IR 05000335/1990011
| ML17223A670 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 05/10/1990 |
| From: | Casto C, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A669 | List: |
| References | |
| 50-335-90-11, 50-389-90-11, NUDOCS 9005230323 | |
| Download: ML17223A670 (28) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos:
50-335/90-11 AND 50-389/90-11 Licensee:
Florida Power 5 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 Conducte arch
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16, 1990 Inspector
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i r si t Inspector Da S
ned M. A.
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Residentp nspector Da S'gned Approved By:
C. A.
as o, Chief, perator Licensing Da e
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, Section ie Division of Reactor Projects ate igne SUMMARY Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, safety system inspection, review of nonroutine events, review of strike activities, and installation and testing of modifications.
Results:
During this inspection period, the Unit 1 protracted, complex refueling outage continued.
Three major plant modifications were installed:
containment cooler fan coil upgrades, ATWS diverse scram circuits, and a
MSIV control upgrade.
Numerous outage tasks were observed along with normal
"at-power" Unit
evolutions.
On March 29, contract health physics field technicians picketed for about three hours regarding their employer not recognizing a particular labor union.
This activity had no adverse effect on plant operations.
On April 15, Unit 1 post-outage startup had progressed through criticality and zero power physics testing but the licensee decided to shut the unit down to correct an inner stage problem with the 1A1 RCP shaft seal.
During cooldown, a
leaking SDC pipe drain valve leaked steam in excess of
gpm to the pipe penetration room - operators responded promptly.
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Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operation REPORT DETAILS Persons Contacted Licensee Employees D. Sager, St. Lucie Site Vice President
- G. Boissy, Plant Manager
- J. Barrow, Operations Superintendent J. Barrow, Fire Prevention Coordinator
- R. Church, Independent Safety Engineering Group H. Buchanan, Health Physics Supervisor
- C. Burton, Operations Supervisor
- C. Crider, Outage Supervisor
- D. Culpepper, Site Engineering Supervisor R.
Dawson, Maintenance Superintendent
- R. Decker, Plant Licensing Engineer
- J. Dyer, Quality Control Engineer
- P. Fincher, Training Superintendent R. Frechette, Chemistry Supervisor R. Englmeier, guality Assurance Superintendent
- C. Leppla, I&C Supervisor P. McCullough, Manager of Nuclear Training
- L. McLaughlin, Plant Licensing Superintendent
- B. Parks, guality Assurance Supervisor
- L. Rogers, Electrical Maintenance Supervisor
- N. Roos, guality Control Supervisor R. Sipos, Services Manager M. Shepherd, Operations Training Supervisor J. Spodick, Licensed Training Coordinator
- D. West, Technical Staff Supervisor J.
West, Mechanical Maintenance Supervisor W. White, Security Supervisor G.
Wood, Reliability and Support Supervisor
- E. Wunderlich, Reactor Engineering Supervisor Chairman Other licensee employees contacted included engineers, technicians, operators, training specialists, mechanics, security force members and office personnel.
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Review of Plant Operations (71707)
Unit 1 began and ended the inspection period in a refueling outage.
The unit was originally scheduled to return to service on March 3 Post-refueling criticality was achieved on April 14 and zero power physics testing was conducted, but the reactor was shut down from low power and cooled down on the 16th due to a RCP shaft seal package failure; the unit experienced an unusual event involving steam leakage from the SDC system during the cool down.
The major completion delay factors were:
a premature starting date, delays in getting contractor personnel approved for site entry under the new fitness for duty program, unexpected critical path work (e.g.,
containment fan cooler welds),
an unexpected critical path problem with polar crane operability, and the RCP seal failure.
Unit 2 began and ended the inspection period at power, day 89 on line.
A short wildcat strike on-March
by contract health physics field technicians against their employer had no adverse effect on plant operations.
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 CCW/ICW platform Unit 2 safety-related switchgear and cable spreading rooms Unit 2 ICW intake structure Unit 1 CCW/ICW platform Unit 1A HPS I
Inspection of Unit 2 Containment During Power Operations On March. 13,.the inspector accompanied operations, maintenance, and health physics'ersonnel on a Unit 2 containment anomaly inspection.
The personnel involved conducted themselves professionally.
Overall, the containment interior was dry and in order.
Some normal condensate was noted on the CCW cooling lines to the fan coolers.
Minor leakage at the vent fitting of Rosemount pressurizer level transmitter LT-1104 was noted and documented in NPWO 6057/62 for work during the next short term outage.
Per NPWO 3138/62 18C personnel unsuccessfully attempted to tighten a leaking fitting on valve V5183, a pressurizer steam space sample line isolation valve.
Valve V5183 was subsequently isolated and scheduled for repair during the next short term outage.
Unit 1 Containment Walkdown The inspectors walked down the Unit
containment following substantial completion of outage activities and prior to the unit entering mode 3.'he condition of equipment and attention to detail in.finishing work and restoring the work area has substantially improved in the last year.
This is attributed generally to management attention and specifically to management expectations being stated in writing -
as in attribute lists for supervisor inspections, upgraded procedures for completing outages, etc.
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 following safety-related tagouts (clearances)'ere reviewed:
1-1-113 1A CEA MG set 1-1-114 1B CEA MG set 2-3-65 pressurizer steam space isolation valve, Unit 2
2-4-16 HCV 3627 HPSI injection valve, Unit 2 The fol]owing safety-rel ated
.jumper/1 ifted lead requests were reviewed:
.
9-60 CETs T2, W6, and C4 for the QSPDS, Unit 2 9-58 HJTC 6 on "A" train, system 70, Unit 2 The following quality assurance activities and findings concerning control room operations were reviewed to determine if the objectives were being met:
installed plant instrumentation audits, control room activities audits, surveillance performance audits, and license amendment audits.
The above audits identified worthwhile findings that are actively being pursued by the quality groups and site departments.
c.
Technical Specification Compliance Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.
These verifica-tions 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,'nd the correct revision.
Instrumentation and recorder traces were observed for abnormalities.
Several pump and valves were placed into LCOs time limits this inspection period and were returned to service in a timely manner.
d.
Physical Protection The inspectors verified by observation during routine activities 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.
The inspectors, as a result of routine plant tours and various operational observations, determined that the general plant and system material conditions were being satisfactorily maintained, the plant security program was being effective, and that the overall performance of plant operations was good.
The condition of equipment and attention to detail in finishing work and restoring the work area has substantially improved
in the last year, primarily due to management attention.
No violations or deviations were identified.
3.
Surveillance Observations (61726)
Various plant operations were verified to comply with selected TS require-ments.
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 test(s)
were observed:
Portions of the Unit 1 containment ILRT were observed.
The test was per OP 1-130050, Rev 8, Integrated Leak Rate Test.
The inspectors had observed test preparations, clearance preparation, and hanging of clearance tags.
The Unit 1 integrated safeguards test was reperformed on April 1 per OP 1-0400050, Rev 21, Periodic Integrated Test of the Engineered Safety Features.
The retest was desired by the licensee because many maintenance and modification activities had affected ESF equipment during the outage.
Specifically, ATWS modifications affected the ESF control cabinets, the EDGs had been overhauled, several safety-related pumps had been overhauled, many safety related circuit breakers had been overhauled off site by a contractor, the plant computer and sequence of events recorder memories had been replaced, and over 1100 spare wires had been removed from the RTGBs.
The test was well controlled, with a pre-briefing, specific test activity assignments, and detailed use of procedures.
The test was initiated by manually opening feeder circuit breakers followed in one second by inserting an ESF signal at the ESF control cabinets.
The operators restored power using EOP 99, Rev. 0, Appendices, Figures, and Tables, Appendix D,
Power Restoration
Equipment functioned properly excepting the sequence timer for CVCS heat tracing, which was three seconds late.
It was subsequently adjusted.
Time response testing of the 1C AFW pump was observed after the unit entered mode 3.
Per OP 1-0400050, Rev 21, Periodic Integrated Test of Engineered Safety Features, Appendix D, Section 9, the test was performed twice, with steam being provided from 1A SG and then 1B SG.
The system performed as designed.
The test was conducted smoothly.
The inspectors determined that the above testing activities were performed in a satisfactory manner and met TS requirements.
No violations or deviations were identifie.
Safety System Walkdown (71710)
The inspector conducted a
walkdown of CCW in containment serving the containment fan.coolers to verify that the lineup was in accordance with license requirements for system operability and that the system drawing and procedure correctly reflected "as-built" plant conditions.
Drawings used in this review were:
8770-G-083, Rev 23, Flow Diagram, Component Cooling System.
BCS-081-189.3014, Rev 0, Large Bore Piping Isometric, Component
'Cooling Piping Rework BCS-081-189.3016, Rev 0, Large Bore Piping Isometric, Component Cooling Piping Rework BCS-081-189.3018, Rev 0, Large Bore Piping Isometric, Component Cooling Piping Rework BCS-081-189.3020, Rev 0, Large Bore Piping Isometric, Component Cooling Piping Rework As a result of this walkdown, the inspector found the system lineup to be in compliance with plant drawings and operating procedures, equipment material conditions to be satisfactory, and system component/equipment labeling to be adequate and correct.
No violations or deviations were identified.
5.
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 were 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:
NPWO 3369/61 accomplished charging pump plunger cartridge preparation with the supporting instructions of procedure 1-M-0041, Rev 10, Charging Pump Maintenance.
NPWO 3138/62 was discussed in section 2 abov NPWO 0827/62 replaced a
2A ICW pump packing leakoff line which had failed from water erosion.
The aluminum bronze material that had eroded and failed was replaced with aluminum bronze rather than monel because this alternate material was unavailable; NCR 2-328 was tracking the material problem.
NPWO 4979/62 and procedure MP 0940067, Rev 4,
MOVATS Testing of Motor Operated Valves, performed a
18 month PM on HPSI injection valve HCV 3627.
For those maintenance activities observed, the inspectors determined that they were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.
No violations or deviations were identified in the performance of the above NPWOs.
6.
Outage Activities (62703)
The inspector observed the following overhaul activity during the ongoing Unit 1 outage:
Appendix B to OP 1-0120020, Rev 49, Filling and Venting of the RCS, provided instructions for the venting of the CEDMs and RVLMS.
TC 1-90-151 to the procedure, in effect at the time, added clarifying torque wrench usage instructions.
The procedure was also unclear concerning RCS pressure and temperature conditions prior to or during venting but the operations management provided clarification during the work via a procedure change.
Similarly, a change was submitted on the voiding of the cavity above the vent valve that is part of a secondary pressure boundary for the CEDMs; the procedure required removal of the water from the cavity but did not specify the amount to be removed for thermal expansion capacity in the cavity at normal operating temperatures.
During the torquing, one of the operators-dropped an extension, socket, and adaptor onto the reactor vessel head.
No damage occurred and the dropped tools were retrieved.
The licensee did not observe the precautionary measures of attaching lanyards to tools to prevent loss.
The personnel using the wrenches had no mockup training and the preliminary venting demonstrated this; once the job task was practiced, work routine efficiency was improved.
A SRO who had performed the venting previously was on hand and provided training to the personnel at the job site.
The licensee was considering mockup training as a future option.
Portions of the containment ILRT were observed as undiscussed in section 3 above.
NPWOs 3386 to 3389 were generated to investigate vibration problems involving the three Unit
CCW pumps and/or systems.
During high
flow conditions, significant vibration was identified on the CCW platform.
This investigation was not completed by the end of the inspection period.
On April 13, the 1A2 RCP shaft seal package had not "staged", i.e.,
achieved proper pressure breakdown between seal stages or developed correct sealing joints between at least one seal of four at low RCS pressures.
Seals sometime require elevated pressures and temperature to operate/seat correctly and the decision to work the seal was deferred until power was achieved.
The reactor was taken critical on the 14th and held at low power.
By the the 15th, the seal condition had worsened and management had determined to cooldown and replace the seal package.
The seal was replaced after the inspection period.
Many outage activities addressed above and throughout this report were viewed by the licensee with fresh interest and were reanalyzed in light of new operational options and maintenance techniques.
This new attitude should provide long-term positive results for the licensee.
No violations or deviations were identified.
7.
Installation and Testing of Modifications During this Unit 1 outage, selected modifications were reviewed to ensure conformance with design and adequate installation testing and preoperational testing to verify satisfactory operation.
Three modifications were reviewed:
Containment Cooler Coil Replacement and Upgrade This modification per PCM 081-189 replaced the containment cooler coils, which were deteriorating, their support structural and the cooler box bottom liners, but retained other cooler structural parts.
Drawings primarily utilized in this review were:
BCS-081-189.3009, sh 1, Rev 1, RCFC Replacement Coil Bank Support and Enclosure Assy.
BCS-081-189.3009, sh 2, Rev 1, RCFC Replacement Coil Bank Support and Enclosure Assy.
BCS-081-189.3010, sh 1, Rev 1, RCFC Replacement Coil Bank Support and Enclosure Assy Details.
BCS-081-189.3011, sh 1,
Rev 1, RCFC Manifold Pipe Support Assembly Westinghouse 8224D42, Rev 3, Reactor Containment Fan Cooler General Assembly Since the replacements were of installed structural equipment, a
number of minor drawing deviations were required.
A substantial
sample of these was reviewed with the engineering staff for proper processing, coordination with the cooler design agent (Westinghouse),
and fiel.d implementation.
DCNs reviewed were:
1377, 1382, 1411, 1418, 1419, 1420, 1427, 1428, 1432, 1445, 1450, 1451, 1457, 1580, 1605, 1631, 1643, 1648, 1658, and 1659.
These were well handled.
The inspector's review found several long-term deviations from the existing design drawing involving failure to use lock washers and/or double nuts on pipe supports and clamps, such as U-bolts, and on pipe-bracket-to-cooler-casing mounting bolts.
Following engineering division evaluation, the subject nuts were staked in three places each since there was not always room for another nut.
During the installation, due to orientation problems, the three-inch pipe flanges between the CCW headers and cooler coils did not fit.
When the CCW header pipe stubs were cut out to be refitted, the licensee discovered that the pipe joints (about 300)
were not full penetration welds as required.
These headers had been supplied as part of the cooler packages during original construction.
Most of the joints were cut out and refabricated to the ASME Code,Section III, Class 3, which involved full penetration pipe welds with quality control inspection.
A few welded joints with backing rings were evaluated by the licensee as acceptable and were not cut out.
ATWS modification This modification per PCM 102-189 installed a diverse scram system in Unit 1 to meet the requirements of 10CFR 50.62.
It was designed to provide overpressure protection during an ATWS event using existing pressurizer pressure instrumentation to generate a reactor scram independent of the RPS.
The pressurizer pressure instrumentation used fed the ESF panel.
The ESF panel was modified to include logic and trip settings for ATWS mitigation.
The output was routed to new contactors in the CEDMCS MG sets'utput circuits.
These would interrupt power to the CEAs when open and, through auxiliary contacts and relays, would also trip open the normal CEDMCS MG set output circuit breakers.
Material used in this review primarily consisted of PCM 102-189, drawings as shown and test procedures as shown:
BCS-102-189.3002, Pressurizer Pressure P-1102A Measurement Loop BCS-102-189.3004, Pressurizer Pressure P-11028 Measurement Loop BCS-102-189.3006, Pressurizer Pressure P-1102C Measurement Loop BCS-102-189.3008, Pressurizer Pressure P-1102D Measurement Loop BCS-102-189.3009, CEA Drive MG Set 1A Panel
BCS-102-189.3010, CEA Drive MG Set 1B Panel BCS-102-189.3030, CEA Drive MG Sets Elementary and Connection Diagram BCS-102-189.3031, CEA Drive MG Sets Elementary and Connection Diagram i
BCS-102-189.3032, CEA Drive MG Sets Elementary and Connection Diagram Preoperational Test 1-1400199, Rev 0, TC 1-90-192, ATWS Preoperational Test I&C Procedure 1-1400166, Rev 8, Engineered Safeguards System-ATI Alignment Check (which was step 12. 12.2 in 1-1400199 above)
I&C Procedure 1-1400052, Rev 27, TC 1-90-183, Engineered Safeguards Actuation System Channel Functional Test, Section 9.2 I&C Procedure 1-1400071, Rev 0, ATWS Functional Test Field activities and workmanship were observed during the modification.
Construction activities were closely monitored by the electrical and I&C departments.
The Consolidated Controls Corporation design engineer for the ESF system was on site and actively involved with the modification.
Testing by the operating plant staff was thorough.
The final test of the newly installed ATWS circuit per I&C procedure 1-1400071, Rev 0, was observed during Unit 1 heatup.
The test was satisfactory and the circuits functioned as designed.
Because the ATI system had been modified as part of the ATWS modification, it was also tested.
Post modification testing revealed that the ATI system did not indicate properly in all cases.
The vendor will provide resistors of a different value to restore the indication function.
MSIV Upgrade The preoperational and surveillance tests of the redesigned Unit
MSIV air operator control and test systems per OP 1-0810050, Rev 9, TC 1-90-236, Main Steam Valves Periodic Test, and OP 1-0400050, Rev 21, Periodic Integrated Test of the Engineered Safety Features, Section 8.3, were observed during Unit 1 heatup.
The modification was intended primarily to reduce the peak energy generated during MSIV closure at power and also to generally upgrade the control system.
It relocated the controls from the valve operator to the adjacent structure; reconfigured and resized the piping to facilitate
maintenance, testing, and operation; and provided for new, more comprehensive tests.
The test circuit DC relay contacts and pressure switch contacts failed during post-modification surveillance testing because of the size of the solenoid being operated.
Subsequent review of GE design data sheet GEH-2024 for HFA relays showed that the relay contacts were rated for 3 A
DC resistive load but not rated for an inductive load.
Review of the AGASTAT design data sheets for series GP power relays showed that the contacts were not rated for more than 0.8 A DC inductive load.
The solenoid valves described provided a 1.25 A DC inductive load.
The circuit was redesigned to use double relay contacts in series and operated well during final testing.
EPRI research supported the downward adjustment of the resistive load rating to account for inductive loading.
This data also supported the increase in current interruption ratings if series contacts were used.
This information was used in the system design and was consistent with the final "as-built" design.
Based on the above review, the licensee has been found to be sensitive to as-found field conditions affecting modifications.
No violations or deviations were identified with the above observations.
8.
Onsite Followup of Events (Units I and 2)(93702)
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.
for Potential generic impact and trend detection were also considered.
On March 9, while the licensee was lowering the Unit I reactor head onto the reactor vessel, the crane operator noticed erratic hoist operation.
When the primary mechanical brake was found to be overheated and smoking, the operator stopped movement of the load, which was suspended over the reactor vessel.
Investigation began immediately and continued for several days.
The reactor head was returned to its storage stand later that night and was subsequently installed on the reactor vessel on March 14.
The inspectors observed portions of the troubleshooting and engineering review, and observed part of the first movement to return the reactor head to its storage stand.
Investigation and evaluation showed that the brake damage proximate cause was the dynamic brake being deenergized by a blown fuse during the head lift coupled with repeated operation of the heavily loaded mechanical brakes, resulting in overheating the primary mechanical brake.
The electrical fuse problem was traced to plant change/modification 047-190D that changed the load cell power supply from the crane control circuit to the utility circuit.
This change prevented the load cell from being deenergized (requiring calibration)
each time the operator pushed the STOP button prior to leaving the crane unattended for short periods.
Unknown
by the 1 icensee at the time, the crane control circuit and the uti 1 ity circuit were actually supplied from different phases of the three-phase electrical supply rather than being supplied from the same phase as shown on drawings.
This'esulted in the installed modification not working properly.
The inspectors, based on their review and observations, determined that the licensee performed in a satisfactory manner and took prompt corrective actions (i.e.,
appropriate engineering review and troubleshooting)
to return the reactor head to its storage stand.
On March 17, Unit 1 shutdown cooling train A failed when valve V3481, hot leg suction to LPSI pump 1A, closed from an automatic shut signal.
Valve V3651, hot leg suction to LPSI pump 1B, lost valve position indication in the control room during the event.
The operator secured LPSI pump 1A due to V3481 closure, however, the operator did not secure LPSI pump 1B based on normal pump motor current and flow indications.
One loop of shutdown cooling was thus maintained.
Subsequent to V3481 closing, the operations staff attempted several times to reopen the valve and reestablish A train shutdown cooling, however no indication of valve travel was apparent in the control room and the valve switch was returned to the shut position.
The valve was subsequently reopened and A train shutdown cooling reestablished.
A blown control power fuse caused the loss of indication.
Subsequent licensee investigation determined that the shut signal was generated when electricians removed a spare wire from the PIC-1103 63k relay in accordance with NPWO 5423 and CWO 6931.
This maintenance activity involved removing spare wires from the RTGBs, CRAG and PAP panels, and Raychem capping remaining spare cables.
PI-1103, through the associated 63k relay, provided isolation signals to both V3481 and V3651 on increasing reactor pressure (approximately 300 psig) to isolate the low pressure portion of the LPSI system from the RCS when the LPSI system was used for shutdown cooling.
When the spare wire was lifted along with other wires, the 63k relay was deenergized and signaled both valves to close.
The process of removing the spare wire and relanding the remaining leads took approximately 8 seconds.
Subsequent testing by the licensee determined that the shut signal took approximately 9 seconds to seal-in, at which point the valve would indicate intermediate position and would travel to the full closed position.
The. licensee believed that valve V3651 did not shut because the shut signal was not present long enough to seal-in for valve V3651.
The licensee believed that the control power fuse blew when the valve motor attempted to reverse direction from close to open when the relay was reenergized.
The licensee also believed that the operators were unable to open V3481 immediately after it went shut because the operators did not hold the switch in the open position long enough to receive dual indication on the valve prior to returning the switch to the shut position.
No violations or deviations were-identified in the above are.
Followup (Units 1 and 2) (92701)
a.
Fol1owup of Inspection Identified Items In response to a meeting held in the Region II office on December 22, 1989, between the NRC and FPL officials (reference meeting summary dated February 20, 1990),
an operator licensing examiner monitored the activities related to licensed operator requalification training for EOP-15, Functional Recovery.
Several NRC inspection/examination reports have documented the concern over operator performance on this EOP; during this meeting the licensee outlined corrective actions which were planned to correct this deficiency.
The examiner observed this training/evaluation on March 1 - 2, 1990.
Two crews of operators were observed by the examiner, the scenarios used to train and evaluate the operators consisted of multiple events and were appropriately challenging to the EOP.
In their usage of EOP-15, the operators did not exhibit any reluctance to enter the procedure, nor did they exhibit any significant deficiencies in their ability to make correct transitions or effectively implement the procedure.
The licensee has made several procedural changes in response to sessions held with the licensed SROs.
These changes appear to have enhanced the operators'bility to manipulate the procedure; the operators'onfidence level with the procedure has also improved.
The operators did display weaknesses in areas other than EOP-15 during this observation; however, the licensee's evaluators noted these deficiencies and provided feedback to the operators to correct the weaknesses.
Specifically, the first crew of operators displayed poor comnunication skills, the second crew had difficulty with event classification, cool-down rate control, feeding a ruptured steam generator and HPSI throttling criteria.
The evaluators identified the problem areas and initiated proper corrective. actions to resolve the performance problems.
The licensee used their simulator evaluators to assess operator performance, and, additionally, has used a Management Oversight Team to conduct independent evaluations of operator performance.
This independent evaluation team consisted of plant, corporate, and/or other utility personnel (two evaluators from Millstone, one from Juno Beach, and one from Turkey Point were used during the retraining/evaluation cycles).
Both sets of evaluators were very adept at assessing operator performance, their observations were astute and their ability to properly evaluate the significance of a given operator action was extremely high.
The examiner noted that the licensee has made extensive use of video tape to evaluate operator performance and give feedback to the operators.
Additionally, the simulator instructors have provided impetus for several plant changes as a result of regular simulator training.
This was a concern documented in previous examination reports.
During
this observation, the examiner noted an improved awareness of plant/procedural deficiencies by the simulator staff.
The examiner reviewed the activities outlined in the letter submitted by FPL on December 22, 1989, concerning the commitments made to strengthen the licensed operators'bility to maintain plant safety.
The examiner found that the licensee has implemented all of 'the commitments, and that the operators observed showed marked improvement in their knowledge, skills, and abilities concerning EOP-15.
The NRC will continue to monitor the operators'nowledge, skills, and abilities related to EOP-15, and other procedures, during routine inspection and examination visits.
No violations or deviations were identified in this area.
Followup of Headquarters and Regional Requests NRC Region II requested a review of information that, in the third quarter of 1987, during a performance based maintenance training test, the instructor left the room and information was passed between two or more students.
Inspector review of this information included discussion with knowledgeable licensee personnel and review of objective evidence such as memoranda and instructions.
On September 18, 1987, an individual did send a
memorandum to the site vice president alleging unnamed violations of the site TDIs during PBT and refusing to reveal details to any lower level person.
This memorandum was referred to the plant manager because the individual made no effort to follow the plant organization structure in resolving the concern.
On March 2, 1988, the individual sent a second memorandum to the site vice president requesting a mee'ting regarding specific TDI violations and requested help in resolving the issue at the company level.
On March 4, 1988, the site vice president met with the individual.
Several training issues were presented:
Examinees did not receive instruction in examination confidentiality.
Instructors subsequently left the room during examinations and conversation occurred between examinees.
Examination questions being word for word out of the book with the examination being an "open book" examination.
These were assigned to the training department for review and response.
On March 8, 1988, the site vice president contacted the concerned individual, thanked him for his input, indicated that in both cases
the individual was correct to be concerned, and that the necessary action would be taken to correct the problem areas.
An April 13; 1988, internal training memorandum showed that:
All instructors in Specialty and Maintenance Training had been counseled in TDI-9 on examinations, particularly regarding explaining examination rules to each group prior to administering examinations and ensuring that an instructor or training staff member was present at all times during an examination.
The subject of open book examinations or tests was clarified.
The licensee found that there were no open book examinations administered in Specialty and Maintenance Training.
About 7 percent of the questions in that technical area may be verbatim from the text, objectives, or examinations.
They would be specific to a component and must be verbatim.
Review of training department procedures concerning examination management showed that two procedures were in effect in August, 1987:
TDI-9, Rev 1, Licensed. Operator Written Examination Management, provided strict control of all aspects of examination preparation, administration, and grading.
This control included verbal instructions to examinees and proctoring as necessary of examinations in progress.
It did not include detailed written instructions to the examinee on the examination cover sheet. It did not apply to other types of training.
TDI-24, Rev 1, Written Examination Management, applied to plant training programs other than licensed operator training.
This control also included verbal instructions to examinees and proctoring as necessary of examinations in progress.
It did not include detailed written instructions to the examinee on the examination cover sheet.
These were combined for reasons other than the subject'oncern in December, 1987, and titled TDI-9, Rev 2,
Written Examination Management.
This version included detailed written instructions to the examinee on the examination cover sheet.
Subsequently, TDI-9, Rev 2,
was superseded by AP-0005754, Rev 0, Written Examination Management, which continues to include detailed written instructions to the examinee on the examination cover sheet.
The inspector could not confirm the details of an actual occurrence but concluded from objective evidence that a valid concern was accepted by plant management and acted upon.,
No violations or deviations were identified in this are Review of Strike Activities (92710)
On March 29, contract health physics field technicians conducted a short wildcat strif<e. at't.
Lucie, among other sites, seeking bargaining recognition of a particular union by their employer, The Institute of Resource Management ( IRM).
Because the Unit 1 refueling outage was nearing completion, the number of contract health physics technicians at St. Lucie had decreased from about 60 to about 20.
On March 26, a sickout (workers calling in sick) kept all remaining field technicians off site.
On March 27 and 28, work attendance was normal.
On March 29, previously laid off IRM employees picketed all gates for a short time from about 5:30 am to 8:30 am.
The FPL-IRM contract was canceled for non-performance and the pickets departed since IRM was no longer associated with St. Lucie.
A number of FPL operators and mechanics honored the pickets, however shift manning was not affected other than some delayed turnovers.
Adequate non-union coverage was avalilable for shift work if needed.
No violations or deviations were identified in this area.
Exit Interview (30703)
The inspection scope and findings were summarized on April 20 with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed the inspection findings.
Proprietary material is not contained in this report.
Dissenting comnents were not received from the licensee.
Abbreviations, Acronyms, and Initialisms A
AB ABB AC ADV A/E AFAS AFW ALARA ANPO ANPS ANSI AP ASME Code ATI ATWS BCS BQAP CAR Ampere(s)
Auxiliary Building ASEA Brown Boveri (company)
Alternating Current Atmospheric Dump Valve Architect/Engineer Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
As Low as Reasonably Achievable (radiation exposure)
Auxiliary Nuclear Plant [unlicensed] Operator Assistant Nuclear Plant Supervisor American National Standards Institute Administrative Procedure American Society of Mechanical Engineers Boiler and Pressure Vessel Code Automatic Test Instrument (in the ESF cabinets)
Anticipated Transient Without Scram Backfit Construction Sketch Backfit Quality Assurance Procedure (EBASCO Services Inc.)
Corrective Action Request
Pe CCW CE CEA CEDM CEDMCS CET CFR CIS CRAG CS CST CT CVCS CWD CWO DC DCN DDPS DEV DPR ECCS EDG EOP EPRI ESF F
FCV FI FIS FPL FRG FSAR FT GDC GE GL GMP gpm HCV HFA HJTC HP HPSI HVE HVS HX I&C ICW IFI ILRT
Component Cooling Water Combustion Engineering (company)
Control Element Assembly Control Element Drive Mechanism Control Element Drive Mechanism Control System Core Exit Thermocouple Code of Federal Regulations Containment Isolation System Control Room Auxiliary Control (panel)
Containment Spray (system)
Condensate Storage Tank Current Transformer Chemical
& Volume Control System Control Wiring Diagram Construction Work Order Direct Current Design Change Notice Digital Data Processing System Deviation (from Codes, Standards, Comnitments, etc.)
Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Emergency Diesel Generator Emergency Operating Procedure Electric Power Research Institute Engineered Safety Feature Fahrenheit Flow Control Valve Flow Indicator Flow Indicator/Switch 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 Heated Junction ThermoCouple 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 Test(ing)
IN INPO IR ISI IX JPE JPN KW LC LCO LER LIV LOI LPSI LT LTOP MSTE MCC MFIV MFP MG min MOV MOVATS mrem MP MSIV MSR MV MW NCR NCV NDE NPF NPO NPS NPWO NRC NSSS OI ONOP OP PAP PBT PCM PCV PAID PI PIC PIS
[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 Event Report Licensee Identified Violation Letter of Instruction Low Pressure Safety Injection (system)
Level Transmitter Low Temperature Overpressure Protection Measuring 5 Test Equipment Motor Control Center (electrical distri Main Feed Isolation Valve Main Feed Pump Motor Generator minute Motor Operated Valve Motor Operated Valve Test System millirem Maintenance Procedure Main Steam Isolation Valve Moisture Separator/Reheater Motorized Valve Megawatt(s)
Non Conformance Report NonCited Violation (of NRC requirements Non Destructive Examination Nuclear Production Facility (a type of 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 Post Accident Panel Performance Based Training Plant Change/Modification Pressure Control Valve Piping 5 Instrumentation Diagram Pressure Indicator Pressure Indicator/Controller Pressure Indicator/Switch (system)
bution)
license)
PN PORV psig ppm PT PWO PWR QA QC QI QSPDS RAB
, RCB RCFC RCO RCP RCPB RCS RDT Rev RG RO RPS RTGB RVLMS RWT SAL SALP SAS SDC SDCS SG SI SIT SNOW SNPO SRO STA Tavg TC TCB TCW TDI TE TEDB TI TMI TR TS URI 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 System Reactor Auxiliary Building Reactor Containment Building Reactor Compartment Fan Cooler 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 Reactor Turbine Generator Board Reactor Vessel Level Monitoring System Refueling Water Tank Service Advice Letter Systematic Assessment of Licensee Perfo'rmance Safety Assessment System Shut Down Cooling Shut Down Cooling System Steam Generator Safety Injection (system)
Safety Injection Tank Short Notice Outage Work Senior Nuclear Plant [unlicensed] Operator-Senior Reactor [licensed] Operator Shift Technical Advisor Reactor average temperature Temporary Change Trip Circuit Breaker Turbine Cooling Water Training Department Instruction Temperature Element Total Equipment Data Base
[NRC] Temporary Instruction Three Nile Island Temperature Recorder Technical Specification(s)
[NRC] Unresolved Item
Volume Control Tank Violation (of NRC requirements)