IR 05000373/1989003
| ML20248E197 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 03/23/1989 |
| From: | Harrison J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20248E159 | List: |
| References | |
| 50-373-89-03, 50-373-89-3, 50-374-89-03, 50-374-89-3, IEIN-88-061, IEIN-88-61, NUDOCS 8904120156 | |
| Download: ML20248E197 (21) | |
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S. NUCLEAR REGULATORY COMMISSION
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REGION III
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i Report Nos. 50-373/89003(DRP): 50-374/89003(DRP)
Docket Nos. 50-373; 50-374 Licen es.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 l
l-Inspection Conducted: January 30 through March 13, 1989
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. Inspectors:
R. Lanksbury R. Ko riva h v$N Approved By:
J. J. Harrison, Chief
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N Reactor Projects Section IB Date Inspection' Summary Inspection on January 30 through March 13, 1989 (Reports No.
50-373/89003(DRp); 50-374/89003(DRP))
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Areas Inspected: Routine, unannounced inspection conducted by resident
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inspectors of. licensee actions on previous inspection findings; operational safety; surveillance; maintenance; training; Licensee Event Reports; security; ESF system walkdowns; plant startup from refueling; onsite followup of written reports of.nonroutine events at power reactor facilities; and onsite followup of events at operating power reactors.
Results: Of. the eleven areas inspected, three violations were identified.
During this inspection period, there were fourteen Emergency Notification System (ENS) notifications, of which three were Engineered Safety Feature (ESF) actuations. Of the fourteen ENS notifications, six were for Static-0-Ring (SOR) failures which are not normally a 10CFR 50.72 reportable occurrence.
These are reportable at LaSalle because of a commitment made by Commonwealth Edison Company (CECO) due to previous problems with SOR switches at LaSalle.
Two ENS phone calls were for the startup of the units, one for Unit 1 and one for Unit 2.
One of the ENS phone calls was the result of the Unit 2 loss of System Auxiliary Transformer (SAT) and subsequent trip of Unit 1.
This avent lead to the formation of an Augmented Inspection Team (AIT).
The results of the AIT have been documented in inspection report 373/89007 and 374/89007.
8904120156 890323 PDR ADOCK 05000373 o
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On March 2, 1989, the loss of the SAT and subsequent trip of Unit i ended a continuous run record for Unit I which was 216 days on line. The best previous continuous run for Unit I had been 89 days. Unit 2 returned to service on March 7, thus ending a 115 day refueling / maintenance outage.
Major items accomplished during the outage were refueling of the reactor, repair of both Reactor Recirculation (RR) pumps, modification of both RR pump discharge valves, completion of the drywell cooling modification, and other miscellaneous outage related activities.
As noted in previous inspection reports, the licensee is continuing to improve housekeeping in radiologically controlled areas.
Progress has been
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recognized, but continued vigorous efforts in this area are needed.
Three Severity Level IV violations were issued during this inspection report period. All three were for failure to follow procedures. One was a repetitive finding pertaining to drywell lighting being energized. The two remaining violations pertained to failure to complete a Field Change Request (FCR) installation of a pulsation dampener and for failure to report an ESF actuation via the ENS phone system.
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DETAILS'
1.
Persons Contacted
- G. J. Diederich, Manager, LaSalle Station
- W. R. Huntington, Services Superintendent
- J. C.. Renwick, Production Superintendent D. S. Berkman, Assistant Superintendent,' Work Planning
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J. V. Schmeltz, Assistant Superintendent, Operations P. F. Manning, Assistant Superintendent, Technical Services
- T.' A. Hammerich, Regulatory Assurance Supervisor W. E. Sheldon, Assistant Superintendent, Maintenance J. H. Atchley, Operating Engineer W. Betourne, Quality Assurance Supervisor M. G. Santic, Master Instrument Mechanic j
W. J. Marcis, Site BWR Engineering Supervisor
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D. R. Reif, Regulatory Assurance J. Borm, Quality Assurance
- Denotes personnel attending the exit interview on March 20, 1989.
Additional licensee technical and administrative personnel were contacted by the inspectors during.the course of the inspection.
2.
Licensee Action on Previous Inspection Findings (92701)
(Closed) Unresolved Item (373/88029-01):
Failure to maintain the Unit 1 AC breakers in the Regular Lighting Cabinet (RLC) 110 circuit, which supply power to the drywell lights in the de-energized position. At the time of this event, Unit 1 was in Operational Condition 1.
Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.8.3.1 requires that in Operational Conditions 1, 2, or 3 that the AC circuits that supply power to all drywell lighting be de-energized.
The significance of the circuitry to the drywell lights being energized is that the associated electrical penetrations of the drywell do not have backup fault protection. With the unit in operation, if the primary fault protection failed during a condition where a fault inside the drywell existed, the potential existed for overcurrent and thermal overload.
This, in turn, could lead to damage of the electrical pene-trations and penetration conductors which, in turn, might cause a breach of primary containment integrity and the possible damage of other t
conductors in the same penetration. The maximum amount of time that l
this situation existed was 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since the position is checked daily
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by the licensee and the previous days check had indicated that the breakers were de-energized.
This unresolved item is closed. The failure to maintain the Unit 1 AC breakers in the RLC 110 circuit in the de-energized position is a violation of Technical Specification 3.8.3.1 (373/89003-01(DRP)).
As immediate corrective action. the licensee de-energized the circuits within 10 minutes of discovery.
Subsequently, the licensee expanded l
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the use of the Out-of-Service (00S) cards originally hung to include the ccn tctor relays.
By taking the contactor relays 00S, in addition to those for circuits that actually penetrate primary containment, more than an inadvertent action is required to energize the drywell lights. These 005 cards were hung on November 29, 1988.
In addition, the licensee locked the Unit I lighting cabinets on November 29, 1988 and added a requirement to the Reactor Building Rounds Package to verify that the cabincts are locked every eight hours until the refueling outage was complete. At that time, the checks would revert to a daily check to verify that the circuits were de-energized.
Based on the corrective actions taken by the licensee, the inspector has no further concerns regarding this matter and this item is considered closed; consequently no reply to this violation is required.
i (Closed) Open Item (373/85032-02): Writing of a lubricant control procedure.
This was administrative 1y closed by Division of Reactor Safety (DRS).
(Closed) Open Item (373/88006-01):
Procedure needs to be revised to remove alternative lubricants from the procedure to eliminate the potential for mixing lubricants.
This was administrative 1y closed by DRS.
(Closed) Open Item (373/86004-02):
Fire and evacuation sirens and local indicating lights relating to the fire detection zones circuitry are not continuously monitored as required by NFPA 720-1975. This was administrative 1y c W ed by DRS.
(Closed) Open Item (373/86022-01):
Total containment volume in FSAR not consistent with the licensee's procedure.
This was administratively
.losed by DRS.
(Closed) Open Item (373/87034-01):
Excessive leak rates on feedwater check valves. This was administrative 1y closed by DRS.
(Closed) Unresolved Item (373/87034-02): Calibration results on flow-meters da not indicate units.
This was admin 13tratively closed by DRS.
(Closed) Open Item (373/86004-03):
Fire protection flow path valve cycling tett procedure will be revised to insure that adequate documentation exists to insure that valves are lubricated and cycled.
This was administrative 1y cicsed by DRS.
(Closed) Open Item (373/87027-01):
Four discrepancies were observed during or as a result of a fire brigade drill by an NRC inspector.
This was administrative 1y closed by DRS.
(Closed) Open Item (373/86042-01):
Place plant specific technical guidelines under document control systems. This was administratively closed by DRS.
(Closed) Open Item (373/86042-02):
Incorporate SRP definition of deviation into P-STE control. This was administratively closed by DRS.
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(Closed) Open Item (373/86042-03):
Revalidate E0P's. 'This was I
administratively closed by DRS.
j (Closed) Open Item (373/Q6042-04): Upgrade validations criteria. This was administrative 1y closed by DRS.
(Closed) Open Item (373/86042-05):
Place operator aid under control
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program.
This was administratively closed by DRS.
(Closed) Open Item (374/85033-02): Writing of lubricant control procedure. This was administratively closed by DRS.
(Closed) Open Item (374/88006-01):
Procedure needs to be revised to remove alternative lubricants from the procedure to eliminate the potential for mixing lubricants. This was administratively closed by DRS.
(Closed) Open Item (374/87033-01):
Excessive leak' rates on feedwater check valve. This was administratively closed by DRS.
(Closed) Unresolved Item (374/87033-02):
Calibration results on flow meters do not indicate units, This was administrative 1y closed by DRS.
(Closed) Open Item (374/85029-01):
Failure of HPCS piping to cycled condensate storage tank - metallurgical degradation. This was administratively closed by DRS.
(Closed) Violation (374/85013-05):
Item A - Lifted lead log. indicated LL130 reinstalled, however, it was still lifted in the field.
This was administratively closed by DRS.
(Closed) Open Item (374/86004-02):
Fire and evacuation sirens and. local indicating lights relating to the fire detection zones circuitry are not continuously monitored as required by NFPA 72D-1975. Tnis was administratively closed by DRS.
(Closed) Violation (374/86018-01):
Drywell temperature data collected between January 1 and March 31, 1986 was not submitted to SNED for evaluation as required by procedure LTP-300-17, Revision 1.
This was administrative 1y closed by DRS.
(Closed) Ooen Item (374/87026-01):
Four discrepancies were observed during or as a result of a fire brigade drill by an NRC inspector.
This was administrative 1y closed by DRS.
(Closed) Open Item (374/86042-01):
Place P-STG under document control system.
This was administratively closed by DRS.
(Closed) Open Item (374/86042-02):
Incorporate SRP definitions of deviations into P-STE control. This was administratively closed by DRS.
(Closed) Open Item (374/86042-03):
Revalidate E0P's.
This was administrative 1y closed by DRS.
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r (Closed) Open Item (374/86042-04):
Upgrade validation criteria. This
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(Closed) Open Item (374/86042-05):
Place operator aid under control program.
This was administratively closed by DRS.
No deviations were identified in this area, however, one violation was-identified.
3.
Oper&tional Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable a.
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logs,'and conducted discussions with control room operators during
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the inspection period.
The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of Unit 1 and 2 reactc buildings, auxiliary buildings, and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations, and
'to verify that maintenance requests had been initiated for equipment i
in need of maintenance. The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan including the following: the appropriate number of security personnel were on site; access control barriers were operational; protected areas were well maintained; and vital area barriers were well maintained. The
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inspector verified the licensee's radiological protection program I
was implemented in accordance with the facility policies and programs and in compliance with regulatory requirements.
b.
The inspectors performed routine inspections of the control room during off-shift and weekend periods; these included inspections between the hours of 10:00 p.m. and 5:00 a.m..
The inspections were conducted to assess overall crew performance and, specifically, control room operator attentiveness during night shifts. The inspectors also reviewed the licensee's administrative controls regarding " Conduct of Operations" and interviewed the licensee's security personnel, shift supervisors and operators to determine if shift personnel were notified of the inspectors' arrivals onsite during off-shifts.
The inspectors deterr.ined that both licensed and non-licensed operators were attantive to their duties, and that the inspectors'
arrivals on site appeared to have been unannounced.
The licensee has implemented appropriate administrative controls related to the conduct of operations. These include procedures which specify i
fitness for duty and operator attentiveness, i
c.
On January 31, 1989, at approximately 5:20 a.m. (CST), the Senior Resident Inspector informed the licensee that he was having difficulty obtaining information from the licensee's Prime computer.
The licensee, upon investigation, found that the Prime computer had stopped at 5:01 a.m..
The licensee called in their computer
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engineer and after evaluating the problem concluded that they could not return the computer to service within the required two (2) hours. At 7:30 a.m. the licensee made the required Emergency Notification System (ENS) notification. The Prime computer provides inputs for calculating offsite dose assessments.
The site main-tained full capability to provide the necessary calculations. The licensee replaced a defective circuit board in the computer and it was returned to service at 9:00 a.m..
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d.
On February 4, 1989, at approximately 4:30 p.m. (CST), the Unit 2 Residual Heat Removal (RHR) shutdown cooling pump suction valve j
2E12-F008, isolated upon receipt of a high pump suction flow signal when the 2B RHR pump was being started.
The valve actuation is an Engineered Safety Feature (ESF) actuation. The licensee informed the resident inspectors that this actuation was anticipated upon
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the start of the RHR pump and they were not going to report the I
actuation via the Emergency Notification System (ENS).
The RHR shutdown cooling system was filled and vented and the isolation reset. On February 6,1989, at approximately 1:27 p.m., valve 2E12-F008 again isolated upon the start of the 28 RHR pump. Again, the licensee did not report the ESF actuation via the ENS because the actuation again was expected. On February 7, 1989, at approximately 1:13 p.m., valve 2E12-F008 again isolated due to receipt of a high pump suction flow signal. This time the 2B RHR pump that was running to provide shutdown cooling at the time, had just been turned off in preparation for startup of Unit 2.
At 3:00 p.m., the 2B pump was re-started after resetting the isolation signal and re-establishing the shutdown cooling lineup. At 3:51 p.m., the licensee made the required ENS notification. Because this isolation was not expected, the licensee started investigating the cause of the isolation.
They suspected that it possibly was a problem with the high suction flow switch, 2E31-6012 AA.
The licensee checked the calibration of the switch and determined that the switch was within calibration. After complet:ag their investi-gation, the licensee believed that the actual cause of all the isolations may have been due to pressure / flow surges being sensed by the inboard flow element, 2E31-N012 AA, during initial pump starts and stops, rather than due to air entrapment as originally believed. The investigation indicated that the flushing and repair of the excess flow check valves in the system have increased the sensitivity of the inboard switches to the point that pulsation dampeners were going to be required as permitted by design. Upon review of the specific drawing, the pulsation dampeners were shown on the approved drawing, but in fact they had not been installed in the plant per Field Change Request (FCR) L85-87 of Modification M-1-2-84-136.
Technical Specification 6.2. A states, in part:
" Detailed written procedures including applicable checkoff lists covering items listed shall be prepared, approved and adhered to:
The applicable procedures recommended in Appendix A of Regulatory
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Guide 1.33, Revision 2, February 1978 which includes administrative procedures".
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Administrative procedure LAP-1300-5, Revision 10, Field Change Requests (FCR's), steps F.22, F.23 and F.24 states, in part, the following:
F.22 Verify that the work was completed by FCR and that the revised documents are updated acceptably F.23 Review and approve final disposition of FCR F.24 Verify completion of FCR.....
Contrary to the above, on July 13, 1987, which was the completion j
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date for n. modification M-1-2-84-136, Replacement of the Barton Differential Pressure (dp) Switches With Static-0-Ring (SOR) dp Switches, the licensee failed to review and verify completion of FCR L85-87. This FCR instructed the installation of pulsation dampeners on SOR switch 2E31-N012AA. The dampeners were never installed even though the approved drawing indicated that they had been installed.
This is a violation (374/89003-01).
Had the licensee investigated the initial ESF isolation actuation instead of presuming that the isolation was due to entrapment of
air in the system, they possibly would have discovered that the
pulsation dampeners had not been installed and possibly would not have had the other ESF isolation actuation.
Title 10 Code of Federal Regulations, Part 50.72, Inmediate Notifications, Section 2 (ii) states, in part, "Any event or condition that results in manual or automatic actuation of any Engineered Safety Feature (ESF)..
Contrary to the above, the;e had been two ESF actuations, one on February 4,1969 and tr.e second on February 6,1989 that were not reported as per 10 CFR 50.72. Both actuations were isolations of the Residual Heat Removal (RHR) shbtdown cooling system. This is a violation (374/80003-02).
The licensee had informed the residents that they felt that the ESF actuations were not reportable in that the actuations were anticipated. The resident inspector reviewed the applicable procedures and was unable to locate any warnings, cautions or notes pertaining to an anticipated ESF actuation which would isolate shutdown cooling upcn the start up or shutting down of the 2B RHR pump.
e.
On February 6,1989, at approximately 5:50 a.m. (CST), the shift engineer was notified that there was an injured Equipment Attendant (EA) on the 694' elevation of the Unit 2 reactor building in the Reactor Core Isolation Cooling (RCIC) water leg pump corner room.
The EA was performing valve lineups in preparation for Unit 2 startup and apparently fell when a va'
hcodle he grabbed came off.
The licensee transported the injured L :o St. Mary's Hospital in
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Streator, Illinois as potentially contaminated. The area in which
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he was found was surveyed and found to be clean and portions of the EA were also surveyed and found to be clean.
However, because of the injuries involved, which included a broken wrist, a punctured i
lung, broken ribs, and head injuries, his back was not surveyed. A j
radiation technician went in the ambulance to complete the surveys at the hospital.
The licensee declared an Unusual Event at 6:40 a.m. in accordance with their General Site Emergency Plan.
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required ENS notification was made at 6:55 a.m..
The Senior Resident Inspector was on site during the event and witnessed the evacuation of the EA and subsequent followup actions. The Unusual i
Event was terminated at 8:15 a.m. when it was determined that the
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EA was not contaminated.
f.
On February 10, 1989, at approximately 10:3U a.m. (CST), the licensee was informed by the Boiling Water Reactor Engineering (BWRE) group of an apparent design deficiency in the Control Room (CR) Heating, Ventilation, and Air Conditioning (HVAC) system.
i BWRE was performing a design review of the CR HVAC system in
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response to Information Notice 88-61, Control Room Habitability."
- Recent Reviews of Operating Experience.
BWRE found that a potential existed for a hot short to cause the systems smoke purge dampers (0VC14YA or YB) to open wh;le the system was running in the pressurization mode. The pressurization mode is initiated automatically upon a signal indicating outside smoke or upon an air intake radiation signal.
With the purge damper open on the operating train, the control room would not be able to maintain I
a positive pressure. The potential existed that the CR HVAC system might draw in any toxic atmosphere that might exist outside.
Because no indication of the position of the purge dampers exists in the control room, the operators would not be aware that a problem existed.
Since both trains of the CR HVAC system contain one of these purge dampers, the discovery of this problem rendered both trains inoperable. As an immediate compensatory measure, the licensee stationed an individual at the purge dampers of the operating train to maintain it in the closed (normal) position. As a temporary solution the licensee mechanically disconnected the dampers. The licensee is evaluating pennanent solutions for preventing the possible hot shorting of the CR HVAC systems smoke purge dampers, g.
On February 14, 1989, at approximately 11:35 a.m. (CST), a painter working on painting local instrument rack 2H22-P002 inadvertently bumped the Unit 2 Reactor Water Cleanup (RWCU) system pump discharge pressure instrument sensing line (2G33-R004/N005) causing it to separate from the instrument.
The line separation permitted a primary system leak into the secondary containment.
No ESF actuation occurred. The painter was contaminated, mainly from the waist down, and two other individuals contaminated their shoe;.
The licensee estimates that the discharge from the instrument line
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was approximately 22 gpm and that the total amount of primary fluid lost was approximately 200 gallons. At 11:45 a.m. operators
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initially attempted to isolate the leak but were unable to do so.
The RWCU system was shutdown from the Control Room'at 11:52 a.m.
reducing the flow at the instrument rack. At 12:00 p.m. the operators were able to isolate the leak.
The painter was working on painting the back of the instrument racks at the time of the event. The instrument rack is located less than two feet from a wall.
Because of seismic bracing for the instrument rack, the space available for maneuvering is less than one foot.
The painter was working in a crouched position and when he attempted to change position his knee hit the instrument sensing line.
Further invest-igation by the licensee indicated that the instrument sensing line fitting had not been properly installed.
Only a small portion of the tube end was compressed by the ferrule.
The ferrule should have been positioned approximately 3/8 inches back on the tubes for a good compression fit.
The licensee inspected five additional fittings on the same instrument rack and found no additicnal problems.
The licensee is also reviewing the need to prepare an assembly procedure for the installation of these fittings and plans on covering the event with the Operating, Maintenance, and Project and Construction Services Organizations.
h.
On February 25, 1989, at approximately 6:05 p.m. (CST), the Unit 1, j
Division 1, drywell humidity monitor tripped when the sample pump
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discharge valve (1CM-019A) closed for no apparent reason.
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indication for 1CM-019A at panel IPM-13J in the control room was also lost.
ICM-019A is an inboard primary containment isolation valve.
The licensee declared ICM-019A inoperable and entered the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time clock of Technical Specification 3.6.3 that required the
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redundant valve (1CM-020A) to be closed. At 6:15 p.m. valve
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position indication at IPM-13J returned. At 6:25 p.m. the Shift Engineer jarred a metal floor plate in front of panel IPM-13J and position indication was again lost. The licensee closed ICM-020A at 6:45 p.m. to comply with Technical Specification 3.6.3 and exited the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time clock. An ENS notification was made at 8:00 p.m..
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Investigation by the licensee revealed that the cause of the problem was attributable to loose fuse holders.
The fuse holders were tightened and other fuse holders in panel IPM-13J were inspected and
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tightened. On February 27, 1989, at 1:20 p.m., the drywell humidity j
monitor was declared operable.
j Two violations were identified in this area.
4.
Monthly Surveillance Observation (61726)
The inspectors observed Technical Specification required surveillance testing and verified for actual activities observed that testing was performed in accordance with adequate procedures, that test instruments-tion was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with Technical Specification and procedure requirements and were reviewed by personnel other than the individual
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directing the test, and that any deficiencies identified during the
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testing were properly reviewed and resolved by appropriate management personnel.
The inspectors witnessed portiorss of the following test activities:
LIS-MS-102 Unit 1 Main Steam Line High Flow Main Steam Isolation
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Valve (MSIV) Isolation Calibration I
LOS-RI-R1 Unit 2 Reactor Core Isolation Cooling Turbine
Overspeed Test LOS-TG-Q1 Unit 2 Turbine Quarterly Surveillance LOS-DG-M2 Unit 1 Diesel Generator Operability Test
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LOS-RI-Q4 Unit 2 Reactor Core Isolation Cooling (RCIC) System Cold Quick Start In Conditions 1, 2, and 3 On February 1, 1989, at approximately 5:30 p m. (CST), during a.
performance of LIS-RH-203, Unit 2 RHR Pump Minimum Flow Bypass (L?CI Mode) Calibration, Static-0-Ring (SOR) switch 2E12-N010A exceeded its reject limit.
The licensee declared the 2A Low Pressure Core Injection (LPCI) system inoperable.
However, since Unit 2 was in cold shutdown for a fifteen week refueling outage, LPCI was not l
required to be operable.
The required Emergency Notification System (ENS) notification was made at 6:40 p.m. (the licensee is required to report all SOR switch failures due to previous problems and history of SOR switches at LaSalle).
At the time of this event
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l Unit I was at approximately 96% power.
The licensee replaced switch 2E12-N010A, calibrated it, and declared the 2A LPCI system operable i
on February 5,1989 at 5:15 p.m..
j b.
On February 3, 1989, at approximately 12:15 p.m. (CST), the 1A Diesel Generator Output Breaker ACB 1423 failed to close during the performance of operating surveillance LOS-DG-M2, IA(2A) Diesel Generator Operability Test.
The breaker failure occurred while the Unit 1 Nuclear Station Operator (NS0) was attempting to synchronize the 1A DG with offsite power.
Troubleshooting revealed that the cause of the breaker failing to close was the failure of overvoltage relay 1427-DG013 in the 1A DG Output Breaker closing circuit.
The purpose of this relay is to actuate at a pre-set generator output voltage following a DG start and to prevent the DG Output Breaker (
from closing before the correct generator voltage is available.
Work Request L8700 was written to the Operational Analysis Department (OAD) to replace the 1427-DG013 relay.
It was discovered that there were no spare ITE-59N type overvoltage relays available (which would be the exact replacement), however, there were 59D type
overvoltage relays available on site.
Both relays are made by the j
same manufacturer.
These two relays perform the same function in an
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i identical manner with the exception of a built in time delay of the
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590 that can be adjusted with a minimum setting of 100 milliseconds.
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The manufacturer of the'59N relay'was'immediately contacted about
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getting a replacement'59N relay. The manufacturer did not have a l
completed 59N relay in stock and were not sure if one could be completed in the required time.
The option to have the faulty 59N
relay repaired by the manufacturer was also determined -to take too
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long. As a short term ~ corrective action to return the 1A DG to
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operable status,'the 59N type relay was replaced with the.59D type relay under Temporary System' Change 1-45-89.
As previously stated, the two relays are identical. with the exception of the built in time i
delay on the 590. An engineering evaluation was performed under administrative procedure LAP-400-5, Technical Evaluation of Parts'.
Used in-Safety Related Components, to verify that the 59D was an acceptable replacement of the 59N.
Following the installation of the 590 relay, Special Test LST-89-023, 1A DG Voltage Sensing Relay
Response Time, was performed in conjunction with LOS-DG-SA2, 1A(2A).
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Diesel Generator Operability Test with Response Time, to verify
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that the 1A DG Output Breaker ACB 1423 would close within 13 i
seconds after receiving a start signal per Technical Specification 4.8.1.1.2.
The test'results were satisfactory. The-1A DG output breaker closing time was 9.9 seconds. The 1A DG was declared operable at approximately.9:00 p.m. on February 4, 1989 after being inoperable for approximately 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br />. ~ 0n February 23,-1989, the repaired 59N' relay was reinstalled and tested satisfactorily.
The cause of the relay failure was a failed zener diode in the power supply circuit of the relay.
This diode is designed to regulate a constant 15 volts DC output in the relay power supply. The faulty relay was sent to the manufacturer (Brown Boveri) for. repair and it was determined that the diode was only maintaining 5 volts DC instead of 15 volts DC.
This caused the power supply voltage to be too low, which prevented the relay from performing its design function. When the diode was replaced, the relay performed as
. designed.
The manufacturer indicated that this diode has not failed previously in their equipment and has sent the diode to its manufacturer to try and determine the cause of its failure. The results of this report will be sent to Commonwealth Edison Company LaSalle Station.
The safety consequences of this ever,t were minimal.
LaSalle
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Station's Limiting Conditions for Operation considers the temporary loss of a Division power supply. All other power stpplies were available during this event The 1A DG was inoperable for approximately 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br />.
Technical Specification 3.8.1 required the 1A DG to be operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. All Emergency Core Cooling Systems (ECCS) for Unit 1 were operable during this event.
c.
On February 7,1989, at approximately 2:10 a.m. (CST), the licensee was performing instrument surveillance LIS-MS-102, Unit 1 Main Steam Line High Flow Main Steam Isolation Valve Isolation Calibration.
While testing SOR switch IE31-N0088, the instrument mechanics found the switch to be out of its reject limits. The reject limits for that switch are 94.8 - 111.2 inches of water column.
SOR switch 1E31-N008B was found at 93.0 inches of water column. This is in
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the conservative direction.
The licensee declared the switch inoperable and the required ENS notification was made at 2:45 a.m..
The switch was replaced, successfully completed the calibration, and placed the switch back into service on February 10, 1989.
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On February 14, 1989, at approximately 1:20 p.m. (CST), during the j
performance of LIS-NB-206, Unit 2 Reactor Vessel Low Water Level i
Confirmed ADS Permissive Calibration, SOR differential pressure switch 2B21-N038B exceeded its reject limit. The licensee declared Division II of the Automatic Depressurization System (ADS) inoper-able and entered the 7 day Limiting Cordition of Operation (LCO) of
the Technical Specification.,.
The reqJired ENS notification was
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made at 2:20 p.m..
At the time of this event, Unit'I was at l
approximately 100% power and Unit 2 was at approximately 19% power.
During the surveillance in which the switch was found to be defective, the switch tripped at an equivalent of -30 inches reactor water level; not the required Technical Specification limit of 12.5 inches.
In addition, because of the arrangement of the differer.tial pressure sensor in relation to the reactor vessel, sufficient
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differential pressure could not have been generated under actual i
conditions to cause the switch to trip.
The licensee plans on returning the switch to SOR for disassembly and inspection to determine the cause of failure as they have routinely been doing.
The licensee replaced the switch, successfully completed the calibration, and declared Division II of ADS operable at 7:20 a.m.
on February 15, 1989.
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l e.
On February 28, 1989, at approximately 9:15 a.m. (CST), the licensee informed the resident inspector that they had a SOR differential pressure switch fail.
The licensee was performing surveillance LIS-NR-102, Unit 1 Reactor Vessel Low-Low Water Level (Level 2)
i Primary and Secondary Containment Isolation Calibration, when they discovered SOR differential pressure switch 1B21-N026 CB cut of calibration and in the rejectable range.
The licensee then jumpered out the Groups 2, 3, 4 and 5 primary containment isolation signals the SOR switch would have actuated.
The licensee then tripped SOR l
switch 1821-N026 CB at 10:08 a.m..
This left the unit with a 1/4
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primary containment isolation pertaining to Groups 2, 3, 4 and 5.
The licensee made the required ENS phone notification at 10:25 a.m..
The licensee replaced the 50R switch, calibrated it, and placed it back into service on March 1, 1989 at 6:45 a.m.,
f.
On March 3, 1989, at 5:00 p.m. (CST), the licensee was performing l
surveillance LIS-NB-106, Unit 1 Reactor Vessel Low Water Level Confirmed Automatic Depresserization System (ADS) Permissive Calibration.
At 6:00 p.m., the Instrument Me-hanic (IM) found Static-0-Ring differential pressure switch 1B21-N038A out of calibration exceeding the reject limit of the procedure.
Division I of the ADS was declared inoperable which placed the unit into a 7 day time clock.
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At 7:07 p.m.,
the licensee made the req; ired Emergency Notification
System (ENS) phone call reporting the defective SOR switch.
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On March 4, 1989' at 3:45 p.m., the IM's were working on replacing
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the defective SOR switch under work request L88000.
At 7:30 p.t.,
i the IM's were per~ ' ming LIS-NB-106 and at 10:45 p.m., ADS Static-0-Ring dif
>ntial pressure switch 1821-N038A was~ declared operable.
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On March 9, 1989, at 11:00 a.m.-(CST), the licensee was performing l
instrument surveillance LIS-RI-101, Unit 1 Steam Line High Flow
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Reactor Core Isolation Cooling (RCIC) Isolation Calibration.
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At 8:45 p.m. the instrument mechanics performing the surveillance discovered Static-0-Ring (SOR) differential pressure switch 1E31-N013BB had a-leaking diaphragm. The switch and the RCIC'
system were declared inoperable. At 10:00 p.m. the licensee made the required Emergency Notification System (ENS) phone call.
On March 11, 1989, the licensee replaced SOR differential pressure i
switch IE31-N013BB with a new SOR switch. At 5:00 p.m., the instrument mechanics had completed surveillance LIS-RI-101 satisfactorily. At 5:40 p.m. the RCIC system was declared operable.
No violations or deviations were identified in this area.
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5.
Monthly' Maintenance Observation (62703)
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 Technica1' 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; functiona'l testing and/or calibrations were performed prict 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 i
were implemented. Work requests were reviewed to determine status of l
outstanding jobs and to assure that priority is assigned to safety
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related equipment maintenance which may affect system performance.
a.
During the week of February 19, 1989, the licensee informed the l
NRC resident inspectors that they would be performing a routine
lubricating maintenance surveillance on the Unit 1 Turbine Driven
Reactor Feedwater Pumps (TDRFP) during the week of. February 26, 1989.
On Monday, February 27, 1989, the resident inspector reviewed I
surveillance procedure, LMP-FW-1L Periodic Lubrication and Maintenance of Turbine Driven Feed ?umo Coupling, in preparation of observing the surveillance.
Through discussions with the licensee, i
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the resident Was ir: formed of' their approximate schedule for.
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performing the' surveillance'and for other preparatory work that o
l was associated.with the surveillance.
' Late.on. February'27, 1989, the licensee placed the Unit 1 Motor Driven Reactor' Feed Pump (MDRFP) in service.'and took th'e 1A TDRFP off line. - On February 28, 1989,-the NRC resident inspector
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accompani.ed by the Illinois Department of Nuclear Safety resident
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inspector observed the performance of LMP-FW-13.
Items of interest h
being observed throughout the surveillance were as follows:
(1) The activities were not violating Limiting-Conditions.for Operations (LCOs).
(2) If there'were redundant components that they were operable.
(3) Required administrative approvals and tagouts were obtained before initiating the work.
(4) Approved procedures were being used or the activity was within the " skills of the trade."
(5) The' procedures used were adequate to control.the activity.
(6) Activities were being accomplished by qualified personnel.
(7) Replacement parts and materials being used were properly certified.
(8) Radiological controls were appropriate and were properly implemented.
(9) Quality control hold points were established,'where required, and observed.
(10) Equipment was properly tested and/or calibrated before being returned to service.
'(11) Equipment and its associated system were properly returned to service.
I (12) Housekeeping practices were being observed.
Through direct observation, the inspector had.reviewe; :he appropriate approvals and tagouts for the work being performed.
TF 3 licensee had employed the services of a General Electric Company tahnician for inspection of the turbine linkages.
Prior to the surveillance and during the past several months of operation, there had been some turbine control valve oscillations for which the licensee had been unable to locate the exact cause. The activities went well.
Radiological controls were observed by the workers and were appropriate.
The workers were organized and were aware of what was expected of them.
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Late on February 28,'1989, the Unit 1A'TDRFP'was returned to service and the 18 TDRFP taken out of service. On March 1, 1989, the same.
maintenance was performed on the B TDRFP.
The mechanics were more proficient in performing their activities on the second day than they were on the first day, and the coordination between the mechanical and electrical maintenance activities was better. After the completion of'
testing and review of the work performed, the 1B TDRFP was placed back-
. in service and the MDRFP shutdown.
' The inspector discussed the surveillance with the licensee's technical staff person overseeing the surveillance..Both constructive criticism and activities performed well were discussed. One item pointed out was general. housekeeping in the TDRFP rooms for both Unit 1 and 2 could ta.
better.
No violations or deviations were identified in this area.
6.
Training (41400)
The' inspector, through discussions with personnel, evaluated the licensee's training program for operations and maintenance personnel to determine whether the general knowledge of the individuals was sufficient for,their assigned tasks.
In the areas examined by the inspector, no items of concern were identified.
No violations or deviations were identified in this area.
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7.
Licensee Event Reports Followup (93702)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine
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that deportability 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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The following reports of nonroutine events were reviewed by the l
inspectors.
Based on this review it was determined that the events were of minor safety significance, did not represent program l
deficiencies, were properly reported, and were properly compensated
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for.
These reports are closed:
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373/88028-01 - Setpoint drift of reactor vessel low water level l
l switch.
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l 373/89001-00 - Automatic start of 0 Diesel Generator due to l
personnel error while removing test equipment.
373/89002-00 - Spurious ammonia detector actuation trip due to design deficiency in the cheacassette tape mechanism.
373/89003-00 - Setpoint drift of reactor vessel low water level switch.
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374/88013-01 - Low pressure core. spray minimum flow bypass differential switch found above rejection limit.
.374/89002-00 - Engineered Safety Feature actuation due to instrument valving error during surveillance testing.
374/89003-00 : Engineered-Safety Feature actuation during performance-of instrument maintenance functional tests due to personnel error.
373/88029-01 - Setpoint drift of low level confirmed Automatic Depressurization System permissive switch.
This revision is made because the rejected instrument was disassembled and examined by its
, manufacturer and one of the microswitch. contacts was found degraded.
374/89004-00 - 2A Residual heat removal minimum flow bypass switch found greater than reject limit during surveillance testing.
373/89004-00 - Spurious ammonia detector trip due to unknown cause.
373/89005-00 - Main steam high flow switch out-of-tolerance due to setpoint drift.
b.
The following : reports of nonroutine events involved violations of regulatory requirements.
These reports are considered closed.
Event closure is being tracked by the associated violation.
Appropriate cross references are provided.
374/88009-01 - Failure of reactor core isolation cooling steam line
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high flow isolation switch to actuate or hold water.
This revision is submitted because of further investigation on the defective SOR switch.
i 373/88027-00 - Drywell lighting circuits found energized during i
surveillance caused by. personnel error.
374/89005-00 - Isolation of the Shutdown Cooling System due to spurious high flow signal.
No violations or deviations were identified in this area.
I 8.
Security (71881)
The licensee's security activities were observed by the inspectors during
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routine facility tours and during the inspectors' site arrivals and i
departures.
Observations included the security personnel's performance associated with access control, security checks, and surveillance i
activities, and focused on the adequacy of security staffing, the security response (compensatory measures), and the security staff's attentiveness and thoroughness. The security force's performance in i
these areas appeared satisfactory.
No violations or deviations were identified in this area.
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ESF System Walkdown _(71710)
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The operability cf selected engineered safety features was confirmed by the inspectors during walkdown of the accessible portions of the following system. The following items were included: verification that procedures match the plant drawings, equipment ccnditions, housekeeping, instrumentation, valvo and electrical breaker lineup status (per procedure checklist), and verification that locks, tags, jumpers, etc.
are properly attached and identifiable. The following system was walked down during this inspection period:
Unit 2 Standby Liquid Control System No violations or deviations were identified in this area.
10. Plant Startup From Refueling (71711)
a.
On February 3, 1989, a conference call was held between the resident's office, Region III, and the Office of Nuclear Reactor Regulation to discuss the contingency plans submitted by the licensee to support startups of Unit 2 with the disk insert lost from the 2B recirculation pump during the units shutdown. The disk insert was not found during the cutage. Agreement was reached that no technical basis existed to restrict startup. Subsequently, the licensee was so informed. As part of the licensee's justification for startup, they conmitted to perform certain actions.
Pending ccmpletion of those actions, they will be tracked as an Open Item (374/89003-03(DRP)).
b.
On February 7, 1989, at approximately 8:58 p.m. (CST), the licensee placed the Unit 2 node switch in Startup and commenced performing
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shutdown margin testing. On February 8, 1989, at approximately 12:02 a.m., the licensee commenced pulling control rods toward critical. The reactor was declared critical at 1:55 a.m..
The residents were in the control room during the startup witnessing the licensee's actions. At the time of startup, Unit 2 had been off-line 116 days (since October 14,1968) in a refueling /mainten-ance outage. Scme of the major work accomplished during the outage included the completion of 69 modifications, rebuilding of both recirculation pumps, repair of both recirculation pump discharge valves, and overhaul of the main turbine.
One open item was identified in this area.
11.
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facil Wi~e~s (92700)
On March 10, 1989, the resident inspectors were informed that Consonwealth Edison Company's (CEC 0) Coiling Water Reactor Engineering (BWRE)
group and Sargent & Lundy (S&L) had corrpleted their review of NRC Information Notice No. 88-61, Control Room Habitability-Recent Reviews of Operating Experience" and BWRE has concluded that the concerns are not
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applicable to the LaSalle Station.
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s The BWRE group has identified one potential corrponent (damper CVC14YA/B -
also discussed in Section 3) that could be caused to open and remain open by a sustained hot short. BWRE has identified that a sustained hot short between terminals or between conductors in Panel OPL15J, could spuriously cause the Control Ventilation (VC) system smoke purge
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damper CVC14YA to open (0VC14YB is similar) while the system was running i
in the pressurization mode.
There is no control room indication of this
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postulated problem. The concern is that, in the event of an accident, radiation /snoke could enter into the control rocm if this daniper is open.
This issue was also previously discussed in Section 3.F.
CECO's review of the design basis found the exhaust purge damper is a normally closed, fail closed damper, whose safety-related function is to remain closed.
The non-safety related function is to open when the VC system purge trode is initiateo. This purge mode was designed as an option to aid in removing smoke from the control room in the event of a fire.
BWRE & S&L's review of the Final Safety Analysis Report (FSAR)
identified that the Nuclear Regulatory Ccamission (NRC) Questions were specifically considering single-failure criteria for the intake and exhaust isolation dampers.
These questions resulted in a design change, in 1978, to install arMitional dampers in accordance with Engineering Change Notice (ECH) M44-LS.
In 1981, the Safety Evaluation Report (SER)
was issued.
Sections 9.4.1 and 7.3.3.3 of the SER specifically concluded that the control room isolation features met the NRC acceptance criteria.
BWRE concluded that the design basis for this nornally closed, fail closed damper would remain closed in post Loss of Cooling Accident (LOCA)
conditions, and if for any reason this damper or any portion of the operating train failed, the train would be shutdown and the redundant train would be started. The redundant train of the Control Room Ventilation System would not be effected by a single sustained hot short.
The resident inspectors had just received scn,e additional information pertaining to this subject at the close of this inspection report period.
Due to the timing, the residents have not fully reviewed this additional material and this subject will be carried as an cpen item (373/89003-02; 374/89003-04) until further review of the information available.
One open item was identified in this atea.
12. Onsite followup of Events at Operating Power Reactors (93702)
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a.
On March 2, 1989, at 11:02 p.m. (CST), Unit 1 scrammed from approximately E6% poner on a Turbine Control Valve (TCV) fast closure.
The TCV fast closure was caused by a turbine generator
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lockout signal. The turbine generator lockout signal was caused by a phase A differential overcurrent signal related to a fault at the Unit 2 System Auxiliary Transformer (SAT) that occurred at the tin.e of this event. All sptoms responded nornially during the scram with the following exceptions:
isolations of the Unit I and Unit 2 reactor building ventilation systems was experienced; isolations of the Unit 2 reactor water cleanup system were experienced; both Unit 1 and Unit 2 staticn air system compressors
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s were lost; the process computer was lost; the Unit 2 alternate RPS breakers tripped (the unit was on normal power); and the A reactor recirculation flow control valve locked up.
The Division III (High Pressure Core Spray) Emergency Diesel Generator (EDG) also started on a loss of power signal.
The Division I and II EDGs did
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not start because their respective busses auto switched from thb SAT to the Unit Auxiliary Transformer (UAT).
In addition, reactor water level swings between 25" and 53.5" were experienced on Unit 2.
Only quick action by the Unit 2 reactor operator prevented Unit 2 scramming on a turbine generator trip at a reactor water level of 55.5".
The licensee had noted that several Unit I alarms relating to reactor water level appeared to come in early and may indicate drift problems with the associated Static-0-Ring (SOR)
switches. At 11:30 p.m., when the licensee determined that offsite
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power through the Unit 2 SAT was no longer available, they entered l
a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Limiting Condition for Operation (LC0) on both units due j
to not having both sources of offsite power available. 'At 2:30 a.m.
j on March 3,1989, the licensee declared an Unusual Event in accordance with the Generating Station Emergency Plan (GSEP) for both sources of offsite power not being available.
At the time of this event Unit 2 was at approximately 89% power.
At 12:00 a.m. all of the Unit 2 systems, with the exception of the Division III EDG and the SAT, had been returned to normal. The EDG was left running to ensure the availability of the High Pressure Core Spray system.
The licensee left Unit 1 in the hot standby condition for approximately 3 days to allow maintenance to be
performed that could not be done with the unit at power.
On March 3, 1989, an Augmented Inspection Team (AIT) was formed to investigate the event of March 2, 1989, the loss of the Unit 2 SAT and Unit 1 trip. The AIT report 373/89007; 374/89007 addresses all of the irregularities during the event.
b.
On March 4, 1989, at approximately 11:00 p.m. (CST), the Unit 2 Division III (High Pressure Core Spray (HPCS)) Emergency Diesel Generator (EDG) was stopped using the local emergency push button when it was discovered that an instrument line for the fuel oil strainer differential pressure gauge had cracked and was spraying fuel oil out into the EDG room. The EDG was declared inoperable
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and placed in pull-to-lock.
Upon the loss of the Unit 2 SAT, the licensee had left the Unit 2 Division III EDG running to ensure the i
availability of the HPCS system.
In addition, the licensee had placed the HPCS pump in operation in the full flow test mode in I
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order to have a load on the buss.
The licensee removed the failed
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instrument line, replaced the filters as a precaution, plugged the tap off for the instrument line, cleaned up the room, and on March 6, 1989, at 1:30 a.m. restarted the EDG. At 1:50 a m. the HPCS pump was restarted in the full flow test mode in order to provide a load on the buss.
The licensee made the required Emergency Notification System (ENS) notification at 2:15 a.m..
At 3:30 a.m. the licensee re energized the Unit 2 SAT. At 3:50 a.m. the electrical lineup, with the exception of the Division
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III-buss, was restored to normal-with the SAT feeding all normal loads.
No problems were noted._'At 4:10 a.m. the SAT was' declared operable and the licensee exited the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time clock for. shutdown
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of_both units. At 5:00 a.m., the Unit 2 HPCS system.was shutdown after the Division III buts was re-tied to the SAT and at 5:25 a.m.,
the Division III EDG was stopped. At 6:15 a.m., the licensee-declared the Division III EDG and the HPCS system operable, c.
On March 5, 1989, at 10:00 p.m. (CST), the licensee placed the mode switch in Startup and commenced pulling control rods toward critical. The reactor went critical on March 6, 1989 at.12:42 a.m..
13. 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 i
on the part of the NRC or licensee or both.
Two open items disclosed
during the inspection is discussed in Paragraphs 10 and 11.
14.
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-i summarized the scope and findings of. the inspection activities. The licensee acknowledged these findings. The inspectors also discussed the likely informational contents 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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