IR 05000387/1987009
| ML17146A836 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 06/11/1987 |
| From: | Wiggins J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17146A835 | List: |
| References | |
| 50-387-87-09, 50-387-87-9, 50-388-87-09, 50-388-87-9, IEB-80-01, IEB-80-1, IEB-85-002, IEB-85-003, IEB-85-2, IEB-85-3, NUDOCS 8706220504 | |
| Download: ML17146A836 (28) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report -Nos.
50-387/87-09.
50-388/87-09 Docket Nos.
50-387 50-388 License Nos.
NPF-14 NPF-22 Licensee:
Penns lvania Power and Li ht Com an 2 North Ninth Street Allentown Penns 1 vania 18101 Facility Name:
Sus uehanna Steam Electric Station
~ Inspection At:
Salem Townshi Penns lvania Inspection Conducted:
A ril
1987 - Ma
1987 Inspectors:
L.
R. Plisco, Senior Resident Inspector J.
R. Stair, Resident Inspector Approved By:
J.
T. Wiggi Chief, Reactor Projects ection 1, RP Date Ins ection Summar
R protection, physical security, plant events, previous inspection findings, surveillance and maintenance.
Results:
One unplanned automatic scram occurred on each unit due to equipment failures (Details 3.3 and 3.6);
one forced shutdown was caused by an LLRT fail-ure (Detail 3.5);
a fire occurred in an offgas guard bed during a
reactor startup (Detail 3.4);
the torque switch setting was improperly set on a con-tainment isolation valve limitorque operator (Detail 5.3);
and several proced-ural and labeling deficiencies were identified during surveillance procedure reviews (Detail 5.2).
No violations were identified.
8706220504 870612 PDR ADOCK 05000387 G
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TABLE OF CONTENTS 1.0 Followup on Previous Inspection Findings
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2.0 Routine Periodic Inspections
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2. 1 Operational Safety Verification
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2.2 Station Tours
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3.0 Summary of Facility Activities
.
3. 1 Unit 1 Summary.
3.2 Unit 2 Summary.
3.3 Reactor Scram Oue to Feedwater Control System (Unit 1).
3.4 Fire in the 'B'ffgas Guard Bed (Unit 1)
, 3.5 Reactor Shutdown Oue to Failed LLRT (Unit 1).
3.6 Reactor Scram Oue to MSIV Closure (Unit 2).
4.0 Licensee Reports
.
4. 1 In-Office Review of Licensee Event Reports.
4.2 Onsite Followup of Licensee Event Reports
.
4.3 Review of Periodic and Special Reports.
4.4 Part 21 Report Followup
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Failure
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5.0 Sur veil lance and Maintenance Activities 5 ~ 1 Monthly Surveillance Observations
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5.2 Review of Periodic Channel Check Surveillances.
5.3 Improper Torque Switch Setting on HPCI Isolation 5.4 Monthly Maintenance Observations.
6.0 IE Bulletin and Information Notice Followup 7.0 Management Meetings
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DETAILS 1.0 Followu on Previous Ins ection Findin s
1.1 Closed Unresolved Item 387/83-03-01:
Com arison Between Instruments Outside the Control Room and Inside the Control Room was Not Bein Performed Since Parameters Were Not Bein Recorded in the
~Lo Closed Unresolved Item 387/84-07-04:
Failure of 0 erator s to Notice Chan es in Ma'or Plant Parameters In February 1983, the inspector reviewed operating surveillance pro-cedure S0-100-006, Shi ftly Survei1 lance Operating Log, to determine whether Technical Specification Channel Checks were being properly performed.
The inspector noted that some channel checks were per-formed in the control room while others were performed outside the control room and that comparisons between instruments outside the control room and inside the control room were not being performed.
In addition, individual parameters were not being recorded in the log, preventing adequate supervisory review of the results.
In March 1984, the inspector expressed concern that the operations survei llances did not provide for operator trending of plant para-meters nor enhance operator or supervisor awareness of plant condi-tions.
The inspector stated that the lack of logging actual values, in addition to precluding trending, prevented supervisory evaluation of the operators comparison among independent instruments monitoring the same parameter.
In addition, two events highlighting the need for improved logging, trending and awareness of plant parameters were noted.
The inspector conducted a
thorough review of the current Channel Check procedures and discussed the operating philosophy with station management.
Based on this review, which is discussed in Detail 5.2, these items are closed.
Several new concerns will be further re-viewed as stated in Detail 5.2.
1.2 Closed Unresolved Item 388/84-34-25
- Review Surveillance Procedures That Enter Switch ear Cubicles for Ade uac Following the Unit 2 loss of AC power event of July 26, 1984, it was determined that all procedures should be reviewed which may require entry into 480V, 4KV, 13.8KV, 250VOC, 125VOC, and diesel generator cubicles to ensure adequate controls were in place to prevent recur" rence of inadvertent knifeswitch operatio.
Initial corrective action by the licensee included revision of admin-istrative procedures to require independent verification for tempor-ary blocking of electrical circuits and pre-test walkdowns to be accomplished prior.to conduct of a major startup test.
These changes were previously reviewed in Inspection Report 50-388/85-10 and found acceptable.
Further corrective actions completed by the licensee included:
The preventive maintenance (PM) program was reviewed regarding the adequacy of PM's which enter switchgear cubicles, The breaker removal procedures have been developed and,incorporated subsequent to the loss of AC power event.
The electrical maintenance surveillance procedures were reviewed and none required changes.
The inspector reviewed the licensee's documentation related to this event action item and found it acceptable.
1.3 Closed Unresolved Item 387/85-01-01: Deficiencies in MSIV-LCS Procedures and FSAR Oescri tion In February 1985, a
system walkdown and procedure review of the Unit 1 Main Steam Isolation Valve - Leakage Control System (MSIV-LCS) was conducted.
Several procedural and FSAR deficiencies were identified.
Portions of the licensee's corrective actions were previously re-viewed in Inspection Report 387/86-09.
In addition, the inspector reviewed the following corrective actions:
The instrumentation on control room panels 1C644 and 2C644 was relabeled to include the instrumentation identification numbers, and is now consistent with the operating procedures.
Engineering Work Request (EWR)
MIS 85-0547 was completed and it determined that the pressure sensor setpoint of 1.0 psig for the outboard blower suction valve interlock is acceptable.
An FSAR change request was is'sued to properly reflect the setpoint.
Plant Modification PMR 83-112 was completed on Unit 1 during the Second Refueling Outage.
The modification documented the as-built condition of flow elements FE-13954 and FE"13959 and up-dated the associated drawings.
The five-minute isolation timers were replaced on Unit 2 with fifteen-minute timers under PMR 85-3062 during the First Refuel-ing Outage.
The timer setpoints were changed
'from three to thirteen minutes to allow more time for system flow to stabilize below 80 SCFH before an isolation occurre The inspector reviewed the panel modifications and FSAR changes and verified that the corrective action had been satisfactorily completed.
1.4 Closed Unresolved Item 387/85-04-01:
Discre ancies Identified in Concrete S ecifications In January 1985, a review of Specification C-1042, Concrete Construc-tion, determined that the specification required clarification con-cerning winter concrete curing temperatures
<and concrete repair inspections.
On winter concrete curing, Specification C-1042, Section 4. 15.2.C stated, in part
"The concrete surface curing temperature shall be between
F and 60 F".
Concrete placement C2.G1, placed on January 29, 1985, exceeded
F during the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of curing.
Nonconformance (NCR)
No.
was issued on January 30, 1985, due to the uncontrollable heat of hydration "of the concrete placement that could not be lowered by reducing the temperature of the enclosure within the specified range.
NCR No.
was closed on February 27, 1985, and was dispositioned
"use-as-is".
The disposition was based on an approved Design Change Request (DE/CD C-51)
which was issued to clarify the intent and meaning of the Specification.
The DE/CD eliminated the 60'F temperature requirement, stating that when the temperatures excedes 60'F, the only requirement is to allow the concrete to cool until it is within the required range.
On repair of concrete, the Specification and the implemented gC pro-cedure provided no definition or requirement for a qualified inspec-tor to verify that chipping had removed all 'unsound concrete.
In response, the licensee provided Dravo Constructors, Inc.
(DCI) Con-struction Site Procedure (CSP)
5.2,
"Forming, Placing, Finishing and Curing of Concrete for Safety Related Work", and CSP 5.10,
"Concrete Patching and Repair".
CSP 5.2, paragraph 16.2 states that repair of defects is to be carried out in accordance with CSP 5. 10, and that repair" and patching of surface defects shall not commence until an inspection of the defective surface has been made by gC.
I'n addi-tion, CSP 5. 10 was revised to prov'ide clear guidance on,repairs.
The licensee's revised procedures and NCR documentation were reviewed
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for adequacy and found acceptabl Closed Part 21 Re ort 387/85-36-02: Air Receiver Tanks for Fifth Oi esel Generator Oefici ent On December 23, 1985, a preliminary
CFR 21 notification was re-ceived by the NRC from Applied Engineering Corporation (APCO) stating that the air receiver tanks for the Fifth Diesel Generator Project were deficient.
Specifically, calculations for two six-inch inspec-tion nozzl.es had not been performed as required by Section III of the ASME Code and therefore the required reinforcements for the two open-ings were missed during the original design and manufacture.
To correct the deficiency, the licensee installed reinforcement pads to the six-inch inspection openings on the four air start receivers.
The repairs were completed on June 8,
1986.
The repairs were per-formed under the licensee's ASME Section XI program utilizing a re-pair plan developed by Morrison-Knudson (M-K) and APCO.
A hydro" static test was performed following the repairs.
The inspector reviewed the Section XI Code Repair Form, the instal-lation procedure and the APCO guality Assurance requirements to verify satisfactory completion of the repairs.
Closed Unresolved Item 387/87-02-02
Emer enc Diesel Generator Interde endence Testin Followin Fifth Diesel Generator Installation During a review of the properational and startup test procedures for the fifth diesel Generator modification, the inspector noted that all EDG testing addressed in Regulatory Guide 1. 108, "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants",
Revision 1,
August 1977, was adequately ad-dressed in the test procedures with the exception of the testing dis-cussed in Section 2.b of the Regulatory Guide.
This section requires in part, that during testing subsequent to any plant modification where EDG unit interdependence may have been affected, a test should be conducted in which redundant units are started simultaneously to help identify certain common failure modes undetected in single EOG unit tests.
This testing requirement is also included in both unit's Technical Specifications.
The licensee stated that this testing requirement would be reevaluated prior to completion of the preopera-tional and surveillance test procedure.
Reevaluation of the testing requirement by the licensee concluded that the fifth diesel generator modification, by design, was not a
modification which could affect diesel generator unit interdepend-ence
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Unit interdependence was maintained by two separate transfer switches between the normal and fifth diesel generator control cir-cuits.
Therefore, the additional testing is not require The inspector reviewed the transfer scheme drawings and discussed the modification installation with licensee engineers and verified that unit interdependence was maintained.
The administrative controls which ensure that the transfer switches are properly positioned will be reviewed further during routine inspection activities.
2.0 Routine Periodic Ins ections 2.1 0 erational Safet Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with LCOs.
Instrumentation and recorder traces were observed and the status of control room annunciators was reviewed.
Nuclear Instrument panels and other reactor protection systems were examined.
Effluent
. monitors were reviewed for indications of releases.
Panel indica-tions for onsite/offsite emergency power sources were examined for automatic operability.
Ouring entry to and egress from the protected area, the inspector observed access control, security boundary integ-rity, search activities, escorting and badging, and availability of radiation monitoring equipment.
The inspector reviewed shift supervisor, plant control operator and nuclear plant operator logs covering the inspection period.
Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (SOORs),
and gA nonconfor-mance reports'he inspector observed several shift turnovers during the period and routinely attended work planning meetings.
In addi-tion, the inspector conducted a midnight shift inspection from 2:00 a.m.
to 6:00 a.m.
on May 6, 1987, and weekend coverage from 9:00 a.m.
to 12:00 p.m.
on April 25, 1987.
No unacceptable conditions were identified.
2.2 Station Tours The inspector toured accessible areas of the plant including the con-trol room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, diesel generator buildings, ESSM pumphouse, the security control center, and the plant perimeter.
Ouring these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to pro-cedures, radiological controls and conditions, housekeeping, secur-ity, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipment.
No unacceptable conditions were identifie.0 Summar of Facilit Activities 3.1 Unit 1 Summar On April 2, 1987 at 7:26 a.m.
an automatic reactor scram from 100 percent power occurred due to a
reactor vessel high water level transient.
The cause of the transient was a component failure in the feedwater level control system which inserted a maximum demand signal to the reactor feedpumps.
The unit was cooled down and entered Con-dition 4, Cold Shutdown, at 5:30 p.m.
on April 2.
Following comple-tion of troubleshooting and repairs, the unit returned to criticality at 2:20 p.m.
on April 11, and full power was reached on April 14.
(See Detail 3.3)
During the reactor startup on April 11, a
radwaste operator noticed that the 'B'ffgas Guard Bed temperature indicator was pegged high.
The bed was then removed from service and isolated since the high temperature was an indication of a possible fire.
The 'A'uard Bed was placed in service to continue the startup.
Further investigation concluded that the charcoal bed caught fire due to an undetermined cause.
(See Detail 3.4)
3.2 On April 15 at 11: 15 p.m.
a manual shutdown of Unit 1 from 100 per-cent power was commenced after the failure of a Local Leak Rate Test (LLRT) on the drywell purge exhaust line.
During the six month LLRT the licensee was unable to establish test pressure between the isola-tion valves, indicating excessive leakage on one or more of the valves.
The shutdown was initiated to meet the containment integrity requirement of the Technical Specifications.
The reactor was manu-ally scrammed from 20 percent power at 2:45 a.m.
on April
and brought to Cold Shutdown.
Following completion of repairs, the unit achieved criticality at 11:50 p.m.
on April 18 and returned to full power on April 21.
(See Detail 3.5)
The unit operated at or near full power for the remainder of the inspection period.
Unit 2 Summar On April 16, 1987 at 8:30 a.m. Unit 2 tripped from 100 percent power due to a Main Steam Isolation Valve (MSIV) closure.
The licensee's post-trip investigation could not determine any problems in the iso-lation circuitry and concluded that spurious actuations of the steam line low pressure switches caused the isolation.
Following comple-tion of the forced outage, the unit returned to criticality at 5:20 a.m.
on April 25, 1987 and full power was reached on April 29.
(See Detail 3.6)
The unit operated at or near full power for the remainder of the inspection perio.3 Reactor Scram Due to Feedwater Level Control S stem Failure Unit
On April 2, 1987 at 7:26 a.m.
an automatic reactor scram from 100 percent rated power occurred due to a
high reactor vessel water level.
The high water level was caused by a fai lure in the feedwater level control system which initiated a near-instantaneous ramping up of the feedwater pumps.
The feedwater master controller output, while in automatic and 3-element control, ramped rapidly from the normal steady-state level to maximum.
As a result of this increase in demand the reactor feedpumps increased flow to the vessel, and level increased from the steady state value of 36 inches to the high level trip of
inches in approximately
seconds.
The turbine trip initiated the reactor scram.
All systems responded as designed following the scram, including automatic initiation of the RCIC sys-tem.
Four SRV's lifted during the transient.
Investigations by I8C personnel following the scram determined that the most likely mode of failure to cause the control system response was a drop in power to the dynamic compensator due to a failure on the dynamic compensator card.
The dynamic compensator card filters the control signal preventing rapid changes in demand.
A new card was installed.
Extensive troubleshooting and bench testing could not identify any further problems.
During the forced outage, repairs were also completed on MSIV posit-ion indications, vacuum breaker position indications, various valve packing adjustments, the 1B RHRSW pump was replaced, and HPCI and RWCU local leak rate tests were conducted.
Following completion of the repairs, the unit was restarted and achieved criticality at 2:20 p.m.
on April 11.
Full power was reached on April 14.
A similar feedwater transient occurred on November 9, 1983 on Unit 1, again resulting in a
Investigation following this earlier event determined that the root cause was the 1/3 element mode switch circuit which was replaced.
The inspector monitored the post-trip review process and observed portions of the outage activities, and no unacceptable conditions were noted.
3.4 Fire in the 'B'ff as Guard Bed Unit
On April 11, 1987 in anticipation of returning Unit 1 to service, purging of the 'B'ffgas Guard Bed was commenced in order to remove any absorbed moisture.
At 9:30 p.m.,
12 1/2 hours later, the purge was terminated and the offgas process stream was introduced into the
'B'uard Be At 4:00 a.m.
the following morning, a radwaste operator noticed the
'B'uard Bed local temperature indication pegged high (>150'F),
indicating the possibility of a fire in the Guard Bed.
Several rad-waste operators entered the Guard Bed room and felt heat emanating from the bed.
At 4:40 a.m.
the bed was removed from service, iso-lated and the 'A'uard Bed was placed in service.
A pyrometer skin temperature of the 'B'uard Bed was measured at 386 F.
Approxi-mately one hour later, surface pyrometer readings of 450'F at the bottom and 250'F at midpoint of the Guard Bed were observed.
Tempor-ary wide range instrumentation was installed at the top and bottom of the Guard Bed in order to monitor the guard bed temperature more closely.
At 5:47 a.m.,
temperature readings of 1100'F at the bottom and 1000 F at the top of the Guard Bed were obtained confirming that a fire existed.
Preparations were initiated to supply nitrogen cool" ing to the 'B'uard Bed, but was not used when further temperature readings exhibited a
slow, but steady decrease.
By 8:30 p.m. April 12, the internal temperatures had dropped to 525 F.
Twelve days later, on April 24, the Guard Bed tank was opened and charcoal removal commenced.
Ouring charcoal removal internal temper-atures increased and water spray was used to reduce the temperature excursion and prevent flareup.
The charcoal was placed in metal drums, topped with a water layer and sealed for disposal.
The 'B'uard Bed was removed from service, isolated, and replaced by the 'A'uard Bed fairly early in the event, therefore no impact on the downstream main charcoal absorber beds or plant operations occurred.
Removal of the charcoal was performed by vacuum, while using a water spray to control dust and reduce temperatures.
Oe-tailed recovery procedures were developed by the plant staff engi-neer's with input from Health Physics, safety, fire protection and construction personnel.
The licensee verified no increase in turbine building exhaust activity by a review of the turbine building stack monitor strip chart.
Currently, the vessel and associated piping are being reviewed to ensure that their integrity was not compromised by the event.
The licensee has not determined the root cause of the event, how-ever, it appears that the Guard Bed air flow rate coupled with another undetermined mechanism resulted in lowering the charcoal ignition temperature.
The Guard Bed was purged for
1/2 hours using air at approximately 330 F.
Samples of the charcoal removed from the Guard Bed and samples of the replacement charcoal were sent off-site and tested for ignition temperature characteristics.
Re-sults have shown that iron present in the samples lowered the igni-tion temperature to approximately 680'F, in localized spots, at an air flow of
SCFM.
The licensee is presently investigating the
mechanisms which could reduce the ignition temperature of the char-coal to approximately 330'F.'otential mechanisms being considered are contaminants, reduced air flow, spontaneous heating, prolonged heating at 300 F temperatures,,
repeated heating to 300 F, or a
corn" bination.
A spectographic analysis of the charcoal samples is also being performed to determine if any other element was present in the charcoal.
This is the first occurrence of this type at SSES, however, Perry Nuclear Station had a similar occurrence in June 1986 when a fire in their main charcoal bed absorbers occurred.
Licensee engineers were aware of the Perry event and used some insight gained from this in-formation to limit the consequences of the event.
However, the licensee was not aware that reduced air flow rate through the char-coal bed affects ignition temperatures of the charcoal although this fact was noted in Perry's report.
As a result of the licensee's actions in switching Guard Beds and isolating the 'B'uard Bed, no impact on plant operations occurred with the exception of eliminating the redundancy of Guard Beds.
Since the Guard Beds are in separate rooms in the radwaste building, a fire in one guard bed would not affect operation of the redundant guard bed or any other portion of the offgas system once isolated.
Prior to returning the 'B'uard Bed to service, vessel integrity will be determined, new charcoal added, the root cause of charcoal ignition determined, to assure ignition will not recur and the potential for occurence within the remaining 3 Guard Beds assessed.
The inspector reviewed and discussed the event and analysis with the licensee's cognizant engineer and operators to determine the adequacy of the licensee's actions to limit the effect on plant operation and safety and to prevent recurrence.
3.5 This item is unresolved pending review of the root cause analysis and corrective actions to prevent recurrence (387/87-09-01).
Reactor Shutdown Oue to Failed LLRT Unit
At 6:00 p.m.
on April 15, 1987, Technical Specification 3.6. 1.8 was entered when the required test pressure of
psig could not be established between the containment purge exhaust valves while at-tempting to conduct the six-month LLRT.
Oue to the excessive amount of leakage, and not being able to determine which valve was causing the leakage, the licensee decided primary containment integrity could not be verified and a
manual shutdown of Unit
was commenced at 11:03 p.m. in order'to investigate and effect repairs.
At 2:45 a.m.
on April 16, the reactor mode switch was placed in shutdown at 20K powe During the three day forced outage the licensee discovered that the resilient rubber seal on the inboard purge exhaust valve had three circumferential tears.
The seal was replaced and the post-mainten-ance LLRT was performed with acceptable results.
However, the valve was subsequently stroked five times and the leak rate increased to an unacceptable amount.
The retaining ring which holds the seal to the valve disc had to be retightened in order to obtain an acceptable leak rate.
The valve was again stroked five times with acceptable results, Condition 2 was entered at 9:02 p.m.
on April 18, and the unit synchronized to the grid at 1:28 p.m.
on April 19.
Since both the outboard purge exhaust valve and its bypass valve exhibited ac-ceptable leak rate test results, containment integrity was not vio-lated.
One previous failure of this penetration took place on December 21, 1984, when a nitrogen makeup line overpressurization event occurred.
The subsequently failed LLRT on the associated drywell and suppres-sion chamber purge valves resulted in Unit 1 being shutdown to effect repairs.
Consequently, the suppression chamber outboard isolation valve rubber seal was found to be scarred and leaking.
The licensee determined that the damage to the seal was unrelated to the overpres-surization event, replaced the seal and performed the LLRT with ac-ceptable results.
The inspector discussed the incident with operations and technical staff members, reviewed Significant Operating Occurrence Report (SOOR) 1-87-114, LLRT results for this event, and Mork Authorizations (WAs)
S73957 and S73967.
The inspector also examined the damaged rubber seal which had been replaced.
No unacceptable conditions were noted.
3.6 Reactor Scram Due to MSIV Closure Unit 2 At 8:20 a.m.
on April 16, 1987, an unplanned automatic Main Steam Isolation Valve (MSIV) closure occurred, initiating a reactor scram from 100 percent power.
The MSIV isolation and subsequent reactor scram resulted in a loss of normal feedwater and a decrease in reac-tor water level, causing automatic initiation of the High Pressure Coolant Injection (HPCI)
and Reactor Core Isolation Cooling (RCIC)
Systems.
The reactor recirculation pumps also tripped as designed due to the low water level condition of -38 inches.
Mater level sub-sequently increased to the high level setpoint as a result of con-tinued makeup from the reactor feedpumps, swell from the recircula-tion pump trip, and the HPCI and RCIC injections, causing automatic trips of the HPCI, RCIC and the reactor feedpumps.
Reactor pressure slowly increased following the MSIV closure and resulted in two auto-matic lifts of one safety relief valve.
The operators then manually opened one SRV per procedure to reduce reactor pressure and minimize SRV cycles.
The RCIC system was operated in the full flow test mode for reactor pressure control.
The plant was placed in cold shutdown at 10:00 a.m.
on April 1 Licensee investigation into the cause of the scram could not deter-mine the root cause of the MSIV closure with certainty.
Analysis of the post-trip data and operator interviews confirmed that MSIV iso-lation logic channel
"C" tripped, followed by a trip of channel
"B" about 7 seconds later.
Tripping of these two channels satisfied the minimum isolation logic, and the MSIV isolation was initiated.
The most probable cause of the MSIV isolation was concluded to be spur-ious actuation of the two associated main steam line low pressure switches (PSL-B21-2N0158
& C).
The switches are located in a
high traffic area in the Turbine Building corridor where it is suspected that they may have been actuated by inadvertently bumping or vibra-tion and actuated causing the event.
The switches are Bourdon type instruments (Barksdale)
which have been observed to be highly suscep" tible to erroneous actuation in the past.
The four main steam line low pressure switches are mounted on adjacent steel support stan-chions.
A review of the pre-transient data was completed which showed that all MSIV isolation logic parameters were at normal values with no observable trends.
To prevent recurrence, the licensee completed the following actions prior to startup of the unit:
All sensor inputs to the MSIV isolation logic were verified to be functioning properly.
One main steam line low pressure switch (PSL-B21-2N015B)
was replaced.
This switch had previously given spurious signals in November 1986, when a
hose was draped over its sensing line.
A protective steel unistrut barrier was constructed around the four Unit
MSL low pressure switches in the Turbine Building under modification PMR 87-9096.
A roped barrier was installed around the four Unit
MSL low pressure switches pending a
permanent installation ~f the same modification performed on Unit 2.
Temporary monitoring equipment was installed to monitor the status of the 'C'ain steam line switch and associated logic channel.
A review of the previous occurrences by the licensee found seven other occasions documented in which the main steam
'line pressure switches have caused or have been suspect in causing MSIY isolation logic actuation'wo of the events were believed to have been caused by bumping the switches, one event was attributed to a temporary hose dropped over instrument tubing to the switches and the remaining four events were determined to be due to spurious actuations of the switches, probably vibration in the sensing line Due to the Barksdale pressure switches proven sensitivity to external disturbances, the licensee has ini'tiated modification requests to relocate the switches and to add time delays in the trip circuitry.
Previous attempts at resolution of the problem included lowering of the device setpoint to make the instrument less susceptible to steam line flow induced vibration.
The proposed modifications would in-stall a
time delay in the actuation circuit to preclude spurious actuations.
The other modification would move the switches from the top of the four foot stanchion to a location on the adjacent wall.
During the post-trip review process the licensee determined that one MSIV had closed in less than three seconds and 'that there were two potential occurrences of a reactor vessel heat-up rate in excess of the 100 degrees/hour Technical Specification requirement.
During the routine scram data review, an STA noted that the 'A'ut-board MSIV (HV-241-F028A)
had closed in less than the minimum re-quired time of three seconds per the GETAR's computer generated data.
Technical Specification requires the MSIV'
to close in more than three, and less than five seconds.
The other MSIV's closed within the required time period, and the 'A'SIV (HV-2F028A) closed in 2.96 seconds.
Further investigation by maintenance personnel discovered an oil leak at a
union on the MSIV actuator, which is believed to have caused the shorter than normal stroke time.
The leak was re-paired, the oil reservior was refilled, and the MSIV stroke time was adjusted to within its normal range.
Following the scram, the control room operators unsuccessfully at-tempted to restart the RWCU pumps in order to warm up the reactor recirculation loops.
The reactor recirculation loops had cooled significantly below bulk reactor coolant temperature following the automatic trips of the recirculation pumps and the RWCU pumps.
Elec-trical maintenance technicians found that the RWCU Supply Inboard Isolation Valve (HV-244F001) full open permissive was not available to allow pump start due to a problem with the valve limit switch.
A jumper was installed to permit pump startup and a
RWCU pump was re-started at about 12:30 p.m., four hours after the scram.
This four hour delay resulted in relatively large differential tem-peratures developing between the reactor core outlet, the reactor bottom head region and the reactor recirculation loops at a reactor water level of about
+35 inches.
Upon restart of the RWCU system, a
heatup transient of about 145'F/hr occurred in the reactor recircu-lation loops.
A review of reactor vessel temperature data indicated that the temperature transient on the vessel wall was well below the maximum heatup rate allowed by Technical Specifications (i.e.,
100'F in any 1-hour period).
The cause of the event was the startup and operation of the RWCU system at too high a flow rate (270 GPM) with greater than a
100 degree differential temperature between the recir-culation loop and vessel saturation temperature.
Furthermore, the
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'
RWCU system was unable to warm up the reactor bottom head region enough to meet the maximum reactor differential temperature limits for recirculation pump startup while maintaining reactor water level at its normal value of +35 inches.
This prohibited restart of the recirculation pumps to reestablish forced reactor coolant circula-tion.
The reactor core was adequately cooled at all times by virtue of the core being covered with normal water level.
Later during the plant cooldown, at 4:45 a.m.
on April 17, about twenty hours after the scram, a
heatup of the reactor bottom head region of 112'F occurred over a
15 minute period.
This heatup occur-red when reactor pressure was being lowered, using the main turbine bypass valves, resulting in a slight reactor level swell from the normal level of +35 inches.
When reactor level exceeded about
+38 inches, a natural circulation flowpath was established which caused mixing of the hot core outlet water with the cooler bottom head region water causing the rapid heatup.
Prior to the level increase the bottom head drain temperature was approximately 160 F colder than the vessel saturation temperature due to stratification.
The stra-tification was enhanced by the cold CRO water flow into that area.
As water level was allowed to increase, natural circulation began to occur as described in GE SIL 357, because the water level reached the bottom of the Predryer, which allowed a flowpath from the core area to the outside of the shroud.
In compliance with the Technical Specification LCO action statement, NPE performed an engineering analysis of the effects of both heatup events on the reactor coolant system structural integrity.
The analysis concluded that the structural integrity of the reactor cool-ant system, including the reactor vessel, had not been compromised and that plant design limits were not exceeded.
In addition, several procedure changes were made which included issuance of a
new general operating procedure for each unit entitled G0-100(200)-011, Plant Cooldown Following a Scram.
Operator training will also be conducted to emphasize the effects of reactor level on establishment of a
natural circulation flowpath.
Ouring the forced outage corrective repairs were completed on a dry-well vacuum breaker operator and the HPCI inboard steam isolation valve.
On April 11, containment vacuum breaker PSV-25704El, located in the drywell, could not be stroke tested from the control room.
In accordance with Technical Specification surveillance requirements, all containment vacuum breakers were stroke tested following the scram and PSV-25704El again failed to stroke.
Maintenance during the forced outage found the vacuum breaker's test solenoid valve to be defective and it was replaced.
The vacuum breaker was then stroke tested satisfactoril Prior to the scram, the drywe1 1 sump unidentified leakage had been steadily incrasing from an initial value of 0.3 GPM on March 6,
)987 to 2.3 GPM on April 16.
Following the scram, a walkdown of the dry-well was conducted with reactor pressure at 560 psig.
The HPCI steam supply valve HV-255-F002 was observed to have a significant steam leak from the packing area.
The valve was repacked.
The inspector reviewed the applicable Significant Operating Occur-rence Reports, Event Notification Worksheets, Scram Report, post-trip data, Work Authorizations, and attended the startup PORC meetings on April 22 and 23, 1987.
No unacceptable conditions were identified.
The engineering evaluation on the two heatup events was provided "to NRC Region I for review by regional specialists.
The adequacy of the licensee's actions regarding the two heatup rate transients will
'emain unresolved pending completion of NRC review of the licensee's engineering evaluation (50-388/87-09-0)).
4.0 Licensee Re orts 4. 1 In-Office Review of Licensee Event Re orts The inspector reviewed LERs submitted to the NRC:RI office to verify that details of the event were clearly reported, including the accur-acy of description of the cause and adequacy of corrective action, The.
inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup.
The following LERs were reviewed:
Unit
"87-007 Loss of Power to Unit 2 Startup Transformer T-20
"87-008 HPCI Inverter Failure 87-009 Upper Relay Room Open Penetrations87-010, Entry Into LCO 3.0.3 to Perform 4KV Bus Degraded Voltage Relay Surveillance 87-011 Fire Barrier Not Properly Sealed 87-012 Entry Into LCO 3.0.3 to Perform 4KV ESS Bus Degraded Volt-age Relay Survey
""87-014 Manual Shutdown Per Technical Specification Due to Failed LLRT
"Further discussed in Detail 4.2.
""Further discussed in Detail Unit 2
- 87-006 Reactor Protection Actuation Oue to MSIY Automatic Closure 87-007 HPCI System Declared Inoperable Oue to a
Malfunctioning Steam Supply Valve
- "Further discussed in Detail 3.0.
- ""Previously discussed in Inspection Report 50-387/87-06; 50-388/
87-06.
4.2 Onsite Followu of Licensee Event Re orts For those LERs selected for onsite followup (denoted by asterisks in Detail 4. 1),
the inspector verified that the reporting requirements of
CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was adequately reviewed by the licensee, and that continued operation of the facility was conducted in accord-ance with Technical Specification limits.
The following findings relate to the LERs reviewed on site:
4,2.1 r
LER 87-007 Loss of Power to Unit 2 Startu Transformer T-20 Unit
At 3:55 a.m.
on March 6, 1987, a lightning arrestor at the site's
KV construction substation transformer failed, resulting in a momentary loss of startup transformer T-20.
The voltage transient affected a
number of systems on both units including initiations of the 'B'rain of SGTS and CREOASS.
Following the transient, the electrical distribu-tion system was returned to a
normal operating lineup and plant systems were restored.
During the transient, isolation of the Unit 1 5A Feedwater Heater Extraction Steam Line occurred due to a
solenoid fai lure.
This, in turn, caused a power excursion above 100 percent thermal power which had lasted for approximately
minutes and peaked at 102.8 percent thermal power until the licensee unisolated the extraction line.
The licensee
verified that no core thermal limits were exceeded and no effects on fuel performance appeared based on a review of off-gas 'radiation levels and reactor water chemistry re-sults.
A review of the power transient by reactor engi-neering personnel and licensed operators will take place to assure understanding of the event.
In addition, the 'B'GTS tripped approximately 3 minutes after it had auto-started due to a problem with the elec-tronics to the filter train differential temperature logic.
This logic includes a time-delay relay which trips the SGTS train if the SGTS heaters do not reaise the differential temperature about 10 F.
The problem occurs due to satura-tion of the electronics which prevents deenergizing the time-delay relay even though differential temperature has increased above the setpoint.
As the result of a similar occurrence which took place on April 21, 1987, the licensee is implementing a modification to the logic circuitry which will prevent tripping of the SGTS train by this time-delay relay; however, the modification was not implemented prior to the second event.
In order to prevent recurrence of the loss of 12KV distri-bution power, the licensee is planning to supply the 12.5KV site distribution from an alternate source =not susceptible to lighting arrestor failure.
LER 87-008 HPCI Inverter Failure Unit
At 8:00 a.m.
on February 23, 1987, the HPCI Inverter Fail-ure Status Light and the HPCI Out-of-Service annunciator were received in the Control Room.
Upon investigation, it was discovered that a capacitor in the HPCI Topaz Inverter ruptured, leaking oil into the HPCI panel and inverter, which caused loss of control circuit power for the HPCI pump.
The inverter was deenergized, HPCI declared inoper-able and an LCO entered.
Since oil was present, the licen-see contacted the supplier and was informed that the oil contained PCBs.
As a precautionary measure, the licensee disposed of the power supply and spilled oil in a hazardous waste drum, cleaned the area and posted
"Caution PCBs" signs.
A new power supply was installed and HPCI returned to service at 5:00 p.m.
on February 23, 1987.
Although this appears to be an isolated case, the licensee intends to inspect all Topaz Inverters and replace any capacitors found to be leakin.3 Review of Periodic and S ecial Re orts Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector.
The reports were reviewed to deter-mine that they included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems; and whether any information in the report should be classified as an abnormal occur" rence.
The following periodic and special reports were reviewed:
Monthly Operating Report - March, 1987, dated April 8, 1987.
Monthly Operating Report
- April 1987, dated May 15, 1987.
The above reports were found acceptable.
4.4 Part
Re ort Followu On April 15, 1987 the licensee notified the NRC persuant to
CFR Part
concerning the Heating, Ventilation and Air Conditioning (HVAC) System for the Fifth Emergency Oiesel Generator (EDG).
A written report was submitted on April 24, 1987 (PLA-2846). '- The licensee identified a number of HVAC design deficiencies which could render the system inoperable following an Operating Basis or Safe Shutdown Earthquake.
These deficiencies included:
The design of the ductwork and supports contained nonconserva-tive assumptions relative to the duct stiffness and mass.
The nonconservative assumptions resulted in unrealistically low stress levels which led the designer to conclude that a detailed design of all ductwork and duct support was not required.
As a result, only 40 percent of the total duct system was analyzed and no analysis was performed to address the connections (welds or bolts) for the ductwork, ductwork supports, or the connection of the ductwork to the supports.
The design control and as-built reconciliation were not properly implemented.
The licensee has initiated corrective action to prepare as-built drawings for the HVAC ductwork and duct supports and to reanalyze the system using conservative assumptions.
This item will remain unresolved pending review of the licensee's corrective action (387/87-09-02).
5.0 Surveillance and Maintenance Activities 5.1 Monthl Surveillance Observations The inspector observed the performance of surveillance tests to determine that:
the surveillance test procedure conformed to Tech-nical Specification requirements; administrative approvals and tag-outs were obtained before initiating the test; testing was accomp-lished by qualified personnel in accordance with an approved surveil-lance procedure; test instrumentation was calibrated; limiting condi-tions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly ac-complished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required fre-quency, These observations included:
Surveillance Procedure SI-164-204, Monthly Channel Functional Test of ATWS Recirculation Pump Trip Actuation Instrumentation (High Vessel Pressure),
performed on May 5, 1987.
Test Procedure TP-116-012, RHRSM 1B Pump and Heat Exchanger Performance Monitoring, performed on April 8, 1987.
Surveillance Procedure SE-159-029, LLRT HPCI Steam Supply Pene-tration No. X-ll, performed on April 9, 1987.
Test Procedure TP-054-057, Diesel Generator
'E'SM Loop
'A'low Analysis, performed on April 14, 1987.
Test Procedure TP-024-063, Diesel Generator 'E'or Diesel Generator 'B'tartup Test, Step 7.2, LOCA and LOOP Start Cir-cuit Tests for Diesel Generator
'B',
performed on May 8, 1987.
No unacceptable conditions were identified.
5.2 Review of Periodic Channel Check Surveillances The inspector conducted a
thorough review of the implementation of the Technical Specification required instrumentation Channel Check surveillances to determine if the survei llances were being performed at the required frequency and to verify the adequacy of the testing method,
The following references were used during the review:
Technical Specifications S0-100-006, Shi ftly'urveillance Operating Log S0-200-006, Shiftly Surveill.ance Operating Log S0-100-007, Daily Surveillance Operating Log S0-200-007, Daily Surveillance Operating Log S0-100-001, Monthly Remote Shutdown Panel Instrumentation Channel Checks S0-100-002, Monthly Accident Monitoring Instrumentation Channel Checks OI-AD-016, Operators Rounds IEEE Standard 338-1977,
"Standard Criteria for Periodic Testing of Nuclear Power Generating Station Safety Systems" The following discrepancies were noted during the review of the sur-veillance procedures:
The location for several of the instruments was not accurately reflected in the procedure (SO-100/200-006).
Reactor Vessel Level Instrument B21-1N031C is listed as being on Panel 1C005, but it is on Panel 1C004.
(Both Units)
Reactor Vessel Level Instrument 821-1N031B is listed as being on Panel 1C004, but it is on Panel 1C005.
(Both Units)
RWCU High Flow Differential Pressure Switch G33-1N044A is listed as being on Panel 1C002 on elevation 749, but it is actually on a local rack on elevation 719.
RWCU High Flow Differential Pressure Switch G33-1N0448 is listed as being on Panel 1C002 on elevation 749, but it is actually on Panel 1C010 on elevation 719.
Main Steam Line Differential Pressur'e Instruments 821-1NOOSA and 1NOOSB are listed as being on Panel 1C015, but they are actual ly on a local rac Labels for several of the instruments and components were miss-ing or incomplete:
Panel 1C614 (Unit 1)
RWCU High Delta Flow FDI-1R615 (Unit 1 and Unit 2)
Refuel Floor High Exhaust (Unit 1)
CREOASS Radiation Monitor (Unit 1)
SGTS Exhaust Vent Radiation Monitor (Unit 1)
LIS-. 142210 (Unit 1 and Unit 2)
LIS-14221C (Unit 1 and Unit 2)
Lockout Relays 86A2 on Panels 1A20301 and 1A20401 (Unit 2)
Ell-2N019B (Unit 2)
Service Water Effluent Radiation Monitor RR-1R604 (Unit 1)
Several of the alarm indicating lights on the local panels were inconsistent with each other and with the station color coding.
For example, SRM and IRM upscale trip lights in the relay rooms were green, white and red.
Unit
Main Steam Line Differential Pressure Switch B21-ZN009A was mislabeled as B21-NOOBA.
Unit
RHR Service Water Radiation Monitor RR-1R606 pen label was not consistent with procedure S0-100-007.
The daily channel checks for the MSIV leakage control system (LCS) instrumentation do not include the four temperature detec-tors, (TI-E32-1R602B, F,
K, and P) which sense the pipe tempera-ture near the heater elements.
These detectors should be in-cluded in surveillance procedure S0-100-007, but they appear to have been omitted.
A similar condition exists in Unit 2.
Tech-nical Specification Surveillance 4.6.1.4.C.1 requires that the operating instrumentation be verified operable by performance of a
channel check at least once per
hours.
The inspector determined, however, that the channel functional tests and cali-brations for these temperature detectors were being performed as per the Technical Specifications 4.6. 1:4.C.2 and C.3.
As noted during previous reviews of the periodic channel checks, the actual instrument readings are not recorded on the log sheets.
The majority of the instrument channel checks require only logging of
"SAT" or
"UNSAT" even though the instrument actually provides an important quantitative readout.
Expected readings or acceptance cri-teria are also not noted on the procedure, only the limit.
This lack of logging actual value, in addition to precluding trending, prevents supervisory evaluation of the operators comparison among independent instruments monitoring the same parameter.
For example, the Main Steam Line Radiation Monitors, with indications in the relay rooms and the control room, are not compare.3 The Technical Specification definition of a
channel check only re-quires a "qualitative assessment" of channel behavior and the major-ity of the instruments are compared to at least one other independent channel.
Therefore, the licensee's current test methodology, al-though not preferable, meets the Technical Specification require-ments.
However, the licensee should review the instruments that only have one available indication to determine other available indica-tions for comparison.
For example, during the daily channel check of the Service 'Water Radiation Monitor RR-lR604, the indication should be compared wi,th the same monitor in the relay room.
The licensee's corrective actions concerning the procedural and labeling deficiencies will be reviewed in a
subsequent inspection (387/87-09"03).
Im ro er Tor ue Switch Settin on HPCI Isolation Valve On May 7, 1987, the licensee discovered during preparation of work documents for the upcoming Unit 1 third refueling outage, that the closing torque switch on the HPCI steam supply isolation valve (F002)
was incorrectly set to nstead of the required setting of '3'.
This valve was not set properly following rework during the previous refueling outage in April 1986.
A torque switch setting of '3's required to close the valve fully under the maximum differential pressure that the valve would experience (i.e.
1147 psid) during a
HPCI steam line break.
The thrust load generated by a torque switch setting of ould correspond to a differential pressure across the valve of 141 psid.
The F002 valve is a Anchor Darling 10-inch split wedge gate valve with a
Limitorque SMB-1-40 operator installed.
Upon discovery of the problem, the licensee issued Nonconformance Report (NCR)
87-0187 which stated that the Work Authorization and LLRT documents showed that the torque switch setting was at ,
and therefore the operability of the valve was indeterminate.
Previous engineering evaluation of IE Bulletin 85-03 by Nuclear Plant Engi-neering (NPE)
had determined that the valve required a torque switch setting equal to '3'o render the valve capable of full closure with the maximum design differential pressure across the valve.
Although the torque switch contacts are bypassed in the closing circuit until the valve reached the full closed limit switches, the limit switches were adjusted to approximately 97 percent closed, therefore the valve would not go fully closed.
Further review of the impact of the improper torque switch setting by the plant staff and NPE resulted in declaring the valve inoperable at 10:52 a.m.
on May 9, 1987.
Since the valve was determined to be inoperable, the Action Statement of Technical Specification LCO 3.6.3 required that the valve be closed and deactivated.
HPCI was then declared inoperable since it's steam supply was isolated.
With HPCI inoperable the Technical Specifications required that the unit be shutdown in 14 day The licensee initiated action to perform a safety assessment to pro-vide a technical basis for reopening the F002 valve and to'et Tech-nical Specification relief from NRR to prevent an unnecessary shut-down.
The safety assessment was completed on May 13, 1987 and was approved by PORC the same day.
The conclusion of the safety assess" ment was that safe operation of the plant with the HPCI F002 valve torque switch set at as justified until the third refueling out-age (September 12, 1987) with the valve open to support HPCI avail-ability.
Based on the probability of the pipe break occurring versus the probability of requiring the use of the HPCI system for an opera-tional transient, the safety assessment also concluded that it was less safe to have HPCI isolated and inoperable than to leave the valves opens However, the PORC also concluded that reopening the valve would constitute an unreviewed safety question, as defined by
CFR 50.59, since the consequences of an analyzed event would be increased.
5.4 The licensee submitted an emergency Technical Specification Change request for LCO 3.6.3 to NRR on May 14.
Based on initial review of the submittal NRR authorized reopening of the F002 valve on May 15, pending formal review and approval of the licensee's submittal.
The HPCI system was restored to operational status on May 15.
The Tech-nical Specification Change was expected by May 22, 1987.
IE Bulletin No.
85-03,
"Motor Operated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings" was issued on November 15, 1985 to request licensees to develop and implement a
program to ensure that switch settings on certain safety-related motor-operated valves are selected, set and maintained correctly to accomodate the maximum differential pressures expected on these valves during both normal and abnormal events within the design basis.
The licensee's initial response to the bulletin was submitted on May 9, 1986 (PLA-2632).
The submittal stated that the individual switch settings on the affected Unit 1 valves would be verified and/
or changed, as necessary, prior to the end of the third refueling outage (November 1987).
This item is unresolved pending further NRC review of the cause of the improper torque switch setting and completion of the licensee's corrective actions (387/87-09-04).
Monthl Maintenance Observation The inspector observed portions of selected maintenance activities to determine that the work was conducted in accordance with approved procedures, regulatory guides, Technical Specifications, and industry codes or standards.
The following items were considered during this review:
Limiting Conditions for Operation were met while components
or systems were r emoved from service; required administrative ap-provals were obtained prior to initiating the work; activities were accomplished using approved procedures and gC hold points were estab-lished where required; functional testing was performed prior to declaring the particular component operable; activities were accom-plished by qualified personnel; radiological controls were implemen-ted; fire protection controls were implemented; and the equipment was verified to be properly returned to service.
These observations included:
Replacement of the 1B Residual Heat Removal Service Water Pump, performed on April 7, 1987.
No unacceptable conditions were identified.
6.0 IE Bulletin and Information Notice Followu IE Bulletin No.
84-02:
Failures of General Electric T
e HFA Rela s in Use in Class 1E Safet S stems IE Bulletin No.
84-02,
"Failures of General Electric Type HFA Relays in Use in Class 1E Safety Systems",
was issued on Harch 12, 1984, to inform licensee's about recent HFA relay failures that were similar in nature to previous HFA relay failures reported in several General Electric (GE)
Service Advice Letters and Service Information Letters which were issued to end-users in 1980 and 1982.
Licensee's were requested to inform the NRC about their plans for implementing the manufacturers recommendations and to provide information concerning their plans to upgrade surveillance and to justify continued operation in the interim.
The licensee responded to the Bul 1 etin on May 3,
1984 (PLA-2153)
and stated that the replacements of all of the Class 1E HFA Relays had been completed.
The replacements were performed in one of two forms:
The Lexan coils were replaced with Tefzel coils.
The HFA relay itself was replaced with the Century Series HFA Relay which contains a Tefzel coil.
The licensees corrective actions were previously reviewed by the inspec-tors in NRC Inspection Report 50-387/82-19 and 50-388/84-13 during follow-up of IE Information Notice 80-01 and Construction Deficiency Report 50-387/81-00-03.
The licensees actions were found to be acceptable and this bulletin is close.0 Mana ement Meetin s
On May 26, 1987 the inspector discussed the findings of this inspection with station management.
Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to
CFR 2.790 restric-tions.