IR 05000335/1992016
| ML17227A596 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 09/09/1992 |
| From: | Elrod A, Landis K, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A595 | List: |
| References | |
| 50-335-92-16, 50-389-92-16, NUDOCS 9209220035 | |
| Download: ML17227A596 (28) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET. N.W., SUITE 2900 ATLANTA,GEORGIA 30323 Licensee:
Florida Power 5 Light Co 9250 West Flagler Street Miami, FL 33102
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Report Nos.:
50-335/92-16 and 50-389/92-16 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
License Nos.:
DPR-67 and NPF-16 Inspection Conducted:
July 14 - August 10, 1992 Inspectors:
PDR.S.
A. Elro
,
S nior Resident Inspector 4-4
~ ~H.
Sco t, Re dent Iqspec r
Approved by:
.
D. Landis, Chief Reactor Projects Section 2B Division of Reactor Projects Date Signed ate Signed t.Signed SUMMARY Scope:
Thi's routine resident inspection was conducted onsite in the areas of plant operations review, surveillance observations, maintenance observations, fire protection review, evaluation of licensee self-assessment capability, review of nonroutine event reports, review of nonroutine events, followup of previous inspection findings, and review of design changes/plant modifications.
Backshift inspections were conducted on July 18, 20, 26 and 29, and August 1 and 8, 1992.
Results:
Many operational activities were observed or reviewed, including a
Unit 2 shutdown, a failure of a travelling screen at the Unit 2 intake structure, and overheating of Unit 1 component cooling water pump motors due to painting activities.
Within the areas inspected, the following non-cited violations (NCVs) were identified:
NCV 335,389/92-16-01, Failure to Forward One Company Nuclear Review Board Meeting Minute as Required, paragraph 7.
NCV 335/92-16-02, Failure to Maintain an Operable Boration Flow Path, paragraph 8.
920922003 05000335 5 q20909 PDR ADOCK PDR
lfithin the areas inspected, the following unresolved item (URI)
was identified:
URI 335,389/92-16-03, Setpoint List Basis and Implementation, paragraph,
Persons Contacted REPORT DETAILS Licensee Employees
- D. Sager, St.
Lucie Plant Vice President
- G. Boissy, Plant'eneral Manager J.
Barrow, Fire/Safety Coordinator H. Buchanan, Health Physics Supervisor C. Burton, Operations Hanager R. Church, Independent Safety Engineering Group Chairman
- R. Dawson, Maintenance Hanager
- W. Dean, Electrical Haintenance Department Head
"J. Dyer, Plant guality Control Hanager
- R. Englmeier, Nuclear Assurance Hanager R. Frechette, Chemistry Supervisor
- R. Grazio, Director, Corporate Nuclear. Licensing
- J. Holt, Plant Licensing Engineer C. Leppla, Instrument and Control Maintenance Department Mead
- L. McLaughlin, Licensing Manager G. Madden, Plant Licensing Engineer
"A. Menocal, Mechanical Haintenance Department Head H. Paduano, Site Engineering Manager A. Pell, Services Manager C. Scott, Outage Manager J. Spodick, Operations Training Supervisor D. West, Technical Hanager J.
West, Operations Supervisor W. White, Security Supervisor
- D. Wolf, Site Engineering Supervisor E. Wunderlich, Reactor Engineering Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Officials E. Merschoff, Deputy Director, Division of Reactor Safety, RII H. Shymlock, Chief, Plant Systems Section, Division of Reactor Safety, RII H. Berkow, Director, Project Directorate II-2, NRR J. Norris, Senior Project Manager, St. Lucie, Project Directorate II-2, NRR NRC Personnel S. Elrod, Senior Resident Inspector
- M. Scott, Resident Inspector R. Carrion, Reactor Inspector, NRC Region II M. Miller, Reactor Inspector, NRC Region II R. Moore, Reactor Inspector, NRC Region II S. Rudisail, Reactor Inspector, NRC Region II F. Wright, Senior Reactor Inspector, NRC Region II
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Plant Status and Activities Unit 1 began and ended the inspection period at power.
The unit ended the inspection period in day 231 of continuous power operation since its.
last refueling outage.
Unit 2 began the inspection period at 100 percent power.
The unit was shut down on July 18 to repair a
RCP motor oil leak.
It was restarted on'July 20 and returned to power on July 21.
The licensee reduced power on July 24 to facilitate repair of a traveling screen in the circulating water intake structure.
Power was returned to 100 percent on July 22.
At the end of the inspection, Unit 2 was in day 20 of continuous power operation.
On July 20 - 24, an NRC inspection was conducted in the area of operational status of the emergency preparedness program.
The results of this inspection were documented in IR 335,389/92-14.
-On July 20 - 24, an NRC inspection was conducted in the areas*of radiological waste management and shipping, and decommissioning planning records per
CFR 50.75 g(1)
and (2).
The results of this inspection were documented in IR 335,389/92-15.
On July 20 - 24, an NRC inspection was conducted in the ar'ea of electrical distribution system functional inspection followup.
The results of this inspection were documented in IR 335,389/92-17.
On July 22 - 24, H. Shymlock, Chief, Plant System Section, was onsite.
His activities included observation of licensee operations and facilities, and participation in the July 24 exit meeting with licensee officials.
On July 20 - 21, H. Berkow, Director, Project Directorate II-2, NRR was onsite.
His activities included observation of licensee operations and facilities,,and informal meetings with licensee officials.
On July 20 - 23, J. Norris, Senior Project Hanager, St. Lucie, Project Directorate II-2, NRR, was onsite.
His activities included observation of licensee operations and facilities, and informal meetings with licensee officials.
On July 28, E. Herschoff, Deputy 'director, Division of Reactor Safety, RII, was onsite.
His activities included observation of licensee operations and facilities, and informal meetings with licensee official,
Review of Plant Operations (71707)
'a ~
Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was proper ly 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 as well as equipment conditions were randomly verified both locally and in the control room.
The following accessible-area ESF system and area walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:
Unit
CCW heat exchangers and Unit 2 CCW heat exchangers, Unit
CCW pumps, Unit 2 charging pumps, and Unit lA and 1B EOGs.
(1)
Walkdown of the CCW areas indicated that the channel heads on the west end of the 2A, 2B, and lA CCW heat exchangers had minor 'salt water leaks where the head joined the main exchanger body.
This was discussed with the licensee.
Drip catches on the Unit 2 exchangers had been mistakenly removed after the Spring, 1992, outage as a part of normal post outage clean up.
The licensee agreed to pursue some permanent fix.
The leaks, which are difficult to prevent, do not rapidly harm the exchanger or prevent its function but tend to cause problems with the component support pedestals and the embeds for major hangers in the CCW pit below the exchangers.
The reinforcing bars in the concrete pedestals rust, and then the concrete cracks as the rust expands.
No cracking was evident during the walkdown.
The embeds exhibited accelerated rusting with the wetting of the salt water leak.
Additional discussions regarding the Unit
CCW pit are in
paragraphs 2.b and 5 below.
Additional discussion regarding the 1A EDG is found in paragraph 2.b below.
(2)
On July 31, the inspector found a problem with the 2B EDG air start system.
One of four compressor pressure shutoff switches had stuck, causing the starting air compressor to run excessively.
This caused the 282 air receiver relief valve to repeatedly lift at its set pressure.
The receiver was one of four for the EDG (one-pressure switch per air receiver).
When the relief would lift, the 282 receiver and the adjacent 2Bl receiver would blow down through common charging piping.
When notified, operations responded immediately and the'ressure switch was repaired.
Another NPWO was written against the check valve that was allowing the 2B1 air receiver to blow down.
Plant Oper'ations 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.
They observed and evaluated control room staffing, control room access, and operator performance during routine operations.
The inspectors conducted random off-hours inspections to ensure that operations and security performance remained at acceptable levels.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verified.
Except as noted below, no deficiencies were observed.
(1)
During this inspection period, the inspectors reviewed the following tagouts (clearances):
- 1-6-38 Waste Ion Exchanger Fill Valve, and 1-8-20 V3659, ECCS Pump Hiniflow Isolation Valve.
2)
During June, 1992, the 1A EDG FOST developed a slowly decreasing level trend that was not immediately recognized.
Contributors to the lack of prompt recognition were the large tank volume of about 20,000 gallons compared to the about 30 gallon per day leak rate, the precision of the mechanical level indicator system, and the periodic transfer of fuel from tank to tank to maintain the required fuel inventory.
The licensee determined that 2,000 gallons had leaked out prior to the leak being stopped.
Since the transfer line was an underground, seismic, ASHE Code Class 3 line, the licensee performed formal evaluation JPN-PSL-SEHS-92-013,
CFR 50.59 Evaluation for Excavation
of Diesel Generator 1A Fuel Oil Transfer Line 1-2"-D0-13, prior to digging it up while attempting to locate the leak.
This evaluation addressed seismic and missile protection issues.
The inspector confirmed that the exposed line was'upported in both the vertical and horizontal directions.
Associated formal evaluation JPN-PSL-SENS-92-014, 10 CFR 50.59 Evaluation for Operation Mith Diesel Oil Transfer Pump 1A Discharge Isolation Valve 1-V17206 Closed, addressed the interim configuration to stop the leak into the environment while allowing for the need to periodically refill the engine-skid-mounted day tanks during an accident.
A key element in allowing for operator action to compensate for automatic action was the almost one hour grace period between EDG start and the need to refill the day tanks.-
Operations Department Instruction 1-LOI-0-55, Rev 0, provided detailed instructions for the specially assigned operators to use in case of need.
Satisfactory operator action per Operations Department Instruction 1-LOI-0-55, Rev 0,
was observed during this inspection period.
Additionally, the monthly EDG surveillance verifying pumping capability to the EDG day tank was observed.
The licensee decided to run a new 1A FOST line.. Desig~ of the new line was in progress at the end of the.inspection period with the expected commencement of installation near the end of August.
In the interim, the existing line was recovered with earth, alleviating concerns about compacted filldirt erosion adjacent to the dig site.
Licensee engineering satisfactorily fielded additional questions regarding potential fire hazard concerns and the potential for released fuel oil changing soil compaction characteristics.
Neither physical evidence nor conjecture supported fire hazard possibilities.
Due to the small amount of leaked oil, no fill compaction changes were anticipated.
Early on July 18, while reviewing an operating log, a St.
Lucie Unit 2 reactor operator observed that the 2B1 reactor coolant pump motor lower bearing oil sump level appeared to have been slowly decreasing over the last day.
Over the next several hours, the licensee confirmed that the sump level indicator operate'd properly and that oil was actually being collected in the co+non oil collection tank.
The licensee commenced a Unit 2 downpower at 4:48 p.m.
on July 18, per OP 2-0030125, Rev 16, Turbine Shutdown - Full Load to Zero Load.
Following confirmation that a welded sump level sensing line joint had a nonisolable crack, the licensee shut down the reactor per OP 2-0030128, Rev 6, Reactor Shutdown.
The generator and turbine were shut down about 7:30 p.m.
and the reactor was shut down with TCBs open about 10:00 p.m.
The operators immediately commenced
preparations for restart since the duration of the shutdown was not apparent.
The inspector identified no concerns about operator performance during the shutdown.
Procedures were followed precisely, management and SRO backup during the evolution were excellent, and additional licensed management persons were provided on shift in an oversight role.
The nonsafety-related sump level sensing line was replaced with a flexible hose having a stainless steel braided cover.
The licensee inspected the other three RCPs for similar problems but found 'none.
The licensee did decide to replace two RCP upper sump cover gaskets while the unit was shut down.
The licensee completed repairs,and restarted Unit 2 late on July 20.
Unit 2 returned to power on July 21.
On July 24, Unit 2 had problems with the 2B2 traveling screen.
This is discussed in paragraph 5 of this report.,
Although these screens are nonsafety-related, they provide a
'very important function for the plants.
On August 3, the 1B CCW pump motor bearing alarm, annunciator S-42; activated.
An SRO was dispatched immediately to the CCW pit, where the motor and,pump were located.
Soon thereafter, with the SRO in transit, the 1A and 1C CCW pump motor bearing alarms activated and cleared several times while the 1B alarm stayed lit (sealed in).
The 1C CCW pump was not operating while the lA and 1B pumps were operating.
The SRO found the electronic panel indicators for the bearing temperatures, located in a electrical box near the pumps, displaying elevated temperature for the 1B CCW pump motor bearings.
In addition, the temperature indications for the 1A, 18, and 1C CCW pump motor bearings were all erratic.
Based on feedback from the SRO in the field and the continued erratic bearing temperature alarms, the operations staff called for an IKC technician familiar with the temperature monitoring system to bring a calibrated pyrometer to provide accurate contact temperature readings.
Additionally, the staff had called for the maintenance reliability support group to take pump and motor readings, including vibration levels for discreet noise analysis.
The licensee staff concluded that metallizing of the hangers in the CCW pit beneath the pumps, a maintenance activity described in paragraph 5,
was transmitting a Radio Frequency noise that was interfering with the proper functioning of the motor bearing temperature electronic panel indicator Qhen the metallizing of hangers and imbeds in the CCM pits was stopped, the panel indicators and pyrometers still indicated somewhat elevated bearing temperatures.
The staff noted that prior to its securing, the metallizing had produced a particulate plume in the area of the pumps, particularly close to the IB motor, and that sand blast grit was around the area of the motors.
The cause of the elevated temperatures was the reduction of air flow through the filter media over the motor air intakes caused by the buildup of particulates on the filter media.
The licensee staff removed the filter media after the particulate generation had been stopped.
Bearing temperatures began to imaediately subside.
The entire episode lasted less than
minutes from the time of the first 1B motor bearing alarms.
The licensee evaluated the event over the next several days as discussed in paragraph 5 of this report.
No motor or pump damage was detected at the time of the event which was determined by the extensive analysis.
(6)
The inspectors reviewed quality assurance activities and findings concerning operational activities to determine if the objectives were being met.
The following gA audits were reviewed:
gSL-OPS-92-885, Reactor Coolant System, dated July 15, 1992; gSL-OPS-92-873, Newport News Industrial Corp.,
Dated June 26, 1992; and, gSL-OPS-92-853, Corrective Action, dated January 29, 1992.
The above audits were complete and contained items of merit.
One audit caused operational enhancements to take place.
Another audit revisited past problem areas without any findings.
Technical Specification Compliance Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.
These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
Instrumentation and recorder traces were observed for abnormalities.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that related plant procedures in use were adequate, complete, and included the most recent revision d.
Physical Protection The inspectors verified by observation during routine activities that security program plans were being, iaplemented
.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.
Operational. activities were positive and complete.
Operations response during the Unit 2 shutdown was commendable as was their prompt action regarding the 2B EDG and the Unit
CCM pump motors.
No violations were identified.
4.
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, RMT 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'ndividual 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:
OP 2-2200050B, Rev 1, 2B Emergency Diesel Generator Periodic Test and General Operating Instructions.
b.
C.
OP 2-1210051, Rev 7, Wide Range Nuclear Instrumentation Channels Functional Test.
OP 2-1400059, Rev 16, RPS Periodic Logic Matrix Test.
This test was performed properly, however the procedure had a number of steps to be individually initialed to test the first of the eight TCBs but repeated the test for the other seven TCBs using only one initialed step for each TCB.
This was. identified to the licensee for review.
d.
e.
Aside survei OP 1-2200050A, Rev 1, 1A Emergency Diesel Generator Periodic Test and General Operating Instructions.
OP 1-0030150, Rev 55, Secondary Operational Checks and Tests
[main turbine front standard trip tests].
OP 2-0030150, Rev 38, Secondary Operational Checks and Tests
[main turbine front standard trip tests].
from the noted review point for OP 2-1400059, the above observed llances were performed in a satisfactory manner.
No violations were identified.
Haintenance 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 ensure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
b.
C.
NPWO 4931/62 2B2 traveling screen.
NPWO 6410/65 Unit.
1 -
HOV V3659 contactor/breaker PM.
NPWO 7655/64 Unit 2 - fix incore detector background correction.
d.
CWO 6223 Unit 1 - sandblast and metallize imbeds on CCW pit floor.
e.
NPWO 5409/65 Unit
HOV V3659, ECCS mini flow recirculation isolation valve, actuator inspection.
During the observation of work performed on the V3659 actuator, questions arose concerning the grease in the actuator.
The grease appeared to be a mixture of two types.
The electrical department agreed with this observation, evaluated that the grease had not changed state, and submitted a
NPWO to have the grease replaced during the next refueling outage.'n July 24, the normal drive gear shear pin broke on the nonsafety-related 2B2 traveling screen during a backwash evolution.
The four screens per unit remove trash and marine growth from the intake water prior to the water reaching the main condensers or intake cooling water pumps.
The 2B2 screen did have a higher than normal differential pressure against it due to presence of an ever-increasing string algae bloom.
The shear pin was replaced based on past experience and, when restarted, the screen motion was abruptly halted as again the pin had sheared.
Power was reduced on the unit to 80 percent and the intake well was dewatered for examination of this screen and its drive assembly.
The 2B2 waterbox was cleaned at this time.
The 2B2 traveling screen was found to be damaged.
There were typically two drive sprockets per screen assembly that rotate the
'screen sections.
One gib key that held the south side sprocket was found missing.
Only one side of the screen length:was being driven.
This, coupled with other missing parts, had allowed the screen basket sections (66 per screen assembly)
to twist and catch on the nearby (I/8 inch clearance)
screen housing splash guard.
This resulted in basket crush and chain drive damage.
Other deterioration was noted at the lower (underwater)
return sprockets (foot wheels).
The 2B2 traveling screen was totally rebuilt.
The foot wheel bushing and foot wheels-were replaced.
At least 10 screen basket sections were replaced.
The gib keys that held the drive sprockets were fixed in place to prevent them from backing out.
On June 29, due to high differential pressure, the 2A2 screen shear pin broke when the screen was energized.
This caused operations to further reduce Unit 2 power to 55 percent such that flow through that screen could be reduced by closing the discharge valve on the recirculation pump for that screen/intake.
With a lower flow and pressure, the screen could be rotated with less force.
After the shear pin was replaced and the screen cleaned, it could be normally operated again.
The 2A2 screen sat idle for a period of time prior to the shear pin breaking and this allowed=
an algae bloom to overload the screen.
The unit was taken back to 80 percent power while maintenance complete repairs 'on the 282 screen.
The overhaul of the 2B2 screen was complete late in the evening of June 29.
The screen was satisfactorily returned to service, then the unit was returned to full power.
During the recent Unit 2 outage, all four screen/intake wells were entered for underwater cleaning and inspection of the structural steel and traveling screens.
In addition, the 2AI and 2BI screen section heads (upper drive assembles that contain the drive sprockets)
were overhauled (sprockets and shafts replaced)
and the head housings were repaired.
The 2B2 screen had last been similarly worked in late 1990.
As identified by the licensee, the root cause for the 2B2 screen failure was inadequate preventive maintenance.
Over the years, maintenance effort had been reduced to a level that was found, with the failure of the 2B2 screen, not to be adequate for the saltwater.induced deterioration.
Prior to this event, maintenance levels had been thought to be acceptable.
With the type of intake and the low level of marine debris challenging the traveling screens, the deterioration was not readily evident until a failure or a marine debris challenge occurre The licensee's planed actions to prevent future traveling screen problems included:
inspection of all drive sprockets and gib keys for the traveling screens on both units (completed);
inspecting all foot wheel bushings and other screen assembly parts to ensure that they are in good working order; and, developing a detailed outage inspection and overhaul guideline to assure reliable screen service.
By August 1, the algae bloom that had challenged both units'raveling screens had abated.
Aside for the 2B2 problem, the bloom never seriously affected either unit.
The licensee kept problems to a minimum by regularly backwashing the screens, the ICM lube water and CCM pit zurn strainers, the SGBD strainers, and the TCW strainers.
On August 3, the Unit
CCW pump motors were challenged as described in paragraph 2.b of this report.
Due to the reduction of air flow to the CCW motors, the 1B and 1A motors experienced bearing temperature rises to 212 and 178 degrees F, respectively, which were above their normal operating range of 125 to 150 degrees F.
Painting related work had -been in progress below the CCW pumps as administratively controlled by CWO 6223 listed above.
Licensee tests and evaluation proved that in either case the temperature rises did not harm the CCW motors.
The 1B motor rise was the worst case since its value, as measured on a bearing thermocouple, exceeded motor vendor recommended bearing temperature as described in the available literature (194 degrees F).
The licensee meggered, dobble tested (NPMO 6458/65),
checked motor winding temperatures, measured phase amperes, performed motor life reduction calculations, analyzed the removed bearing lubricating oil, vibrationally tested, and contacted the vendor regarding the 1B CCM pump motor.
The 1A motor had been vibrationally tested, winding temperature checked, and its amperes analyzed.
Based on the acceptable vibr ational tests (no change on either motor) and the lack of bearing oil deterioration or bearing babbitt finds in the oil, the vendor concurred in the licensee's conclusion that no damage had occurred to the 1B motor or its bearings.
The licensee sumaarized their conclusion in engineering correspondence JPN-SPSL-92-0529 of August 10, 1992.
As'the result of an earlier violation, 50-389/91-19-01, regarding painting and paint preparation activities, the licensee had made changes to their paint program.
In the above instance, the CCW pit activities conformed to their program defined by procedure ASP 30, Rev 2, Protective Coatings for Steel Surfaces.
Preparation for painting work under the CCM motors in the CCW pit
was extensive and included building containment tents around objects to be cleaned, stripped, and coated.
These tents were'aintained at slightly less than atmospheric pressure by exhaust ventilation.
The personnel replaced the filter media on the CCW motor air intakes daily while the work was in progress.
The personnel performing the work wore protective clothing and face masks/respiratory protect)on.'he hangers in the pit were blasted with a paint and rust removing grit and then aluminum metal was deposited on them (metallized)
with a plasma spray device.
Both processes generated airborne particles.
The root cause for the partial clogging of the media filter over the CCW motor air intakes was that the containment tent ripped as personnel were metallizing.
The tent ventilation was no longer able to force inward airflow.
Both aluminum particles and blast grit were then released outside the tent.
This parting of the tent went undetected by the personnel metallizing until operations personnel saw the plume of metallized particles near the 1B CCW pump motor 'and the darkened filter media and brought it to their attention.
Licensee management stopped the CCW pit painting work through the end of the inspection period and beyond.
They were very concerned about the implications of the motor problem, and initiated their own investigation into the event.
Some painting program improvements were being considered at the end of the inspection period.
An issue related to the above was identified to the licensee.
The motor bearing temperature alarms on the 1B CCW motor actuated at 203 degrees F.
This temperature is 9 degrees F above the vendor's recommended maximum bearing temperature.
Although it is nonsafety-related, the alarm should have been conservative with regard to the vendor recommendation.
The setpoint list in question was FPL drawing number 8770-8-470, Rev 6, Setpoint List, Unit
(page 83 for TIS-14-29-1Al to 1C2), which specified an alarm setpoint of 203 degrees F.
Control room procedure ONOP 1-0030131, Rev 47, Plant Annunciator Summary, listed the alarm set point as 180 degrees F, which was in conflict with the setpoint list.
One event in the last year involved a different nonconservative setpoint that had caused a problem.
The Unit 2 containment fan coolers'CW low flow alarms had been set nonconservative relative to the TS flow limit.
This had contributed to a violation of TS minimum flow requirements.
The licensee indicated that a review of setpoints was underway with a number of engineering persons reviewing the documents.
The licensee stated that this was a two year program.
Based on the inspection period ending with uncertain setpoints for
the CCK motors and other plant equipment, this subject will remain open pending further review as URI 50-335,389/92-16-03, Setpoint List Basis and Implementation.
Aside from the CCW problem, maintenance work appeared to be well controlled.
The traveling screen PH improveaents will be followed by licensee and resident inspectors.
No violations were identified.
Fire Protection Review (64704)
During the course of their normal tours, the inspectors routinely examined facets of the Fire Protection Prograa.
During specific activity such as large scale test of fire protection systems, exercises, extensive repair or drills, the inspectors observed.
The inspectors reviewed transient fire loads, flammable materials storage, housekeeping, control of hazardous chemicals, ignition source/fire risk reduction efforts, fire protection training, fire protection system surveillance program, fire barriers, fire brigade qualifications, and gA reviews of the program.
During the inspection period, the licensee ran one fire drill on August 5 and began their annual fire hose hydrostatic test on August 7.
Both activities were observed to be going well.
No violations were identified.
Evaluation of Licensee Self-Assessment Capability (40500)
The inspector reviewed the activities of the CNRB to determine compliance with the requirements of Unit 1 and 2 TS 6.5.2, Company Nuclear Review Board.
Implementing procedures or summaries reviewed included:
NP-803, Rev 2, Corporate Nuclear Review Board.
CNRB-Ol, Rev 2, Company Nuclear Review Board, Rules of Conduct.
This procedure implemented NP-803 in part by setting forth the rules covering the conduct of CNRB meetings and related matters, including defining a
CNRB administrator and defining a standing subcommittee to perform technical reviews of a number of areas.
CNRB-02, Rev 0, Company Nuclear Review Board, Plant Tours.
This procedure required CNRB members perform plant tours and, while at the plants, attend site review comnittee meetings.
CNRB-03, Rev 3, Company Nuclear Review Board, Review procedure.
This procedure implemented NP-803 in part by setting forth the implementing procedures for the review function established in NP-80 CNRB-04, Rev 1, Company Nuclear Review Board, Audit/Assessment Procedure.
This procedure implemented NP-803 in part by setting forth the implementing procedures for initiation, conduct, and reporting of CNRB audits and assessments..
Education and Experience summaries for members and alternates.
The inspector confirmed that FPL had met requirements regarding meeting frequency, designation of membership in writing, and quorum.
The inspector also found that members and alternates met educational and experience requirements.
The meeting minutes for the last year showed that 19 of 20 minutes were approved and submitted to the Chairman, Nuclear Division, within the required 14 days.
The July 16, 1991, meeting minutes were submitted in 16 days.
This deficiency was of minor safety significance and the many other minutes submitted on time showed that no programmatic problem existed.
This NRC identified violation is not being cited because
'the criteria specified in Section VII.B of the Enforcement Policy were satisfied.
This non-cited violation is identified as NCV 335,389/92-16-01, Failure to Forward One CNRB Meeting Minutes as Required.
This review included attending the July 21 monthly meeting at the Juno Beach corporate office.
The licensee rotates the monthly meeting between the corporate office, the St. Lucie site, and the Turkey Point site.
The meeting agenda and meeting room were both well organized; The meeting was effectively conducted.
Inspection and audit items reviewed by the CNRB members and discussed at the meeting were separated into categories including NRC IRs for St.
Lucie and Turkey Point with no violations, NRC IRs for St. Lucie and Turkey Point with violations, and gA audits with findings closed.
The CNRB was particularly interested in root causes and corrective actions, and assurance that either problems were known to be confined to one nuclear plant or corporate activity or corrective action scope was appropriately expanded.
Items presented for CNRB discussion and approval included a proposed security plan revision.
A proposed license amendment for St. Lucie Units 1 and 2 had been scheduled but was deferred.
Plant tour plans by two members were discussed.
Information presentations of current interest, requested by the CNRB, included:
Thermo-Lag fire barrier performance; the fuel load safety evaluation for St.
Lucie 2, Cycle 7; a status report on the health physics program; and a description of the gA vendor audit program.
The inspector concluded that the CNRB met TS requirements with one minor exception identified above as an NCV.
The CNRB effectively performed reviews and assessments.
The inspector had no further questions in this area.
One NCV was identifie,
Onsite Followup of Mritten Nonroutine Event Reports (Units 1 and 2)
, (92700)
LERs were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events that the licensee reported immediately were reviewed as they occurred to determine if the TS were satisfied.
LERs were reviewed in accordance with the current NRC Enforcement Policy.
LER 50-335-92-005, dated July 27, 1992, documented a Unit 1 TS 3.1.2.2 non-compliance regarding boration flow path availability.
Mhile at 100 percent power, boration flow paths were technically lost on June 18, 1992.
This condition existed for approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
The TS non-compliance was discovered by the licensee on June 29 while the control room logs were being reviewed.
Unit 1 TS 3. 1.2.2, Boration Flow Path
- Operating, requires two of three boration flow paths to be operable for Nodes 1 through 4.
The TS Action statement allows continued reactor operation for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with one boration injection flowpath operable, but does not allow continued reactor operation with no boration injection flowpath operable.
The three boration flowpaths are:
1)
1A Boric Acid Nakeup (BAN) tank through 1A BAH pump or the "A" gravity feed valve, 2) The 1B BAN tank through the 1B BAH pump or the "B" gravity feed valve, and 3) the Refueling Mater Tank (RWT) through the RMT suction valve.
TS 3.8.1.1.b requires with an emergency diesel generator inoperable that all the required equipment on the remaining operable diesel generator also be operable.
Both BAN pumps are powered from the "A" electrical train while both gravity feed valves and the RWT suction valves are powered from the "B" electrical train.
With the 1A BAH tank declared out of service (below required volume, 6878 gallons as opposed to 8097 gallons, and high boric acid concentration, 3.88 vs 3.5 weight percent, as graphically presented in TS figure 3. 1-1),
and with the 1B BAH pump out for maintenance, the
'icensee then declared the 1B EDG out of service for maintenance.
This left the unit with no operable flow paths.
Had a loss of normal AC power occurred on the "B" 4160 Volt electrical bus, manual operation of the "B" train gravity feed valve or RMT suction valve would have been required to get the contents of the operable 1B BAH tank or RMT to the suction of a charging pump.
As a practical matter and as stated in the LER analysis, the 1A BAH tank water volume was slightly below TS minimum and it did contain sufficient boric acid to provide 223 kg boric acid for emergency shutdown addition.
Based on the total boric-acid and its solubility,'he licensee determined that the 1A BAH tank contents would have been able to perform its design function.
The 1A BAN pump breaker was not racked out and the pump would have started had a SIAS signal been received.
This fact mitigated the safety significance of the event.
The above reported condition is a TS violation and identified as NCV,
335/92-16-02, Failure to Provide a Technical Boration Flow Path.
This, violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the
'criteria specified in Section VII.B of the Enforcement Policy.
LER 50-335-92-005 was complete and timely. It will remain open until. the corrective action for the above violation is reviewed.
One NCV was identified.
9.
Followup (Units 1 and 2)
(92701)
'a ~
Followup of Inspection Identified Items (Closed)
IFI 389/90-30-01, Followup on the 2B CCW Heat Exchanger Bimetallic Welds - This IFI is closed based on the satisfactory UT and VT inspection of the 2B heat exchanger bimetallic welds during this past Unit 2 outage as documented in FPL correspondence JPN-ESI-92-247, dated April 22, 1992 (ESI-NDE-92-082).
b.
Followup of Bulletins Sent For Information and Information Notices As requested by NRC management, a copy of NRC bulletin 92-01, Thermo-Lag 330 Fire Barrier of June 24, 1992, was provided to the FPL site management.
The licensee has responded to the bulletin in a timely manner.
c.
Followup of Headquarters and Regional Requests A survey of EDG performance requested by NRC Region II to support a
NRC study of reliability was forwarded to the regional office.
A survey regarding Agastat E7000 relays was forwarded to the regional office.
No violations were identified.
10.
Design, Design Changes, and Modifications (37700 and 37878)
During the inspection period, the licensee implemented PC/M 139-192, CCW Heat Exchanger TCV Minimum Stop Set Point on Unit 1.
This engineering package allowed setting the minimum open stop limit on the pneumatic controller for nonsafety-related temperature control valves TCV-14-4A and 4B as low as 8 percent open.
These TCVs, described in the FSAR, regulate ICW flow through the CCW heat exchangers, maintaining an optimum CCW flow outlet temperature.
The previous minimum opening had been 25 percent.
This change increased flow through the Turbine Cooling Water (TCW) heat exchangers which are cooled in parallel by the ICW flow.
The ICW system also cools the SGBD System.
Increased flow through the TCW system is highly desirous in the peak temperature summer months to maintain the turbine status.
The inspectors observed PC/H implementation and reviewed test data and t
the design package.
The test data indicated that the valve operated as described with the change.
The package information was in order, including an appropriate 10 CFR 50.59 review.
The ICW flow to TCW and SGBD heat exchangers would still be secured during a postulated accident and the total ICW flow would be directed through the CCW heat exchangers.
NRC management is currently reviewing inforaation on the subject TCVs per previous URI 335,389/92-05-06.
The review results will be addressed at a later date in a subsequent inspection report.
This URI remains open.
No violations were identified; 11.
Exit Interview The inspection scope and findings were summarized on August 10, 1992, with those persons indicated in paragraph-1 above.
The inspector described the areas inspected and discussed in detail the inspection results listed below.
Dissenting comments were not received.
Proprietary material is not contained in this report.
Item Number Status 335,389/92-16-01 closed Description and-Reference NCV - Failure to Forward CNRB Heeting Hinutes as Required, paragraph 7.
335/92-16-02 closed NCV - Failure to Maintain an Operable Boration Flow Path, paragraph 8.
335,389/92-16-03 open 335,389/92-05-06 open URI - Setpoint List Basis and Implementation, paragraph 5.
'I URI - Evaluation of Whether or Not Air Controls for CCW TCVs Should be Safety Related, paragraph 10.
12.
Abbreviations, Acronyms, and Initialisms AC AP ATTN BAH CCW CFR CNRB Alternating Current Administrative Procedure Attention Boric Acid Hakeup (tank etc'.)
Component Cooling Water Code of Federal Regulations Company Nuclear Review Board
FOST FPL FSAR ILC ICW IFI ILRT IR JPN LCO LER LOCA HOV NCV NPF NPWO NRC NRR ONOP OP PC/H PH gA gC RCP Rev RF RWT SGBD SIAS SRO St.
TCB TCV TCW TS UFSAR URI UT VIO VT
Containment Spray (system)
Construction Work Order Direct Current Demonstration Power Reactor (A type.of operating license)
Emergency Core Cooling System Emergency Diesel Generator Engineered Safety Feature Fahrenheit Fuel Oil Sto}age Tank The Florida Power
& Light Company Final Safety Analysis Report
'nstrumentation and Control Intake Cooling Water
[NRC] Inspector Followup Item Integrated Leak Rate Test(ing)
[NRC] Inspection Report (Juno Beach)
Nuclear Engineering TS Limiting Condition for Operation Licensee Event. Report Loss of Coolant Accident Hotor Operated Valve NonCited Violation (of NRC requirements)
Nuclear Production Facility (a type of operating license)
Nuclear Plant Work Order Nuclear Regulatory Commission NRC Office of Nuclear Reactor Regulation Off Normal Operating Procedure Operating Procedure Plant Change/Hodification Preventive Haintenance guality Assurance guality Control Reactor Coolant Pump Revision Radio Frequency Refueling Water Tank Steam Generator Blowdown System Safety Injection Actuation System Senior Reactor [licensed] Operator Saint Trip Circuit Breaker Temperature Control Valve Turbine Cooling Water Technical Specification(s)
Updated Final Safety Analysis Report
[NRC] Unresolved Item Ultrasonic Test Violation (of NRC requirements)
Visual Inspection Test
'