IR 05000373/1988022
| ML20205N826 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 10/27/1988 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20205N812 | List: |
| References | |
| 50-373-88-22, 50-374-88-21, NUDOCS 8811040367 | |
| Download: ML20205N826 (22) | |
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U. S. NUCLEAR REGULATORY C0l411SSION
REGION III
Report Nos. 50-373/88022(DRP);50-374/88021(DRP)
Docket Nos. 50-3/3; 50-374 License Nos. NPF-11; NPF-18 Licensee: Comonwealth Edison Company P. O. Box 767 Chicago, IL 60690
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Facility Name: LaSalle County Station, Units 1 and 2 Inspection At:
LaSalle Site, Marseilles, Illinois Inspection Conducted: August 9 through October 21, 1988 Inspectors:
R. D. Lanksbury R. A. Kopriva P. L. Eng J. F. Smith Approved By:
M. A. Ring, Chief f
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Reactor Projects Section IB Date Inspection Sumary Inspection on August 9 through October 21, 1988 (Report Nos. 50-373/88022(DRP);
No. 50-374/88021(ORP))
Areas Inspected:
Routine unannounced inspection conducted by the residents and regional specialists, of licensee action on previous inspection findings, operational safety verification, monthly maintenance observation, monthly surveillance observation, licensee event reports followup, outages, Inservice Testing Program, training, security, and onsite followup of events at operating reactors.
Results:
Of the 10 areas inspected, one violation involving failure to follow l
approved procedures (paragraph Sb) was identified.
In addition, three apparent violations (one for failure to follow procedures, one, with two examples, for
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inadequate procedures, and one for inadequate design control) were identified
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and are being reviewed for enforcement action. The violation for failure to follow procedures involved a Reactor Core Isolation Cooling (RCIC) steam line isolation that was misdiagnosed by the operators and was missed on j
shift turnover. As a resuit it went unrecognized for approximately 91/2 hours resulting in an ENS phone call not being made within the expected time frame. The apparent violation for failure to follow a procedure dates back I
to 1984 and involved the licensee's failure to follow the(r procedure for l
1.Tplementation of Service Information Letters (SILs).
The specific SIL involved was one issued by General Electric (GE) to alert BWR owners to
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l 8811040367 881028 PDR ADOCK 05000373 o
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recommendations for operations that could be used to prevent or mitigate neutron flux oscillations.
The apparent violation for an inadequate procedure had two examples. The first example involved the licensee's failure to implement GE's SIL covering neutron flux oscillations.
As a result, when the event described in the SIL occurred unexpectedly, the operators did not know how to respond.
The second example involved the one procedure the licensee did implement, as a result of the above SIL, to monitor for core instabilities.
The abnormal procedure that referred the operator to that surveillance procedure was worded such that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> could elapse before entry into the surveillance procedure would be required. As a result, the actions of the surveillance procedure required to be performed in less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following the start of the event would not be accomplished within that time frame.
The apparent violation for inadequate design control involved the licensce's failure to establish and maintain adequate design control of their contractor and to adequately verify the calctl.tions and methodology used to produce the stability decay ratios submitted as part of the core reload analysis licensing submittals.
In addition to the above, one unresolved item was identified involving the potential for an inadequate proceoure that resulted in the RCIC steamline isolation event and one unresolved item was identified involving verification of remote position indicators for valves.
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DETAILS 1.
Persons Contacted 0+*G. J. Diederich, Manager, LaSalle Station 0+*W. R. Huntington, Services Superintendent 0+*J. C. Renwick, Production Superintendent D. S. Berkman, Assistant Superintendent Work Planning J. V. Schmeltz, Assistant Superintendent, Operations
- P. F. Manning, Assistant Superintendent, Technical Services 0+*T. A. Hamerich, Regulatory Assurance Supervisor
- J. W. Gieseker, Technical Staff Supervisor W. E. Sheldon, Assistant Superintendent, Maintenance J. H. Atchley, Operating Engineer 0*D. A. Brown, Quality Assurance Supervisor M. G.' Santic, Master Instrument Mechanic W. Marcis, BWR Engineering
- R. D. Sagmoe, Inservice Testing Coordinator D. R. Winterhoff, Tech Staff Performance Monitoring Group Leader 0W. E. Morgan, Nuclear Licensing Administrator 0C. M. Allen, Nuclear Licensir.g Administrator OH. E. Bliss, Nuclear Licensing Manager 0M. A. Ring, RIII, Chief, Section IB
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OC. J. Paperiello, RIII, Deputy Regional Administrator
- Denotes personnel attending the IST exit interview on August 26, 1988
+ Denotes personnel attending the interim exit interview on September 23, 1988.
9 Denotes personnel attending the final exit interview on October 21, 1988.
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 & 92702)
(Closed) Violation (373/85016-03; 374/85016-03):
Failure to obtain vibration data per the method delineated either in the Inservice Testing (IST) program or in the American Society of Mechanical Engineers (ASME)
Code. By letter dated July 28, 1987, the licensee submitted its revised IST program to the NRC for review.
The revised program included a relief request which defined the method of obtaining vibration measurements.
The licensee's alternate vibration measurement method and associated accep)tance criteria were approved in the IST Safety Evaluation Report (SER issued on August 16, 1988.
The inspector verified that vibration measurements were being obtained and trended as defined in the revised relief request.
This item is closed.
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(Closed)OpenItem(373/86029-01;374/86030-02): Determination of ecceptance criteria for vibration velocity measurements. The licensee defined those acceptance criteria used for evaluation of vibration velocity measurements in the revised IST program.
These limits were approved by the Comission in the IST SER on August 16, 1988. This item is closed.
IClosed) Violation (373/86029-02):
Failure to verify operability of Unit 1 Residual Heat Removal (RHR) pumps after maintenance as required by Section XI of the ASME Code.
The licensee has revised the surveillance test procedures for the ECCS pumps to require that the pump 3 are tested within 7 days of returning the system to service, and provided for Technical Specification required testing using alternate means and acceptance criteria.
This item is closed.
(Closed) Open Item (373/86029-03):
Establish appropriate reference values for water leg pumps.
In the revised IST program the licensee submitted relief request RP-02 which requested relief from some of-the Section XI testing requirements for the Emergency Ccre Cooling System (ECCS) water leg pumps. Alternate testing requirements and acceptance criteria were also submitted. The licensee's relief request and alternate testing method were approved in the IST SER on August 16, 1988.
This item is closed.
(Closed) Unresolved Item (373/86029-04):
Determination of waen Division I ECCS pumps were declared operable following the Unit 1 summer,1986, refueling outage.
The inspector reviewed the pump test records and noted that the subject pumps were proved operable by test on August 15, 1986.
The subject pumps were not required to be operable until September 17, 1986.
This item is closed.
(Closed) Violation (373/86029-05; 374/86030-03a; 374/86030-03b):
Failure to use test equipment required by IST test procedures.
Licensee procedure LAP 100-29 was revised to require that data, obtained with instruments other than those originally called out in the test procedure, be evaluated before determining the test to be acceptable.
The licensee has also revised LTP 600-4, "ASME Section XI Inservice Testing of Pumps and Valves,"
to require that all test data be obtained as a group.
This item is closed.
No violations or deviations were identified in this area.
3.
Operational Safety Verification (71707)
The inspector observed control room operations, reviewed applicable a.
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 Unit 1 and 2 reactor buildings and turbine buildings were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations, and to verify that
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maintenance requests had been initiated for equipment in need of maintenance. The inspector, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan 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 inspector verified the licensee's radiological protection program 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 everall 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 determined that both licensed and non-licensed operators were attentive to their duties, and that the inspectors'
arrivals on site were unannounced.
The licensee has implemented appropriate administrative controls related to the conduct of
operations.
These include procedures which specify fitness for duty and operator attentiveness, c.
As of August 12, 1988, the LaSalle County Nuclear Station plants performance had been affected minimally by the summer drought. The units had only minor deratings due to high lake temperature. Unit I had experienced some derating due to high condensate polisher temperatures and high condensate polisher differential pressures.
Unit 2 was being derated by fuel depletion and had very minor deratings due to high condenser vacuum.
The licensee monitored lake temperatures and plant pararreters closely while the heat wave and drought existed.
d.
At 4:35 a.m. (CDT) on August 31, 1988 with the "2A" compressor
out of service, decreased output from the "2B" Drywell Pneumatic j
(IN) compressor was experienced, dropping the IN system pressure to approximately 155 psig.
Normal operating pressure for the
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"2A"/"28" compressors is 167-175 psig/162-175 psig, respectively.
At 4:39 a.m., the "D" Automatic Depressurization System (ADS)
accumulator low pressurf. alann (set at 152 psig) began cycling and at approximately 6:30 a.m. eventually stayed in the alarm i
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condition.
The "?A" IN compressor still had high interstage pressure and was allowed to run for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for observation. At 1:00 p.m., the "2A" compressor was again taken out of service for troubleshooting purposes.
The 1N syetem pressure was approximately 155 psig with the "2B" compressor running.
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At 1:18 p.m., the "0" ADS accumulator low pressure alarm initiated, as it previously had done when the "2A" compressor was cut of service. At 2:30 p.m., the
"C" ADS accumulator low pressure alarm initiated, and at 2:48 p.m., the
"V" ADS accumulator low pressure alam initiated.
While investigating the "C" ADS accumulator alam, it was observed that IN system pressure was 148-150 psig, indicating further degradation of the "2B" IN compressor. Pressure gauges were installed on the "C", "V", and "D" ADS accumulator pressure switches.
Accumulator pressures were indicating 146-148 psig, which is acceptable but less than the alarm setpoint of 152 psig.
With less than 6 operable ADS valves, a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> timeclock to place the unit in HOT SHUTDOWN was initiated at 2:35 p.m. per Technical Specification 3.5.1.
The Mechanical Maintenance Department (WiD)
found that the "2A" compressor's unloader valves were not operating properly and adjustments were made to correct the problem.
At 2:45 p.m., the "2A" compressor was retu'->d to service and all the ADS accumulator alarms were reset. The ADS nitrogen bottle regulators should have maintained system pressure when the "2B" IN compressor was degraded.
It appeared that the regulator setpoints had changed or the regulators were malfunctioning.
The ADS nitrogen regulators were tested for the north (21N038) and south (21N035)
bottle banks. The performance of the north side regulator was detemined to be acceptable, however, the south side regulator demonstrated a very slow / sluggish response, taking approximately twice the time (when compared to the north side regulator) to repressurize the system during pressure drop tests.
At 6:20 p.m., following discussions with the shift engineer, a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification to the NRC was made.
Further adjustments were made to the south side regulator, but little affect on pressure response time was noted.
Since there was no readily available criteria on repressurization rate with which to evaluate the ADS regulator, the nitrogen bottle backup for ADS was considered inoperable and a plant shutdown initiated. At 7:10 p.m., an Unusual Event was declared and proper notifications were made.
On September 1,1988, at 1:00 a.m., the south side bottle bank was controlling at 161 psig, which is an acceptable pressure setpoint, but response was still sluggish. An inspection of the valve internals was deemed necessary. At 2:31 a.m. on September 1, 1988, all control rods were inserted and the mode switch placed in SHUTDOWN. At 3:35 a.m., the Unusual Event was exited.
The mechanical maintenance department inspected the regulator and two pieces of a rubber material were found.
However, these did not appear to have caused the operational problem. A new stem assembly was installed and the regulator was tested per LLP-88-057 (Drywell Pneumatic Regulator Ad,iustment) by operating and technical staff personnel with satisfactory results. Operating and technical staff personnel adjusted the south bottic bank regulator to control at
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higher pressure. The regulator was satisfactorily tested in accordance with LLP-88-057. Mechanical maintenance department repaired the "2A" and "28" IN compressors.
Long term corrective actions were established in response to this event and were addressed in LaSalle On-Site Review 88-057 for Unit 2 startup.88-057 addressed the following items:
A surveillance procedure will be written to functionally cycle
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the ADS bottle bank pressure regulators on an 18 month refueling cycle,
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j Annunciator / Abnormal procedural guidance will be developed for
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ADS accumulator low pressures, to outline actions to be taken when the ADS bottle bank pressure is fluctuating at the low pressure setpoint.
Doiling Water Reactor Engineering will determine the criteria
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for operability of the ADS bottle bank subsystem to assist the I
station in operability a:;sessments and setpoints.
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On September 2, 1988, at approximately 10:40 p.m. (CDT), the licensee
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commenced startup of Unit 2.
Unit 2 was critical at 12:45 a.m. on
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September 3,1988, and the turbine / generator connected to the grid at
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aaproximately 11:10 a.m..
There were no problems encountered during '
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tie startup.
No violations or deviations were identified in this area.
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4.
Monthly Maintenance Observation (62703)
a.
Station maintenance activities of safety related systems and
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components listed below were observed / reviewed to ascertain that
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they were conducted in accordance with approved procedures, l
regulatory guides and industry codes or standards and in conformance l
with Technical Specifications.
The following items were considered during this review:
the limiting
i conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations
I were performed prior to returning components or systems to service; j
quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly
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i certified; radiological controls were implemented; and, fire f
prevention controls were implemented. Work requests were reviewed to i
determine status of outstanding jobs and to assure that priority is
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assigned to safety related equipment maintenance which may affect i
system performance.
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The following maintenance activities were observed / reviewed:
Work" being performed on the "0" Emergency Diesel Generator cooling water pump motor.
b.
On August 18, 1988, at approximately 8:00 p.m. (CDT), the licensee comenced load reduction of Unit 2 in order to effect repair of a
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j steam leak that developed downstream of the no. 4 main turbine i
control valve. The licensee had originally planned to commence this work on August 13, 1988, however, due to the extended high ambient temperatures effecting the midwest this summer and the loss of some of their reserve capability, the licensee decided to defer the work i
to a later date. At 4:00 a.m. on August 19, 1988, the main turine/
generator was tripped.
Unit 2 was at approximately 1]% power with 1 and 1/2 bypass valves open and the main turbine stop and control valves closed. The licensee maintained the unit in this status during the outage, which lasted approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
In addition to repairing the steam leak, the licensee deinerted the drywell to allow some additional-
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maintenance to be performed.
No violations or deviations were identified in this area.
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I 5.
Monthly Surveillance Observation (61726)
a.
The inspector observed Technical Specification required surveillance
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i testing and verified for actual activities observed that testing was performed in accordance with adequate procedures, that test instru-mentation 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 Specifica-tion and procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies
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i identified during the testing were properly reviewed and resolved by
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appropriate management personnel.
The inspector witnessed portions of the following test activities:
i LIS-NR-107 Unit 1 APRM/RBM Flow Converter to Total Core Flow l
Adjustment
LIS-NB-302 Unit 1 Reactor Vessel Low-Low Water Level (Level 2)
l Primary and Secondary Containment Isolation Functional
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Test
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LIS-LP-304 Unit 1 LPCS Pump Discharge Pressure Pennissive Functional l
Test i
LIS-LC-406 Unit 2 MSIV Leakage Control Outboard Reactor Vessel Pressure Functional Test
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b.
On August 17, 1988, at 10:30 a.m. (CDT), the instrument maintenance department began the routine performaace of the Functional Surveillance LIS-RI-401, "Unit 2 Steam Line High Flow RCIC Isolation functional Test", for the 2E31-N007 AA/AB/BA/BB switches.
The Reactor Core Isolation Cooling (RCIC) system has these four leak detectior, differential pressure switches designed to sense a line break on the Residual Heat Removal (RHR) steam condensing line or the instrument lines themselves.
Per the procedural prerequisites, the RCIC system isolation valves were closed and the RCIC system was declared inoperable in accordance with the Technical Specifications.
During this surveillance, each of the differential pressure switches are separately equalized, isolated, and pressurized, to verify switch closures and the proper isolations, isolation signals, and alarms occur.
Af ter the 2E31-N007AA, AB, and BA switches were satisfactorily tested and returned to service, the 2E31-N0078B switch equalizing valve was opened, the instrument stop valves were closed and then the equalizing valve was reclosed.
The next step of the surveillance called for applying a differential pressure to the switch until actuation occurs. At this time it was discovered that the switch would not hold any differential pressure.
The switch would not actuate when the attempt was made to pressurize, and in addition the test supply water was passing from the hi side of the switch to the lo side.
The IM's then preceeded to determine if the actual switch diaphragm was ruptured or if the 3 valve manifold equalizing valve was leaking. A work request which had previously been initiated indicated that a valve or valves on the manifold was leaking.
The instrument mechanic then proceeded to isohte the 3 valve manifold.
In order to accomplish corcplete isolation of the N0078B switch (and its 3 valve manifold) without affecting the N007BA switch, the instrument mechanic closed the intermediate stop valves.
Once the N007BB switch was fully isolated, the instrument mechanic proceeded to troubleshoot and verified that the diaphragm was indeed ruptured.
Knowing that the switch was to be declared inoperable and replaced, the instrument mechanic left the intermediate stop valves closed.
On August 18, 1988, the failed switch was replaced with an identical, certified switch.
The new switch was then calibrated per LIS-RI-201,
"Unit 2 Steam Line High Flow RCIC Isolation Calibration."
In order to return the switch to service, the instrument equalizing valve was opened and then the instrument stop valves were opened.
Next, the instrument rack root stop valves were checked and found to be fully open.
The instrument mechanics then closed the instrument equalizing valve, believing they were returning the N0078B switch to service.
Since the intemediate stop valves are not identified in the procedure, the instrument rechanics were not aware that the valves had been closed.
Therefore, the switch remained isolated from the system in an enactuated state.
The new 2E31-N0078B switch remained in this isolated nd unactuated state until September 1,1988 at 4:31 p.m.,
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Pending further review by the inspector to determine how wide spread the problem is and the safety significance of this event, the issue of inadequate procedures will be tracked as an unresolved item (374/88021-01).
On September 1, 1988, at 4:31 p.m., during the Unit 2 shutdown which was caused by problems with the ADS nitrogen bottle regulators (refer to paragraph 3), DP switch 2E31-N0078B actuated causing the following system responses:
Automatic closure signal to the RCIC steam 1%e inboard
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isolation valve, 2E51-F063.
The valve wert to the closed position.
Automatic closure signal to the RCIC steam line wamup valve,
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The valve was in the normally closed position and remained closed.
The RCIC channel B steam line differential pressure hi (B309),
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alarm window on panel 2H13-P601 actuated.
Also, the same annunciation occurred on the alaru typer.
The RCIC Division 2 isolation signal (B409), alarm window on
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panel 2H13-P601 actuated.
Also, the same annunciation occurred on the alarm typer.
The RCIC turbine received a trip signal.
The RCIC turbine is
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not required below 150 psig reactor pressure and was not operating, i
The unit operator acknowledged the alarms at the 2H13-P601 panel, however, the operator did not recognize this event to be a RCIC steam line high dp switch actuation.
Instead, he believed that the isolation was due to a RCIC low steam supply pressure isolation which occurs when reactor pressure reaches 57 psig. Had this been a low supply pressure isolation, the "RCIC Division 1 or Division 2 isolation signal" and "RCIC steam supply channel A or channel B pressure lo" alarms would have actuated. Due to this misunder-
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standing of the isolation and failure to follow appropriate annunicator response procedures, no other actions were taken at this time by the operator. On September 2,1988, at 2:00 a.m., the error in interpreting the annunciator signal and RCIC isolation
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signal was recognized by the shift engineer during a panel walkdown.
Technical Specification (TS) 6.2.A requires that detailed written procedures, including applicable checkoff lists, shall t;e prepared, approved and adhered to for the following:
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The applicable procedures reconmended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix l
A of Regulatory Guide 1.33 includes procedures covering operations of the plant.
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b.
Actions to be taken to correct specific and foreseen potential malfunctions of systems or components including responses to alarms, suspected primary system leaks, and abnormal reactivity changes.
LAP-200-3 "Shift Change" states in part for the licensed personnel:
"Perform a visual control room panel check which shall include but is not limited to:
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Status of annunicated alarms and use of ' orange rings'."
LAP-1600-2, "Conduct of Operations", part F.1.aa.1 states in part:
"The operator is expected to know the reason for each annunciator which is in the alanned condition..."
Part F.1.aa.2 states in part:
"Response to an annunciator is potentially the operator's highest priority, and until evaluated, should be treated as such."
Contrary to the above, the licensee failed to meet the requirements of TS 6.2.A by failing to adhere to the following procedures:
LAP 200-3 Shift Change LAP 1600-2 Conduct of Ope ations LOA 8309 "RCIC CHAN B STM LINE DIFF PRESS HI" alann procedure LOA 8409 "RCIC DIV 2 ISOL SIG" alarm procedure.
On September 1,1988, at 4:31 p.m., differential pressure switch 2E31-N0078B actuated causing a RCIC steam line isolation.
This caused the "RCIC CHAN B STM LINE DIFF PRESS HI" and "RCIC DIV 2 ISOL SIG" alarms to annunciate in the control room.
The operator failed to follow procedures a nd therefore misinterpreted the alarms and isolation.
The other licensed operators en-shift at the time of the event also failed to recognize the isolation and the on coming shif t personnel did not recognize it during their shift turnover, either.
The error in interpreting the annunicator signals and RCIC isolation signal was finally recognized on September 2, 1988, at 2:00 a.m.-
approximately 9 1/? hours after the isolation.
The failure of the operators to follow the annuciat)r procedure for the alarms that came in, failure to follow the procedere fur conduct of operators, and failure to follow the procedure for shift turnover is a violation of Technical Specification 6.2.A (374/88021-02).
The instrument maintenance department was intnediately called out to troubleshoot the problem. A red phone notification (4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> reportable) was made on September 2, 1988, at 3:05 a.m. due to the
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Engineered Safety Feature (ESF) actuation.
This phone call should have been made by 8:31 p.m. on Sept mber 1, 1988. On September 2,
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1988, a calibration check was performed on switches 2E31 N0078A
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and 2E31-N0078B, per LIS-RI-201, "Unit 2 Steam Line High Flow RCIC
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Isolation Calibration." When the 2E31-N007BA switch was equalized by opening the instrument equalizing valve, the alarm signals remained present in the control room.
This implied that the 2E31-N0078B switch was tripped, causing the actuations. The 2E31-N007BA switch was then returned to service.
The 2E31-N0078B switch was then equalized, at which time the alarms cleared. The calibration was then completed and the 2E31-N0078B switch was found to be slightly below calibration tolerance.
The 2E31-N007BB switch diaphragm was evaluated as being intact.
The instrument was then satisfactorily recalibrated within allowable tolerances.
Upon completion of the calibration procedure on the 2E31-N00788 switch, the instrument mechanics performing the surveillance discovered that the two intermediate stop valves were in the fully closed position which had isolated POS-2E31-N007B8. The valves had been in that condition since August 18, 1988.
Due to the numerous problems encountered during these events, the following corrective actions have been or will be implemented:
Walkdown all Unit 2 safety related instrument racks which have
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intermediate stop valves and verify the valves are open.
This was completed prior to Unit 2 startup. The inttroment maintenance department has lockwired these valves in the open position. This was completed on September 2,1988.
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The instrument maintenance department completed a walkdown of
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all Unit 1 instrument racks similar to Unit 2.
This was completed on September 2, 1988.
The existence of these intermediate stop valves on certain
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instrument racks will be specified and addressed in LaSalle instrument surveillances and procedures. This is to be completed by November 30, 1988. This will be followed as an i
open item (374/88021-03A).
i The instrument maintenance mechanics started their review of the
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event and lessons learned during the department comunications meeting on September 2,1988. All instrument maintenance
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department personnel are to complete the review of the event by October 15, 1988, i
The instrument maintenance department will review practices and
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i consider methods for identification of instrument valves lef t
off-normal.
This is to be completed by October 15, 1988.
This will be followed as an open item (374/88021-03B).
This event is to be highlighted in the instrument maintenance
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i departnent's continual training program.
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All licensed operators will review this event.
This is to be
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completed by September 30, 1988.
All individuals involved on the 3rd shift of September 1,1988,
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and the 1st shift of September 2, 1988, have been counseled on the event. The following items were covered:
Failure to follow procedures:
LAP-200-3, "Shift Change" LAP-1600-2 F.1.o.,p..q..s.,aa.1), and aa.2).
"Conduct of Operations" LOA B309, "RCIC Channel B Steam Line Differential Pressure Hi" LOA B409, "RCIC Division 2 Isolation Signal" and the failure to notify supervisors of a perceived abnormal condition (57 psig isolation coming too soon), were emphasized.
Unit NSO shift turnovers are being monitored to address apparent
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inadequate turnovers. All reviews will be evaluated and possible recommendations for improvement are to take place prior to October 14, 1988.
This will be tracked as an open item (374/88021-03C).
The event was reviewed with all available SCRE's and shift
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engineers, emphasizing their responsibilities for retaining accountability.
c.
On August 22, 1988, at approximately 7:10 p.m. (CDT), the '0' (swing)
Diesel Generator (DG) room cooler pump motor tripped on overcurrent when an attempt to auto start it while on Unit 2 power was made. A second attempt to auto start the pump was made with the same result.
The DG room cooler pump had been running off Unit 1 power just prior to the event and had just been shutdown to allow the power supply to be swapped over. The 'O' DG room cooler pump also supplies water to the room coolers for the Reactor Cort Isolation Cooling (RCIC)
system, Low Pressure Core Spray (LPCS) system, and RHR ' A' system (Low Pressure Core Injection (LPCI), suppression pool cooling, and suppression pool spray).
This includes the corner rooms for both units as well as for one train of hydrogen recombiners.
The licensee declared the above systems inoperable at 7:10 p.m. and entered the appropriate Technical Specification action statements.
At 8:05 p.m. the licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Emergency Notification System (ENS) report.
Investigation by the licensee indicated that the room cooler pump motor burned up.
The most limiting of the Technical Specification action statements put the licensee in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time clock to affect repairs or comence shut down of both units.
The licensee was unable to locate a replacement motor that could be obtained prior to the 72 time clock expiring.
However, they did detemine that the motor installed on the "B"
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Auxiliary Building compressor was equivalent. This motor was removed f rom its normal location and used to replace the burned out motor (there are no specific time clocks associated with having the "B" Auxiliary Building compressor out-of-service). The licensee verified operability of the "0" DG room cooler pump and at 5:05 a.m. on August 25, 1988, exited the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time clock. A spare "B" Auxiliary Building compressor motor yas already on its way back to the licensee at the time they made the decision to use the installed motor. Upon arrival of the replacement motor it was installed and the system returned to service, d.
On August 29, 1988, at approximately 1:30 p.m. (CDT), the licensee was performing a test on the Ur t 1
'B' Diesel Generator (D/G) output e
breaker. During the test the D/G breaker failed to close onto the dead bus (143) within the specified time of 13 seconds.
A second attempt to close the breaker was successful.
The testing was being performed because there has been previous history of the breaker failing to close on the first attempt.
Inspection of the breaker revealed no obvious defects or problems.
The licensee proceeded to interchange the High Pressure Core Spray (HPCS) motor feeder breaker with the '1B' D/G output breaker since they are identical breakers.
The '1B' D/G output breaker was then tested again, this time closing onto the dead bus and loading in the required time. The D/G was then declared operable.
Since the breaker installed in the HPCS motor feed was questionable, the licensee declared the HPCS system inoperable and proceeded to make the required ENS notification.
The licensee continued to pursue testing of the questionable breaker and the associated logic for the breaker. A replacement breaker was bench tested and placed into the diesel generator circuit and the breaker that had originally been in the HPCS motor circuit was placed back into the circuit from the diesel generator.
One unresolved item, one violation, and one open item with three examples was identified in this area.
6.
Licensee Event Reports Followup (93702)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports 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.
The following reports of nonroutine events were reviewed by the inspectors.
Based on this review, it was determined that the events were of minor safety significance, did not represent program deficiencies, were properly reported, and were properly compensated for. These reports are closed:
373/87002-02 Non-Valid Test failures of '0' Diesel Generator Due to Synchroscope Failure During Testing. Resubmitted as revision 2.
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373/88007-00 Engir.dering Safety Feature Isolation Due to Jumper Falling Off Terminal and Shorting Isolation System 373/88008-00 Reactor Protection System Trip Due to Inadvertent Grounding During Jumper Installation 373/88009-00 High Pressure Core Spray Low Lov Level Initiation Static-0-Ring Level Switch Diaphragm Rupture 373/88010-00 Spurious Amonia Detector Trip Due to Design Deficiency in the Chemcassette Tape Mechanism 373/88011-00 Loss of 120/208 Volt Power from Distribution 136X-1 Due to Contractor Bumping and Tripping Breaker 373/88012-00 Failure of '0' Diesel Generator to Satisfy Frequency Requirements Due to Governor Out of Adjustment 373/88015-00 Reactor Core Isolation Cooling Turbine Trip Due to Over-Sensitive Mechanical Overspeed Trip Linkage 374/87019-01 Failure of Static-0-Ring Differential Pressure Switch Due to Leakage Across Diaphragm.
Resubmitted as revision 1.
374/87020-01 Failure of Several SOR Differential Pressure Switches Due to Diaphragm Failures 374/88006-00 Hissed Loose Parts Monitor Surveillance Due to Personnel Error 374/88007-00 Failure of 2A Diesel Generator Due to Improper Installation of Closing Fuse Af ter Maintenance 374/88009-00 Failure of Reactor Core Isolation Cooling Steam Line High
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Flow Isolaticn Switch Due to Failed Diaphragm No violations or deviations were identified in this area.
7.
Outages (71707)
INPO was on site August 22, 1988, at the licensee's request, to review their planning for the upcoming October outage for Unit 2.
The visit
concluded on August 26, 1988.
8.
Inservice Testing Program (73756)
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The inspectors noted that the licensee had significantly revised the administrative procedures governing the conduct of the IST program.
It was noted that the revised procedures were comprehensive and adequately addressed the requirements of the IST program as defined in Section XI of the ASME Code.
Procedures reviewed were:
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LAP-100-12 Trend Analysis Program LAP-100-29 Conduct and Review of Station Surveillances LTS-600-10 Relief Yalve Inservice Test LTP-600-4 ASME Section XI Inservice Testing of Pumps and Valves
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LMP-GM-06 Bench Testing / Setting of Crosby Safety / Pal'af Valves and Common Safety Related ASME Code (Class 1, 2, and 3)
During the inspection, the inspectors inquired as to whether the licenree verified the Remote Position Indicators (RPI) for valves as required by IWV 3300, of Section XI of the ASME Code. The licensee stated that it had implemented the requirements of IWV 3300 only for those indicators located in the control room and that this was the case throughout Coninonwealth Edison (CECO).
IWV 3300 states that:
"Valves with remote position indicators shall be observed at least once every 2 years to verify that valve operation is accurately indicated."
The inspector also noted that step F.2.c of licensee procedure LTP-600-4 requires that "Any valve having a remote position indicator in the control room or in other areas remote from the valve must be tested to ensure that actual valve position is accurately indicated." The licensee stated that it was currently reviewing testing of components which are controlled and/or indicatad on the Remote Shutdown Panels (RSPs) and that RPI verification for those valves indicated on the remote shutdown panels would be implemented when plant conditions permitted. The licensee also stated that the test procedures would be in place by the end of September
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1988 and that verification of the RPIs located at the RSPs would be accomplished during the next scheduled refueling outage for each unit.
Acceptable :ompletion of RPI verification for the valves indicated on the remote shutdown panels is considered an unresolved item (373/88022-01; 374/88021-04).
The inspector stated that IWV 3300 applied to all RPIs regardless of their location and asked whether the licensee planned to perform RPI verifications for RPIs other than those in the control room and the RSP. The licensee stated that since the practice of verifying only those RPIs in the
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control room resulted from a corporate decision, no further actions regarding RPI verification would be taken until further direction from its corporate offices was received.
The inspector stated that clarifica-tion of the NRC's position regarding RPI verification at all Ceco sites would be addressed in separate correspondence.
The inspectors also witnessed the post maintenance run on the
'O' diesel generator room cooler pump (0DG01P) motor.
The inspectors noted that vibration data was obtained using calibrated equipment and that the points used for vibration measurements were clearly marked and numbered on both the pump and the motor.
The points were also explicitly referenced in the surveillance test procedure. Vibration data was obtained by members of the technical staff who had been trained in vibratiN measurement and data analysis.
One unresolved item was identified in this area.
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9.
Training (41400)
The inspector, through discussions with personnel and a review of training records, evaluated the licensee's training program for operations and maintenance personnel to determins whether the general knowledge of the individuals was sufficient for their assigned tasks.
No violations or deviatf ons were identified in this area, 10. Security (71881)
The licensee's security activities were observed by the inspectors during routine facility tours and during the inspectors' site arrivals and departures. Observaticns included the security personnel's performance associated with access control, security checks, and surveillance activities, and focused on the adequacy of security staffing, the sec srity response (compensatory rceasures), and the security staff's attentiveness and thoroughness.
The sacurity forces' perfomance in these areas appeared satisfactory.
No violations or deviations were identified in this area.
11. Onsite Followup of Events at Operating Reactors (93702)
On March 9, 1988, LaSalle Unit 2 experienced a dual reactor recirculation pump trip from approximately 84% power. The plants response to this event resulted in core performance anomalies consisting cf neutron flux oscillations, as seen on the Average Power Range Monitoes (APRM's), of between 25*, and 50% power every two to three seconds.
In response to this event, on March 16, 1988, the NRC formed an Augmented Inspection Team (AIT) to investigate the circumstances surrounding the event and to follow the licensee's investigation and corrective actions.
The results of this inspection are contained in Inspection Reports No. 373/88008(DRP)and No. 374/88008(DRP). Two of the areas of concern to the AIT involved the adequacy of the licensee's procedures for responding to a dual recircula-tion pump trip and the associated operator training and the discrepancy between the predicted stability decay ratio and what was actually observed.
The inspector followed up on these issues and reviewcd the pertinent licensee operacing procedures in place at the time of the event (LOP-RR-06, Revision 12. "Restart of Tripped Reactor Recirc Pump";
LOA-RR-07, Revision 5, "Loss of Recirculation Flow - Both Loops";
LOA-FW-01, Revision 11, "Loss of a Feedwater Heater (s)"; and LOS-RR-SR1, Revision 2. "Thermal Hydraulic Stability Surveillance"), General Electric (GE) Service Information Letter (SIL) No. 380, Revision 1, issued February 10,1984, "BWR Core Thermal Hydraulic Stability," NRC Generic Letter (GL)
No. 86-02, issued January 23, 1986, "Technical Resolution of Generic Issue B-19 - Thermal Hydraulic Stability," and the :icensee's adminis-trative procedure for processing SILs in place at the time SIL 380, Revision 1, was issued (LAP 850-3, Revision 9 "Service Information Letters (S!Ls))".
The inspector detemined that the licensee failed to adequately provide operating procedures which were responsive to GE SIL No. 360, Revision 1, and GL No. 86 02. The absence of explicit operator
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procedures contributed to improper response to the dual recirculation purrp trip event.
In addition, the Office of Nuclear Reactor Regulation (NRR)
reviewed the General Electric (GE) analysis and methodoiogy involved in predicting the stability decay ratio as well as other pertinent information, including all of the licensee's submittals in this area, and determined that tSe licensee's measures to establish design control were deficient in ensuring that GE's analysis was adequate.
The fcilowing discusses the details of this review:
e.
The licensee, in a May 13, 1988, transmittal from C. M. Allen to A. B. Davis, responded to the following AIT question:
"The predicted decay ratio for LaSalle 2 Cycle 2 was 0.60.... Evaluate and explain why there was 40% error in the predicted decay ratio...."
The response, prepared by GE, stated that best estimate stability calculations, based on core nuclear conditions during the event and actual plant data, confirmed that the reactor scram was due to core wide limit cycle neutron flux oscillations.
The calculation results were consistent with the observed plant behavior and correctly predicted the trend in stability during the event:
decay ratio
= 0.81 af ter the recirculation pumps trip; 0.94 due to bottom peaking of the flux distribution af ter 3 minutes; and 1.05 after 5 minutes when oscillations were o5 served.
The main difference between the licensing basis analysis and the best estimate calculation using plant data was attributed to the radial power distribution. This difference was about 0.30 in the value of the core decay ratio (based on sensitivity studies), and apparently was due more to the greater detail in modeling (more radial channels were used in the best estimate calculation) than to the difference in input value3 of bundle powers used in the radial power distribution.
The remaining difference between the best estimate calculations and the original licenWg analysis was attributed to the differences in subccoling and power / flow condition input values.
Apparently the level of detail used in the radial representation for licensing basis calculations is a function of the number of fuel types in the core.
This resulted in a relatively coarse
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radial representation in the cycle specific licensing calcult.tions for LaSalle and may explain the low core decay ratio compared to licensing calculation results for most other recent vintage EWR cores which typically show relatively high values (0.85 - 1.0) when th' worst case operating conditions for several fuel cycles is ccnsidered.
It is believed that a simplified core model used for the cycle specific calculations degraded the quality of the calculations to an unacceptable accuracy in comparison to calculations submitted for the NRC methodology review. Also, the sensitivity of the calculation results to the radial power distribution modeling could have becn initially identified by the licensee (or its contractor) during the licensing of the Unit 1 Cycle 2 core reload analysis licensing
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submittal (Amendment 40) if a more thorough analysis had been i
performed in response to questions posed by the NRC concerning large differences in decay ratio results for similar cores. A sectnd chance also existed for the licensee to identify the sensitivity of the calculations during the licensing of the (Jnit 2 Cycle 2 c)re reload analysis licensing submittal (Amendment 32).
The failJre of the licensee to establish and maintain adequate design cN trol of their contractor (GE) and to adequately verify the cal'.ulations and methodology used to produce the stability decay ratio submitted as part of the core reload analysis licensig tu bictals is an apparent violation of the requirements of 10 CFR 50, Appendix B,
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Criterion III (373/88022-02; 374/88021-05)
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b.
GE SIL No. 380, Revision 1, reconmendation 5 prescribes the following actions after a recirculation pump (s) trip event:
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Immediately reduce power by inserting control rods to or below l
the 80% rod line using the plant's prescribed control rod
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shutdown insertion sequence.
2.
Af ter inserting control rods, frequently monitor the APRMs and
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monitor the local regions of the core....
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After inserting control rods, monitor the LPRM upscale alarn
indicators....
4.
When restarting recirculation pumps (or switching from low to high frequency speed for flow control valve plants), the
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operation should be performed below the 80% rod line, c.
Once p sps have been restarted....
The licensee did not incorporate any of these recomendations into their operating procedures.
In addition to the SIL, GL 86-02 was issued in January 1986 advising BWR Owners to review the need for
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In response to GL 86-02, the licensee i
did propose certain changes to the Technical Specifications, however, J
changes to the plant operating procedures were still not made.
The i
AIT, in its review of the March 9 event, indicated that the licensee
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probably believed that no additional requirements were warranted because the cycle specific calculated decay ratio was 0.60, which was indicative of a very stable core, In addition, the licensee may
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have believed that explicit instructions were not necessary since GL l
86-02 does infer that a calculated decay ratio of less than 0.80
demonstrates compliance with GDC 12.
However, their conclusion to l
not incorporate the reconvendations of SIL 380, Revision 1, is not considered to be valid nor resp:.1sive to either the SIL or GL 86-02.
The absence of explicit operations procedures contributed to the
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confusion of the operators as to the proper course of action to take
and ultimately to their choosing a course of action, which ha'J it
,j been successful, would probably have caused the plant to scram on l
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high neutron flux. The inspector considers that had the licensee implemented the SIL recomendations, and then reacted to them in a timely manner, that the March 9 power oscillations event wculd either have not occurred or at least have been reduced in riagnitude. The AIT also noted that the operators trt'ning in recngpizing the symptoms on core instability had been adequate at exemplified by the fact that they had recognized the situation during the March 9 event.
The inspector considers that, indeed, the operator training was adequate for the procedures in place at the time of the event, but due to the inadequate procedures existing at the time of the event and the licensee's apparur>t attitude toward their suscept-ibility to core instabilities, the training was not adequate to allow the operators to know the correct course of action in response to the core instabilities. The failure to implement the recomenda-tions of the SIL into the operating proceduras is are apparent example of a violation of 10 CFR 50, Appendix B, Criteria V, for having a procedure that prescribed an activity (affecting quality that was not appropriate to the circumstances 373/8802;-03A; 374/88021-06A).
As r.eted above, none of the listed recomendations of SIL 380, Revision 1, were inct rporated by the licensee into their operatir.g procedu res. However, a review of the records available on actions taken in response to the SIL indicates that the licensee did initiate a surveillance procedure (LOS-RR-SRl) which monitored neutron flux noise levels of the APRMs and LPRMs to verify stability.
Entry into this procedure, for the event in question, would be made from LOA-RR-07, step D.9.
Howeser, step D.9 only requires this procedure be entered if operating for more than four Fours in the instability region of the power-to-flow map (greater than 80% rod line and less than 45% core flow). The inspector considers that this procedural guidance is not adequate since LOS-RR-SR1 requires a nurrber of actions to be taken, and also implements Technical Specification requirements to be taken, in four hours or less.
For example, LOA-RR-07, Revision 5 "Loss of Recirculation Flow -
Both Loops," Step D.9 states, "Perform LOS-RR-SRI... if operating for more than four (4) hours in the region of possib'e instability on the power-to-flow map...." Section E of LOS-RR-SRI contains a nurrber of requirerrents that must be parformed in less than four hours such as:
"E.1.
If baseline LPRM and APVi noise level rea lings have not been established since hst refueling, ob':ain these bcseline readings within four hour? of entering the surveillance region of Attachment A (TS-4.4.1.2)....
E.4 With the APRM and LPRM neutron flux noise level greater than three (3) times their established baseline noise levels:
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(a)
Initiate corrective action within 15 minutes to restore the noise levels to within the required limit within two hours, otherwise.
(b) Leave the surveillance region specified in Attachment A within the next two hours (TS-3.4.1.)....
E.6 When operating within the surveillance region specified in Attachment a with core flow less than 39% of rated core flow, initiate action in accordance with Step D.1 within 15 minates to either:
(a) Leave the surveillance region within four hours, or (b)
Increase core flow to greater than or equal to 39% of rated flow within four hours (TS-3.4.1.1)."
Thus, an operator following strictly what LOA-RR-07 required and waiting at least four hours to perform LOS-RR-SRI would then find he not only had violated the requirements of LOS-RR-SR1 but several
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Technical Specification requirements as well.
This is an example of an apparent violation of 10 CFR 50, Appendix B, Criteria V, for having a procedure that prescribed an activity (370/88022-038);affecting qual that was not appropriate to the circumstances 374/88021-06B).
C.
As part of the review of the licensee's actions in response to SIL 380, Revision 1, the inspector reviewed the licensee's process for dealing with Sits. Administra tive
"Service Information Letters (SILs) procedure LAP-850-3, Revision 9
", which was in effect at the time SIL 380, Revision 1, was issued, contained the instructions to be
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used to process a SIL when it arrived on site.
Stro E.2 states in part, "The following time limits apaly to SIL imp 1L entation:
a.
Category 1-no later than three mont as after issue date." SIL 380, Revision 1, had an issue date of February 10, 1984, and was specified to be a Category 1 SIL. Therefore, per LAP-850-3, implementation would have to be complete by May 10, 1984. The only action taken by the licensee to implement SIL 380, Revision 1, was the issuance of
LOS-RR-SRI. A review of available records indicates that LOS-RR-SRI had an origination date of April 22, 1985, and an original issue date of April 29, 1985.
This was over 14 months after the issue date of the SIL and well in excess of the specified 3 month limit.
The review also indicated that LAP-850-3, step F.3, requires that the licentee obtain the GE onsite representative's coments, or an indication of none if applicable, and step F.4 requires that the original of that response be filed in the SIL notebook with the
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SIL.
A review of the SIL notebook revealed that the GE coment sheet was not on file and the licensee was unable to produce it during the inspection period.
In addition, step 5.b requires, among other actions, that a letter be completed to the Division Manager Nuclear Station (DMNS) and that a copy of this letter and copies of the SIL guideline document (Attachment A of LAP-850-3) and Status Response
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Form (Attachment F of LPA-850-3) be filed with the SIL in the SIL notebook.
The review of the SIL notebook also revealed that copies of the letter to DMNS and the SIL guideline documents were not on file as required and the licensee was not able to provide copies prior to the close of the inspection.
The failure of the licensee to implement SIL 380, Revision 1, within the required time frame and to have on file in the SIL notebook the required documentation discussed above is an apparent violation of 10 CFR 50, Appendix B, Criterion V, for not accomplishing an activity affecting quality in accordance with the approved procedure (375/88022-04; 324/88021-07).
Three apparent violations, one with two examples, were identified in this area.
12. Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, open items, devistions, or violations.
Unresolved items disclosed during the inspection are discussed in Paragraph 5 and 8.
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 sore action on the part of the NRC or licensee or both.
One open iten with three parts disclosed during the inspection it discussed in Paragraph 5.
14.
Exit Interview (30703)
Thc 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 activitics. 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 idertify any such documents or processes as proprieta ry.
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