IR 05000373/1993026
| ML20059D041 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 10/18/1993 |
| From: | Forney W, Wilcox J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20059D024 | List: |
| References | |
| 50-373-93-26, 50-374-93-26, NUDOCS 9311020112 | |
| Download: ML20059D041 (47) | |
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e 3 U. S. NUCLEAR REGULATORY COMMISSION ,
REGI0ti Ill Reports No. 50-373/93026(DRS); No. 50-374/93026(DRS) ,
Docket Nos. 50-373; 50-374 Licenses No. NPF-11; No. NPF-18 i
Licensee: Commonwealth Edison Company ,
Executive Towers West III 1400 Opus Place, Suite 300 Downers Grove, IL 60515
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Facility Name: LaSalle County Station, Units 1 and 2 Inspection At: LaSalle Site, Marseilles, Illinois Inspection Conducted: September 16 through September 21, 1993 Inspectors: M. J. Miller, DRP R. A. Winter, DRS J. H. Neisler, DRS R. A. Spence, AE00 A. J. Kugler, NRR Mb Approved By:/* John D. Wilcox, JV 4 *// 4'/9.3 ,
PTeamLeader,NRR Q Date
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Approved By:
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RimamCForneMActingDirecto)
o/<dee Date '
Division of Reactor Safety .
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Inspection Sumary Inspection on September 16 throuah September 21. 1993 (Reports No.
50-373/93026(DRS): No. 50-374/93026(DRS))
Areas Inspected: Special Augmented Inspection Team (AIT) inspection conducted in response to the loss of the Unit I station auxiliary transformer (SAT) and reactor scram at the LaSalle County Station on September 14,:1993. The review included validation of the sequence-of-events, determination of the root cause' ,
for-the scram and equipment failures during the event, evaluation of whether there was an electrical design vulnerability, evaluation of management and operator response to the event, and evaluation of_ the licensee's notification process and classification of the event.
Results: No violations or deviations were identified in any of the areas inspected. The significant operational safety parameters that were approached included reactor vessel level and pressure, and suppression pool' level and '
temperature. No radiation was released. This event imposed no immediate 9311020112 931025 ,
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Inspection Summary 2 impact to the health and safety of the public. The AIT's conclusions-are contained in Section 8.0 of this report. *
Specific strengths included the following: there was good professional ~ action in accordance with procedures on the part of the operating crew and technical- ;
support center (TSC) during the event. Also, there was good support-from other organizations throughout the event. .;
Specific weaknesses included the following: there was a high number of equipment failures related to this event with maintenance being. identified as j a common factor; the initial notification and continuous updates to the NRC l operations center were incomplete and did not include degradation and failure ;
of multiple systems and components; and there was a. lack of effective !
corrective actions resulting from a similar event on August 27, 1992. l l
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AUGMENTED INSPECTION TEAM
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t U.S. NUCLEAR REGULATORY COMMISSION LASALLE UNIT 1 LOSS OF STATION AUXILIARY TRANSFORMER SEPTEMBER 14. 1993
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INSPECTION REPORTS NO. 50-373/93026(DRS): NO, 50-374/93026fDRS)
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,4 JABLE OF CONTENTS Title Paae 1.0 Introduction................................................ 1 ,
1.1 Event Summary......................................... I 1.2 AIT Formation............. ........................... 1
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1.3 AIT Charter........................................... 2 2.0 Event Description..........-................................. 2 3.0 Eauipment Failures.......................................... 4 3.1 Loss of Station Auxiliary Transformer . . . . . . . . . . . . . . . . 4 3.2 Safety Relief Valves (SRVs) Anomalies................. 5-3.3 Loss of Security Secondary Alarm Station and Loss of l Heating Ventilation and Air Conditioning (HVAC) to Prime Security Computer.. ... .................... . 5 3.4 Loss of Reactor Protection System (RPS) Bus 1B...... . 6
3.5 Shutdown Cooling Mode of Residual Heat Removal -(RHR). . 6 3.6 Failure of One Intermediate Range Monitor (IRM) to'
Insert.............................................. 6 ;
3.7 Loss of Instrument Air................................ 7-
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3.8 Reactor Core Isolation Cooling (RCIC) and Low Pressure Core Spray (LPCS) Check Valve Position Indicators... 7 3.9 Failure of Recirculation Pump Suction Valve to Close on First Attempt.................................... 8 3.10 Loss of Spent fuel Pool Cooling on Unit 2. . . . . . . . . . . . 8 3.11 Othe r Equi pment Probl ems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 4.0 El ect rical Desian Vul nerabilit y. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 4.1 Cross-Tie Limitations.......... . .................. 9 4.2 Des ign of Of fs ite Power Supplies. . . . . . . . . . . . . . . . . . . . . . 10
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Table of Contents 2 *
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5.0 Human Performance Elements of the Event. . . . . . . . . . . . . . . . . . . . . 10 5.1 Procedures............................................ 10 5.2 Command, Control , and Communications'. . . . . . . . . . . . . . . . . . 11 5.3 Training.............................................. 12 5.4 Stress................................................ 13 ,
5.5 Human / Machine Interface............................... .13 :
5.6 Licensee Management Performance....................... 14 6.0 Reportino of the Event...................................... 15 6.1 Evaluation of the Event............................... 15
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6.2 Completeness and Accuracy of Licensee's 10 CFR 50.72 Report...................... ....................... 15
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6.3 Alert Classification.................................. 17 7.0 Ouality Assurance / Verification. ............................ 17 8.0 Safety Sionificance and Conclusions......................... 18 :
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9.0 Exit Meetina................................................. ' 19 -
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,g-DETAILS 1.0 Introduction 1.1 Event Summary At 11:47 a.m. (CDT) on September 14, 1993, while Unit I was at 100% power, following a fault on the SAT, the reactor scrammed due to low water level.
The turbine subsequently tripped automatically. Subsequent to the scram, the following significant equipment problems occurred:
a. Several safety relief valves exhibited anomalies.
b. Reactor protection system (RPS) bus 18 was lost when the 8 RPS motor generator (MG) set drive motor shorted.
c. Due to the containment isolation, the reactor water cleanup system and shutdown cooling system were unable to function.
d. Due to the electrical fast transfer and the loss of RPS bus 18:
the service water; instrument air; both units spent fuel pool cooling system; security secondary alarm station; heating, ventilation, and air condition to the prime security computer; and service air systems were unable to properly function.
1.2 AIT Formation On September 15, 1993, senior NRC managers determined that an AIT wac warranted to gather information on the loss of the Unit 1 SAT, reaci or scram,-
subsequent turbine trip, and equipment failures which occurred during the-event. An AIT was formed consisting of the following personnel:
Team Leader: J. D. Wilcox, Jr. , Team Leader Special Inspection Branch Office of Nuclear Reactor Regulation Assistant Team Leader: M. J. Miller, Resident Inspector Division of Reactor Projects - Region III Team Members: A. J. Kugler, Licensing Project Manager Office of Nuclear Reactor Regulation J. H. Neisler, Reactor Inspector, Electrical Plant Systems Section -' Region Ill R. A. Spence, Reactor System Engineer Office for Analysis and Evaluation of Operational Data R. A. Winter, Reactor Inspector, Electrical Plant Systems Section - Region III
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The -full AIT was onsite the morning of September 16, 1993. In parallel with !
formation of the AIT, Region III issued-a Confirmatory Action Letter (CAL) I (Enclosure 2) on September 16, 1993, which confirmed certain actions in I support of the team and established conditions required to be met prior to the restart of the plant.
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l 1.3 AIT Charter A charter was formulated for the AIT and transmitted from W. L. Forney to J. D. Wilcox on September 16,1993 (Enclosure 3), with copies to appropriate Office of the Executive Director for Operations (EDO), NRR, AE00, and Region III personnel.
The AIT completed its onsite activities on September 21, 1993.
2.0 Event Description NOTE All equipment and activities described below are for Unit I except ,
where otherwise indicated.
The plant was at full power with no surveillances or other activities in
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progress.
At 11:47:33 a.m. on September 14, 1993, the SAT tripped due to a bus duct fault. The following equipment was affected due to the fault and the' J
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associated voltage transients:
- SAT was deluged
- Busses 152, 141Y, 142X, and 142Y fast transferred to the unit auxiliary transformer (UAT).
Bus 143 de-energized and was re-energized by Division 3 diesel generator (DG)
Reactor building ventilation (VR) dampers closed
Reactor water cleanup (RT) isolated The voltage dip associated with the fault in combination with the fast transfer was the most probable cause of the B turbine driven reactor feed pump (TDRFP) controller ramping the control valve closed for the B TDRFP. The A'
TDRFP increased flow but was not able to maintain reactor water inventory by i t sel f. ,
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At 11:47:52 a.m., the reactor scrammed on low water level, level 3. Steam demand from the main turbine decreased as the turbine control system maintained reactor pressure.
The reactor scram was followed by rapid recovery of reactor water level which continued to increase rapidly to level 8, where:
- TDRFP A tripped
Motor driven reactor feed pump (MDRFP) tripped
Main turbine tripped 2 '
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-4 At 11:49:12 a.m., the main generator tripped on reverse current causing:
- Loss of VAT
- Loss of both RPS busses used to power:
- Radiation monitors
- Primary containment isolation signals
Main steam isolation valve (MSIV) control and indication
- Power range monitors :
- RPS logic
- Start of the Division 1 & 2 DGs which energized busses 141Y and 142Y
- Reduction of Service water (crosstied between units) to one pump on Unit 2 '
Loss of station air and instrument air for both units (Unit 1 air compressor due to power loss, Unit 2 air compressor due to loss of the crosstied turbine building closed cooling water (TBCCW) from Unit 1)
The containment isolation resulted in decay heat being rejected to the containment and the following actions were taken:
- Suppression pool cooling was manually started
- Reactor core isolation cooling (RCIC) was manually started and used to control level and to assist with pressure control
- High pressure core spray (HPCS) was started and placed in full flow test
- Safety relief valves (SRVs) were used to control pressure (Automatic l depressurization system (ADS) accumulators were used later in the event to operate the SRVs when the low pressure accumulators were depleted.)
At 11:55 a.m., power had been restored to both RPS busses via the MG sets.
Containment isolation signals were being reset.
At 11:57 a.m., suppression pool temperature reached the high temperature alarm of 105'F and by 12:02 p.m. the temperature reached 110*F.
At 12:17 p.m., the B RPS MG set electrically failed, which de-energized the ,
RPS bus IB and caused isolation signals.
At 12:20 p.m. the licensee declared an Alert.
Efforts were made to restore electrical power to additional busses; state, i local, and NRC notifications were made; and the reactor was cooled down in 1 preparation for shutdown cooling. J At 7:07 p.m., temporary power was connected to RPS bus 18. The isolation ,
signals were reset.
J At 10:43 p.m., suppression pool temperature dropped to less than 110*F and the A residual heat removal (RHR) pump was shutdown to prepare system for shutdown cooling.
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At 4:59 a.m..on September 15, 1993, shutdown cooling was established and' cold shutdown was reached at 11:50 a.m.
At 3:15 p.m., the UAT was energized through a backfeed and the Alert was terminated at 4:48 p.m.
Detailed sequence-of-events.is specified in Enclosure 4.
3.0 Eauipment Failures 3.1 Loss of Station Auxiliary Transformer 4 The Unit 1 SAT tripped while the plant was operating at full power. The cause of the SAT trip was a short circuit to ground in the bus. duct to the 4160 volt (V) surge suppressors. Water had accumulated, at least 3 inches deep, in the bottom of the duct to a level sufficient to create a. conductive path between the bus bars and the duct. -
The short circuit between the bus bars and the duct tripped the SAT and resulted in severe damage to the duct. The team observed torn metal at bolt holes of the duct flange nearest the short. The duct was distorted in the '
vicinity of the short and for several feet above the short.
The team noted that the lower portion of the duct was severely corroded both inside and out, Severe corrosion was also observed in the surge suppressor compartment. Discussions with cognizant licensee personnel indicated that a preventive maintenance program had recently been initiated for the SATs and UATs. However, the preventive maintenance had not been performed on the Unit '
1 SAT.
The team also observed that the bus duct design did not provide. drainage patiis for accumulated moisture in the duct. All seams and joints had originally been sealed with tape or gaskets to prevent moisture entry. The seals also prevented accumulated moisture from draining from the duct. Some of the seal-tape in the top of the horizontal duct had deteriorated permitting rain water to enter the duct and run down inside the vertical duct section.
The licensee s corrective action is to remove the 4160V and 6.9 kilo-volt (kV) ,
surge suppressors and vertical bus bars and duct work from the transformer.
The SAT will still have surge protection (lightning arresters) on the primary (345kV) side. This configuration is similar to the surge protection on other nuclear plants in the region.
The licensee performed insulation resistance tests on the SAT windings, insulating oil quality tests, and gas quality tests. None of the tests i indicated damage to the SAT. -
The team concluded that the root cause of the SAT trip to be the lack of appropriate maintenance on the SAT and its associated equipment and a design that did not provide for drainage of collected moisture from the bus duct.
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3.2 Safety Relief Valves (SRVs) Anomalies L
Safety relief valve "D" failed tc open upon demand during the event. The !
licensee's investigation revealed a solenoid air valve-to-actuator body leak '
that reduced air pressure in the 100 psig accumulator to a level below the pressure required to operate the SRV. The leakage was sufficient to fail the pressure drop test within one minute. Overall pressure drop for the ten minute test was 20 psig. After the valve was replaced, a second pressure drop test found that air still leaked from the accumulator. The licensee is '
continuing to investigate and repair the leaks.
The attempt to open SRV "D" during the event occurred over two hours after the scram and the loss of. supply air to the accumulator due to the containment isolation. This was more than sufficient time to depressurize the SRV "D" accumulator.
The team determined that the root cause of the failure of SRV "D" to function on demand was the lack of adequate maintenance.
The SRVs are grouped in a sequence of opening. SRVs "S" and "U" have the lowest setpoint and should open first. During this event, SRV "K" opened before "S" or "U". The setpoint for SRV "K" is 20 psig higher than either "S" or "U"; however, the valves are opened by pressure switches that have a tolerance of plus or minus 15 psig. The tolerance results in overlapping - '
pressure areas of approximately 10 psig in which either valve may be the first to operate. At the end of the inspection on September 21, 1993, the licensee had not specified what, if any, corrective action would be initiated to address these overlapping areas.
3.3 Loss of Security Secondary Alarm Station and Loss of Heatino Ventilation and Air Conditionina (HVAC) to Prime Security Computer During the event, the station lost the electric power supply to the secondary alarm station (SAS), HVAC to the prime security computer, two high mast lighting towers, and part of the protected area lighting. Station security initiated system failure compensatory measures.
These components were being supplied through the Unit 1, 6.9kV buses by 480V '
buses 131A and 132A. When Unit I lost the 6.9kV system, power was not available to the motor control centers (MCCs) supplying these components. ;
Backup power is supplied to the MCCs by Unit 2 buses 231A and 232A through manually operated keyed mechanical interlocked circuit breakers. When power was lost to MCC 033-1, the backup circuit breaker from Unit 2 bus 231A was out-of-service for maintenance so that power could not be returned to the MCC until the maintenance department could return the breaker to service.
The circuit breaker from Unit 2 bus 232A to MCC 033-2 mechanical interlock failed to function properly when the operator attempted to close the breaker.
A maintenance electrician restored power to the MCC. l The team concluded that the loss of these systems had minimal safety significance due to implementation of. the licensee's enhanced security measures to compensate for system loss. ;
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3.4 Loss of Reactor Protection System (RPS) Bus 1B Reactor protection system Bus 1B was lost early in the event when RPS MG set tripped. Two unsuccessful attempts were made to restart the MG set. On each of the restart attempts, the operator observed sparks emanating from the motor.
The licensee performed an inspection and analysis of the motor failure at a contractor facility. Their conclusions were that the motor experienced a turn to turn short of the first coil of one phase group. The windings had a heavy layer of dirt on both ends of the windings. The failure was probably caused by degradation of the insulation on individual coil strands.
A preventive maintenance inspection was performed on the MG set on !
November 11, 1992. The inspection did not identify the layers of dirt on the motor windings, and apparently did not observe this part of the motor. The ,
licensee's failure analysis identified the dirt on the windings as a contributor to the failure. *
The team concluded that the major contributor (root cause) to the failure was inadequate maintenance of the MG set. The safety significance of losing the RPS bus 18 for a significant time was minimal; however, the loss complicated the recovery of several systems, required additional effort by the operations and maintenance departments, and could have been more significant had it occurred during an accident.
3.5 Shutdown Coolina Mode of Residual Heat Removal (RHR)
The inability to initiate the shutdown cooling mode of RHR was due to the containment isolation. Until RPS bus IB could be re-energized, shutdown cooling could not be established.
During the warming procedure for shutdown cooling, the process was slowed due to the unavailability of the normal back-flow path. A solenoid for an air operated valve in the normal flow path had lost power, thereby making the path ,
unusable. An alternate path was used, which directs back-flow to an equipment drain. This flow path was limited by the pump-out rate for the samp. The station arranged to provide alternate power to the solenoid; however, by the time the alternate power was available, the shutdown cooling had been sufficiently warmed and was ready for use.
The licensee maintained the plant in a stable condition while waiting to clear the containment isolation signal. The delay in warming the lines was of little significance. The best estimate was that the delay increased warm up time by 30 minutes to I hour.
3.6 Failure of One Intermediate Ranae Monitor (IRM) to insert This apparent failure was not associated with the loss of the station auxiliary transformer and scram on September 14, 1993. IRM "E" had been declared inoperable on September 9,1993. During the event, it was observed that IRM "E" may not have inserted correctly. The licensee's investigation <
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inserted.
3.7 Loss of Instrument Air The loss of instrument air affected several systems. Service water control valves failed to the full open position and DG fuel oil storage tank level indication was lost. The A and B drywell chillers could not be operated without air. Unit 2 was in a refueling outage and air'was lost to the bladders for the main steam line plugs in the reactor vessel. Instrument air was lost in the containment due to the containment isolation resulting from the loss of the RPS bus 18.
The loss of air to the service water control valves, DG fuel level, and Unit 2 main steam line plugs did not have any significant effect on the event. The A and B chillers for the drywell could not run until the instrument air was restored. The C drywell chiller had a dedicated air compressor and was not affected by the less of instrument air; however, it could not operate until service water pressure was restored. The containment isolation prevented '
recharging the SRV low pressure accumulators, requiring ADS accumulators to be used.
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3.8 Reactor Core Isolation Coolina (RCICI and Low Pressure Core Sprav (LPCSI Check Valve Position Indicators The LPCS check valve did not indicate full closed following shut down of the LPCS system. The LPCS was used for reactor vessel level control on the i evening of September 14 in preparation for securing RCIC. Licensee investigation found the valve to be in the fully closed position. The closed limit switch cam was loose which resulted in inaccurate position indication. '
The electrical maintenance section reset the closed indication limit switch cam and the valve position was properly indicated. ,
The RCIC check valve (E51-F065) did not indicate full closed following the shutdown of the RCIC system. The check valve was found in the partially open position as indicated. The valve was cycled to the closed position by -
rotating the external limit switch cam by hand. There was no excessive binding or internal interference preventing disk movement. Without system backflow, the check remained partially open after RCIC shutdown.
Because the valves are installed in a vertical pipe run, the packing friction in the indicator stuffing box is greater than the force provided by the disk weight. The RCIC check valves (E51-F065/66) are installed in series causing one valve to close on backflow leaving the other subject to overcoming packing box friction to close. ,
The licensee has obtained new disks designed to be used in vertical pipe t installations. The new design extends the center of gravity and shifts the counterweight to compensate for use in a vertical installation to prevent the disk from remaining open when system backflow is unavailable. The licensee is installing the disks in the Unit 2 RCIC system during the current refueling outage and will replace the existing disks in Unit 1 during the March 1994 outage.
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The loose limit switch cam on the check valve was another example of 1 inadequate maintenance. The failure of the RCIC valve to close was the result j of an inadequate design that placed the check valves in series in a. vertical j pipe run. Neither of these failures had any significant effect on the event. 1 3.9 . Failure of Recirculation Pumo Suction Valve to Close on First Attemot -
During recovery from the SAT trip and subsequent reactor scram, the A reactor recirculation pump suction valve f ailed to close on the first attempt. The valve moved in the closed direction for approximately.6 seconds and stopped.
The valve was reopened and closed normally on the second attempt.
The licensee's tests of the valve did not detect any abnormalities in valve operation. The licensee indicated that the station plans to disassemble and i rebuild this valve during the next refueling outage.
3.10 Loss of Spent Fuel Pool Coolino on Unit 2 Unit 2 spent fuel pool cooling was lost for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following the Unit 1 i scram. Pool temperature increased 5*F to 93*F. i
Unit 2 spent fuel pool cooling pumps are powered from Unit 2 buses, however, control power to the pumps was provided from Unit I through the spent fuel pool filter and demineralizer panel. Upon loss of non-Class lE 6.9kV buses, .i the contactors dropped out, shutting down the pumps-.
t Root cause of the failure of Unit 2 spent fuel pool cooling was design ,
inadequacies that permit both units' spent fuel cooling to be lost with the loss of one panel in Unit 1. The loss of the spent fuel pool cooling had no ',
effect on the event, based on decay heat rate; however, it could have required the attention of operators if a higher heat load existed. ,
3.11 Other Eouipment Problems The design or operation of several components negatively affected the operators' recovery efforts. Problems were noted with the following components and/or systems:
The air compressors need both 4160V and 6.9kV power sources to operate.
The air compressors are powered from 4160V power, but their lube oil pumps are powered from the 6.9kV power supply. With the loss of the 6.9 kV power supply, the Unit I air compressors could not be operated. This ,
appears to be a design weakness.
With the loss of both reactor building closed cooling water (RBCCW) and control rod drive (CRD) systems, there was a potential for warpage of
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the reactor recirculation pump seals. However, there was no evidence of seal leakage during the event. The licensee will replace the seals before Unit I restart.
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An RCIC oil filter high differential pressure alarm annunciated about 22 minutes into the event,12 minutes after initial RCIC operation, and the RCIC oil filters were swapped. Equipment operator (EO) rounds (including RCIC) during the second shift during the event were missed.
RCIC was secured at 7:54 p.m. on September 14, 1993. At 3:30 a.m. on September 15, 1993, the operators found that the level in the RCIC oil reservoir was low. About 1 quart of oil was found on the RCIC bed plate. Four quarts had to be added in the 21/2 gallon capacity tank to restore the level to normal.
After receiving the containment isolation signal, the operators had to jumper containment isolation valves in the post accident sampling system +
to obtain air samples from the suppression pool air space. These lines are tested during Type A integrated leak rate testing as part of the containment.
4.0 Electrical Desion Vulnerability 4.1 Cross-Tie limitations The team examined the inability to cross-tie the backup power supply of the RPS buses to Unit 2.
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The backup power supply to the RPS buses is fed from a 6.9kV bus which is normally powered by the SAT or alternately by the UAT. The loss of the SAT coupled with the main generator trip that de-energized the UAT took away all incoming power to the 6.9kV busses. No cross-tie existed between the units <
for the 6.9kV bus.ses and there was no cross-tie capability specified in LaSalle's original design. This power source was classified as non-safety and meets LaSalle's Updated Final Safety Analysis Report (UFSAR). The normal power supplies to the RPS are from the 4160V busses that have cross-tie capability between units. The backup RPS power supply. coming from the 6.9kV bus is provided for redundancy. About 30 minutes into this event, the RPS B MG set failed because of shorted windings in the motor. Due to the MG set failure there was a loss of the voltage output from the MG. This caused RPS '
bus 18 to be de-energized even though power was available at the 4160V level.
The loss of RPS bus IB resulted in the loss of power to circuits that affected -i the power range neutron monitors, process radiation monitors, RPS logic, and primary containment isolation including MSIV control and indication, instrument air supply to the SRV low pressure accumulators, and reactor recirculation sample valves.
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The team determined that there was some vulnerability from multiple failure events such as this, where the normal power supply through the RPS MG set and the alternate power supply from the 6.9kV bus are lost. The most vulnerable area would be from the non-safety power supply bus at the 4160V cross-tie level to the actual RPS bus. To reduce the risk associated with these vulnerabilities, performance of preventive maintenance on critical electrical components is essential. Of particular importance are transformers, circuit breakers, and MG sets. Because the relaying scheme creates a greater effect 9 i
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on various isolations for primary containment by RPS bus 18 failure than by RPS bus IA failure, priority should be given to the RPS bus IB power source '
path components.
4.2 Desian of Offsite Power Supplies The team noted that it took longer than expected to establish the backfeed through the VAT. Also, the team examined whether there was a power ,
configuration design or procedure problem associated with the event. !
It took almost 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> to initiate backfeeding after the loss of offsite >
power from the loss of the SAT and the UAT. The licensee had three existing procedures that performed various actions involved in backfeeding the UAT by removing the SAT from service. The failure of the SAT made certain procedural -
steps inapplicable. Under procedure compliance guidelines, a procedure change was necessary to delete or change certain procedural steps. This need for a procedure change was not identified until commencing the actual performance of ,
, the procedure many hours into this event. The system engineer cognizant of these procedures had been involved in other electrical power restoration activities and had to be redirected to make the procedure change. l The inordinate amount of time was not related to the plant design or the routine configuration of offsite power supplies. However, having a breaker t rather than links isolating the generator might be an alternate design which *
would speed up some of the steps. A normal backfeed procedure at this plant
- can be completed in-about 8 to 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />, which is consistent with the time for other utilities to complete this task. '
The implications of the delay in backfeeding was the continued loss of i circuits fed from the 6.9kV bus which included the backup power to the RPS bus (discussed in Section 4.1, above), MDRFP, solid radwaste processing panel, radwaste supply and exhaust fans, turbine building supply and exhaust fans, '
TBCCW pumps lA & IB, electro-hydraulic control pumps lA & IB, and Unit I air compressors.
The team determined that a procedure with the option to backfeed through the !
UAT when the SAT was lost or de-energized was warranted. -
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5.0 Human Performance Elements of the Event ;
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5.1 Procedures During the event, the operators followed emergency operating procedures (EOPs) l'
and abnormal procedures extensively. However, xerox capability to copy abnormal procedures for field use was impaired because of the loss of power. I The EOs removed and used controlled copies from the shift supervisor's office in the plant.
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Only one minor issue in the E0Ps was identified during the event. LaSalle general abnormal (LGA) procedure LGA-01 directed the operators to use the RHR pumps in shutdown cooling at the same time that LGA-03 directed the operators to start all available pool cooling to reduce the temperature of the suppression pool. The licensee initiated a temporary procedure change to provide more flexibility in this area during the event. ;
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, l Two instances were identified during the event where operators performed I actions without using an approved procedure: I 1. An E0 rolled over an RPS NG . set flywheel before attempting to start it.
This action was not included in a site procedure. The licensee is evaluating corrective actions.
2. Operation of RCIC at full flow using both the test and injection lines.
Operations procedure LOP-RI-09 " Operation of RCIC System for Pressure Control" .
allowed this method of operations, while LOP-RI-02 " Operation of RCIC System I for Level Control" directed the RCIC flow controller tape setting to be used.
The team agreed that full flow operation was beneficial in this event in that it dissipated as much reactor decay heat load as possible in this method of ;
operation. tiowever, the team was concerned that the operators appeared to ,
have operated RCIC primarily for level control without consulting or '
temporarily changing the appropriate procedures.
5.2 Command. Control . and Communications !
Based on operator interviews and direct NRC resident observation, the team i found that the operating crew was very effective in diagnosing and responding to this event.
According to interviews, logs, and the sequence-of-events, the shift engineer (SE) exhibited sound command and control in the control room, and used extra available personnel very effectively. The shift control room engineer (SCRE) :
normally directs activities on a unit, but during emergencies the SE assumes direct control over the unit while the SCRE fulfills the shift technical advisor (STA) function. This necessitates a turnover during an event. The SE and SCRE/STA assumed their emergency roles effectively.
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flowever, it should be noted that the SE came into the control room immediately after the scram and little turnover was necessary. This turnover between the SE and SCRE/STA has experienced problems in the past during actual events and ;
during simulator training. The STA was assigned oversight of the primary ,
containment and an extra SE was assigned oversight of the reactor and 2 emergency core cooling system and engineered safety feature functions.
As trained, the Unit 2 SCRE/STA assumed the duties of providing emergency declaration recommendations and initial state, local, and NRC notifications -
for the opposite unit. ,
The nuclear station operators (NS0s) exhibited e.vcellent teamwork and communication skills during the event. Extra NS0s were assigned operational ,
responsibility of the RCIC system, SRVs, and the electrical panel, while the '
unit NSO maintained an oversight role of the control board manipulations and monitoring. i i
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The shift supervisor and other NS0s checked with the NSO handling the DGs and electrical cross-ties before starting additional equipment to ensure that load limits were not exceeded. The operators appropriately stabilized the plant while on DGs power before attempting to energize the cross-ties.
The turnover between the first and second shifts during the event was >
excellent. In addition to the crew briefing, each operator had the opportunity to be briefed by his associated offgoing operator and the offgoing operators remained in the control room for some time until the new crew had mastered the new plant conditions and unusual operating modes. However, as mentioned earlier, second shift E0 rounds were missed during the event. i
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The team identified two communications problems:
1. The E0 who identified and called in the fault at the SAT by radio did
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not receive any response from the control room, in part because of the loss of the console radio and the immediate actions being carried out by the NSO in response to the reactor scram. The E0 also told the control i room that no fire brigade call out was necessary. The shift supervisor. !
(fire chief) responded anyway and methodically assessed the fire potential _by directing other E0s to check the bus ducts in the auxiliary and turbine buildings and the SAT before securing the SAT deluge system.
The team determined that the E0 should not have made the fire brigade call-out determination, but should have left that decision to the fire chief.
2. The ENS communicators were not fully informed by shift or TSC management on the extent of system degradation or their affects on the plant, or positive recovery efforts. Also, the ENS communicators failed to communicate these conditions to the NRC, as described in Section 6.2 of this report.
5.3 Training The team identified several examples of differences between the plant and the simulator. In the simulator:
The shrink and swell during SRV operation at high pressures was milder than observed during the actual event.
The effect of cross-tied air and service water systems on the other unit was not considered, whereas in the plant, a cross-tied system problem on one unit would substantially affect the other unit. This event's crosstie complexity was not addressed during training scenarios.
RCIC was mainly injected at full flow. During the event, RCIC was operated for an extended period of time with throttled flow.
When the 6.9kV buses were lost, there were always random lights lit in the full core display, but this did not happen during the event.
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Several operators noted difficulties on the transfer of control from the SE to the TSC and operations support center (OSC) during the event. During the first half hour of this transition, E0 support was lacking because the NS0s '
were using their normal method of calling the E0 break room instead of getting E0s through the SE and OSC.
The team noted that there were problems with the ENS communicators and licensee management on the NRC notification process at or above the Alert ' -
level as described in Section 6.2 of this report. Several operators interviewed expressed a need for additional training in these areas.
Both the SCRE/STA and SE noted that prior training had helped during the .
event. The SCRE/STA and SE trained together for the first time'in a year the Friday before the event. Also, E0s were included in some simulator training on abnormal conditions.
5.4 Stress '
Operai.or stress did not appear to play a significant role in this event.
During the event, control room operator stress levels appeared to be only slightly elevated for a number of reasons. The operators did.not have the high stress levels that accompanies an unexpected scram with complication lasting a long time. Extra operators were available who were assigned specific duties. Up to 39 people were counted in the control ' room at one point. Extra personnel usually remained away from the operating or event command areas. There were many advantages and one disadvantage to this.
Although management, operating, maintenance, and support personnel were readily available when needed, noise levels occasionally increased and interfered with operator communication. The SE or STA asked everyone to ;
reduce the noise levels on several occasions. s The only significant stress related incident identified was an interaction ~l that occurred with the E0 group. A group of E0s cbjected to an OSC health physics (HP) technician, who, by procedure, required them to full body frisk at the OSC step off pad, after they hv just come down a hall from the control room. This situation was decisively resolved by a shift supervisor, who directed the E0s to comply with the different HP requirements used when establishing the OSC. There appeared to be a number of contributory causes for this situation, including unfamiliarity with the OSC process, working rapidly in a darkened plant for an hour, trouble getting copies of procedures, !
and a lack of a plant status briefing. )
i 5.5 Human / Machine Interface !
The team identified a number of human / machine interface issues that affected operator performance in this event.
Jumpers had been set aside for E0Ps along with the. administrative paperwork for their quick use. However, jumpers had not been similarly set aside for
- abnormal procedures, including those needed during loss of power' events,
- especially when the jumper storage area was darkened.
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Emergency lighting was insufficient for operation of some A, B and C chiller !
valving during the loss of power. E0s had difficulty reading procedures and identifying specific components.
There was no indication of SRV accumulator pressure in the control room. '
After several cycles, SRVs no longer had sufficient air to open fully and had dual indication. The operators had known from their simulator training.that this would happen and were concerned about it but had no instrumentation for i them to anticipate when it would occur.
While the A and B chiller service water lines have pressure indication, the C.
chiller service water line did not. This led to starting, then securing, the ;
C chiller, when the service water pressure was too low to support chiller operation. i
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One of three control room clocks stopped during the event on loss of power and caused slight confusion to a number of individuals and difficulty in !
reconstructing some parts of the event.
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The restart of the station air compressor was complicated and delayed by the need to obtain the right fittings and an air bottle for seal air. The .
licensee had staged an air cylinder storage rack for air cylinders near the !
station air compressor. However, this air cylinder storage rack was empty. .{
5.6 Licensee Manaaement Performance *
The team concluded that the licensee management was effective in directing the I completion of the actions taken to maintain the unit in a safe condition and bring it to cold shutdown. They managed and directed the available resources to deal with a number of difficult situations. Excellent teamwork and mutual -
support were evident throughout the event.
l The team interviewed operations and maintenance personnel involved in the event and reviewed the actions taken by the licensee to determine how :
management actions affected the course of the event. On-shift management maintained effective command and control throughout this complex event, 1 directing the activities of the normal operating crew plus'the additional '
available personnel who reported to assist in the recovery. Other management personnel reported to the control room, to the TSC, or to the OSC to assist :
the operating crew.
L The team noted that having the shift engineer both direct the performance of the plant recovery actions required by the emergency and abnormal operating- ,
procedures and perform the duties of the emergency director for classification and notification of the event put him in a very difficult situation. Extra personnel who reported to the control room assisted him in carrying out these i concurrent duties. ;
, The acting plant manager had assigned the single manager who coordinates human I performance evaluation system (HPES) reviews on identified issues.or events to ,
work on unrelated issues on the Unit 2 refueling outage. Sixty' other licensee ,
personnel had been trained in HPES techniques, either in an industry or-
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I company program, but varied in effectiveness. After the event, the acting plant manager returned this manager to his HPES duties and the HPES manager ,
interviewed the operators involved. The acting plant manager ensured that the HPES manager had access to the operators involved in the event on a timely basis to establish the time line of the event before memory loss could impair.
the investigation. The team determined that the number of HPES interviews was too limited and the interviews too narrowly focused on the time line. This i resulted in a detriment of other human performance issues, especially training.
6.0 Reportina of the Event 6.1 Evaluation of the Event The team. concluded that the licensee should improve the effectiveness and timeliness of corrective actions. Licensee initiated. reviews have also '
identified this concern.
The team reviewed the licensee investigation, root cause analysis, and corrective actions for previous events. Most of the review effort was directed at the scram with complications that occurred on August 27, 1992.
Each of the licensee corrective action plans from the scram report was ,
reviewed. A number of the corrective actions have not been completed yet. >
Some of these actions can only be worked during -an extended plant outage. An additional corrective action recommended by Quality Assurance and Verification (QAV) in their independent review of the event has been implemented.
The team reviewed the QAV aurlit of the corrective action program. In general, the audit found that there were areas in which corrective action had been -
ineffective in rectifying the associated problems and that other corrective actions were not being implemented in a timely manner. The information reviewed supported these conclusions. !
The team noted that during the September 14, 1993 event, the TSC made a recommendation to leave the control rod drive system secured until forced
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circulation was restored for the reactor vessel to prevent thermal stratification in the reactor vessel. This recommendation was due at least in part to a recent NRC information notice and some older General Electric Company service information letters. This action was an example of the successful implementation of the operational experience review process.
6.2 Completeness and Accuracy of Licensee's 10 CFR 50.72 Report Based on emergency notification system (ENS) communicator interviews and NRC Operations Center tape reviews, it was determined that the initial 10 CFR.
50.72 notification and continuous updates to the NRC made by the licensee was timely, but significantly incomplete. Licensee notification to the NRC Operations Center was made immediately after the state and local calls were completed, about thirty minutes after the Alert was declared. The licensee did not identify a number of-degraded plant conditions, failure of multiple systems and components, and their safety significance either initially or'
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during the event, as specified. in 10 CFR 50.72 (c).
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Most importantly, the licensee's ENS communicator did not inform the NRC of the loss of RPS bus 1B (identified later) or station air, the degradation of the service water system, or the associated complications to the recovery efforts. The licensee did not notify the NRC that safety parameter display system (SPDS) control room monitors had not been operable for the first 20 minutes of the event or that the security secondary alarm system had failed and that plant security had institutad compensatory measures. In some cases, the ENS communicators were unawue of the degraded conditions while at other times they had been notified ref certain conditions. It was determined by the team that during certain times when the ENS communicator was unaware of degraded conditions, these conditions were known by either the SE or TSC.
Within the first hour after the event declaration, the NRC Region 111 ENS communicator requested a list of equipment that was out of service. The licensee's ENS communicator passed that request on to another licensee person and responded a few minutes later with a 6 item list containing only tagged out-of-service equipment prior to the event.
During the initial call to the NRC Operations Center at 1247 hours0.0144 days <br />0.346 hours <br />0.00206 weeks <br />4.744835e-4 months <br />, the licensee's ENS communicator stated, in part, that the instrument air system had been restored. In fact, the instrument air pressure was not returned to normal until 1404 hours0.0163 days <br />0.39 hours <br />0.00232 weeks <br />5.34222e-4 months <br />. The Unit I drywell instrument air crosstie to the station instrument air was not established until 1923 hours0.0223 days <br />0.534 hours <br />0.00318 weeks <br />7.317015e-4 months <br />, after RPS bus IB was restored. This allowed the B primary containment isolation signals associated with that bus to be reset and the drywell instrument air containment isolation valve to be reopened at 1924 hours0.0223 days <br />0.534 hours <br />0.00318 weeks <br />7.32082e-4 months <br /> to recharge the SRV accumulators.
This 6-1/2 hour loss of instrument air to the drywell affected the operation of the SRVs. The SRV air accumulator pressures decreased as the SRVs were cycled, to the point that the SRVs could not be fully opened. Since the non-ADS SRVs had no alternative gas source, the TSC recommended that the ADS SRVs be operated from the ADS nitrogen bottles. Although the TSC did not consider it, the safety significance of partially open SRVs was that they may have a higher probability of sticking open and depressurizing the reactor. The ADS SRVs could still be operated from their ADS accumulators, but not from the control room. An equipment operator was stationed in the auxiliary electrical room, with telephone communication to a control room NSO, to open the ADS SRVs -
as necessary. Thus, with proper communication and control, primary reactor pressure control was performed outside the control room.
The service water system operated with open crossties between both units, such '
, that 3 of 5 service water pumps were needed for system operation. The licensee's ENS communicator did not identify that due to the power and maintenance, only I service water pump was operating, which prevented the operation of the drywell chillers when the operators wanted to restore them to operation to decrease containment pressure. The operating service water pump was not able to provide sufficient pressure and flow to the C chiller ,
condenser. The operators shut the chiller down for equipment protection. '
When power was restored, a second service water pump was started and some service water loads were valved out to increase flow and pressure to the A, B.
and C chillers before they could be used.
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The licensee notified the NRC of the use of jumpers to bypass containment isolation signals on several valves as a part of their initial 10 CFR 50.72 '
notification, as required in their E0Ps and by 10 CFR 50.54(x). This part of the notification was delayed until the NRC Headquarters Operations Officer (H00) could establish a conference call with NRC management and Region 111 in accordance with NRC. procedures. Once the conference call was established, the licensee informed Region III that the jumpers had been installed. This information was not included in the H00's ENS report in its proper time '
sequence.
6.3 Alert Classification The inspection team concluded that the classification of this event as an .
Alert was appropriate.
An off-shift SCRE made the initial recommendation for the classification of the event as a Notification of Unusual Event under Emergency Action Level '
(EAL) 3d due to the unplanned loss of normal power to the unit's 4160V emergency core cooling system (ECCS) buses. However, licensee management decided that it was appropriate to man .the TSC and partially staff the corporate emergency operations facility (CE0F). Licensee management also decided that due to the degradation in plant safety associated with the large number of complications in the event, and the need for support personnel over an extended period of time, that the appropriate classification for the event ,
was an Alert under EAL 9c which reads: '
A condition that warrants activation of the TSC, AND '
Precautionary activation of the EOF (CEOF)."
The classification was made approximately 30 minutes after the initiation of the event and notification of the event, and the classification was made to the NRC within 30 minutes of the classification of the event.
7.0 Quality Assurance / Verification The team reviewed (1) recent audits performed in _the areas of maintenancs and the corrective action program, (2) a QAV walk through of the support ;
procedures for the emergency operating procedures, and (3) a QAV review of the August 27, 1992, scram on Unit 2. The most recent audit that included the preventative maintenance program was performed in 1990. The corrective action program audit only reviewed the effectiveness of a small number of corrective actions for equipment failures. There were no audits available.for the operator training program for the emergency operating procedures. However, the QAV review of the scram with complications on August 27, 1992, critiqued the actions taken in response to the equipment problems encountered during
- that event. '
Within _their respective scopes, each of the audits or reviews- appeared to- be '
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thorough. In particular, the team noted that the QAV: review of the August 27,
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,.- l 1992, scram recommended that the licensee revise the'high reactor water level ;
response procedure to remind operators that the RCIC turbine should not be !
started with water in the associated steam supply line. This problem had not !
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previously been addressed by the licensee's reviews of the event. However, the team concluded that the scope of the audits and reviews excludes some areas that could benefit from independent evaluation. In particular, audits i of the preventative maintenance area and the operator training program for ,
emergency operating procedures might be appropriate based on the problems ,
encountered during the event that occurred on September 14, 1993. ,
8.0 Safety Sionificance and Conclusions !
The AIT concluded that while the event was a significant operational occurrence, no radiation was released and it did not pose an immediate impact on the health and safety of the public. Nonetheless, NRC is concerned that l inadequate maintenance resulted in several equipment failures that occurred during the event and recovery. We note that inadequate maintenance has been a contributing factor to other events at LaSalle and we are concerned that your corrective actions have not been effective. In view of these events, we
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consider it important for you to carefully assess the scope of your current maintenance activities and practices.
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The significant operational safety parameters that were approached i.ncluded reactor vessel level and pressure and suppression pool temperature and level.
There was no release of radiation. This event imposed no immediate impact to the health and safety of the public. The NRC was concerned about the number of equipment failures that occurred subsequent to the event, with maintenance being identified as the common factor.
The operators safely responded to a challenging plant event and their actions were indicative of a strong knowledge of plant systems and procedures.
Licensee recovery from this event was thorough.
.I The AIT concluded the following:
The most probable cause for the trip of the SAT was inadequate maintenance.
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- The most probable cause for the loss of RPS bus IB wo: a failure to adequately maintain the associated MG set. '
The failure of the D SRV to lift fully was due to a large air leak on the low pressure accumulator.
The most probable cause of the failure of the LPCS check valve position indicator was a ' loose cam limit switch which allowed rotation.
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The initial notification and continuous updates to the NRC operations center were incomplete and did not include degradation and failure of ;
multiple systems and components. '
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There was a lack of effective corrective action resulting from a similar event on August 27, 1992.
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- There were two examples where operators performed actions without using i an approved procedure. '
- The licensee needs to increase their sensitivity associated with the ~
risk of cross tieing units. This was evident during the training area review.
- This event and some of the complications with the event were ,
preventable. A stronger maintenance program is needed to improve future operations.
9.0 Exit Meetina The team met with licensee representatives (denoted in Enclosure 5) on September 21, 1993, and summarized the purpose, AIT charter items, and findings of the inspection. The team discussed the likely informational content of the inspection report with regard to documents or processes ,
reviewed by the team during the inspection. The licensee did not identify any such documents or processes as proprietary.
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e*MC49 UNITED STATE.S
/ \ taucLEAR HEGULATORY COMMISSIOt4
" ! '" 3 1 IL n[cion :::
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. SEP 1 G 1993 ,
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C.0tJFIRMA10RY ACT1014 iETTER Docket tio. 50-373 CAL-Rill-93-014
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Commonwealth Edison Company ,
ATTil: Mr. Michael Vice President
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Chief Nuclear Officer ;
Executive Towers West III, Suite 500 1400 Opus Place Downers Grove, Illinois 60515
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Dear I:
r Wallace:
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This confirms the conversation on September 16. 1993, between Mr. Geof frey Wrigh'.- :
of my staf f and ifr. Warren !!urphy of your'staf f related to the loss of of f-sits power (LOOP) event at LaSalle Unit 1 which occurred on September 14, 1993. With respect to the LaSalle Unit 1 matters discussed, we understand that ycu will perform the following actions: '!
1. Conduct an investigation to determine: -
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The. root cause of the LOOP event and the loss of the IB RPS MG set. j b. The adequacy of EOPs and Abnormal' Procedures to handle this event, ,
c. The security system's power supply-performance during the event.
d. The adequacy of the 10CFR50.54(x) reportability. determination.
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The reasons for identified equipment' and ' indication failures '
including the safety relief- valves, the - f ail.ure of one lRM to- .i insert,' the fall'ure of. the recirculation pump suction-valve to closeL-on the first attempt, and'the problems associated with the RCic and LPCS check valve-position indication. ;
f.
The sequence of events -and adequacy of operator. actions.
2. Maintain documentary evidence.of your investigation effort =and make thiL
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available to the Augmented Inspection Team (AIT).
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Commom:ealth Edison C o.H:an. 2 C r L-R i l l - 9 2 .~ .1 f
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Provide within 30 dajs to 11RC Re; ion 111 a doc =ented evaluatier. :# tte .l above issues ir. cit.dir.g c:rrective actions you have taken or plan to :ake.
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t,'e further understand that reactor startu;) (power o;1 erat ion) ill not occur r.t t'
you have informed the RE;ional Admints;rator. or his designee of the resul,5 c'
your investigation and corrective acticas.
lione of.the actions specified herein should be construed to-take precedence over actions which you feel necessary to ensure plant and personr.el- safety. .,
If your understanding differs from that set forth above, please cali ce immediately. Issuance of this Confirmatory Action Letter does not pre: lode issuance of an Order forcalizing the above commitments or requiring other actiori '
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on the part of Commonwealth Edison Company. flor does it preclude T1RC from takir.; ;
enforcement action for violations of !!RC requirements that m2, have prompte: the issuance of this letter.
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l S i r.C e r e ly , ,
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d hn B. Martin I Regional Administrator See Attached Distribut ion
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SE? 16 993:
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Conmanucalth Edison Company 3 '
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Distribution:
W.11arphy, Site Vice President J. Schmeltz, Acting Station flanager
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J. Lockwood, Regulatory Assurance Supervisor .;
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D. ' f arrar, fluclese Pegula tory Services -
lianager 0C/LfDCB Resident inspectors,'LaSalle, Clinton, Dresden,, Quad Cities j R. Hubbard ,
J. W. licCaffrey, Chief, Public !
Utilities Division 1
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Licensing Project Manager, 11RR
- __ R. tiewmann, Office of Public Counsel, State of Illinois Cer.ter 1 1.
U ' State Liaison Officer '
Chairman, Illincis Commerce Commissica
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-J . M Taylor, EE)
J. H. Sniezek, DEDR .'
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H. L Thorpson, DEDS T. E. tiurley, I!M
, J. G.-Partlow, IP
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J. 'J. Roe, IJRR J. A. Zwolinski, ';RR l J. E. Dye _r, flRR E. L. Jordan, AEOD -l
~J. Lieberman, OE j
,. J. R. Goldbeig, 03C R. J. Strasma, Rill J. D. Wilcox, Ali lean Leader
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UNITEo STATES
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o NUCLEAR REGULATORY COMMISSION REGtON nt 0' E 799 HOOSEVELT ROAD
'o, 'f GLEN ELLYN, ILLINOIS Co137-s927 )
I.. . . / SEP 161993 1
MEMORAfiDUll FOR: John D. Wilcox Jr. , Team Leader, LaSalle Augmented lospection Team (AIT)
FROM: W. L. Forney, Deputy Director, Division of Reactor Safety, Region III l SUBJECT: AIT CHARTER - LASALLE UtilT 1 LOSS OF 0FTSITE POWER Enclosed for your implementation is the Charter developed for the inspection of the event associated with the September 14, 1993, LaSalle Unit 1 Loss of Offsite Power and Reactor Scram. This Charter was prepared in accordance with the flRC Incident Investigation Manual and the Manual Chapter 032S AIT implementing procedure dated April-18, 1991. As stated, the objectives of the AIT are to communicate the facts surrounding this event to regional and headquarters management, to identify and communicate any generic safety .
concerns related to this event to regional and headquarters management, and to !
document the findings and conclusions of the onsite inspection, if you have any questions regarding these objectives or the enclosed Charter, please do not hesitate to contact either Dick Hague (DRP) or myself. ,
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William L. Forney, Deputy Directo)
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Division of Reactor Safety, Region 111 '
Enclosure: AIT Charter See Attached Distribution
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John D. Wilcox 2 SEP 1- 61993 - ,
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Distribution cc w/ enclosure: .
J. B. Martin, Rll!
H. J. Miller, Rill r E. G. Greenman, Rill T. O. Martin, Rill C. E. Norelius, Rill F. J. Miraglia,-NRR' ;
'J. G. Partlow,.NRR ;
J. W. Roe, NRR C. E.'Rossi, HRR J. . A. Zwolinski, NRR A. E. Chaf fee, HRR -
W. M. Dean, NRR B. A. Boger, NRR E. V. Imbro, NRR J. L. Kennedy, NRR -
J. E. Rosenthal, AE00 A. T. Gody Jr. , EDO Resident inspector Of fices, LaSalle, Clir.:on, Dresden, Quad Cities ,
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j LASALLE UNIT 1 LOSS OF STATION AUXILIARY TRANSFORMER (SATl i
Under your direction, your team is to perform an inspection to accomplish the {
-following:
i 1. Determine and validate the sequence of events associated with the !
September 14, 1993, LaSalle Unit 1 Loss of Station Auxiliary 1 T rans former. ;
2. Evaluate the safety impact and identify the root cause of equipment ,
failures at LaSalle Unit I that were identified on ~ September 14, 1993,
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including: ,
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a. Loss of the SAT. '
b. Safety Relief. Valve (SRV) anomalies.
c. Loss of Security Alarm Station and Loss of Heating Ventilation and Air Condition'ing (HVAC) to prime security computer. :
d. Loss of Reactor Protective System (RPS) bus lE. the associated loads, and the impact on plant recovery.. ;
e. Inability to initiate shutdown cooling mode of Residual Heat- [
Removal (RHR) . >
f. Difficulty warming lines to get on shutdown cosling, a g. Operators failure to report a 10CFR50.54.x action that was required by the station Emergency Operating Prccedures (EOP's) and the appropriateness of the E0P reference to 50.54.x. '
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I h. Failure of one Intermediate Range l'onitor (IRf1 to insert. '
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' i. Evaluate the impact of the loss of-instrument air.
J. Problems with RCICL and LPCS check valve position l indication.
,
L f ailure of recirc pump suction valve to close cn first attempt.
,
. l. Loss ct Spent fuel Poul Cooling cn Lnit 2.
3. Revie.e Lu in perf ormance eierent s of i' . event s inch :tr.g numan,q v; im '
inter:ac.
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'4. Evaluate.whether there is an electrical design vulnerability in the following areas:
a. The inability to cross-tie the backup power supply of the RPS buses to the other unit.
b. The design or routine configuration of offsite power' supplies ,
which results in an inordinate amount of time and preparation prior to backfeeding through.the UA1.
t 5. Identify, evaluate, and determine the root cause of any other significant equipment problems with safety-related or balance of plant ,
equipment that could have interfered with the operators' ability to
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safely operate the plant.
6. Interview plant personnel involved in the event and the. equipment failures to evaluate crew effectiveness in diagnosing and responding to i
the event. Identify both positive and negative aspects of crew
.
,
!
performance.
7. Review the adequacy of the licensee's program for evaluating significant'
events. -Oversee troubleshooting, testing and analysis of equipment. -
8. 3 Evaluate licensee managerial performance related to this event-- including- !
shift supervision, management response, and maintenance supervisicn for activities involving failed components. '
i 9. Evaluate the completeness and accuracy of licensee's 10 CFR 50.72 report. a l
10. Review the appropriateness of the Alert classification.
11. !
For broad issues and concerns identified by the team, determine if and i to what extent licensee quality assurance / verification identified i similar concerns in audits and reviews of licensee operations. Assess' l whether licensee QA/QV activities conducted in the recent past were .l capable (i.e., of adequate scope and depth) of finding such problems 1 where'thev exist.
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-Enclosure 4 I
Seouence-o f-Event s Tuesday, September 14, 1993 (all times are CDT)
~ (All entries refer to Unit I except where otherwise indicated.)
Initial condition: Unit I was at full power with no surveillances or-other activities.in progress, 11:47:33 Unit I system auxiliary transformer (SAT) tripped due to a bus duct fault. Fast transfer of busses 152, 141Y, 142X, and 142Y from the SAT to the unit auxiliary transformer (UAT) occurred as expected.
The SAT deluge activated and 0A diesel fire pump (DFP) started.
The motor driven reactor feed pump (MDRFP) flow control valve !
and the 1A & 18 turbine driven reactor feed pumps (TDRFP)
control signal failure lockout occurred, which would cause the '
feed water flows to remain constant. However, the B TORFP control valve closed, rapidly reducing the feed water flow from that pump. ,
The B reactor recirculation flow control hydraulic power unit (HPU) isolation valves close due to momentary power loss.
,
Unit 1 station air compressor (SAC) tripped due to momentary loss of control power. ;
i Bus 143 (Division 3) lost power causing high pressure core spray (HPCS), diesel generator (OG) to start. The UAT does not feed .
bus 143. !
Reactor building ventilation (VR) secondary containment dan.Nrs closed due to momentary loss of control power. ,
11:47:35 VR no flow alarm occurred due to damper closure and the. fan ,
tripped upon damper closure. (Without prompt' restoration of ventilation the main steam line tunnel will-heat up quickly and cause the~ main steam . isolation valves (MSIV) to isolate.) ,
Operators immediately' called for the jumpers to be installed.
08 DFP started due to the SAT deluge.
11:47:37 Division 3 DG running due to bus 143 undervoltage, 11:47:41 Reactor low level alarm, level 4, (+31.5 inches above instrument' :
zero).
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-I Enclosure 4 2 ' Sequence-of-Events I
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l 11:47:42 Reactor water clean up (RT) pump low flow was indicated when the RT suction outboard isolation valve IG33-F004 valve closed due to momentary loss of power to the high filter /demineralizer inlet temperature switch.
,
11:47:44 Bus 143 energized by the Division 3 (18) DG.
11:47:52 Reactor SCRAM - low water level, level 3, (+12.5 inches above instrument zero). 1 This is a Lasalle General Abnormal (LGA)-01 entry condition j (LGA procedures are the station's emergency operating procedures) 1 Reactor recirculation pumps downshifted to slow speed at reactor ;
water level 3 as designed. 1 Steam demand from the main turbine decreased as the turbine ~
control system maintained reactor pressure. !
11:48:11 A & B RT pumps off due to low flow caused by the suction isolation valve closure, a
18 TDRFP tripped and reset (reset due to defective limit switch.
'
11:48:21 identified prior to event, work request had been written).
11:48:25 Operator closed IB TDRFP 18 discharge valve, IFW0108, (normal
.
post scram action).
11:48:46 Reactor water level increases above level 3.
11:48:50 Operator closed 1 A TDRFP discharge valve, IFWO10A' (normal. post
'
scram action).
.
MDRfP auto started as expected. ]
11:48:56 Reactor water level increased above level 4. ;
RT valve 1G33-f004 valve. closed ;
- 11:49:00 Reactor water level increased above high level alarm, level 7, (-41.5 inches above instrument zero). .
!
11:49:04 Reactor water level. increased =above level 8-(+55.5-inches above-instrument zero). (Maximum water level reached was unknown as- {
power to the upset range was lost.) -1 j
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Enclosure 4 3 Sequence-of-Events
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11:49:06 Main turbine, TDRFP, and MDRFP tripped due to high reactor water level 8. ;
11:49:12 Main generator tripped due to reverse power. All busses lost power due to loss of UAT, which received power from the main generator. Reactor protection system (RPS) busses lost power following loss of power to motor generator .(MG) sets. l Containment isolation signal occurred upon . loss of RPS busses.
Main steam isolation valves (MSIVs) close following the loss of RPS busses.
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Unit 2 SAC tripped due to loss of cooling from-Unit I turbine building closed cooling water (TBCCW).
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Control rod drive (CRD) pump tripped.
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Fuel pool cooling was lost for both units.
11:49:30 0 DG (Division 1) energized bus 141Y and 1A DG (Division 2)
energized bus 142Y.
.
11:50:21 Primary containment coolers (VP) chilled water isolation ~ valves ;
isolated. l 11:50:30 A residual heat removal (RHR) service weter (WS) pump started j manually for suppression pool cooling. ,
l 11:50:37 8 RHR WS pump started manually for suppression pool cooling. 1 (These pumps support A RHR loop) l
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11:50:44 Drywell instrument air (IN) was-lost due to closure of containment isolation valves.
11:51:00 Both trains of standby gas treatment started due to loss of RPS busses.
11:51:03 1 A RHR pump started manually. for suppression _ pool cooling.
11:51:11 Suppression pool cooling valve IE12-F024A valve opened, 11:52:01 Reactor high pressure alarm occurred (1020 psig).
11:53:22 Safety / relief valve (SRV) K opened on pressure. (This SRV was not expected to be the first SRV to open on pressure. Pressure was approximately 1070 psig.)
-11:53:24 IB RPS MG manually restarted.
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l Enclosure 4 4 Sequence-of-Events t
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11:53:31 1A RPS MG manually restarted.
ll:53i49 SRV K closed automatically. 5 11:53:59 SRV U opened manually. ,
11:54:01 SRV S opened manually.
Low-low set (LLS) initiated due to two SRVs open, as expected. !
11:54:17 Reactor high pressure alarm cleared (1020 psig).
11:54:47 IB RPS bus re-energized. .
11:55:14 1A RPS bus re-energized.
11:56:30 Instrument air receiver air pressure low alarm received. 'l lli57:42 Suppression pool temperature high alarm (105'F)
This is a LGA-03 entry condition.
11:58:06 SRV S auto closed. ,
11:58:08 SRV U auto closed by LLS logic. With the SRVs. closed, reactor water level shrunk, due to the collapse of voids, below level 8 trip.
11:58:12 Reactor water level continued to decrease, below level 7 alarm. t 11:58:19 Motor control center (MCC) 134Y 480vac normal (From 142Y,14.16kV -
bus).
i 11:58:20 Low reactor water level 3 trip.
11:58:25 Reactor core isolation _ cooling (RCIC) manually started for ,
injection into the core with the condensate. storage tank being '
the source of water.
11:58:29 HPCS pump manually started.
11:59:13 HPCS placed in full flow test. HPCS was not needed for reactor. -
water level control.
i 12:00 ~ 'LGA-CM-01 containment monitoring (CM) jumpers . installed per LGA-03. .
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12:01:33 Reactor watar level ' recovered above level' 3 using RCIC -
. injection.
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t Enclosure 4 5 Sequence-of-Events ,
12:02:23 Suppression pool temperature reached 110*F due to SRVs and RCIC.
12:03:05 B RHR WS (C and D pumps) was manually started.
,
12:04:15 B RHR pump started manually for suppression pool cooling.
12:05:29 Reactor water level increased above level 4.
I 12:06:07 Main condenser vacuum low alarms IA/lc occurred.
12:07:06 Reactor water level increased above level 7 from RCIC injection.
,
12:08:12 Primary containment pressure increased above 1.0 psig.
12:08:30 RCIC placed in full . flow test and injection was secured.
(maintained decay heat removal through RCIC)
12:09:13 Drywell air temperature reached 135*F.
LGA-03 entry condition.
12:10 - High differential oil pressure on RCIC oil filter.
.
12:11:32 The IB VP loop was unisolated. [
(both RPS busses were energized)
12:12:33 The 1A VP loop was unisolated. ,
12:13:46 Manually restored bus 138 to normal.
12:14:06 Primary containment pressure drcpped below 1.0 psig 12:14:47 18 main condenser vacuum low alarm occurred.
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SRV U auto opened by LLS logic.
12:14:50 Reactor water level reached level 8 due to swell. I 12:14:52. RCIC auto shutdown on level 8.
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12:15 - RCIC high differential oil pressure cleared after alternate oil' '
filter was.placed in service.
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12:15:18 The turbine received second trip as expected from low condenser vacuum.
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12:17:01 Reactor water level returned below level 8.
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Encl'osure 4 6 Sequence-of-Events
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12:17:31 B RPS MG set tripped due to a motor fault.
B RPS bus de-energized.
12:17:41 SRV U auto closed by LLS.
.,
12:17:48 Reactor low level alarm, level 4.
12:18:07 RCIC manually restarted in injection mode.
12:20:~ ALERT declared. I
LGA-VP-01 primary containment jumpers installed to allow chilled ;
water to flow to the containment air coolers.
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12:20:45 Reactor water level. increased above level 4.
12:20:47 Power manually restored to busses'131X and 131Y.
i 12:22:31 Reactor water level increases' above level ~ 7. ;
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12:25 f4ARS phone call . made.
'12:27:07 SRV U opened.
. . i 12:27' RCIC shutdown at level 8. ]
12:28 Level 8 clears, reactor water level decreasing.
12:30 SRV U closed.
Reactor water level 3, level decreasing. "
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12:31 C VP chiller was started then was manually shutdown 'due .to -low W5 cooling to the condenser. l 12:31:36 . Reactor water. level 3 clears, level increasing. j 12:42:26 SRV U opened.
.l 12:45:14 SRV U closed.
12:47 D;S notification made.
'12:51 Manually energized bus 137X/Y.
12:53:26 Main turbine'on turning gear.
, 12:56:26 SRV U opened.
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Enclosure 4 7 Sequence-of-Events
. 12:57 WS pump discharge pressure normal (due to second WS pump being started and some loads being valved out).
12:57 Division 1 (4160 volt) cross tied to Unit 2, O DG shutdown and ,
placed in standby, 12:58 $RV U closed.
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Manning of technical support center (TSC) complete. ,
13:00 - C VP chiller restarted (adequate WS available).
13:04 Division 2 (4163) cross tied to Unit 2, IA DG shutdown and placed in standby. .
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Unit 2 TBCCW system started to support air compressor operation, Unit 2 SAC started.
13:06 RCIC in full flow test mode (not injecting into reactor),
13:12 SRV.U opened.
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13:14 SRV U closed.
RCIC started injection mode.
13:16 SRV A opened. Began sequencing for cycling SRVs.-
,
13:18 C suppression chamber to drywell vacuum breaker opened, as i expected due to SRV and RCIC adding inventory to suppression pool.
13:21 SRV A closed.
13:22 C vacuum breaker closed.
13:35 l.GA-02 entered. High temperature in the main steam line tunnel.
13:45 Control transferred to technical support center (TSC).
13:53 Ring bus restored to normal, oil circuit breakers (OCBs)L 9-10 and 10-11 closed.
13:54 SRV B opened.
13:55 SRV B closed.
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Enclosure 4 8 Sequence-of-Events ]
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13:57 SRV C opened.
14:00 - Maximum suppression pool temperature identified was approximately 124*F. ,
14:00: 14 8 vacuum breaker opened. >
14:01:27 C vacuum breaker opened.
14:01:49 SRV C closed.
14:02 RCIC in injection mode. (data lost as to when RCIC stopped )
injecting between 13:14 and 14:02)
Unsuccessful attempt to open D SRV. ;
i 14:03:16 C vacuum breaker closed. >
14:03:55 SRV E opened. y 14:03:58 C vacuum breaker opened.
14:04:11 B vacuum breaker closed.
14:04:31 Instrument air pressure normal.
14:04:33 RCIC in full flow test mode. '
14:04:49 SRV E closed.
.,
14:04:54 C vacuum breaker closed. i
14:05:20 RCIC in injection mode. '
14:08:25 SRV F opened. i I
RCIC in full flow test mode, 14:10:34 SRV F closed. '
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14:13:36 SRV~G opened.
]
14:16 RCIC 'in injection mode. !
500 psig low pressure emergency core' cooling system (ECCS).
interlocks cleared,-reactor pressure at 500lpsig.
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Enclosure 4 9 Sequence-of-Events 14:16:59 RCIC in full -flow test mode.
RCIC check valves appeared to have stuck open. -Sequence of ,
events recorder showed that IE51-F013 discharge valve was closed but there was no computer entry for valves F065 or.F066.
B vacuum breaker opens.
14:17:36 C vacuum breaker opens. ,
14:17:40 RCIC in injection mode.
14: 19 56 B vacuum breaker closed.
14:23:03 C vacuum breaker closed. ,
14:23:19 SRV G closed. .,
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14:33:50 SRV H opened.
14:37:11 SRV H closed.
14:45:23 SRV J opened.
,
14:50:20 SRV J closed.
14:54 Temporary power to fuel pool cooling (FC).
Unit 2 FC system started. !
15:03:24 RCIC in-full flow test mode.
15:03:45 SRV K opened.
RCIC'in injection mode.
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15:08:19 i
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15:15:22 SRV K closed.
15:20:39 SRV L opened.
15:20:54 RCIC in full flow test mode.
15:25:07 RCIC'in injection mode. ,
15:27:21- SRV L closed.
15:43:17 SRV H opened. ,
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15:47 Started turbine building ventilation. .1
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Enclosure'4 -10 Sequence-of-Events
-15:53:08 RCIC in injection mode. (RCIC data lost between-modes)' !
16:25:22 SRV N opened. l 16.:25:40 SRV H closed.
16:26:44 RCIC in full flow test mode.
i 16:33:40 RCIC in injection mode. ;
16:36:37 SRV M opened.
!
16:38:28 SRV H closed (position indications problems noted due to low ;
accumulator pressure not fully opening valve). '
,
16:44:00 SRV N closed (position indications problems noted due to low accumulator pressure not fully opening valve).
l i 16:53:45 RCIC injection valve closed. !
.$
17:00 -
.
TSC directed automatic depressurization system (ADS) '
accumulators to be used for SRV operation. ,
17:04:07 SRV R opened (equipment operator opening SRVs using ADS air from-auxiliary electric room in communication with the control- room)
l (ADS valves are, C, D, E, R, S, U, and V.)
!
17:08:38 Primary containment pressure high; alarm, I psig. 3
17:11:40 Low pressure core spray'(LPCS) pump manually started.
ti ,
17:12:05 LPCS injection valve open, for level control. 1 i
17:14:58 SRV. C closed (dat'a lost on when it _ had ' opened).
17:15:45 LPCS injection valve closed. :
i 17:29:15 LPCS injection valve opened. l 17:29:42 SRV R closed. S
!
17:38:12 LDCS injection valve closed.
ll 17:43:46 SRV Sl opened.
j;1, l'7.: 521 to LPCS injection valve opened and closed to maintain level. -!
18:06 J l
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t Enclosure 4 11 Sequence-of-Events '
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i 18:06:57- ADS S accumulator air pressure low. j 18:06:58 SRV S closed. '
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18:20 5RV U opened. 'I 18:35 LPCS' injection valve opened. i ,
18:38 SRV U closed. '
18:39 LPCS injection valve closed.
18:42 SRV U opened.
?
SRV U closed. '
18:47 SRV U opened.
18:49- SRV U closed. ;
18:57 SRV V opened. -
ADS V accumulator low pressure alarm.
19:07 B RPS bus- re-energized through temporary alternate feed i
'19:16 LPCS injection valve opened. ;
19:17 ADS V accumulator low pressure alarm cleared. e
SRV V closed, a
ADS V accumulator low pressure alarm received. !
19:20:08 LPCS injection valve closed.
19:23 Drywell instrument air crosstie to station instrument air established. Regulator supply alarm cleared. '
19:24 - Drywell IN containment inlet isolation valve opened. Low- ,
pressure accumulators for SRV started recharging. l
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19:26 A/B/C/D MSIV accumulators normal. pressure. 3
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i 19:27 All drywell:lN isolation valves open. j
19:28 Reactor building closed cooling water isolation valves open. l
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Enclosure 4 12 Sequence-of-Events 19:31 CM isolation valves open.
19:33:20 ADS V accumulator low pressure alarm reset.
19:36:26 SRV A opened.
19:50 RT isolation valves opened.
19:51 RT discharge to the main condenser flow path established through 1G33-F034 valve.
19:52 IG33-F034 closed 19:53 RCIC injection valve opened.
,
19:54 RCIC injection check valve IE51-F066 closed.
RCIC injection valve closed.
RCIC manually tripped.
20:00 LPCS injection valve closed. ,
20:05 SRV B opened.
20:10 ~ RT was on line.
20:11 LPCS injection valve opened - Indications of testable check valve indication problems.
20:13 LPCS injection valve closed.
20:16 LPCS injection opened. :
!
20:17 LPCS injection valve closed.
20:23 LPCS injection valve opened.
SRV 5 accumulator air press normal. l
20:25 RCIC steam pressure low, reactor pressure dropped to approximately 57 psig. )
LPCS injection valve closed.
20:32 to LPCS injection . valve opened and closed several times- to control 21:31 reactor water. level. .
21:25 CRD pump on,' suction lined up to condenser hotwell.
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Enclosure 4 13 Sequence-of-Events ,
21:27 Cycled vacuum breakers per surveillance due to SRV usage.
21:44 SCRAM reset.
'l; 22:11 SRV B opened. I 22:31 SRV A closed. !
SRV B closed. {
22:43 Suppression pool temperature dropped to less than-Il0*F ,
22:44 Temporary procedure change to LGA-03 to allow a loop of suppression pool cooling to be secured for establishment of-shutdown cooling had been approved and A RHR pump was . shutdown i to prepare A RHR' system for shutdown cooling.
22:45 SRV C opened. ;
Wednesday, September 15, 1993 ,
00:44 Shutdown cooling line temperature high alarm' received (indicative of line starting to warm up in preparation to establish shutdown cooling). :
03:30 - TSC informed of low oil level on RCIC. ;
04:40 Recirculation pump suction valve IB33-F023A failed to close on first' attempt, closed on second attempt.
04:59 A RHR pump on - lines were sufficiently warmed and shutdown i cooling established.
'
09:34 SRV C closed.
. 09:48 Eulk sunpression pool temperature normal,105*F.
10:46 Suppression pool bulk temperature normal Division 2..
Suppression pool bulk temperature . normal Division 1.
11:03 11:50 3erating condition 4,' cold shutdown reached.
LGA-01 was exited.
13:18 to 13:25 Drywell personal access. hatch alarms - . interlock'. checked.
13:20 Unit 2 reactor building ventilation was' started.
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Enclosure 4 14 Sequence-of-Events 13:22 Unit I reactor building ventilation was started. .
.
13:30- Exit LGA-02. Reactor building ventilation lowered main steam !
line tunnel temperature within limits.
- i 14:24 LPCS pump shutdown. i 15:05 First Attempt to close in UAT/ main power transformer' breaker for. ;
backfeed/ restoration of unit power unsuccessful - Redundant ;
switch left in pull. to lock. .;
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15:15 UAT energized - power available. i 16:44 Division 14160 fed from UAT. '
16:48 Bus 151 picked up, along with 480 volt sub-busses. l
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16:48 ALERT terminated. ;
16:56 Bus 152 picked up, along with 480 volt sub-busses.
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Area radiation monitors restored.
16:58 NARs phone call for event termination, 17:05 TSC secured.
Thursday, September 16, 1993 19:40 - Exit LGA-03. Suppression pool level returned to normal, i
During the event, the sequence of events recorder memory became full'several i times, which resulted in event data being lost. '
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Indicates approximate times.
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Enclosure 5 Exit Attendance
!
Commonwealth Edison Company (Ceco)
W. P. Murphy, Site Vice President, LaSalle Station J. V. Schmeltz, Operations Manager i J. W. Gieseker, Site Engineering and Construction Manager .
C. E. Sargent, Support Services Director M. L. Reed, Technical Services Superintendent M. Santic, Maintenance Superintendent J. E. Lockwood, Regulatory Assurance Supervisor J. A. Miller, Station Support Engineering Supervisor R. Ragan, System Engineering Supervisor J. H. Atchley, Senior Operating Supervisor T. Blackmon, Corporate Emergency Preparedness Supervisor J. Bell, Maintenance Supervisor R. Christensen, Human Factors Supervisor .
R. Dillon, Security Supervisor J. Bur;.s, Regulatory Performance Administrator i P. J. Leheney, Training Instructor W. Kirchhoff, Site Engineering Station Support l J. Houston, Emergency Preparedness Coordinator '
D. R. Carlson, Coordinator .4 M. R. Doughery, Secretary '
R. W. Coen, Performance Monitoring and Improvement T. flauman, Master Mechanic M. Cooper, Regulatory Assurance '!
G. Master, Employee ?
T. Hammerich, System Engineer Mentor Public J. A. Hustis, The Daily Times :
J. Roman, Illinois Resident Inspector R. Schulz, Section Chief, Illinois Resident Program R. R. Wight, Manager, Office of fluclear Facility Safety U. 5, fluclear Regulatory Commission (f4RC)
W. L. Forney, kting. Director, DRS, RIII J. D. Wilcox, Jr., Team l mder, f4RR !
M. J. Miller, Assistant N m Leader, Resident inspector, Rill l R. A. Winter, Reactor Inspector, R111 '
J. H. fieisler, Reactor Inspector, RIII
.
R. A. Spence, Reactor System Engineer, AE00 A. J. Kugler, licensing Project Manager, f4RR )'
H. J. Miller, Deputy Administrator, RIII G. E. Grant, Director, DRS, RIII '
J. E. Dyer, Assistant Director, 11RR P. S. Koltay, Section Chief, 11RR l R. L. Hague, Section Chief, DRP, P,Ill l D. E. Hills, Senior Resident _ Inspector, RIII ;
J. L. Kennedy, Project Manager, f4R !
R. J. Strasma, Senior Public- Affairs Officer, RIII l l
_