IR 05000335/1990008
| ML17223A602 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/29/1990 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A601 | List: |
| References | |
| 50-335-90-08, 50-335-90-8, 50-389-90-08, 50-389-90-8, NUDOCS 9004190256 | |
| Download: ML17223A602 (24) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos:
50-335/90-08 AND 50-389/90-08 Licensee:
Florida Power II Light.Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
License Nos.:
DPR-67 and NPF-16 Inspection Conducted:
ary 13 - March 12, 1990 Inspecto nio i
e t Inspector Da e
Ss e
Approved By:
M. A.
o
, Resident I spector R.
V. Cr nba
,
c son Division of Reactor Projects Da e S'ed ate
)gn SUMMARY Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, review of nonroutine events, and review of outage" activities.
Results:
This report describes several instances where the licensee, initiated proactive surveillance activities or proactive responses to outside information.
As one might expect, these dynamic activities discovered some previously unknown equipment problems which are being vigorously pursued with senior management support.
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REPORT DETAILS 1.
Persons Contacted D.
G.
A.
J.
J.
R.
H.
C.
C.
D.
R.
R.
J.
C.
L.
L.
N.
R.
D.
J.
W.
G.
E.
Licensee Employees Sager,:St.
Lucie Site Vice President Boissy, Plant Manager Bailey, guality Assurance Supervisor Barrow, Operations Superintendent Barrow, Fire Prevention Coordinator Church, Independent Safety, Engineering Grou Buchanan, Health Physics Supervisor Burton, Operations Supervisor Crider, Outage Supervisor Culpepper, Site Juno Engineering Manager Dawson, Maintenance Superintendent Frechette, Chemistry Supervisor Harper, guality Assurance Superintendent Leppla, 18C Supervisor McLaughlin, Plant licensing Supervisor Rogers, Electrical Maintenance Supervisor Roos, guality Control Supervisor Sipos, Services Manager West, Technical Staff Supervisor West, Mechanical Maintenance Supervisor White, Security Supervisor Wood, Reliability and Support Supervisor Wunderlich, Reactor Engineering Supervisor p Chairman Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview 2.
Acronyms and initialisms used throughout this report are listed in the last paragraph.
Review of Plant Operations (71707)
Unit 1 began and ended the i nspection period in its 11th refueling outage.
Power resumption is tentatively scheduled for April'4, 1990.
During this period, two inadvertant CIS actuations occurred.
Unit 2 began and ended (day 54) the inspection period at power.
The licensee declared an Unusual Event on March 3 involving the loss of Unit 2 RCS inventory via a damaged charging pump.
a.
Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was
properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly and combustible materials and debris were disposed of expeditiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic.restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates.
Some tours were conducted on backshifts.
The frequency of plant tours and control room visits by site management was noted to be adequate.
The inspectors routinely conducted partial walkdowns of ESF, ECCS and support systems.
Valve, breaker, and switch lineups and equipment conditions were randomly verified both locally and in the control room.
The following accessible-area ESF system walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:.
Unit 2 ICW
Unit 2B EDG (trouble shooting maintenance performed)
Unit 2 MFIVs Unit I ESF cabinets b.
Plant Operations Review The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs and equipment tagout records.
The inspectors routinely observed operator alertness and demeanor during plant tours.
During routine operations, control room staffing, control room access and operator performance and response actions were observed and evaluated.
The inspectors conducted random off-hours inspections to assure that operations and security remained at an acceptable level.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verified.
The inspectors reviewed the following safety-related tagouts (clearances):
2-2-45 2C AFW Pump
.Pressurizer Heaters 1-2-82 1-2-176 1B Charging Pump HVS 1D Containment Cooler 1-2-219 1B HPSI Pump
,
1-2-302 1B EDG NCRs 1-435, 441, and 1-446 addressed ECCS piping potential water hammer problems identified during the current Unit 1 outage.
The hammer did not appear during normal operation but had occurred during previous refueling outages and had been troublesome enough to damage a wall penetration seal and bend small hangers.
The first two NCRs identified movement in the 10-inch SDC return piping to the 1A LPSI pump during SDC evolutions.
Starting the pump unthrottled appeared to cause up to 3-inch pipe movements in the SDC return piping portion located above the equipment drain pumps in the HPSI pump room.
The line movement was severe enough to rupture a wall penetration seal in the wall between the pump room and the adjacent pipe tunnel.
Other seals may be involved since the line passed through two other walls with separating seals prior to reaching the LPSI pump.
The line movement was accompanied by a loud noise thought to be coming from the'pump's discharge check valve.
The third NCR identified movement in the two-inch cross connect piping between the charging pumps and the 1A HPSI pump six-inch discharge line (auxiliary header).
The movement was induced by starting the lA HPSI pump with the charging pumps isolated for outage-related repairs.
The HPSI pump discharge auxiliary header
- and the cross-connect piping moved at least 3/4 inch, which was sufficient to damage several hoop-type cross-connect piping hangers.
The licensee identified these problems and entered them into their corrective action program.
Immediate operability reviews had not identified problems by the end of the inspection period.
Modified operational controls have remedied water hammer effects.
On February 11, during Unit 1 refueling operations, a 8-train con-tainment isolation occurred.
However, A-train containment isolation did not occur, nor did the Unit 2 control room isolate.
Seven of the eight B-train CIS Actuation Modules did not have the
"output activated" lights lighted though most equipment operated
by the modules activated.
Three aspects of the event were investigated.
The cause of the B-train containment isolation.
The reason why seven of eight B-train Actuation Nodule lights did not light.
The reason why A-train actuation and Unit 2 control room isolations did not occur.
The licensee's ISC department conducted an excellent root cause investigation, discussed in Appendix A, that included both field and bench tests.
The causes of the B-train isolation, the Actuation Module lights not lighting, and the A-train isolation not occurring were clearly determined.
The Unit 2 control room not isolating could not be repeated during tests so suspect components were replaced as a precaution.
The inspector reviewed the results of the licensee's investigation and found the root cause analysis determination, along with their corrective actions to be satisfactory.
On February 28, partial containment spray actuation and containment isolation actuation occurred while ATWS modifications were in progress.
1A EDG started and MOV-18-01 actuated while a jumper wire-was being attached to a terminal strip.
An initial analysis led to troubleshooting (FRG reviewed) which found and corrected several marginally tight screws and one loose screw on a
power supply buss.
The jumper wire installation had physically disturbed the buss causing loss of el'ectrical continuity at the loose screw.
The licensee issued a
NPWO to check the integrity of all Unit 1 safeguards cabinet connections during this outage.
At approximately 12:28 am on March 3, investigation of a Unit 2 charging pump room fire alarm found water spraying from the 2A charging pump at a valve cover.
Water spray had failed the fire sensor.
When informed of the spray, the control room operators, who had
'eceived no operational alarms from the event condition, manually controlled letdown to halt the slight pressurizer level reduction.
Charging flow had fallen from a normal of 88 gpm to 76 gpm.
The non-licensed operator in the cubicle stopped the 2A pump and isolated the suction to prevent loss of VCT inventory.
Three check valves in series isolated the discharge of the 2A pump from the RCS.
Pressurizer inventory was maintained by the 2C charging pump.
Without the fire alarm, automatic annunciation of the leak in the pump would not have occurred until either the VCT level had dropped to 42 percent - illuminating an annunciator requesting VCT make up, or the ECCS sump pumping annunciator would have lit when the sump level was high enough to start the sump pum With 2A pump leakage determined to be 13 to 18 gpm, the licensee declared an Unusual Event at I:48 am.
The declaration of an Unusual Event was conservative because the inventory loss was not directly from the RCS, but via the VCT and charging pump.
Both are separated from the RCS by multiple isolation valves.
The Unusual Event was exited at 2:00 am when plant conditions were stabilized.
When the event occurred, the 2B charging pump had been out of service for packing replacement.
Wi'th the disablement of the 2A pump, the licensee placed Unit 2 in 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO based on two charging pumps being out of service.
The 2B charging pump was returned to service the following morning.
Licensee inspection of the 2A charging pump found two of four valve cover studs broken on the valve cover for one of the three pumping cylinders.
The release of tension on the cover released spray initially at system pressure until the associated check valves seated.
Additionally, the pumping head of the pump had some cracks in the base metal around the stud holes.
At the end of the inspection period, the 2A pump remained out of service while the licensee investigated the failure cause.
No violations or deviations were identified in this area.
Technical Specification Compliance Licensee compliance with selected TS LCOs was. verified. This included the review of selected surveillance test results.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that plant procedures involved were adequate, complete, and the correct revision.
Instrumentation and recorder traces were observed for abnormalities.
No violations or deviations were identified in this area.
Physical Protection The inspectors verified by observation during routine a'ctivities that security program plans were being implemented as evidenced by: proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.
No violations or deviations were identified in this are Surveillance Observations (61726)
Various plant operations were verified to comply with selected TS
'equirements.
Typical of these were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation and AC and DC electrical sources.
The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs were met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel, The following surveillance tests were observed:
2C AFW pump mechanical controls were adjusted under NPWO 8675/62 per procedure 2M-0018, Rev 13, Appendix A, PM 1710, Spring Adjustment and Governor Valve Stroke.
The system engineer was present for this PM.
2C AFW pump controls were lubricated under NPWO 8676/62 per procedure 2M-0018, Rev 13, Appendix A, PM 1709, Lubricate Throttle and Control Linkages.
The system engineer was present for this PM.
Procedure OP 2-0110050, Rev 9, Control Element Assembly Periodic Exercise, observed on February 15, 1990, was performed without incident.
The operator controlled the evolution well and focused on the cycling of the CEAs.
Procedure OP 2-0400053, Rev 10, Engineering Safeguards Relay Test, a major test performed every six months, was observed on February 19.
The test was performed without major incident.
Minor changes to the procedure were required to clarify points in the test.
These changes were implemented during the test and were submitted for permanent procedure changes prior to the end of the shift.
One pipe tunnel fan damper (HVE 120)
had an outstanding NPWO for dual indication but the damper opened on a test signal and exhibited proper indication when opened.
The NPWO had yet to be worked due to outage priorities.
No violations or deviations were noted with the above surveillances.
Maintenance Observation (62703)
Station maintenance= activities involving selected safety-related systems and components were observed/reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations'ere performed prior to returning components or systems to service; quality control records were maintained; activities were
accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
The "as found" lift of pressurizer safety/relief valve V1201 was tested per maintenance procedure M-0017, Rev 21, Pressurizer Safety Valve Maintenance.
Utilizing the licensee's test bench, the contractor performing the work in a radiologically controlled area increased pressure to approximately 1500 psig when valve seat leakage exceeded the test bench air supply capacity and prevented further pressure increase.
These safety valves had been weeping primary steam during the last power run with no detrimental effects and the "as found" leakage was expected.
The other two pressurizer valves also weeped on the test bench but bench-provided pressure could maintain the pressure increase until the valve popped/lifted at or near the desired values.
The 1A AFW pump rotating assembly end pl.ay was measured per NPWO 3157/61 and found to be excessive.
The
pump had previously exhibited excessive end play during a pre-disassembly measurement.
The 1C pump end play was examined later and also found to be excessive.
In all three instances, the end play was due to wear caused by loose thrust bearing lock nuts.
Although each rotating element's lock nut was found against the bearing with its retaining lock washer in place, it was apparently not torqued sufficiently.
At the end of this inspection period, several possible scenarios were being developed, such as:
the bearings were heated to assist in installation but perhaps not allowed to cool sufficiently prior to installing the locking nut.
The contraction of the bearings (a duplex pair) upon cooling might have caused the initial looseness.
the bearings might have hit a high spot or burr on the shoulder of the rotating assembly shaft when installed and, when operated, the bearing might have obliterated the interference, which allowed the bearing to induce other damage".
With the bearing not tightly restrained on the shaft, the bearing wore excessively and the shaft seating area under the bearings fretted - increasing shaft-to-pump-housing end play from a nominal 0.016 to approximately 0.040 inches.
Additionally, the 1C pump duplex thrust bearing set was found reversed, which also contributed to its clearance problem.
All three pump rotating assemblies were removed and sent to the pump vendor for refurbishmen At maximum end play, the previous normal surveillance-related vibration testing still did not indicate pump problems.
Discreet noise testing beyond regulatory requirements had not been performed.
All three pump's thrust bearings had been removed by
'he licensee in 1987 during bearing inspections in which only the pump bearing caps were removed for the inspections.
The inspection that was initiated on the 1B AFW pump this outage was part of the Mechanical Maintenance Department's effort to enhance plant equipment material condition.
Initially, only the 1B pump was slated for a preventive disassembly inspection to kick off the pump periodic disassembly program.
Once pump problems were identified, the inspection scope was increased to encompass possible related problems.
The site has been generating root cause packages on all pumps.
Considerable effort has been expended to identify the proper method for torquing the bearing lock nut; neither the vendor's manual nor the vendor's in-house shop had a lock nut torquing procedure.
NPWO 5496/61 performed trouble shooting work on breaker 40204, the bus tie to 480 volt swing LC 1AB from the 1A2 (A-train) LC.
Control power to the breaker would not energize.
The breaker would rack in but would not close and, when the breaker was racked out, interlock switch 52 R in the breaker's cabinet would not open to allow B-train feed to LC 1AB.
Troubleshooting found that melted epoxy residue from a previously-replaced CT had run down and disabled the control power stabs and switch 52 R.
Over the past year, the licensee has been replacing 480'olt breaker CTs that had defective epoxy encapsulation.
ABB had reported this issue to the NRC per
CFR 21 on April 17, 1989.
Several of the CTs installed in plant circuit breaker cabinets had melted their defective epoxy encapsulation.
Although most of the melted CT epoxy for breaker 40204 had been previously removed, residual material had flowed down onto the breaker control power stabs and onto the
R switch just above the stabs.
The licensee has stated that all breakers on Unit 1 where the CTs had been previously replaced would be examined for melted CT epoxy prior to returning to power.
The problem is not probable on Unit 2 due to the unit age difference (Unit 2 is seven years newer) but the licensee plans to change out the Unit 2 CTs during the fall, 1990 outage.
During a tour of the Unit 2 RAB, the inspector noted that the ECCS spaces and the charging pump rooms contained abnormal levels of dust.
The concrete and paint dust was from mechanical abrasion of floors and walls during the preparation for painting.
The vendor involved had not anticipated the amount of dust that would be produced.
Work was stopped and cleaning was initiated.
The charging pump motors that were operating at the time were cleaned of retrievable internal dust.
The vendor issued extensive
guidelines and purchased needle gun vacuum heads to prevent further dust problems.
No violations or deviations were identified in the above maintenance observations.
Outage Activities (60710)
The inspector observed the following overhaul activity during the ongoing Unit 1 outage:
Performance of OP-0110022, Rev 11, Coupling and Uncoupling of CEA Extension Shafts was obs'erved during latching.
All CEAs were
- latched in accordance with the procedure.
Performance of LOI 1-T-47, Rev 0, 1A HPSI Full Flow Verification, was observed by the inspectors with satisfactory results; the testing (as with subsequent testing discussed below)
was in response to NRC GL 89-04.
The pump was then satisfactorily tested for flow balance across all the injection valves.
Although the 1B HPSI pump had passed its last and previous survei llances prior to the outage, as postulated in the generic letter the pump was approximately 20 percent below its total head curve.
Upon disassembly, it was discovered that an internal break-down sleeve had corroded and required replacement to restore the pump's nominal output.
The sleeve was made of the wrong material.
A pump vendor representative was present and working
'ith the licensee to resolve the material problem.
At the end of the inspection period, the site had an open NCR to address the vendor/regulatory aspects.
The inspectors observed the satisfactory initial retesting of the 1B pump and the flow balancing of that pump in accordance with LOI 1-T-43, Rev 0, HPSI Flow Balance Test.
During the outage, CE found both the SG tube leak that initiated the premature shutdown for the Unit 1 outage and the cause of the leak.
A piece of weld slag was lodged between three SG tubes.
The slag was left in place and the tubes were plugged on both ends.
Onsite Followup of Events (Units 1 and 2) (92701)
Nonroutine plant events were reviewed to determine the need for further or continued NRC response, to determine whether corrective actions appeared appropriate, and to determine that TS were being met and that the public health and safety received primary consideration.
Non-routine events discussed in this report include two partial Unit
containment isolations and a loss of Unit 2 RCS inventor Exit Interview The inspection scope and findings were summarized on March 16, 1990 with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed the observations made during this inspection.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensee.
Abbreviations, Acronyms, and Initialisms
'BB AB AC ADV A/E AFAS AFW ALARA ANPO ANPS ANSI AP ASME Code ATWS BOP CAR CCW CE CEA CEDMCS CFR CIS CS CST CT CVCS DC DDPS DEV DPR ECCS EDG EPRI ESF F
FCV FI FIS ASEA Brown Boveri (company)
Auxiliary Building
'lternating Current Atmospheric Dump Valve Architect/Engineer Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
As Low as Reasonably Achievable (radiation exposure)
Auxiliary Nuclear Plant [unlicensedj-.Operator Assistant Nuclear Plant Supervisor Amer'ican National Standards Institute Administrative Procedure American Society of Mechanical Engineers Boiler and Pressure Vessel. Code Anticipated Transient Without Scram Backfit guali ty Assurance Procedure (EBASCO Services Inc.)
Corrective Action Request Component Cooling Water Combustion Engineering (company)
Control Element Assembly Control Element Drive Mechanism Control System Code of Federal Regulations Containment Isolation System Containment Spray (system)
Condensate Storage Tank Current Transformer Chemical 5 Volume Control System Direct Current Digital Data Processing System Deviation (from Codes, Standards, Commitments, etc.)
Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Emergency Diesel Generator Electric Power Research Institute Engineered Safety Feature Fahrenheit Flow Control Valve Flow Indicator Flow Indicator/Switch
FPL FRG FSAR FT GDC GE GL GMP gpm HCV HFA HP HPSI HVE HVS HX IKC ICW IFI ILRT IN INPO IR IS I IX JPE JPN KW LC LCO LIV LTOP LER LOI LPSI MKTE MCC MFIV MFP MG
"
min MOV MSIV MSR MV MW NCR NCV NDE The Florida Power
& Light Company Facility Review Group Final Safety Analysis Report Flow Transmitter General Design Criteria (from 10CFR 50, Appendix A)
General Electric Company
[NRC] Generic Letter General Maintenance Procedure Gallon(s)
Per Minute (flow rate)
Hydraulic Control Valve A GE relay designation Health Physics High Pressure Safety Injection (system)
Heating and Ventilating Exhaust (fan, system, etc.)
Heating and Ventilating Supply (fan, system, etc.)
Heat Exchanger Instrumentation and Control Intake Cooling Water
[NRC] Inspector Followup Item Integrated Leak Rate Testing
[NRC] Information Notice Institute for Nuclear Power Operations
[NRC] Inspection Report InService Inspection (program)
Ion Exchanger Juno Beach)
Power Plant Engineering Juno Beach)
Nuclear Engineering KiloWatt(s)
Load Center (electrical distribution)
TS Limiting Condition for Operation
,
Licensee Identified Violation Low Temperature Overpressure Protection (system)
Licensee Event Report Letter of Instruction Low Pressure Safety Injection (system)
Measuring 8 Test Equipment Motor Control Center (electrical distribution)
Main Feed Isolation Valve Main Feed Pump Motor Generator minute Motor Operated Valve mrem millirem Main Steam Isolation Valve Moisture Separator/Reheater Motorized Valve Megawatt(s)
Non Conformance Report NonCited Violation (of NRC.requirements)
Non Destructive Examination
NPF NPO NPS NPWO NRC NSSS OI ONOP OP PCM PCV PAID PIS PM PORV Pslg ppm PT PWO PWR QA QC QI QSPDS RAB RCB RCO RCP RCPB RCS RDT Rev RG RO RPS RWT SAL SALP SAS SDC SDCS SG SI
.SIT SNPO SRO STA Tavg TC TCB e of license)
System Performance Operator Nuclear Production Facility (a typ Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Plant Work Order Nuclear Regulatory Commission Nuclear.
Steam Supply System Operating Instruction Off Normal Operating Procedure Operating Procedure Plant Change/Modification Pressure Control Valve Piping 8 Instrumentation Diagram Pressure Indicator/Switch Preventive Maintenance Power Operated Relief Valve Pounds per square inch (gage)
Part(s)
per Million Pressure Transmitter Plant Work Order Pressurized Water Reactor Quality Assurance Quality Control Quality Instruction Qualified Safety Parameter Display Reactor Auxiliary Building Reactor Containment Building Reactor Control Operator Reactor Coolant Pump Reactor Coolant Pressure Boundary Reactor Coolant System Reactor Drain Tank Revision
[NRC] Regulatory Guide Reactor [licensed] Operator Reactor Protection. System Refueling Water Tank Service Advice Letter Systematic Assessment of Licensee Safety Assessment System Shut Down Cooling Shut Down Cooling System Steam Generator Safety Injection (system)
Safety Injection Tank Senior Nuclear Plant [unlicensed]
Senior Reactor [licensed] Operator Shift Technical Advisor Reactor average temperature Temporary Change Trip Circuit Breaker
TCW TE TEDB TI TMI TR TS URI V
VCT VIO Turbine Cooling Water Temperature Element Total Equipment Data Base
[NRC] Temporary Instruction Three Mile Island Temperature Recorder Technical Specification(s)
[NRC] Unresolved Item Volt(s)
Volume Control Tank Violation (of NRC requirements)
APPENDIX A ST.
LUCIE UNIT 1 CONTAINMENT ISOLATION of FEBRUARY 11, 1990 Event synopsis:
On February 11, 1990, St. Lucie Unit 1 was refueling.
Shutdown cooling train 8 was in service.
At 1:37 pm, a 8-train containment isolation occurred.
However, A-train containment isolation did not occur, nor did Unit 2 control room isolation.
Seven of the eight 8-train CIS Actuation Modules did not have the "output activated" lights lighted though most equipment operated by the modules had activated.
Three aspects of the event were investigated.
The cause of the 8-train containment isolation.
,The reason why seven of eight 8-train Actuation Module lights did not light.
II The reason why A-train and Unit 2 control room isolations did not occur.
A CIS signal flow channel is outlined in Figure 1.
Cause of the 8-train containment isolation:
At the time of the event, CIS input channel 8 had been de-energized for ATWS modifications.
The de-energized channel 8 bistable
{8/S) acted as a trip signal to the two optical isolators it fed.
Each optical isolator fed a trip signal to eight associated Actuation Modules.
Thus, the Actuation Modules for train A and for train 8 had one of the two inputs required for actuation.
A sufficient signal from one of the remaining three containment radiation detectors would actuate CIS.
There was speculation that a power grid line failure caused a signal spike.
Though possible, the cause of the input spike was irrelevant to equipment operation:
The event occurred when an undetermined external input caused the C containment radiation analog signal to spike positive.
This was known because, independent of the ESF equipment, a
containment evacuation alarm occurred.
No observed meter indications showed an actual high radiation field.
Additionally, control room annunciation of CIS actuation pre-trip occurred.
This was a warning annunciator independent of ESF, but from the same signal loops that fed ESF.
The reason seven of eight Actuation Module lights did not light:
Technical review showed the most likely causes to be equipment responses to narrow (short) pulses or noise inputs.
Normal testing
using "clean" signals of normal long duration (push button)
showed that the Actuation Modules and associated lights worked as designed.
The Actuation Relays operated by the Actuation Modules took about
ms to actuate, while the Actuation Nodules took about 30 ms of trip output to lock-in the trip.
Since the Actuation Relays did operate, but only one Actuation Module locked in, it was concluded by FPL IKC Department investigator that the tri'p pulse was between 14 and
ms in length, probably nearer 30.
The reason B-train containment isolation occurred but not A-train:
The FPL IKC Department investigator, working with the Consolidated Con-trols design engineer on site for the ATWS modification, hypothesized the most probable cause to be associated with the Optical Isolation Switch Nodules.
The reasons for this hypothesis follow:
1.
There were eight A-train Actuation Modules and eight B-train.
It was extremely improbable that all eight B-train modules would actuate while no A-train modules did.
The Actuation Nodules were therefore probably not the cause.
2.
The bistable was common to both trains, therefore it was probably not the cause.
3.
The Optical Isolation Switch Nodules each outputted to a different actuation channel.
A single Optical
~Isolation Switch Nodule effected all Actuation Modules in its channel; therefore a single difference in Optical Isolation Switch Modules could cause the noted symptoms that the B-train operated and the A-train did not.
The bistables fed the Optical Isolation Switch Nodules.
A high input current being a non-trip and a low input current being a trip.
The isolation modules fed this signal into a photo transistor which would output a trip if the input current were below 1.5 ma and a non-trip if the input current was greater than 12 ma.
Operation between 1.5 and
ma input current was undefined.
The input was believed to be a short pulse.
The Actuation Relays, as described above, operated by the Actuation Modules took about
ms to actuate, while the Actuation Modules took about
ms to lock-in to trip.
Since the Actuation Relays did operate, but only one Actuation Module locked in, it was concluded by the FPL ISC Department.
investigator that the trip pulse was between 14 and 30 ms,in length, probably nearer 30.
The investigator hypothesized that the short input pulse from the channel C containment radiation was noisy, as opposed, to being a clean square pulse.
Under these conditions, it is probable that the output pulse from the bistable was not a clean pulse, but jittery and noisy.
If so, the Optical Isolation Switch would see some input, quite probably within the 1.5 to
ma area where operation was not defined;
That is, the isolator could put out either a trip or a nontrip dependent on the characteristics of its integrated circuits.
The investigators postulated that, due to the different chip characteristics, the B Optical Isolation Switch tripped while the A did not.
Bench tests of the two Optical Isolation Switch Modules showed that both switches met design standards for the application but the 8-train switch was about twice as responsive to higher frequency signals when compared to the A-train switch response.
The reason Unit 2 control room isolation failed to function:
Review subsequent to the initial 50.72 report showed that either CIS Actuation Module 48, or the Actuation Relay it operated, failed to actuate.
The relay had three output functions:
Unit 2 control room isolation - It did not occur.
Unit 1 equipment drain tank isolation - It did not occur.
Unit 1 reactor drain tank isolation - It was tagged out.
Though-this Actuation Nodule and Actuation Relay functioned during the recent safeguards test and again functioned under test following this containment isolation event, the licensee intends to replace them because failure to operate during the event could not be explaine FIGURE /
ENGINEERED SAFECUARJS CHANNEl
.
CONTAINS/ENT ISOlATION NOTE
ANALOG INPUT SIGNAL E
ANALOG INPUT SIGNAL (ie, CONTAINMENT RADIATION MONITOR)
4-20ma TEST SWITCHES ~ MANUAL TEST PANEL SWITCH NOTE
CIS BISTABLE NON-lATCHING% WITH TRIP SET POINT AND LATCHING UGHT TO SHOW THAT IT IS OR HAS BEEN IN TRIP.
15 VOLTS - ON / 0 VOLTS - OFF NOTE
"A" TRAIN OPTICAL ISOLATION SWITCH MODULE
"B" TRAIN OPTICAI ISOIATION SWITCH MODULE OPTICAL ISOLATION SWITCH
"A" TAN CIS ADDlllONALINPUTS ACTUATION MODULE NOTE 4 MODULES 12 ma in - turns on 1.5 ma in - turns off RELAYS ONE OF 8 TO OPERATE EQUIPMENT EQUIPMENT
Note 1:
Each CIS Input Channel (A,B,C,D) had two analog input signals.
There are four channels of each signal.
CIS Input Channel Signals:
(Analog) Containment Radiation (4-20 ma) - Powered external to the ESF cabinet.
(Analog) Containment Pressure (20-4 ma) - Powered from the ESF Cabinet.
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Note 2:
The CIS Channel Bistables were non-latching B/S with trip set point adjustment and a latching indicating light to show that it was currently or had been in trip.
The 8/S output went low to trip.
The B/S had one output that fed both the A-train and B-train Optical Isolation Switch Nodules.
Note 3: Optical Isolation Switch Nodules had one input and one output that fed eight paralleled CIS Actuation Nodules.
Note 4:
Each CIS Actuation Module had nine inputs.
Four inputs (train A,B,C,D) for Containment Radiation.
Four inputs (train A,B,C,D) for Containment Pressure.
One direct trip from Safety Injection.
Two of four inputs actuated for either radiation or pressure or the direct trip from Safety Injection would cause the Actuation Nodule to actuate.
Each CIS Actuation Module had one output which could drive up to four Actuation Relays in the ESF Cabinet.
Each relay could start up to four discrete functions.
The CIS Actuation Module output would latch when actuated for about 30 ms.
Each CIS Actuation Module has four lights:
One non-latching light on if one or more, containment radiation trip inputs were active.
One non-latching light on if one or more containment pressure trip-inputs were active.
One light not used for CIS.
One non-latching light tied to the Actuation Module output and showing output state.
It would light if the output were actuated.