IR 05000335/1989016
| ML17223A297 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/15/1989 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A295 | List: |
| References | |
| 50-335-89-16, 50-389-89-16, NUDOCS 8908250208 | |
| Download: ML17223A297 (25) | |
Text
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UNITEO STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos:
50-335/89-16 AND 50-389/89-16 Licensee:
Florida Power 5 Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 License Nos.:
DPR-67 and NPF-16 Facility Name:
St.
Lucie 1 and
Inspection Conducte
.
ril 10 - June 12, 1989 Inspectors:
S.
A.
od, nior Resi ent inspector
. A.
S
,
esid Inspector Approved By:
R.
V.
rlenj
, Section ief Division of Reactor Projects g/> /
at Signed D
e igned Date gned SUMMARY Scope:
This routine resident inspection was conducted onsite in the areas of plant tours, plant operations review, Technical Specification. compliance, maintenance observations, review of nonroutine events, physical protection, surveillance observations, outage activities, review of special reports, drawing control, and licensee action on previous inspection findings.
Results:
An unresolved item* identified in a previous report, concerning operability of containment coolers, remained unresolved after further inspection during this period.
Subsequent to the previous inspection of Unit 2 containment while in Mode 4,
when containment cooler door discrepancies were identified, discrepancies were also identified on Unit 1 while operating.
Additionally, a
follow-up inspection of Unit
revealed that previously noted deficiencies were not completely corrected prior to the unit entering mode 3.
Weaknesses were identified in the design and implementation aspects of the design change program.
These concerned the consideration of missile hazards, the documen-tation of items considered, the implementation of the completed design, and informal design by the plant staff in lieu of the engineering staff.
Many operational activities related to ending a major outage were observed.
Most were well planned and executed.
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One violation regarding failure to preclude missile hazards resulting from the installation of compressed gas cylinders, paragraph 3.
One non-cited violation regarding failure to follow procedures for equipment clearance.release and independent verification, paragraph 4.
One non-cited violation regarding failure to install Class 1E equipment in containment in accordance with drawings, paragraph 13.
- Unresolved items are matters about which more information is required to determine whether they are acceptable or may involve violations or deviation 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 ST Brain, Independent Safety Evaluation Group
- H. Buchanan, Health Physics Supervisor
- C. Burton, Operations Supervisor
- C. Crider, Outage Supervisor
- D. Culpepper, Site Juno Engineering Manager
- R. Dawson, Maintenance Superintendent R. Frechette, Chemistry Supervisor
- J. Harper, Superintendent C. Leppla, ISC Supervisor
- L. McLaughlin, Plant licensing Supervisor V. Mendoza, System Engineer L. Rogers, Electrical Maintenance Supervisor N. Roos, guality Control Supervisor B. Sculthorpe, Reliability and Support Supervisor R. Sipos, Service Manager
- D. West, Technical Staff Supervisor
- J. West, Operations Department W. White, Security Supervisor
- C. Wilson, Mechanical Maintenance
'E.
Wunderlich, Reactor Engineering Supervisor 0ther licensee employees contacted included engineers, technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Plant Status Unit 1 began and ended the inspection period at power.
The unit ended th 1 nspection period in day 263 of power operation.
During this inspection e
period plant performance and operations were routine and uneventful with respect to non routine events.
Unit
began the inspection period in day 69 of a maintenance and refueling outage that began on February 1, 1989.
Unit 2 entered mode 4 on April 13 and mode
on April 14.
Loop check valve 3227 for loop 2A1 was found to leak at pressure.
The startup was'uspended for evaluation of the condition.
The unit was returned to cold shutdown on April 16 because
of continued loop check valve 3227 leakage and leakage of pressurizer code safety valves 1200 and 1201.
Following repairs, the unit was started up on April 23 and commenced power operation on April 28.
Unit 2 ended the inspection period in day 43 of power operation.
During this inspection period, Mr. Arie de Joode of The Netherlands Ministry for Social Affairs and Employment, Nuclear Safety Department, visited the inspectors to discuss inspection programs and techniques.
3.
Plant Tours (71707).
Plant tours were periodically conducted to verify that monitoring equip-ment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditi'ons, 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 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 ECCS systems.
Valve, breaker and switch lineups and equipment conditions were randomly verified both locally and in the control room.
The inspectors conducted a complete walkdown in the accessible areas of the Unit
AFW system and Unit 2 Containment Spray system to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory.
The following items were noted during the plant tours:
Containment Walkdowns The inspector accompanied site personnel during an anomaly inspection of the Unit
RCB with the unit at power on April 12.
Anomaly inspections are intended to discover normally-unseen problems at power, to perform routine surveillances, and to perform minor valve alignments.
The entry crew consisted of one HP technician, one SNPO, and the inspector.
Prior to entry, the crew was briefed on the radiological requirements and restrictions by the HP technician and his supervisor.
During the tour, the HP technician used radiation detectors to determine dose rate and generally led the way.
The crew stayed together while inside the RCB.
During the walkdown, the following was found:
The 1B instrument air compressor had some minor seal leakage. It was noted by the inspectors that, this leakage did not affect the operability of the compressor and that the automatic leakage makeup feature was performing satisfactory.
After leaving the RCB, the operator wrote a
PMO to initiate repair.
Compressor observation was one of the routine inspection items.
There was a dripping leak at a valve beneath PT 3321 that had created some standing water in the safety injection trench.
A PWO had been written against the leakage.
At the letdown regenerative heat exchanger, there appeared to be some dried leakage.
The material was black in color.
The material may have been there for some time; regardless, the SNPO recorded the information on his entry log and informed the NPS.
At NRC request, the SNPO checked the condition of the contain-ment cooler's access door dogs.
Containment coolers are part of the containment heat removal system.
Several dogs were not properly positioned.
Door check results are discussed further in paragraph 11.
During a Unit 2 RCB tour on April 15, the Unit 2 containment cooler doors were inspected for 'closure.
The unit was in mode 3 and the coolers were required to be operable in that mode per TS 3.6.2.3.
Several door dogs were in position but loose, i.e., not squeezing the door gasket against the mating knife edge.
This condition is discussed further in paragraph 13.
During that tour, other minor discrepancies were observed and identified to the licensee for evaluation and correction.
b.
Compressed Gas Cylinders On May 17, a poorly mounted compressed gas cylinder (missile hazard)
was observed in the 1B EDG room.
This cylinder was used to pressur-ize the fire suppression sprinkler system with Nitrogen.
A past plant modification to add an air dryer to the EDG starting air system placed an electrical conduit in an interfering position.
The cylinder then stood away from the wall with a slack mounting chain.
This rendered the cylinder susceptible to falling over.
Further review of the 1A EDG room showed no similar problems.
Subsequent to the inspection, it was discovered that the design change installing the air dryer also relocated the nitrogen cylinder out of the room.
The modification was reported as complete in 1985.
'ANSI N18.7-1976, sections 5.2.7 and 5.2.17, invoked by site and corporate procedures, requires proper completion and inspection of design changes; After the NRC identified the missile hazard concern, the licensee found the uncompleted design package for relocating the nitrogen cylinder.
The cylinder has subsequently been relocated as required by the 1985 desig Review of the Unit 2 EDG sprinkler pressurization system showed that each EDG room had it's own sprinkler pressurization system and that the nitrogen cylinders were located outside the EOG rooms on opposite sides of the building in corners under the air intake overhangs.
The cylinders each had a substantial restraining bracket structure made of angle iron, but they were located very high on the cylinders and were significantly oversized.
The restraints would prevent tipover but, in a seismic event, the cylinders could slide out of the bottom and fall.
The 2A EOG cylinder installation was in close proximity to the Unit 2 RWT and it's appurtenances.
There was nothing of safety significance near the 2B EDG cylinder installation.
The licensee could not locate design information for these rack designs.
Further review of gas cylinder storage in safety-related areas showed a
nitrogen cylinder stored against a handrail in the 2A steam trestle area near the 2A steam isolation valve, the two 2A feed isolation valves, the eight steam code safety valves, and the two 2A steam system power operated relief valves.
This installation had no apparent purpose except for the very infrequent charging of Hain Feed Isolation Valve Accumulators, when a cylinder of nitrogen could be temporarily positioned in the area.
The installation used a single loose chain loop that did not appear to possess any particular seismic qualities.
Subsequent to the inspection, it was determined that this installation was not designed by the engineering design group, but was informally designed and installed by the plant maintenance group.
ANSI N45.2. 11 and implementing procedures require that the design organization prepare modification packages as discussed below.
Subsequent discussion with the plant staff highlighted two additional gas cylinder storage problems which are considered licensee-identified.
First, nitrogen cylinders were used to pressurize the charging pump accumulators.
A local rack was not provided.
Temporary storage was not always satisfactory.
Second, fire extinguishers in Unit 1 safety-related areas had several bracket styles, including merely a small hook.
It was not apparent that seismic events were considered when the mounting brackets were being selected.
No design information could be located for the Unit 1 fire extinguisher mounting and location design.
Criterion III, as implemented by FPL Topical guality Assurance Report 1-76A, Rev 15, T(R 3.0, requires that design inputs be specified and correctly translated into design output documents.
ANSI Standard N45.2. 11 - 1974, Section 3, invoked by the topical report Appendix C, echoes this requirement.
ANSI N45.2.11, Section 3.2, further requires that design inputs include:
Loads, such as seismic, wind, thermal, and dynamic; Mechanical Requirements, such as vibration, stress, shock, and reaction forces; Structural Requirements covering such items as equipment foundations and pipe supports; and Interface Requirements including definition of the functional and physical interfaces involving structures, systems and components.
ANSI N45.2.11 Section 4 further requires that methods shall provide for relating the final design back to the source of design input, and
that design activities be documented in sufficient detail to permit certain verification and auditing.
The, design inputs for the adequate mounting of compressed gas
.cylinders in safety related eauipment areas and the protection of safety related components such as the main steam isolation valves, refueling water tank appurtenances, and main feed isolation valves from missile effects of damaged compressed gas cylinders had not been considered or had not been translated into output documents.
In some cases the design process had been ignored or was not implemented in the resulting modification.
This is identified as Violation 335,389/89-16-02, Failure to Preclude Nissle Hazards Resulting From The Installation Of Compressed Gas Cylinders.
4.
Plant Operations Review (71707)
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.
In addition, the inspectors verified.
Control room annunciator status.
The inspectors specifically reviewed the following tagouts (clearances):
1-5-88
- Inspect Check Valve V-06130 for the 1-C gas decay tank.
(PWO 2728)
1-8-404 - Administratively Controlled Equipment 1A BAMT heater B breaker 42048 1B BAMT heater B breaker 42116 Polar Crane breaker 405516 Jib Boom Crane breaker 42030 HVS - 11 Decon Room Fan breaker 42063 HVS - 36 Decon Room Fan breaker 42064 1-10-60 - Personnel Air lock Power 2-5-14
- 2B Fuel Pool Cooling Pump 2-4-149 - Movable Incore Detector 2-3-324 - Diesel Fuel Oil Piping between Units
2-3-375 - Administratively Controlled Equipment SDC Isolation Valve breaker i 42013 Jib Crane breaker 842151 SIT Isolation Valve breaker 442048 2-4-245 - Pressurizer Heater G-4 Under clearance 2-4-245, pressurizer heater G-4 had a tagged out breaker that was physically located inside the containment.
The breaker was not indicated in procedure AP 0010726, Power Distribution Breaker List, Rev.
3, which made it's location difficult to find.
The licensee indicated that they would submit a procedure change.
The inspectors identified a clearance tag, which did not reference a
current clearance control number, hung at circuit breaker number 26 in the Unit
125 VDC non-safety-related power panel 138.
The circuit fuse, which was removed, was for a reflash module in the control room.
There were no active records in the control room for the tag as required by procedure OP 0010122, Rev.
39, In Plant Clearance Orders.
Examination of released clearances in the records vault found that the tag had been signed for as being released and that its removal had been independently verified as being completed.
There were other clearance-associated tags that had been handled correctly.
When the referenced tag was found by the NRC, the licensee performed a survey of control room records and discussed the event with the various operating shifts.
The site performed a
complete review of all power panels and controlled valves.
No other anomalies were noted.
The failure to properly clear the above tag violated procedure OP 0010122, and TS 6.8.1.a which requires that the procedures recommended in Appendix "A" of RG 1.33, Rev. 2, be implemented.
Appendix
"A" includes a
recommendation of procedures for equipment control, e.g.,
locking and tagging.
This NRC identified violation is not being cited because criteria specified in Section Y.A. of the NRC Enforcement Policy were satisfied.
This item is identified as non-cited violation (NCV) 335/89-16-03.
The control room operators were observed pulling CEAs on April 14 and again on April 23 for startup.
In both cases, procedures were carefully used, the operators discussed ongoing operations with the SRO, the audible count rate monitor was in operation, and the operators were sensitive to RCS temperature, boron concentration, and NTC.
The control room operators were observed conducting a plant cooldown on April 16 in accordance with OP 2-0030127, Rev.
29, TC 2-89-8, Reactor Plant Cooldown - Hot Standby to Cold Shutdown.
The procedure was open and in use.
The cooldown and entry into mode 5 was routine and uneventful.
The cooldown was conducted primarily to repair leaking loop 2Al check valve 3227 and leaking pressurizer code safety valves 1200 and 1201.
Performance of OP 2-0210021, Rev.
4, Volume Control Tank Hydrogen and Nitrogen Concentration Control, was observed during startup efforts on April 22-23.
The procedure established initial gas concentrations prior to criticality for primary chemistry maintenance.
At the same time, the
i preparation for filling and pressurizing the four SITs was observed at an adjacent control panel.
The HPSI headers were recirculated prior to beginning the filling to insure that the proper boron concentration was available.
The observed control room operations showed strengths in folowing operational procedures and control room operator alertness.
In addition, the review conducted by the licensee following the discovery of the improperly cleared tag was addressed and corrected in an expeditious manner.
5.
6.
Technical Specification Compliance (Units 1 and 2) (71707)
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, valv'e 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.
Naintenance Observation (62703)
Station maintenance activities involving selected safety-related systems and components were 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:
PWO 8083/62, PORV Inspection and Test, addressed rolled, or reversed, leads for accelerometers downstream of pressurizer PORVs.
These accelerometers provide acoustic annunciation of pressurizer PORV or code safety valve lift by sensing the vibration of the valve tailpipe.
I&C personnel removed the flow accelerometers from the tailpipes at the beginning of each refueling outage and then reinstalled them at outage completion.
ISC had replaced the accelerometers after being told that work in the area around the valves had been completed.
Subsequent insulation work in the area damaged several accelerometers.
The licensee replaced the accelerometers and upon post-installation functional testing, it was noted that two of the leads had been rolled on valves V1474 and
V1475, causing indication reversal.
The inspectors found that the problem had been properly corrected and the PWO implemented in a satisfactory manner.
The inspectors noted that when the flow indicators were replaced, they were marked with plastic tags.
These plastic tags are damaged in the high temperature atmosphere of the pressurizer space.
This condition could have contributed to the rolled leads.
When discussed with the licensee, there were plans to identify these sensors and,leads with tags appropriate to the application.
On April 22, during a Unit 2 startup attempt, maintenance on RPS channel A
was observed
.
The startup rate meter and annunciator for the pre-trip of the A rate instrument indicated unusually high count rates.
A technician made preliminary measurements of the B channel to determine that the rate input was in error and then had a
PWO written.
The false high count rates could cause the channel to trip early during initial criticality and perhaps cause an unnecessary plant trip.
The licensee was observed testing a
new molded case circuit breaker in accordance with new electrical maintenance procedure EM 2-0940074, Rev. 0, Molded Casing Circuit Breakers Testing.
The new procedure was written in response to NRC Bulletin 88-10, Nonconforming Molded Case Circuit Breakers.
The circuit breaker that supplied the 2A battery charger had tripped several times during the last part of April and early May.
The licensee had investigated the problem, and was replacing the breaker prior to more extensive testing.
The new breaker passed all parts of the procedure used.
After replacement, the removed breaker was tested by the same procedure.
The inspectors noted that the procedure steps were in the proper sequence and provided adequate guidance to the technicians utilizing the procedures.
The technicians were asked by their management to mark up a
copy of the procedure with any additional refinements for subsequent incorporation.
The changeout of hydraulic oil in Unit 2 MFIV 09-1A was observed on May 5 per PWO 0279, procedure OP 2-0810050, Rev 12, Main Steam/Feedwater Isolation Valves Periodic Test, and Man'ual E-3199, Feedwater Isolation Valve Maintenance Manual.
The operators had previously discovered by observation that the oil in the sight glass was milky and not clear.
Following preparations, the valve was removed from service for one hour while the oil was changed.
TS 3.7. 1.6 allows inoperability for four hours.
The inspector observed
'the removal of resin and the dewatering of the spent resin from the radiological waste system.
The resin was processed in accordance with procedures HP-49, Rev.
3, Dewatering Radioactive Bead Resins, and HP-49A, Rev.
4, Transfer of Radioactive Bead Resins.
The procedures were performed very smoothly.
All phases were monitored satisfactory throughout the process, as demonstrated by the licensee's use a television camera to monitor cask filling.
PWO 6956/61 replaced a program power supply'or Unit
CEA number 33.
Each CEA has two power supplies operating in parallel.
The criteria for
power supply replacement was that it no longer provided 15 volts dc or that the RNS output ripple exceeded 0.04 mi llivolts and a indicating lamp on the outside of the CEA cabinet provided an indication of these conditions.
The licensee replaced the power supply in accordance with procedure gI ll-PR/PSL-4, Instrumentation and Control Test Control, and the vendor manual.
The replacement was performed without incident.
Upon completion of installation and functional testing for the power supply, the indicating lamp alert status cl'eared.
No violations or deviations were identified in this area.
Review of Nonroutine Events (Units 1 and 2) (93702)
Non-routine plant events were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events which were reported immediately were also reviewed as they occurred to determine that TS were being met and that the public health and safety received primary consid'eration.
At 9:42 pm on June 8, the power supply transformer for the Unit 2 fire detection computer, located in the Unit 2 control room, failed and emitted a large amount of smoke.
The fire team was activated and the control room ventilated.
Within about two minutes, the desk-size unit was deenergized and flooded with carbon dioxide to stop the smoldering which produced the smoke.
The Unit 1 fire detection computer was then used to monitor both Units 1 and
until repairs could be made.
The control room operators reported that the smoke did not prevent them from performing required duties.
The licensee's-actions in this case appeared to be prompt and appropriate.
No violations or deviations were identified in this area.
Physical Protection (Units 1 and 2) (71707)
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.
No violations or deviations were identified in this area.
Surveillance Observations (61726)
Various plant operations were verified to comply with selected TS requirements.
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:
a.
EDG Test The initial performance of OP 1-2200050, Rev.
44, Emergency Diesel Generator Periodic Test and General Operating Instructions, was observed for the
EDG.
This procedure had been completely rewritten by the licensee.
The inspectors reviewed the procedures.
No discrepancies were noted.
b.
AFW Test The Unit
AFW Monthly Test, which was controlled by procedure 1-0700050, Rev.
27, was observed.
This test involved alignment verification of important flowpath valves and operation of the three pumps to obtain ASME Pump and Valve Program data.
The test was conducted in a satisfactory manner from a technical viewpoint; however, procedure sequencing concerns were identified.
Section 8.5, Test Pump C,
was conducted before sections 8.3, Test Pump A, or 8.4, Test Pump 8, and the first valve position verification of section 8.7 was conducted prior to conducting section 8.5.
The procedure did not specify that sections could be performed out of sequence.
Subsequent to the test, the licensee explained that the section 8.7 valve lineup was a
plant-desired check, independent of the test, that was added to the procedure rather than write another procedure.
The current plant policy on procedure sequencing allowed the sections to be sequenced by the SROs as needed.
This test met that policy.
Observations were made of nearby equipment conditions during the test.
Several safety-related electrical conduits were found not sealed and rusting.
These conduits serve AFW motor-operated valves.
The significance was that they were outside and exposed to potential adverse weather conditions.
These were identified to the licensee.
for repair.
c ~
Star tup Activities - The following surveillance-type activities were observed during the Unit 2 startup:
On April 14, surveillance procedure 2-0110054, Rev. 6, Periodic Rod Drop Time Test and CEA Position Functional Test, section was observed from the control room with the unit shutdown.
Section 8.4 verified CEA out of position limit alarms.
For CEA 80, the DDPS did not detect CEA motion and initiate alarms K22 (CEA position
+
4 inches)
and K38 (CEA position
+ 8 inches).
The test was suspended pending resolution of the equipment problem and restarted the next day with performance of sections 8. 15 and 8. 16, which involved movement of CEAs by banks, CEA number one experienced control electronics problems during initial drop testing.
Portions of OP 2-0110054 were observed being reperformed on April 22, following equipment repairs Just prior to startup, performance of OP 2-0700050, Rev.
14, Auxiliary Feedwater Periodic Test, was observed for the 2C AFW pump.
After satisfactory test performance, the pump was used to fill the Unit 2 SGs.
The test and the filling of the generators reduced the heatup rate at the time, which merely increased the time the unit would remain in Mode 3.
The personnel hatch inner and outer door seals were leak tested on April 13 in accordance with OP 1300052, Rev.
22, Air lock Periodic Leak Testing, prior to Unit 2 entering Mode 4.
The seals did not leak.
No violations or deviations were identified in this area.
10.
Outage Activities (71707)
The inspector observed the following overhaul activity during the ongoing Unit 2 outage:
On April 6, during a post-repair surveillance test on the 2A EDG, a pillow block thrust bearing assembly failed on one of the engine radiator cooling fans.
The fan thrust then forced the fan blades against the shroud at the radiator.
The fan blades rubbing on the shroud alerted the operator and the test was aborted.
On Unit 2, there are two radiator-cooled diesel engines per generator.
Each engine drives, through belts, two cooling fans for it's radiator.
The failed bearing operated for 56 minutes during this test prior to the inner race fai ling from undetermined causes.
The outage repairs that precipitated the surveillance were not bearing-related.
The failed race apparently had an existing crack that suddenly propagated.
This caused the race failure and loss of the shaft axial position retention function.
The licensee initiated an inspection of other bearings on both this EDG and the 2B EDG.
The scope of the inspection was increased in response to NRC concerns.
The Unit
EDG cooling systems were of a different design.
The following corrective actions were implemented:
The damaged 2A cooling fan was weld repaire The failed thrust bearing on the 2A unit was replaced.
A total of 40 other Unit 2 EDG fan-related bearings susceptible to this failure mechanism were inspected.
These included fan shaft, idler shaft, and drive shaft bearings.
Five thrust bearings and two floating bearings were replaced.
Two fan shafts, one on each generator, had damaged shafts due to excessive shaft-to-collar clearance.
New shafts were manufactured and installed.
Successful post-repair surveillance runs were made on both EDGs.
The licensee submitted a special report, L-89-185, date'd June 5, 1989, on the failure in accordance with TS 4.8. 1. 1.3.
The licensee intends to revise maintenance procedures to require periodic inspections of the EDG fan shaft bearings.
On April 12, the operations staff was observed receiving onsite training on the rapid changout of EDG fuel filters and strainers in the event they became clogged during an emergency.
The site had been informed by their contract testing laboratory that, while the last fuel received was within specifications, there was significantly more sediment than usual.
It was locally determined that a
new shipment of sample bottles had cap liners that deteriorated in diesel fuel.
New fuel samples had been obtained but had not yet been analyzed.
The training was conducted "just in case" even though the specifications were met and the proximate cause had been determined.
Subsequent retesting confirmed that the fuel was satisfactory and that the sediment resulted from deterioration of the bottle cap liners.
The bottles were removed from the site.
On April 16, the site deferred Unit 2 startup pending additional repairs.
One of the primary jobs was the repair of the 2A2 loop check valve'.
The valve had developed a 0.2 gpm leak.
Although the plant could be operated with this valve leaking, the staff conservatively decided to repair it.
It was disassembled in place and the disk assembly removed.
The disk and seat were lapped; blue checks between the two indicated that additional cleanup was necessary.
A Dexter machine was brought in from FPL's Martin plant to polish the seat in the valve body.
After polishing was completed, the valve was reassembled and startup resumed.
The valve leaked slightly at low plant pressure but sealed as the plant reached normal operating pressure and temperature.
On April 21, prior to attempting startup for the second time, maintenance personnel were observed evaluating Unit 2 MSIV leakage.
On the previous day, Unit
steam was cross connected to Unit 2 for testing purposes.
Leakage came past the MSIVs or their associated bypass valves and was seen in the Unit 2 SGs.
On the 21st, the site was attempting to duplicate the leakage under more controlled circumstances with remote instrumentation.
A leakage path past the 2B MSIV was identified.
The licensee's actions in this case appeared to be appropriat The above activities demonstrate that the licensee usually makes conserv-ative operational and maintenance decisions, The EDG fan bearing activ-ities, however, were'
departure from the norm.
The licensee's final action plan concerning the EDG fan bearings was thorough and produced beneficial results.
No violations or deviations were identified in this area.
11..
Review of Special Reports (71707)
FPL letter L-89-133, dated April 6, 1989, and titled "Report of 10 CFR 50.59 Plant Changes" addressed Unit 2 plant changes completed between October 7,
1987 and October 6,
1988.
The letter and enclosures, which contained. brief descriptions of plant changes made and summaries of the respective safety evaluations, were reviewed for content and for compliance with 10 CFR 50.59(b)(2)
and
CFR 50.4.
No violations or deviations were identified in this area.
12.
Drawing Control (71707)
Documents reviewed included:
gP 3.4,. Rev. 9, Plant Changes and Modifications for Operating Plants gP 3.6, Rev.
5, Control of FPL Originated Design gP 6.6, Rev. 3, Drawing Control for Operating Nuclear Power Plants JPE-gI 3.7, Rev.
1, Design Equivalent Changes'Performed by JPN JPE-gI 6.2, Rev. 2, Drawing Control Delegated to JPE Contractors JPE-gI 6. 1, Rev.
1, Document Control by JPE JPN-gI 3. 1, Rev.
14, Control o'f Design Performed by JPN JPN-gI 3. 10, Rev. 0, Drawing Change Requests Performed by JPN JPN-QI 6.3, Rev.
1, Drawing Control by JPN Supplement gI 3.1-3, Rev.
2, Engineering Package (EP) for Nuclear Plants BgAP-1, Rev. 4, Turnover of Project Drawings and Sketches BgAP-2, Rev. 8, Preparation of As-Built Documents B(AP-4, Rev. 0, Drawing Change Requests
BQAP-9, Rev.
6, Preparation of Backfit Change Sketches BQAP-10, Rev. 9, Preparation of Engineering Packages BQAP-22, Rev. 2, Preparation of Design Equivalent Engineering Packages QA Audit. QAS-JPN-88-1, Quality Assurance Audit of Nuclear Engineering Department, Dated January 31, 1989 QA Audit QSL-OPS-88-598,
CFR 50, Appendix B, Criterion VI, Document Control, Dated April 28, 1988 QA Audit QSL-OPS-88-624, Emergency Diesel Generators and Safety Related Switch Gear System, Dated December 19, 1988 QA Audit QSL-OPS-88-645, Design Control, Dated January 12, 1989 ANSI N45.2. 11 - 1974, Quality Assurance Requirements for the Design of Nuclear Power Plants RG 1.64, Rev.
2, Quality Assurance Requi'rements for the Design of Nuclear Power Plants At St.
Lucie, the document control, onsite drawing distribution, and records vault functions have been under the direction of the QC supervisor.
The onsite drawing distribution and records vault functions have been performed in separate locations by separate administrative sub-groups.
The selection of SRDs for each unit has been made by the QC supervisor as directed by procedure QI 6-PR/PSL-l, Document Control, in coordination with the operations management.
The updating of SRDs in places other than the control rooms and the TSC has been routinely accomplished by mail distribution.
The updating of SRDs in the control rooms and the TSC has been routinely accomplished by QC department administrative personnel.
The detailed process was not found in plant procedures because it was a job function of only a few persons.
Control room SRDs were updated on a fast-turn-around basis by the document control persons who normally issued drawings.
The TSC drawings were separately updated upon receipt by mail distribution by records vault persons.
The QC staff had recently decided to combine the two functions and have all the updates made by the document control persons.
That turnover was in preparation during this inspection.
The SRD list, updated monthly, consisted primarily of:
Flow Diagrams and Selected Miscellaneous Drawings (about 125)
Control Wiring Diagrams (several hundred)
Instrument Listings The Valve Operational Number Index.
Power Distribution and Motor Data
The relationship between SRDs and PCNs was reviewed using Unit
as the sample.
Interviews with document control pers'onnel indicated that the data base correlating PCMs and SRDs was maintained on a computer and that-the correlation printouts were printed weekly and placed in the control rooms. for operator use.
These printouts were not routinely updated in the TSC because the records vault was not on the distribution list for them.
These interviews also indicated that reissued SRDs were routinely placed in the control room on a daily basis and the PCM stamps updated as necessary at the same time.
TSC drawings might have a
PCN stamp upon issue by document control but the stamps were not later updated nor were previously-issued drawings stamped upon approval of a new PCM.
The PCN reference material found in the control rooms was not present in the TSC.
A sampling of SRDs and PCN reference material were reviewed to determine the adequacy of updates and determine the ease of use by operators.
The 18 Control Wiring Diagrams for the Component Cooling Water system were reviewed.
They comprised Drawing 8770-B-327 pages 201-205 and 207-219.
All page 'revisions agreed with index sheet 2,
Rev.
44.
Five of the pages were stamped as affected by PCNs.
o PCM 294-188, that affected most of the above drawings, changed a
resistor in large motor controllers.
The documentation in the control room referred to a Bill of Material, but did not describe the PCN in functional terms.
o PCM 24-185 affecting sheet 208 could not be found.
o PCN 039-185 was referred to by many 3509-8-327 sheets.
It also showed that it affected EDG 1A and 1B drawings 8770-G-086, 093, and 096.
The updated drawings were not in the PCM folder.
Drawings 086 and 093 both required that the PCM be reviewed.
The operators indicated that the EDG PCM drawings had been referred to many times in the past and were surprised that they were missing.
Approximately 30 flow diagrams in the Unit 1 control room were reviewed for ease of cross reference to PCNs.
The cross reference was intended to show either "in progress" or "completed" dates to alert the operator to the PCM status.
Five of the drawings contained cross references.
o 8770-G-078, sheet 121, Rev. 8, CVCS, was affected by two PCMs.
PCM 137-181 was completed 6/4/85, PCM 296-183 was started 12/20/84.
o 8770-G-088, Rev.
19, Containment Spray and Refueling Water Systems, was marked as affected by PDCN-000-000-21D but no dates for "In Progress" or "Completion" were show r o
8770-G-078, sheet 140, Rev.
3, Fuel Pool, was affected by PCN 142-186 which was started 2/4/88.
The inspector had no comments.
o 8770-G-085, sheet 1,
Rev.
23, Service and Instrument Air, was affected by PCN 125-181 which was started 3/04/83.
The PCN reference drawing was Rev.
13 vice the current Rev.
23.
The relationship was not obvious to the operators nor to the inspector.
o'770-G-085, sheet 4,
Rev.
23, Instrument Air System, was affected by PCM 050-186 which was started 4/27/89 and CRN 050-186-1149 which was started 5/23/89.
The sketch provided with PCM 050-186 was clear and understandable.
The sketch provided with the CRN was an isometric drawing vice a flow diagram, poorly marked and understood by neither operators nor the inspector.
In addition the inspectors reviewed approximately 30 flow diagrams in each control room and for each unit in the TSC, 120 total, for legibility. Legibility problems were not found and the drawings were all the latest revision shown in the index.
The inspectors also verified that QC self audits involving this area were not conducted by the licensee.
QA audits focused on this process were not conducted, however QA audits involving SRD accuracy were conducted and are reviewed below.
Audit QSL-OPS-88-595 involved SRD 2998-G-082, Rev.
18, Intake Cooling Water Flow Diagram.
The audit found several minor physical discrepancies such as missing labels or handwheels, a loose hanger, an inaccessible small valve, and two occurrences of an extra instrument isolation valve.
Serious drawing errors were not found.
Audit QSL-OPS-88-624 involved the EDGs for both units and SRDs involving both the engine-mounted and external piping systems, some of which had not previously been shown on drawings.
The auditors found the drawings to be inadequate and incomplete.
At the time of this inspection, they were being redrawn, as well as the systems being redesignated and components renumbered.
Audit QSL-OPS-89-672 involved the Unit
RCS and SRDs 2998-G-078 sheets 107, Rev.
1; 108, Rev. 0; 109, Rev 2; and 110, Rev.
2.
No drawing errors were found.
These audits appeared to be aggressive and professional.
The inspector walked down the accessible AFW flow path for Unit 1 as shown on drawing 8770-G-080, Sheet 3 of 4, Rev.
26.
The major findings were:
Three pump discharge guage lines had an extra isolation valve not shown on the drawin The root valve for PI 09-7 was located downstream of the recirculation, line tapoff rather than upstream.
There were no components located between the depicted and actual locations.
The system provides for several temporary gauge connections.
The drawing shows the temporary gauges connected, however the gauges are usually removed, as intended, and the connection points capped.
None of these walkdown findings are considered to have safety significance'he program concept for use of SRDs, updating of control room copies, and accounting for PCM impact is judged as a reasonable concept; however, program management has been lacking.
Some of the implementation, as discussed above, has been marginal and below the site's routine capabilities.
13.
Licensee Action on Previous Inspection Findings (92701)
(Closed)
URI 335,389/89-10-06, Sealing Requirements for Class lE Solenoids in Containment.
The solenoids in containment did not meet the current requirements of a plant drawing which was revised subsequent to installation of the solenoids.
Subsequent review shows that:
The solenoids did not have post accident operability requirements so they did not require environmental qualification per 10CFR50.49.
That type solenoid was qualified in TRC Testing Laratories Report No.
2375 with the thread sealant inadvertently pulled away from the threaded connection.
The sealant was not actually required.
The inspectors did not find other cases of improper sealing, nor, did the licensee.
Based on the above review, this was found not to be a safety issue in this case.
However, the current plant drawings required sealant to be installed.
The licensee has entered the new sealing requirement into the I&C training program.
This NRC-identified violation is not being cited because criteria specified in Section V.A of the NRC Enforcement Policy were satisfied.
This item is identified as NCV 335,389/89-16-01, Failure To Install Class 1E Equipment in Containment in Accordance with Drawings.
(Open)
URI 335,389/89-10-05, Operability Requirements for Containment Coolers.
During a containment walkthrough of Unit 2 prior to entering mode 4, the the maintenance access doors on the four containment coolers were found to
be in an unsecured condition.
The latching dogs around the periphery of the doors were found to be unlatched or loosely latched, i.e.,
the dog did not pull the door closed against the door seal, yet the coolers had been aligned for operation and were running.
The coolers were not required for the present plant mode; however, the condition was pointed out to the plant staff and the above referenced URI opened.
During a Unit
RCB anomaly inspection on April 12, with the unit at power, the inspector requested that the SNPO check the condition of the containment cooler access door dogs.
Unit 1 was in mode
and the fans were required to be operable per TS 3.6.2.3.
Two of the doors were latched by one dog each.
One door was latched by all dogs except one.
The 1B cooler door was not latched by any dog.
The negative pressure in the 1B cooler, which was running, was maintaining the door closed.
The cooler was secured to open the door and inspect the dogs'nterior handle position.
It was found that the door would have been caught at approximately six inches open by the dog's interior handle.
It was unlikely that the door would have swung completely open even if the cooler were not running without additional mild force being applied.
Site personnel dogged closed all of the doors.
The inspector noted that the dogs functioned properly.
The doors had been undogged since the last Unit 1 startup in August, 1988.
During a followup inspection of the Unit 2 RCB on April 15, the contain-ment coolers'oors were inspected for closure.
Unit 2 was in mode 3 and the coolers were required to be operable in that mode per TS 3.6.2.3.
One of four dogs on the 2B cooler door was in position but loose, i.e., not squeezing the door gasket against the mating knife edge.
Two of four dogs on 2C cooler door were in position but loose, as above.
The plant staff had positioned the Unit 2 dogs since being informed while in mode 4,
as discussed above, but had not corrected the maintenance problem of loose dogs.
The Unit 2 dogs have since been tightened.
A review of instructions that might include the fan cooler doors showed that, for example, OP 2-0010123, Rev.
29, Prestart Check-Off List, required verification that the containment cooling system was in operation per OP 2-2000020, Containment Cooling System Operation.
OP 2-2000020 did not address the dogged doors.
It did not appear that the licensee had any program to ensure that the doors were securely shut when the coolers were placed in operation or when either unit's operational mode was changed to a
mode requiring the coolers.
These additional containment cooler
concerns listed above remain unresolved pending the completion of the licensee's engineering evaluation for operability and will be tracked under the previously opened URI 335,389/89-10-05.
14.
Exit Interview (30703)
The inspection scope and findings were summarized on June 16, 1989 with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection findings listed below.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number Status Descri tion and Reference 335,389/89-10-05 open URI - Operability Requirements for Containment Coolers, paragraph 13.
335,389/89-10-06 closed URI - Sealing Requirements for Class 1E solenoids in Containment, paragraph 11.
335,389/89-16-01 open 335,389/89-16-02 open NCV - Failure to Install Class 1E Equipment in Containment in Accordance with Drawings, paragraph 13.
YIO - Failure to Preclude Missile Hazards Resulting from the Installation of Compressed Gas Cylinders, paragraph 3.
335/89-16-03 open NCV - Failure to Foll.ow Procedures for Equipment Clearance Release and Independent Yerification, paragraph 4.
15.
Acronyms and Abbreviations AC AFW ALARA ANSI ATWS BQAP CEA CFR CIS DC DDPS DEV ECCS Alternating Current Auxiliary Feed Water (system)
As Low as Reasonably Achievable (radiation exposure)
American National Standards Institute Anticipated Transient Without Scram Backfit Quality Assurance Procedure (EBASCO Services Inc.)
Control Element Assembly Code of Federal Regulations Containment Isolation System Direct Current Digital Data Processing System Deviation (from Codes, Standards, Commitments, etc.)
EDG FPL FSAR GDC GL HP HPSI IFI IN I&C INPO, IP, ISI JPE JPN LTOP LCO LER LPSI MFIV MSIV MTC NCV NPS NRC ONOP PCM PORV ppm PT PWO QA QC QI RCB RCP RCPB RCS RG RO RWT SDC SDCS SGSIT, SNPO SRD SRO TS URI VIO Emergency Diesel Generator The Florida Power
& Light Company Final Safety Analysis Report General Design Criteria (from 10CFR 50, Appendix A)
NRC Generic Letter Health Physics High Pressure Safety Injection (system)
NRC Inspector Follow-up Item NRC Information Notice Instrumenta'tion and Control Institute for Nuclear Power Operations Inspection Report (NRC)
InService Inspection (program)
(Juno Beach)
Power Plant Engineering (Juno Beach)
Nuclear Engineering Low Temperature Overpressure Protection (system)
TS Limiting Condition for Operation Licensee Event Report Low Pressure Safety Injection (system)
Main Feed Isolation Valve Main Steam Isolation Valve Moderator Temperature Coefficient Non-Cited Violation (of NRC requirements)
Nuclear Plant Supervisor Nuclear Regulatory Commission Off Normal Operating Procedure Plant Change/Modification Power Operated Relief Valve Part(s)
per Million Pressure Transmitter Plant Work Order Quality Assurance Quality Control Quality Instruction Reactor Containment Building Reactor Coolant Pump Reactor Coolant Pressure Boundary Reactor Coolant System
[NRC] Regulatory Guide Reactor [licensed] Operator Refueling Water Tank Shut Down Cooling Shut Down Cooling System Steam Generator Safety Injection Tank Senior Nuclear Plant [unlicensed] Operator Safety Related Document Senior Reactor
[licensed] Operator Technical Specification(s)
NRC Unresolved Item Violation (of NRC requirements)