified the respective relays were energized which was the case because
of the prepressurization. The reason the instruments were prepressurized
was that after the instrument stop was opened, a spike would not be felt
by the instrument and cause an unnecessary actuation. The instrument
checkoff sheet in LIS-RH-312 for PS-1833-N18B required the instrument
stop valve to be open and verified by two people. Technical Specification 6.2.A requires that detailed procedures including checkoff lists shall
be adhered to. Item 7 in the lists of procedures is for surveillance
and testing requirements. Contrary to the above, the check off sheet
for LIS-RH-312 was not adhered to in that two persons did not verify the
instrument valve stop open. This is considered a violation
(373/86040-01(DRP)).
When the prepressurized high pressure instrument eventually bled down
due to slight leakage in the system, the greater than 135 lb isolation
for the RHR system was removed and the Division II indication of this
isolation no longer appeared on the primary containment isolation status
panel in the control room. The control room operator did not recognize
this change in the panel indication. He also did not recognize that the
process computer had printed an alarm, "Rx. vsl. pressure Div II not
high", which indicated that the high pressure isolation was no longer in
affect. Step 43 of the operating surveillance LOS-AA-51, "Shif tly
Surveillance", requires a lamp test on the primary contairment isolation
status panel. The alarm indicating the removal of the high pressure
isolation appeared on the process computer typer at 12:35 a.m. on
October 16, 1986. The midnight shift reactor operator (RO) stated he
thought he had completed the status board light check portion of his
surveillance prior to that time so he would not have seen the abnormal
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_ condition'at that time. However, the dayshift and swing shift
surveillances should have identified the light being out as not normal
and taken action. This was not done. Also, each shift the R0 pushes
the isolation reset pushbuttons. This also extinguished the light on
the back_ panel indicating the Group 6 06 vision II isolation was no longer
enforcing.
Technical Specifications 6.2.A requires 'that detailed procedures shall
be adhered to. Item 7 in the list of procedures was'for surveillance
-and testing requirements. Contrary to the above, procedure LOS-AA-S1
was not followed in that the check that the resulting indications are
normal did not identify' that the Group 6 isolation light were out.
.This is considered a violation (373/86040-02(ORP)).
The RHR isolation function for the Division II inboard valves on high
reactor pressure (135 lbs) was inoperable for approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />
before being discovered. The alarm printer indicated the Division II-
RHR shutdown cooling mode isolation on high reactor pressure did not
have the minimum number of operational channels per trip system. starting
on October 16, 1986 at 12:35 a.m.. The R0 on swing shift noticed the
light out on the Primary Containment. Isolation System (PCIS) panel the
evening of October 16. The required instrument and channel was back
into service on 10:50 p.m. on October 16, 1986. Technical Specification 3.3.2.b. requires that when the number of operable channels per trip
system are less than required by table 3.3.2-1 then either the channel
should be tripped within one hour or, if tripping the channel could cause
the trip function to occur, the inoperable channel shall be restored to
the operable status within two hours or-take the action required by table
3.3.2-1. The table requires for the Group 6 RHR shutdown cooling mode
isolation (RHR cut in permissive pressure - high) to lock the affected
system isolation valves closed within one hour and declare the affected
system inoperable.
The valves listed in Technical Specification 3.6.3 that were controlled
by Group 6 isolation for Division II electrical distribution were not
locked closed within three hours (i.e. 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to restore + 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to
lock closed). These valves were IE12-F009 (inboard RHR shutdown cooling
suction valve) and IE12-F099A and B (RHR shutdown cooling injection
bypass around check valve). The 1E12-F009 valve did have its power
supply turned off, but not " locked" off. The remaining valves had the
power supplies on. The valves all remained closed after the isolation
permissive was removed, but could have beer, manually opened. The failure
to lock the valves closed within the Limiting Condition for Operation
time allowed by Technical Specifications is considered a violation
(373/86040-03(DRP)).
On November 7, 1986 at 6:00 a.m., while performing LOS-AA-WI,
" Technical Specification Weekly Surveillance" on Unit 2, the licensee
was exercising control rod 42-47 when it started drifting in from the
48 position. The rod continued to drift into the 00 position, fully
. inserted into the reactor core. Subsequent investigation in to this
event determined that the solenoid operated Directional Control Insert
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Valve (123) had some chips of metal which prevented the plunger in the '..
valve from operating. The valve then stuck open which caused the control' W
rod to continuously drift in. The valve was replaced and the control
rod tested and returned to service. All systems functioned as expected.
The licensee is investigating the source of the metal chips which caused
the problem. _This item will remain open (374/86040-01(DRP)).
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5. Monthly Maintenance Observation (62703) w4
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The-inspector observed work on-the leaking Unit 1 B/C Residual Heat
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Removal (RHR) water leg pump 1E12-C003 (Work Request No. 61981). The - A
work involved replacement of a piece of metal tubing and new fittings. }. ,
The inspector observed the removal and replacement of a Traversing Incore - -
Probe (TIP) detector on Unit 1. The inspector attended the pre-job '
meeting, the_ actual job, and a post job critique. .The coordination ..
between the maintenance department and radiation protection department "
was.well planned and executed. The defective TIP detector was removed,
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transported, and placed in the Unit I refuel pool. The new TIP detector
was then installed and tested.
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On November 11, 1986 the licensee had informed the resident inspectors -
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that a section of the station lake make-up piping had ruptured. The lake
make-up system was shut down, isolated, and the piping drained down.
-The locaticn of the rupture was off site by approximately 1-2 miles,"
between the river and station cooling lake. By November 13, 1986 the
ground around the ruptured section of pipe had been removed, the damage ,
evaluated, and a new section of pipe ordered. The make-up line is a 60 ,
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inch diameter, prestressed concrete with metal liner pipe. Repairs to .
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thepipinysystemareexpectedtotakeapproximatelyoneweek. An
operation s concern arises if the cooling lake level through evaporation-
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becomes too low causing the units to be shut down due to insufficient
suction for the circulating water pumps. The repair to the piping system .. ..',
should be completed well before the tire that the lake level becomes a *'fq
concern. +
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6. Training (41400) e
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The inspector, through discussions with personnel and a review of -
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training records, evaluated the licensee's training program for ,
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operations and maintenance personnel and determined that the general ~",,*# o
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knowledge of the individuals was sufficient for their assigned tasks , s
7. Licensee Event Reports (92700) [ ,
Through direct observations, discussions with licensee personnel, and
review of records, the following Licensee Evert Reports (LER's) were
reviewed to determine that reportability requirements were fulfilled,
immediate corrective action was accomplished, and corrective action +to
prevent recurrence had been accomplished in accordance with Technical -
Specifications. ,
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' (Closed) 373/86022-02 - Shutdown cooling isolation due to operator
operating the wrong keylock switch. This revision was issued to correct
the date in the abstract.
(Closed) 373/86029-00 - The (plus or minus) 24 VDC blown fuses for the
SRM'and IRM operability. Fuse failure gave no indication of system
inoperability. Corrective actions were taken and LaSalle has other
safety systems that would mitigate any potential problems concerned
with SRM's or IRM's being inoperable.
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' (Closed)-373/86032-00 - Unit 1 S.0.R. switches 1821-N024A and 1821-N037AB
not actucting at proper level setting and exceeding their respective
Technical Specification LCO's. This event was documented in Inspection
f. Report 374/86023.
Closed) 374/86016-00 - Missed suppression pool high level alarm
% (surveillance.This event was docutented in Inspection Report 374/86036.
[dpen)374/86012-01- Improper terminations of environmentally qualified
/ equirment. This revision was issued to include the Architect Engineer's
,; Mresult'5/vf testing with Raychem overlap less then manufacturer's
recomme ded overlap. Followup on this event was documented in Inspection
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Report 374/86035. This LER was transferred to Region III for final
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closing.
2(Closed)
Dolation374/86006-01
occurred which - On Marchthe
isolated 2, 1986, a Group
Reactor WaterVCleanup
primary System
containment
(RWClt) . This revision presented the apparent cause as failure of a valve
motor. A com'lete p description of the event was presented in Inspection
Report 374/86008.
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(Closed) 373/86025-01 - This revision presented the probable cause of a
w . ppuricus actuation of the 2C hi-radiation monitor as its return to
! . service after a calibration prior to the reinstallation of the detector
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(Closed) 373/86021i01 - This revision presented the probable cause of a
spurious trip of'the 2D hi-radiation monitor as a bad connector from the
, indicator relay at the detector housing. The connector was replaced.
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AlsoseeLER373{F6030-01.
%. -(Closed) 373/86030-01"- This revision presented the probable cause of a
spurious trip of the 20 hi-radiation monitor as a bad connector from the
indicator relay at the detector housing. The connection was replaced.
Also see LER 373/86021-01.
(Closedi 373/86037-00 - Group II and Group IV containment isolation due
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to inadequate out-of-service. This event was documented in Inspection
Report 373/86035.
(Closed)373/5N38-00-DuringstartupfromColdShutdown, Unit 1
experienced a. Croup I (MSIV) isolation and reactor scram due to an
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erroneous mode switch manipulation. A complete description of the event
and followup is detailed in Inspection Report 373/86035.
j' (Ciosed) 374/86017-00 - Technical' Specification LC0 exceeded. Remote
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. shutdown panel indication inoperable _ due to failure to recognize
Technical Specification related equipment. Residual heat removal heat
exchanger service water outlet temperature indication was not functioning
due to out-of-service to replace thermocouple.,
(Closed) 373/86029-01 - Intermediate Range Monitors (IRM's) potential
inoperability due to blown fuse in (plus or minus) 24 VDC power supply.
LaSalle does not intend to modify the system due to other controlling
systems already established.
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(Closed) 373/85004-00 - Hi Rad Door #396 to the Unit 1 Rx building
- equipment drain pump room went into alarm without reset. Investigation
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,found this door to be closed but not latched,'thus having no positive
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control over entry which is contrary to Technical Specification 6.1.1.
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The cause of the occurrence was determined to be a faulty door latch.
The latch was repaired. Reviev. of dosimetry records was performed and
no unauthorized exposure occur encas had taken place.
(Closed) 373/85005-00 - The Station Control Room Engineer was informed
that the Unit 1 Standby Gas Treatment (SBGT) train had been declared
inoperable. Since the Unit 2 SBGT train was already inoperable, a
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shutdown of Units 1 and 2 was commenced as specified by Technical
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Specification 3.0.3. The SBGT replacement heaters exceeded the maximum
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power output requirements of Technical Specification 3.6.5. A GSEP alert
was declared. Upon subsequent review and discussions with the licensee's
, corporate' command center, NRC Region III, and NRR, it was determined that
l the SBGT replacement heaters were adequate to allow continued operation
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(Closed) 374/85002-00 - Unit 2 High Pressure Core Spray (HPCS) pump
suction valve to the suppression pool opened while the normal suction
valve to the cycled condensate storage tank closed. The cause of the
, valve transfer was attributed to high suppression pool level. Transfer
on high suppression pool level is a designed function. High suppression
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pool level is due to minor valve leakage. The suppression pool level
was lowered and the normal HPCS suction flow path was reestablished.
(Closed) 374/85003-00 - An air particulate sample from the Unit 2 Standby
Gas Treatment System was collected and analyzed during the period of
December 13 to December 14, 1984. Technical Specification 4.11.2.1.2
requires an off site dose calculation to be performed. This was not done
, 3 due to misplacement of the hard copy computerized analysis information
sheet.
A thorough' search of possible locations for the missing paperwork was
conducted. Off site dose calculations prior to and subsequent to the
incident were reviewed for trends. All fractions resulting from off site
dose calculations are less than 1% for all limits. All other off site
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dose calculations indicate no abnormal releases during this time period.
The continued proper routing of paperwork requiring off site dose
calculation has been re-emphasized to responsible personnel.
(Closed) 374/85021-00 - Cables 2LD054 and 2LD'052 had been mislabeled
and thus were miswired in the control room. This resulted in ambient
temperature sensors being wired to a differential temperature trip
unit and a differential temperature sensor to be wired to an ambient
temperature trip unit. The error appeared to have taken place during
initial construction. The wiring error was corrected and the systems
were checked. Also, on a periodic basis, all detectors are heat checked
to validate proper wiring and functional operation.
The last five LER's were closed in this report to correct an
administrative error in failure to close them in previous reports.
These events had been reviewed at the time they occurred by the resident
inspectors and action was taken at that time.
8. Licensee Action on an IE Bulletin (92703)
(Closed) IE Bulletin 86-03 (373/86-03-BB; 374/86-03-BB): Region III
requested the inspectors to evaluate the licensee's response to IE
Bulletin 86-03 by C. Norelius' memo dated November 5, 1986. The licensee
issued a response on November 14, 1986. This bulletin describes a
single-failure vulnerability in the minimum flow recirculation line of
Emergency Core Cooling System (ECCS) pumps that could cause a failure of
more than one ECCS train. The failure of multiple trains in an ECCS due
to a single failure violates the single failure criterion in General
Design Criterion (GDC) 35 of 10 CFR 50, Appendix A.
The ECCS at LaSalle County Station is not vulnerable to the multiple
train failure due to a single failure in a minimum flow recirculation
line since each ECCS pump has an individual minimum flow valve which is
fed from an individual Motor Control Center (MCC) 480V breaker. Failure
of any minimum flow valve and/or breaker will potentially cause the loss
of only one ECCS pump. Therefore, multiple ECCS failures will not occur
due to loss of one minimum flow valve or MCC breaker.
This problem was addressed specifically for the Residual Heat Removal
(RHR) system in IE Bulletin 86-01 which was summarized and closed in
Inspection Report 373/86025.
The inspector reviewed the licensee's response and found the content to
satisfy inspection procedure 92703. This item is considered closed.
9. Followup of 10 CFR 50.54(f) Request for Information (71707, 30702)
On October 16, 1986 a management meeting between the NRC and the licensee
was held at the U.S. Nuclear Regulatory Commission's Regional Office to
discuss the licensee's progress in resolving the NRC's concerns related
to the overall operation of the LaSalle County Station. These concerns
were expressed to the licensee by letter, dated November 22, 1985. The
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meeting was attended by Mr. J. G. Keppler, NRC Region III Administrator
and members of his staff, and Mr. J. J. O' Conner of Commonwealth Edison
and members of his staff.
The discussion included a progress report of the licensee's commitments
for improved performance and a followup on the error free start up and
operation of LaSalle Unit 2. It was noted and agreed that significant
progress was being made toward improved performance in all areas of
concern. Also included in the meeting was an update of activities on
the Static-0-Ring switches, a review of recent personnel errors and
Engineered Safety Feature (ESF) actuations, and a review of the Unit 1
startup and power ascension.
10. Part 21 Followup (92701)
The inspectors received a 10 CFR 21 notification concerning a potentially
significant safety problem resulting from the failure of springs in
solenoid globe valves manufactured by Valcor Engineering Corporation.
This problem was also addressed in IE Information Notice 86-72. The Part
21 was sent to the inspectors by memorandum from C. E. Norelius dated
October 28, 1986. The residents forwarded a copy of the Part 21 to the
Assistant Superintendent of Technical Services.
The licensee has completed their review of the extent of implementation
of this type of Valcor valve at LaSalle County Station. This review by
the licensee indicates that no valves of this specific type are currently
in use on safety-related systems which contain borated water or reactor
chemistry water. The inspector reviewed the licensee's documentation and
finds the review and documentation acceptable. This item is closed.
(373/86040-05; 374/86040-02)
11. General Site Emergency Plan (GSEP) Orill (82205)
On November 5, 1986 the site held an unannounced GSEP assembly drill.
The drill went well with a few exceptions. There were twenty people who
were not logged in on the computer as assembling. Of the twenty people
not logged in, twelve had logged in at the assigned card reader in the
control room. Due to a computer software problem, the card reader used
did not record those persons as having used a designated assembly card
reader. Six of the twenty people not logged in were interviewed and
found to have logged in correctly, but due to card reader errors, had
not been recorded by the computer. Two of the twenty people, contractors,
did not acknowledge the assembly alarms and did not assemble, The
remainder of the drill was executed well and no other problems were
encountered.
12. Regional Request (92703)
The Region III office received a memorandum from R. L. Baer, Office of
Inspection and Enforcement, dated September 30, 1986 requesting the
resident inspectors to followup on the licensee's actions taken with
respect to the Ir.termediate Range Monitor (IRM) fuse failure event which
occurred at Monticello.
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The IRM system is required for startup per the Technical Specifications
for adequate neutron monitoring capability. It was shown that a
Monticello type single failure event occurring at LaSalle will not
unexpectedly and unknowingly result in an IRM trip system being left
inoperable. The General Electric analysis of LaSalle's IRM circuitry
concluded that for a single failure event that would cause the (plus or
minus) 24 VDC IRM chassis fuses on one RPS bus to blow, the operator
would detect the failure of the +24 VDC fuses. In order to make sure
that the -24 VDC fuses are checked, a placard has been placed above the
IRM and SRM chassis drawers stating that if any of the (plus or minus)
24 VDC chassis fuses are found defective or blown, check all the fuses
on the same bus and perform the weekly IRM/SRM functional tests (these
functional tests, performed weekly when in startup or shutdown, cannot be
performed successfully if any of the (plus or minus) 24 VDC chassis fuses
are defective) upon completion of troubleshooting. The reason the note
applies also to the SRM's is that at LaSalle the SRM and IRM electronics
are powered by the same power supply. There are also 6 AMP panel fuses
linking both systems. If any of these fuses should blow, as a minimum,
an RMCS rod block will occur preventing further rod pulls. Thus, LaSalle
is now protected against a single failure like the one that occurred at
Monticello. General Electric is not aware of any other single failure
event that would cause multiple undetected IRM channel failures, i.e.,
anything that would cause just the 4 -24 VDC IRM chassis fuses on one bus
to blow.
There are no safety consequences at LaSalle due to the fact that LaSalle
has hardware systems that Monticello does not (RSCS,' RWM, and 15% APRM
setdown upscale trip). The two events of concern, rod drop accident, and
the continuous rod withdrawal transient, are bounded by the 15% APRM
setdown upscale trip.
In addition, Sargent and Lundy performed a review of the possible design
problem. They concluded, based on a review of the FSAR and Regulatory
Guide 1.47, that no circuit modification is required.
In Inspection Report 373/86025; 374/86026, it was stated that actions
taken by the licensee were:
A. A warning label was to be placed on each SRM/IRM chassis to help the
operator in diagnosing a problem.
A plaque has been placed on the IRM/SRM drawers to check all the
(plus or minus) 24 VDC chassis fuses if any are found blown or
defective, and perform weekly surveillance upon completion of
troubleshooting. To date the licensee has completed item 1.
B. A long term hardware modification is to take place. Two SRM/IRM
modifications are being evaluated and will be submitted to the
licensee for review after a safety analysis has been performed.
Concerning item 2, the licensee has elected to not pursue the
modifications. Due to the reviews performed by General Electric
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and Sargent & Lundy, coupled with the hardware systems already in
place at LaSalle, the licensee is electing not to pursue the issue
any further.
In a memorandum from G. C. Wright to C. E. Norelius dated August 23,
1986, the resident inspectors were requested to perform an inspection on
items of concern pertaining to the Brookhaven National Laboratory (BNL)
Report on LaSalle's modification program.
Commonwealth Edison listed responses to the eight concerns identified in
section 2 of the BNL report. Followup on seven of the eight items was
necessary.
Item 1 - Closed (0 pen Item 373/86040-04A(DRP)).
The training of personnel, especially licensed operators, on the system
changes resulting from a modification, should be accomplished prior to
declaring the modification operable.
A. Procedures LAP-1300-2, " Modifications," and LAP-200-3 pertaining
to shift change, and the Administration and Course Management
Information (ACMI) for license requalification have been revised
to reflect new or changed requirements due to modifications.
B. Training on modifications completed after issuance of the BNL report
has been thorough and effective.
Item 2 - Closed (0 pen Item 373/86040-04B(DRP)).
Modification 83-018 regarding the upgrade of the de system instrumentation
and annunciation should specify that procedures be changed and operator
training be conducted prior to returning the modified system to service.
Commonwealth Edison's response was adequate. No further action is
necessary.
Item 3 - Open (0 pen Item 373/86040-04C(DRP)).
Conflicting setpoint information provided in the CRD Auto Scram
modification package (82-305) should be resolved by approved documentation
within the package.
The concern was to determine if the Control Rod Drive (CRD) charging
water header pressure instrument calibration setpoint was adequate to
meet the design setpoint when the inaccuracies of the calibration method
and plant instruments were taken into consideration. The Technical
Specification instrument setpoint for this reactor trip was greater than
or equal to 1157 psig (TS Table 2.2.1-1, Functional Unit 13.a). The
allowable value was greater than or equal to 1134 psig. The engineering
calculations determined the 1157 setpoint by considering all of the
system, calibration, and environmental inaccuracies. Setting the CRD
low charging header pressure at greater than or equal to 1157 will
ensure the analyzed inaccuracies will keep the trip setpoint range of
uncertainty from reaching the Limiting Safety System Setting (1134).
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Engineering Change Notice (ECN) No. PFL-67-LS-A, pages 11 and 12, changed
the range of the pressure transmitter (500 to 1500 psig), and the trip.
unit setpoint to 1170 psig. The licensee was setting the trip setpoint
at 1170. This was performed in surveillance procedure, " Control Rod
Drive Water Header Low Pressure Scram Calibration," LIS-RD-104 (Unit 1)
-and LIS-RD-204 (Unit 2).
Further review of the two procedures determined the static head
correction (2.25 psig) in Section E.8 was not considered in the
calibration. Both procedures stated the head correction was less than
0.1% of full calibrated range. The 0.1% was based on'the previous design
, (range of 0 to 2500 psig). The present design uses a range of 500 to
1500 psig (span of 1000). This makes the head correction 0.225% of
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- calibrated range.
,
The head correction acts in the non-conservative direction. The present
calibration method in both procedures sets the desired trip setpoint to
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open at-1170 psig with an allowable tolerance of.1157 to 1183. The ,
actual trip setpoint will be (1170-2.25) 1167.75 psig with a tolerance
of 1154.75 to 1180.75. The actual trip setpoint will be different from
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what was stated in design documents (1170) and the lower setpoint limit -
(1154.75) will exceed the Technical Specification trip setpoint value
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(1157).
Static head corrections are not included in the setpoint design
- calculations. They are determined after field installation of the
- transmitter and may have a measurable affect on the instrument loop
calibration.
This item will remain open pending the licensee's resolution of section
E.8 and inclusion of the head correction in the instrument loop
calibration for procedures LIS-RD-104 and LIS-RD-104 and LIS-RD-204.
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Item 4 - Closed (0 pen Item 373/86040-04D(DRP)).
'
Completed engineering and design of the modification, including a
physical walkdown of the proposed installation, should be conducted
prior to submittal of the package to the plant.
- Although Commonwealth Edison's response appeared to have only addressed
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actions for the upcoming Unit 2 refueling outage, they do in fact have a
i program in place for reviewing all modifications with respect to design
problems, conflicts with current station equipment configuration, review
for potential reduction of Field Change Requests (FCR's) and verification
, walkdowns.
- Item 5 - Closed (0 pen Item 373/86040-04E(DRP)).
An excessive turnaround time for drawing changes resulting from
modifications exists which could increase the potential for operating
errors.
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A. The Proactive Management Plan.has established a goal'of six months
for a turnaround time for processing of drawing changes. fTo date
this appears adequate. The LaSalle site is monitoring the progress
of drawing. change turnaround time and may try to decrease this time
. frame even further.
B. There is a program in place to monitor the status of the drawing
changes prior to the six month time limit established. Periodic
printouts of the outstanding drawing changes are reviewed and
tracked for completion within the established time limit.
Item 6 - Closed (0 pen Item 373/86040-04F(DRP)).
Quality Assurance (QA) involvement in the_ station modification program-
sh'ould address the operationally significant aspects of the program.
The QA department, in compliance with.their program, has: (1) established
requirements necessary to perform audits on modifications, and (2) has
physically performed the. audits prior to signing _the Modification ,
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Approval Sheet. The inspector reviewed the program requirements and
reviewed an audit performed on a recent modification,
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Item 7 - Closed (0 pen Item 373/86040-04G(DRP)).
Licensed operators should be made aware of precedure and Technical
Specification changes resulting from certain safety related modifications
activities prior to system operability.
This item is similar to Item 1. All the applicable revisions to
. procedures LAP-1300-2, LAP-200-3 and the ACMI for License
Requalification have been made. These actions to date have been
effective in notifying on shift personnel of Technical Specification
and procedural changes relating to critical modifications.
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Item 8 - Closed (0 pen Item 373/86040-04H(DRP)).
An inventory of " critical control room drawing" status is performed on
a quarterly basis. The results of the inventory should be reviewed by
- technical staff management to insure appropriate action is taken to
correct discovered * discrepancies.
The licensee's response appeared to meet the recommendations of
Brookhaven. A consideration for the licensee was to possibly increase
the frequency of the audits on inventory check of critical control room
drawings. The inspector held a discussion with the licensee on reviewing
their present audit schedule and to give some consideration to increasing
the frequency of their audits.
-13. Temporary Instruction (TI) (92701)
TI 2515/75 requested a followup inspection of the limitorque motor valve
operator wiring to determine if wiring is environmentally qualified.
This licensee was one of the first sites in 1985 to identify this
problem. Inspec, tion Report 373/85039; 374/85040, paragraph 2.a.,
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documents the inspection conducted in November and December 1985 on
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miswiring and unqualified wiring of limitorque operators. The
inspection documents the licensee's action taken to resolve the problem.
The inspection was conducted prior to issuance of this TI; however, a
review of the inspection report indicates the action required by the TI
had been completed. A followup inspection in July 1986 (IR 373/86030;
374/86031) addressed the notices of violation identified in the previous
inspection and closed all items concerned. Based on these two
inspections, this TI is considered closed.
14. Open Items
Open items are matters which have been discussed with the licensee, which
will be reviewed further by the inspector, and which involve some action
on the part of the NRC or licensee or both. Open items evaluated and
closed during the inspection are discussed in Paragraphs 10 and 12.
Open items disclosed during the inspection are discussed in Paragraph 4.
15. Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
throughout the month and at the conclusion of the inspection period and
summarized the scope and findings of the inspection activities. The
licensee acknowledged these findings. The inspector also discussed the
likely informational content of the inspection report with regard to
documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents or processes as
proprietary.
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