IR 05000335/1992020
| ML17227A650 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 11/18/1992 |
| From: | Elrod S, Michael Scott, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A649 | List: |
| References | |
| 50-335-92-20, 50-389-92-20, NUDOCS 9212040316 | |
| Download: ML17227A650 (41) | |
Text
. ~gg REGIj (4 P0
, g
++*++
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-335/92-20 and 50-389/92-20 Licensee:
Florida Power 5 Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St.
Lucie 1 and
License Nos.:
DPR-67 and NPF-16 Inspection Conducted:
September
October 19, 1992 Inspectors:
ro
, Senior esl ent nspector e
Igne cott, es)
e nspector a
e
>gne or
,
ess ent nspector, urry Approved by:
an
>s, le Reactor Projects Section 2B Division of Reactor Projects SUMMARY at
>
ne I(
a e
gne Scope:
'his routine resident inspection was conducted.onsite in the areas of plant operations review, surveillance observations, maintenance observations, fire protection review, followup of service water team inspection findings, and followup of other inspection identified findings.
Backshift inspection was performed on September 22, 23, 24, 25, 26, 27, 29 and October 7, 10, 12 and 14.
Results:
In the plant operations area:
Operators reacted well to three small plant transients and one Unit 1 trip during this inspection period.
All of the above perturbations were caused by problems in the secondary plant.
The Unit 1 startup from the trip was well done and uneventful.
(paragraph 3.b)
In the surveillance area:
A number of important surveillances were performed in a competent manner.
In one instance, the licensee promptly 9212040316 921118 PDR ADOCK 05000335
repaired and retested a Unit 2 main feed isolation valve after it failed its,surveillance test and before exceeding Technical Specification time limits.
Two maintenance groups (Hechanical and Instrumentation E Contr'ols)
were present for the failed surveillance test, and provided excellent support for the repair and subsequent satisfactory re-test; Overall licensee surveillance control and performance were competent.
(paragraph 4)
In the maintenance area:
Nonsafety-related equipment failures of a main turbine hydrogen cooler temperature control valve, a main turbine throttle v'alve digital electro-hydraulic system "0" ring backing ring, and 4B heater level controller switch caused secondary system perturbations.
The temperature control valve and'the heater level controller failures were due to specific weak preventive maintenance practices.
The "0" ring failure may have been due to a minor design problem and was still under review at the end of the inspection period.
Overall, observed maintenance activities were satisfactory.
(paragraph 5)
In the engineering area:
Engineering supported maintenance in resolving a mixed grease issue regarding valve motor operators.
The NRC reviewed the licensee's operability analysis and concurred with the licensee's conclusion that there were no immediate safety
. concerns and that timely replacement of the mixed grease was appropriate.
Also, NRC inspectors noted that the licensee's documentation and resolution of the service water inspection open item issues were excellent.
(paragraphs 5.j and 7).
Persons Contacted REPORT DETAILS Licensee Employees e
- D G
J.
H.
- R.
- W.
- J
- R.
- H.
- R.
- J
- J
G.
- A.
H.
C.
J.
- D
- J
- W.
- D
- E Ot op Sager, St.
Lucie Plant Vice President Boissy, Plant General Manager Barrow, Fire/Safety Coordinator Buchanan, Health Physics Supervisor Burton, Operations Manager Church, Independent Safety Engineering Group Chairman Dawson, Maintenance Manager Dean, Electrical Maintenance Department Head Dyer, Plant guality Control Manager Englmeier, Site equality Manager Fagley, Construction Services Manager Frechette, Chemistry Supervisor Geiger, Vice President of Nuclear Assurance Holt, Plant Licensing Engineer Leppla, Instrument and Control Maintenance Department Head McLaughlin, Licensing Manager Madden, Plant Licensing Engineer Menocal, Mechanical Maintenance Department Head Paduano, Site Engineering Manager Scott, Outage Manager Spodick, Operations Training Supervisor West, Technical Manager West, Operations Supervisor White, Security Supervisor Wolf, Site Engineering Supervisor Wunderlich, Reactor Engineering Supervisor f
her licensee employees contacted included engineers, technicians, erators, mechanics, security force members, and office personnel.
NRC Personnel S. Elrod, Senior Resident Inspector
- M. Scott, Resident Inspector J. York, Resident Inspector, Surry
- Attended exit interview 2.
Acronyms and initialisms used thro'ughout this report are listed in the last paragraph.
Plant Status and Activities Unit 1 began the inspection period shut down since September 14 for pressurizer SRV V-1202 replacement.
The licensee started up Unit 1 on September 23, but it tripped on September 24 when the turbine control system failed.
The Unit 1 reactor was restarted the same day and the turbine was restarted on September 28 following repairs.
Unit 1 ended
e the inspection period in day 21 of power operation since the September
turbine startup.
Unit 2 began the inspection period at full power and has run at power since.
There were small power reductions for. turbine valve testing, main turbine subsystem component failure, turbine control system hydraulic leak repair, and a heater drain pump control system repair.
Unit 2 ended the period in day 66 of power operation since startup on August 13, 1992.
3.
Review of Plant Operations (71707)
Plant Tours b.
The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with'rocedures, 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 2 Control Room A/C, Unit -1 4160 Volt switch gear, Unit 1B EDG system, and Unit 1A ICW system.
Plant Operations Review The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs, and equipment tagout records.
The inspectors routinely observed operator alertness and demeanor during plant tours.
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
'erified.
Except as noted below, no deficiencies were observed.
During this inspection period, the inspectors reviewed the following tagouts (clearances):
~NUMBE COMPONENT WORK 2-9-98 NV 08-15 Clean Contactor 2-6-182 PCV-25-46A, Administrative-46B, 8-468 Control(partial)
~LCO yes no*
(2)
(3)
2-10-24 FCV-25-30 FHB Emergency Vent yes Valve 1-10-47 1A CCWHX Clean Heat Exchanger yes
CCW to Unit 2 A/C - instrument air isolation valves were tagged shut, the flow regulating AOVs were therefore failed open.
At the beginning of this inspection period, Unit 1 was shutdown in a mini-outage to replace V-1202, a pressurizer SRV.
This had been discussed in previous IR 335,389/92-18.
The valve was
'successfully replaced.
1Al RCP seal, which began leaking during the shutdown for the mini-outage, was also replaced prior to unit startup.
The inspector witnessed Unit 1 reactor startups on September
and 24 per OP 1-0030120, Rev 46, Prestart Checkoff List, and OP 1-0030122, Rev 46, Reactor Startup.
In both cases, the inspector observed that the licensee had provided the essential elements for a well controlled startup.
Reactor engineering had computed the 500 PCH stop points for plotting the inverse count rate ratio.. The licensee stationed an SRO, in addition to the regular. shift assignments, as reactivity manager.
Procedures were in hand and followed.
Nuclear performance was monitored closely.
Coordination between the operators performing control manipulations and reactor engineering was excellent.
Outside activities were not allowed to distract persons conducting the startup.
RCO trainees performed the actual. control manipulations under the direct control of licensed persons.
Reactor criticality occurred very close to predicted conditions.
The inspector had no further questions in this area'.
(4)
Fol,lowing the September 23 reactor startup, Unit 1 tripped at 11:38 a.m.
September 24 from apparent loss of turbine load I
signal.
At the time; the unit was stable at 42 percent power while a circuit breaker on the 1B main feedwater pump was being troubleshot.
Control room operators noted 'generator monitor'nd
'DEH DC bus fail'larms immediately. after the trip.
Standard Post Trip Actions were implemented per EOP-1.
All reactor and main turbine support equipment reacted normally.
No safety valves lifted and the plant was placed in Mode 3 without further problems.
As documented in in-house-event report IHE 92-61, the Unit
trip was caused by DEH system component failure.
A capacitor in the turbine speed control circuit card failed, interrupting
'he -15 VDC bus to the turbine supervisory control system and grounding the. bus that provided power to the loss-of-DC turbine trip relay.
Interruption of power to this bus resulted in energization of relay 20-AST that dumped Auto Stop Oil and DEH fluid to their respective reservoirs and the closing of all turbine steam admission valves.
The turbine trip signal caused an expected reactor trip signal.
With the unit again shutdown, the licensee troubleshot both the above problem and a second DEH computer problem involving its ability to sense inputs from a second speed sensing circuit not related to the speed control circuit discussed above.
This second problem precluded use of the DEH control system in automatic mode.
DEH system. vendor experts were flown in to support the troubleshooting.
While troubleshooting continued on September 24, the licensee restarted Unit 1 per OP 1-0030122 as discussed above and held it at low power.
This evolution went without problems.
This held Unit 1 in readiness (Mode 2) for operational testing of the turbine control system.
On September 26, after several electronic boards had been replaced and operational simulation had seen the computer and control system respond correctly, the licensee again attempted turbine operation to check the viability of the DEH system.
The turbine was latched at 11:44 a.m.
and power increased.
The DEH control system computer lost speed input at 11:52 a.m.
and defaulted to manual control in a stable manner.
Operators tripped the turbine in an orderly fashion to permit additional troubleshooting and returned the reactor to Mode 2 at 12:25 p.m.
Late on September 27, the licensee found the DEH computer problem through wire-by-wire electronic testing.
A lead to a pin connector was loose.
As with most old computer connections, the pins were connected to electrical leads by wrapping the cuneiform pin with eight coil's of bare wire.
The wire wraps were tight enough to normally make a good connection without solder.
The loose lead in question had a slightly
e (5)
(6)
higher resistance which reduced speed signal transmission.
The licensee soldered the lead.
After some additional testing, the turbine was put on line at 00:45 on September 28.
Power was gradually ramped up in stages while the DEH system was shown to be stable.
Full power was reached the following day.
During a light test of the lA EDG local annunciator panel, annunciator 24, 'Start DC power= failure -
CS isolated',
remained lit.
For the test, all annunciator targets are lit to insure the light bulbs function.
This was immediately investigated by the electrical and operations departments, with the system engineer, and determined to be an annunciator'elay K-34 failure and not a
DC bus failure.
The EDG DC supply and the EDG were still operable.
This was made readily apparent because the same DC power operated other functioning lights and features on'he EDG local control panel.
A green work tag had been hung at the local panel, within two feet of the annunciator, indicating the K-34 relay involved was bad but the tag did not identify the annunciator number.
The K-34 relay was replaced on October 2 per NPWO 5707/65 in coordination with the lA EDG being taken out of service for hydrostatic testing of r'eplacement portions of the fuel oil transfer pipe.
On October 1, for no apparent reason, the Unit
DEH control shifted from automatic sequential valve operation to automatic single valve operation.
The turbine lost 40 to 50 HW of output due to the control change and operators adjusted reactor power to compensate for the reduction in turbine power.
The NRC inspector observed the licensee's initial assessment.
Within minutes of the above power change, management personnel were present and Operations, with I&C supervision present, assessed the turbine control situation.
Chart recorders on the DEH power supplies that had been left in place since the earlier events (September 27)
showed no electrical fluctuations.
As a result of the initial assessment, the turbine control system was placed into manual mode until the computer was troubleshot.
Subsequently, troubleshooting revealed that the computer interfacing analog-to-digital converter, that had been replaced on or about September 27, had failed.
This component failure could have caused the shift to automatic single valve and subsequent loss of power generation.
The converter had failed within the first few days of service.
This part was again replaced with the previous converter which was considered still good.
The replaced component and system performance were
monitored until October 1 without any changes being observed.
On October 1,
a Westinghouse technical representative reviewed the past turbine control problems and corrective actions.
He could find no fault in the computer or the licensee action as it stood at the time.
The licensee planned to wait for the next 'unit power reduction to,attempt the swap from manual sequential mode to operator automatic mode to reduce the likelihood of turbine perturbation.
This will probably occur at the next water box cleaning which would occur beyond this current report period.
On October 4, with Unit 2 at 100 percent power, main generator hydrogen cooler TCW flow control valve TCV 13-15 failed in an unpredicted manner.
The feedback control arm on the valve's air operator fell off when an attaching.fastener loosened, making the valve fail shut.
Normally, should control air,be lost to the valve operator, the valve would fail open and continue to provide cooling.
Operations personnel responded rapidly to the TCV failure.
As the turbine trouble annunciators lit (first GEN TEHP HONITOR ALARH and then TURB GEN H2 GAS DEWPOINT HI), staff was deployed to investigate at the hydrogen cooling station.
ONOP 2-2200030, Rev 1, Hain Generator, led the operators to the applicable TCV, which they found failed closed.
Operators opened the TCV bypass valve to re-establish cooling flow.
During the 15 minutes required to restore hydrogen temperature to the normal range, hydrogen cold g5s temperature had risen to 6.5 degrees 6 above its alarm limit.
Hot gas average temperature had risen to 73.7 degrees C from about 61 degrees C.
Hain generator winding damage would have begun had hot gas temperature risen to 96 degrees C.
Westinghouse review concluded that no, damage had occurred to the main generator.
Licensee followup actions included repair of TCV 13-15.
General plans to evaluate this type actuator for corrective actions at other locations were not formulated at the close of the inspection period.
Due to the potential impact to the steam and reactor plants, this review will remain an open item IFI 335,389/92-20-02, TCV Condition Review.
The NRC inspector noted to the licensee that the new off-normal procedure did not clearly state when a differential hot gas temperature graph in the procedure was to be invoked.
A similar event occurred on the Unit
1B nonsafety-related TCW heat exchanger (ICW) outlet valve 13-2B approximately one month ago.
The actuation arm on that valve actuator bent and then fell off and the valve failed shut.
This could have led to a temperature rise on all systems cooled by TCW but at a much slower rate due to the second heat exchanger being in service
(8)
(above, the hydrogen coolers have only a single combined supply from TCW).
-As with the Unit 2 hydrogen cooler event, operators.
noticed the TCW system temperature'rise and had the valve repaired prior to damage occurring.
During a routine calibration check of a temperature measuring instrument, it was found to be out of specification.
As a part of the licensee's M&TE program corrective action, all surveillances performed with the out of specification device were reperformed.
All retests were satisfactory except the one discussed below.
On the morning of October 7, the licensee reperformed the quarterly surveillance of the 2B HPSI pump per OP 2-0410020, Rev 19, HPSI/LPSI Normal Operation, because of METE calibration.
During the test, the pump outboard bearing temperature increased into the ASME Code Section XI alert range for this pump and stayed constant at 120 degr ees F.
Aside from the slightly elevated bearing temperature, the pump ran satisfactorily.
Operations and the system engineer reviewed and, under controlled conditions, repeated the test again.
The pump bearings were cooled by CCW flow through throttle valves.
The outboard bearing was cooled through one inch throttle valve V-14625.
Prior to retest performance, the operators checked the bearing cooling valve alignment per OP 2-0310020, Rev 24, Component Cooling Water Normal Operation.
'CW cooling throttle valve V-14625 was found to be one quarter turn short of its one-turn position required by OP 2-0310020.
The valve was returned to its normal position and the surveillance was rerun with the NRC inspector present.
The repeated surveillance and associated bearing temperature (approximately 86 degrees F) were satisfactory.
The "T" bar type valve operator to V-14625 had some slop in its motion that probably contributed to the mispositioning.
"The hand wheel moved approximately one quarter of a turn prior to initiation of valve stem movement.
So during pre-startup CCW system lineup (OP 2-0310024 in June 1992) the non-licensed operator probably moved, the valve what he thought was one turn open and actually left it three quarters turn open.
The system engineer had performed the cooling water flow testing for the HPSI pumps and knew that'valve's position was very critical to proper cooling flow to the pump bearing.
The licensee was following up on the throttled valve issue when the inspection period ended.
The technical support and maintenance engineering support staffs were reviewing the repositioning of V14625 from a human factors perspective.
This issue will remain an open item, IFI 389/92-20-'03, Unit 2 CCW Throttle Valve (9)
(10)
On October 13, The inspector observed the NWE and SNPO returning the lA CCW HX to service following mid-cycle cleaning and plugging of one leaking tube.
The, procedures in use were OP 1-0310020, Rev 33, Component Cooling Water Normal Operation, Appendix B, and Clearance 1-10-47, Clean and Shoot Tubing on lA CCW HX.
The operators interfaced the procedures smoothly while filling,.venting, and establishing system flow.
Independent verifications were made where designated in the procedures.
The inspector had no further questions.
On October 18, Unit 2 developed a minor DEH leak in the number 1 main turbine throttle valve control'ox that required a power reduction to repair.
With no. annunciators alarming (no major leakage)
a non-licensed operator on normal rounds noticed some minor spray and dripping from the throttle valve box.
Once the leakage source, a
DEH fluid filter body/cartridge
"0" ring
. backing ring was identified, power was reduced 10 percent, and turbine controls were adjusted such that the throttle valve could be closed and DEH isolated.
The "0" ring and the backing ring were then replaced and the unit was returned to full power.
The failed "0" ring backing ring was being evaluated by the licensee.
The "0" ring backing ring was not continuous.
The ring had a diagonal butt-cut.
The leak occurred at this joint.
Mechanical maintenance'as asked the turbine support vendor to evaluate the root cause and possibly provide a design change.,
(ll) On October 19, with the plant at 100 percent power, the Unit 2 4B feedwater heater level control components failed, causing a
feedwater heater low level condition, which'-in turn resulted in the tripping of the 2B heater drain pump'.
With the loss of the
,2B heater drain pump, operators adjusted plant power to 93-percent.
Just prior to the above perturbations, the number 5B heater level control was in manual operation for maintenance.
The 58 heater level control being in manual and thus unable to respond to feedwater system transients caused some level swings in the 4B heater.
Micro switches for the 4B heater level control failed or failed to respond rapidly due to age/condition related problems.
With the failure of the switches, the alternate 4B valve opened to the main condenser, resulting in the 4B heater drain pump trip on low 4B heater level.
The licensee was investigating the event at the end of the inspection period.
In-House Event Report 92-067 had been issued in draft.
Tentatively, investigation revealed that the normally shut High level setpoint switch contact was broken and in the open position.
The alarm contact for the High level setpoint was frozen in its normally open position.
The High-High level setpoint switch was 'sticky'nd not operating
properly.
This did not allow the 4B Alternate valve to close after the 4B Feed Water Heater level had returned to normal.
Because of the potential for. plant transients, the licensee planned to look at critical level switches during the next refueling outage.
c.
Operations guality Review The inspectors reviewed quality assurance activities and findings concerning control room operations to determine if the objectives were being met.
The following Operations gC quality control reports/activities were reviewed:
REP RE NEARER RAPE
~EEPE EE N ARE 092-113 6-16-92 clearances on TS equipment 092-127 7-6-92 clearances on TS equipment 092-128 7-8-92 TS surveillances, reactor startup, and 'operator activities in power ascension 092-132 7-15-92 chemistry surveillances and gaseous permits 092-141 7-24-92
.clearances on TS equipment and surveillance 092-163 8-25-21 TS surveillances The above reports covered areas well within the expertise of the individuals performing the audits.
The findings were worthwhile and clear.
The Operational gC inspections that resulted in the above reports prevented at least two TS violations on a Unit
CEA periodic surveillance and on a Unit'
TS air conditioning action statement.
d.
Technical Specification Compliance Licensee compliance with selected TS LCOs was verified. This included'he 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. e.
The inspectors verified by observation during'outine 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.
f.
Required Notices The residents reviewed the posting of required notices to workers and found them to be satisfactory.
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, 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 result's 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.
AP 2-0010125A, Rev 29, Surveillance Data Sheet
¹8A, NV-08-19, 2A SG Atmospheric Steam Dump.
b.
OP 2-0810050, Rev 16, Hain Steam/Feedwater Isolation Valves Periodic Tests (see paragraphs S.d and 5.e below).
c.
OP 2-0410020, Rev 19, HPSI/LPSI - Normal Operation
[2B HPSI pump]
(see paragraph 3.b(8) above).
d.
OP 1-1400054, Rev 3, Reactor Protection System - Loss of Turbine Hydraulic Fluid Pressure'ow.
This test was performed prior to the September 23 Unit 1.reactor startup to verify that a turbine trip would actuate the reactor loss-of-load trip.
The inspector considered excellent communication between operators in the control room and at the turbine front stand to be an essential element of this test.
The operators performing this test demonstrated a clear understanding of the test and Operations responded well to the three minor plant transients and one unit trip.
The transients were kept minor by rapid and.sure action.
The secondary plant problems were being reviewed by the licensee at the end of the inspection perio maintained excellent communications.
The inspector had no further questions.
e.
OP 1-1400059, Rev 19, Reactor Protection System Periodic Logic."
Matrix Test.
The inspector observed performance of this test on September
prior to a Unit 1 reactor startup.
During the test, the Channel C
Low Steam Generator Pressure Bistable No.
2 light did not illuminate.
The operator properly stopped the test and immediately informed the instrumentation supervisor.
The illumination circuit was quickly corrected by shifting the plug-in card slightly and the test continued.
The oper'ators performing the test were knowledgeable.
The inspector had no further questions.
f.
OP 2-01100050, Rev 13, CEA Periodic Exercise.
The inspector observed a Unit 2 licensed operator and IEC technicians performing this test on October 15.
I&C support was per NPWO 0316/67.
The procedure was in use at both the RTGB in the control room and the CEA coil current trace equipment in the CEDMCS equipment area.
The operator and technicians effectively coordinated via sound-powered phones.
The technicians were tracing coil currents for 45 specified CEAs, about one third of the total, so that all CEAs would have current tracings each 3 months.
The inspector had no further questions.
Surveillance control and performance were professional.
5.
Maintenance Observation (62703)
Station maintenance activities involving selected safety-related systems and components were observed/reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
a.
NPWO 5644/66 Clean contactor for Unit 2 MV 08-15.
b.
NPWO 5562/61 Clean CCW heat exchanger 1B.
c.
NPWO 5691/66 FCV 25-30 overhau d..
NPWO 9231/64 Nitrogen pressure gage reading higher than expected on HCV 09-1A.
e.
During a surveillance being performed on the Unit 2 MFIVs, HCV 09-lA failed to return to the required Nitrogen pressure after a nitrogen pressure dump test.
Since the valve was in a TS action statement for the test (TS 3.7. 1.6, 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> out of service time allowed),
Operations closely controlled the test and then the repair sequence.
NPWO 9231 performance proved that the pressure reading was correct.
Subsequent evaluation revealed a failed spool valve that was a part of the MFIV valve assembly.
NPWO 9232/64 Replace
"N" spool valve on MFIV HCV 09-1A.
NPWO 9332 controlled the replacement of the defective spool valve on the MFIV.
With the valve replaced and with the NRC inspector present, the valve satisfactorily passed its surveillance per OP 2-0810050, Rev 16, Main Steam/Feedwater Isolation Valves Periodic Test, approximately 53 minutes prior to the end of the time limit of the TS LCO.
The removed MFIV spool valve (reference drawing Anchor/Darling Valve Company H8020821, Rev E) was examined for root failure cause.
The valve had been replaced during the Spring 1992 refueling outage with a new valve from the vendor.
The removed valve was inspected for under sizing of the main internal valve cavity that had been reported through the industry channels to the licensee.
There was no deviation from plan dimensions.
The IEC department did find grease globs in the main cavity that may have contributed to its sluggishness.
Coupled with the operator technique discussed below, the grease globs may have not allowed the valve to exit its test position.
IKC was going.to talk with the vendor about the finding.
Other surveillance test considerations not related to the valve's operational capability may have contributed to the surveillance test problems.
To perform the test dump, instrument air was isolated to the MFIV assembly.
Compressed air remaining in the support valve train (assembly tubing, SOVs, and spools)
was required to change the state of the spool valve when recovering from the dumped condition.
During the test, when the valve was being dumped of internal nitrogen pressure, the operators performing the test tried to dump the pressure with several short strokes of a test actuation button to limit the amount of hydraulic fluid forced out of the reservoir vent atop the MFIV assembly.
Over time, maintenance has gained understanding of the process and,limited the volume in the reservoir to limit fluid ejection.'KC believed that the several short stroke method used by the operators may bleed off air needed for the change of state.,
Operations was considering changes to their surveillance
'rocedure to require the dump test button to be held down for five seconds to prevent the undesired bleed of Aside from the above discussion on surveillance test problems, the MFIVs in their operable state are not affected by the testing mode.
The'importance of the testing problems was.the potential inability to return to an operable condition meeting the TS 3.7. 1.6 requirement.
Based on the need for licensee resolution of procedure issues and root cause resolution of potential spool valve problems, this item remains open IFI'389/92-20-04, MFIV Testing Issues.
NPWO 5561/61 Clean 1A CCW Heat Exchanger.
The inspector observed portions of the cleaning of 1A CCW HX.
The tubes were snaked with a 6,000 psig hydrolaser.
Licensee evaluation concluded that sacrificial anodes would last until the Spring, 1993, refueling outage and that the channel head surface coatings were holding up well.
The inspector concurred with that evaluation.
During the cleaning, a leaking tube was identified and the NPWO scope expanded to plug it per MMP-14.01, Section 8.3.
A NPWO scope change indicated that the specified gaskets were too large in diameter.
The gaskets were actually proper, however the workmen attempted to install the gaskets on the closure head vice the heat exchanger body.
The inner circumference of the head's seal surface was smaller than the gasket, leading to confusion.
The shop supervisory engineer stated that he intended to make a simple procedure text clarification.
NPWO 5757/65 Rebuild Operator for MV-14-2.
The inspector observed portions of the rebuilding of the Limitorque SMB-00 operator for MV 14-2, header B from CCW pump 1C.
This operator was exposed to the weather and had been believed to be lubricated with two greases (see discussion in paragraph 5.j below).
Per MP 0960067, Rev 2, Maintenance and Repair of Limitorque Valve Actuators, Type SMB/SB-OO, the components had been disassembled and cleaned and were being reassembled in the electrical department's MOV shop.
Upon disassembly, the licensee found moisture in the spring pack area and found that the worm bearing had developed a
flat spot.
The worm bearing was replaced.
The inspector observed that the springpack end-position cupped springs had not been installed
"cupped side out" as required by the current procedure.
This appeared to be because the vendor had changed the requirement since the last time the operator was assembled.
The licensee planned to install the washers per the current requirements.
The inspector judged the "ready to assemble" component material conditions to be excellent.
10/12/92 NPWO 5753/65, 1A EDG Governor Oil Level too High.
This NPWO involved draining the governor sump until the oil level was 3/16 inch above the si.ght glass mark with the engine stopped to correct a perceived error in filling the governor.
Personnel
performance during this activity was satisfactory, but only a few ounces of oil were drained.
The inspector reviewed maintenance and surveillance procedures to understand the basis for such a small correction.
Procedures reviewed included:
OP 1-2200050B, Rev 2, 1B Emergency Diesel Generator Periodic Test and General Operating Instructions.
. 1-EMP-59.01, Rev 7; 1A Emergency Diesel Electrical Periodic Maintenance and Inspection.
1-EMP-59.02, Rev 7, 1B Emergency Diesel Electrical Periodic Maintenance and Inspection.
MP 2-2200062, Rev 15, 2A Emergency Diesel Electrical Periodic Maintenance and Inspection.
There were minor governor-oil-level procedural inconsistencies between the Unit 1 and 2 maintenance procedures, and between maintenance and surveillance procedures.
While EDG operability was not in question, the licensee was addressing these procedural inconsistencies to improve work coordination and efficiency.
The inspector concurred with the licensee's approach.
CWO 3324 Replace IA EDG Fuel Transfer Line.
On October 12 the inspector observed work and test activities related to replacing the line per the subject CWO.
Observations included:
Hydrostatic test 9A of a weld neck flange designated D013/FW95 on isometric drawing JPN-225-192-010 8/17/92.
This test was conducted at 150-159 psig, or 150X of the 100 psig design pressure.
Important elements observed included use of 1/4 X accuracy test gages FPL-PSL-2171 (0-400 psig)
and 2173 (0-600 psig) that were within their calibration period; system fill and vent; hold at pressure for,the required ten minutes; and gC inspection of activities in general and visual inspection of weld joint integrity in particular.
The inspector had no further questions.
Installation of the insulating flange kit at the joint downstream of lA diesel oil line isolation valve V-17206.
Important elements observed included torque wrench FPL-PSL-2322 and multimeter 2082 being within their calibration periods; cleaning, installation, and torquing of insulating kit components; pre-and post-installation electrical resistance measurements to confirm the joint's insulating quality; and gC inspection of the above attributes.
The inspector had no further question On October 13, the licensee placed the new 1A EDG fuel transfer line in service, with no leaks.
The new underground line was an improved design with a pipe inside a guard pipe.'
IR 92-16 discussed preventive maintenance on a non-environmentally qualified HOV 3659 which appeared to have mixed greases.
A communication error had occurred and the valve actually had Sun Oil Company
EP grease as indicated by the grease sample analysis.
Due to darkness of the grease (deep black) which had not been seen previously, the NRC inspector had thought that it was a mix and the miscommunication had persisted.
The actual grease, which had been in the actuator since manufacture (pre 1976),
had shown some slight separation between constituents (light oil and heavier components).
The actuator had been scheduled for overhaul in which the grease would be replaced.
As the discussion continued into this inspection period on the grease topic, it.was determined between the licensee and the NRC inspector that some Nebula (Exxon EPl and EPO, white) grease had been introduced into the Sun Oil grease during preventive maintenance.
This meant that at least two dissimilar grease bases were being mixed (lithium base in the Sun Oil 50 and calcium base in the Exxon).
At the time that. current NRC inspectors were discussing the current grease issue, certain othe'r plant historical facts were not known.
Subsequently, a previous grease mixing issue came to light.
On February 10, 1984, Juno Engineering issued an evaluation (file 8 PSL 100-14, REA SLN-689)
on mixing grease stemming from an INPO report of November 1983.
The evaluated greases involved were Texaco RB (lithium based)
and the above mentioned Sun Oil.
The RB grease had been used to fill several actuators and then used as a periodic PH grease at grease addition fittings (zerks) at the actuator handwheels.
The perceived mixing problem was the grease base chemical interaction.
The 1984 evaluation caused both containments'ctuators to be filled with the Exxon nebula greases.
Additionally, the remaining actuators in both units wer e left as-is based on initial investigations and empiric examinations with a test report that followed.
Subsequent 1984 FPL correspondence supported leaving mixed grease in the safety-related actuators outside of containment.
Inter-office correspondence EPO-84-1777 (file: REA SLN-689, dated September 7,
1984)
and EPO-84-2052 (file: REA SLN-689, dated October 19, 1984)
stated the positions on mixed greases in the subject actuators.
The second correspondence EPO-84-2052 concluded that degradation of the lubricating qualities of mixed greases (Sun Oil and RB or Exxon Nebula and RB) would not occur and did not recommend change out of actuator greases outside of containment.
This information (mixed grease outside containment was acceptable)
was translated to documentation packages for the subject valves that were E In early 1989, the actuators on site changed ownership.
Responsibility for actuator maintenance was transferred from mechanical maintenance to electrical maintenance.
During the transfer, the above mentioned evaluation did not surface.
Electrical maintenance did not question the presence of mixed greases existing in actuators (outside of containment)
based on the statements authorizing this condition in the Eg documentation packages.
The electrical department began to develop a program as GL 89-10 and other related documents began to surface.
Sometime in 1985, preventive maintenance was changed on the valves.
General Maintenance Procedure 1-M-0018, required that Nebula EPO be introduced in the zerk on all type SMB actuators.
This change from adding RB as the PM grease voided the 1984 engineering evaluation due to the fact that RB, Sun Oil, and Exxon grease mixes were not strictly discussed.
This subtlety was not detected until the NRC/licensee discussion of this report period.
On October 6 based on the above, electrical maintenance wrote NCR 1-728 for adding Exxon grease to Sun Oil Company grease.
Engineering provided interim operability resolution to the NCR stating that the condition though degraded was satisfactory.for continued operation of the plant.
This was based on an inspection of a typical Eg valve FCV 25-30 (NPMO 5691)
and a report done by a consultant who happened
'o be a retired EPRI, grease expert and current EPRI consultant.
The overhaul/careful disassembly of FCV 25-30 revealed that no loss of lubricity had occurred within the body of the actuator.
This valve actuator had been chosen to preclude placing the plant in a TS LCO and due to the fact that it had been greased every 18 months and was a
Eg valve.
The NRC inspector and licensee engineering and electrical department management were present for the dissection of the actuator.
Although there were three types of grease present (Texaco RB, Sun, and Exxon), there were no signs of degradation of the greases.
The Sun Oil grease which had been present in the actuator since construction (circa 1975)
was the primary grease with small percentages of RB and EPO mixed in a slurry.
The RB and EPO could be seen in spots as intact striations but had 'achieved a high degree of mixing in the actuator.
The greases injected over the years (first RB and then EPO in or around 1985) at the handwheel grease fitting had passed through the handwheel end drive sleeve (which was sitting horizontal in situ in the plant) roller bearing and travelled down the drive sleeve to the vicinity of the valve end roller bearing.
All parts were well covered in grease and no loss of light oils or caking (signs of chemical.reaction previously reported in 1979) were evident around moving parts.
There was no sign of mechanical wear on the actuator.
The electrical department understood the language of the NCR 1-728 recommendation and was, scheduling/performing actuator grease change outs.
Engineering via the NCR stated that although the grease situation was acceptable for interim.pl-ant operations, the mixed
'
e
grease should be changed out long term.
The NCR interim answer requested that the NCR be returned to engineering for determining the required time-frame for replacing the grease.
This second disposition was to occur beyond the end of the inspection period.
The electrical department was proactive in selecting actuators for grease change as operations made them available for work.
There were 34 on Unit 1 to be worked and 35 on Unit 2 to be worked.
The electricians had worked two prior to the end of the inspection period.
In summary, the mixed grease in limitorque actuators was a
licensee realized degraded condition.
The condition was aggravated by a change in the grease used for PH.
The NRC resident inspectors
.
and Region II technical staff reviewed the licensee's NCR 1-728 operability analysis and concurred with the licensee's conclusion that there were no immediate safety concerns and that timely replacement of the mixed grease was appropriate.'n summary, overall the observed maintenance activities were satisfactory.
Secondary plant problems that had caused operational'ifficulties were caused by outdated equipment such as the DEH computer or the lack of targeted preventive maintenance to items such as the micro-switches on the feedwater heater level controllers.
6.
Fire Protection Review (64704)
During the course of their normal tours, the inspectors routinely examined facets of the Fire Protection Program.
The inspectors reviewed transient fire loads, flammable materials storage, housekeeping, hazardous chemicals control, ignition source/fire risk reduction efforts, fire. barriers, and fire brigade qualifications.
Observed fire protection activities were satisfactory.
7.
Followup of Service Water Team Inspection Identified Items (Units 1 and 2)
(92701)
A team inspection was performed from September 23, 1991 through October 4,
1991, (ref: Report Nos. 335,389/91-201).
This was a pilot team inspection to assess the functional performance of the ICW system, which performs the ser vice water function at St. Lucie.
Following is a list of followup items from that inspection that had remained open up to this inspection period, along with closeout actions.
a ~
(Closed - Units 1 and 2)
OBS 335,389/91-201-01, Component Cooling Water Heat Exchanger Heat Load Summary.
This observation involved the inspection team conclusion that the CCW heat exchanger heat load summary for Unit 1 was not an accurately maintained document.
One of the examples given was a footnote in an EBASCO Services calculation dated May 4, 1970, for various components cooled by the CCW system, (table shows normal and accident leads).
The note stated that the design total included contingencies for magnetic jack control rod drives.
This design was not installed at St.
Lucie
J (this was a small heat load), but the table was not updated to remove the note.
The licensee uses the correct heat load for calculations without this small valve. added.
Additional remarks for calculations -are contained in action taken for OBS 335,389/91-201-02.
This item is closed.
(Closed Units 1 and 2)
OBS 335,389/91-201-02, Variations in-Accident Heat Loads.
This observation pointed out that, in 1990, a
more realistic approach utilizing a time-history study with proper sequencing of the fan coolers and shutdown cooling heat exchangers demonstrated that the maximum accident heat load was 195 x 10 to the sixth power BTU per hour.
However, it was stated that the documents were not updated for consistency.
The inspector's review showed that heat loads were provided for different reasons in different sections of the FSAR and in calculations and may show a different value.
Some heat loads may be maximum loads expected during normal or accident conditions.and some loads may be more conservative values used for procurement of equipment.
The inspectors reviewed some of the calculations where the system heat loads varied depending on whether they were a total of equipment procurement heat loads, maximum expected heat loads, containment analysis heat loads, or time dependent heat loads on the CCW HX (see IR 335,389/92-18 for additional discussions).
'eviewed
.
in the context in which they were provided,'hese differences did'ot appear relevant.
Discussions with the licensee revealed that the NSSS vendor was performing new containment analysis heat load calculations which were due to be completed by December, 1992.
Changes to the FSAR because of these calculations will be submitted in April, 1993, (the normal submittal date for FSAR changes).
The resident inspectors will follow these calculations and FSAR changes.
This will be IFI 335,389/92-20-01, Heat Load Calculations and Resultant FSAR Changes.
Observation 335,389/91-201-02 is closed.
(Closed Units 1 and 2)
OBS 335,389/91-201-03, Lubrication Water Header.
This observation involved the potential for a common mode-failure of the lubricating water supply for the ICW pumps because the two trains of lubricating water joined in a common header.
The two examples given for a common mode failure were a pipe break and a
bearing failure.
The licensee has modified all three ICW pumps on Unit 1 and two out of three on Unit 2.
The last ICW pump to be modified will be started approximately the first of November and completed the middle of November.
These modifications have eliminated the potential for such a common-mode failure.
This item is closed.
(Closed Units, 1 and 2)
OBS 335,389/91-201-04, Pipe Break of TCW Header.
This item addressed Unit 1 non-essential header isolation valves NV-21-2 and NV-21-3 being located below the flood level but not qualified for submersible operation.
These valves failing
~-
.during a flood, combined with a pipe break and cross connection
. through the TCW header, could compromise ICW system operability.
This observation addressed the same base condition as Deficiency Item 335,389/92-201-01, Incomplete and Inaccurate FSAR Descriptions, which was closed in IR 335,389/92-05.
The inspector concluded that the closure analysis also applied to OBS 335,389/92-201-04.
This item is closed.
(Closed Units 1 and 2)
OBS 335,389/91-201-05, GL 89-13 Review for Licensing Basis.
This item addressed FSAR discrepancies in IR 335,389/92-201-01, paragraph 2.1.4.
These same FSAR discrepancies were addressed by Deficiency Item 335,389/92-201-01, Incomplete and Inaccurate FSAR Descriptions, which was closed in IR 335,389/92-05.
The inspector concluded that the closure analysis also applied to OBS 335,389/92-201-05.
This item is closed.
(Closed - Units 1 and 2)
OBS 335,389/91-201-06, Component Cooling Water Heat Exchanger Cleaning.
This observation concerned the licensee's indication that they planned to further review test data by evaluating the worst-cas'e cleanliness factor in combination with the worst-case flow conditions experienced or anticipated.
The inspectors discussed with the licensee the calculation (No.
PSL-BFJH-92-001, Rev.
0) used to evaluate the interim operability criteria of the CCW systems.
Worst case cleanliness/fouling factor for the CCW tubes in conjunction with the worst case ICW flow rate expected were used to (1) demonstrate adequate heat removal by CCW HXs, (2) determine the cleaning interval for these HXs, and (3)
confirm allowable differential pressure across these HXs.
As a result of these calculations, the licensee determined that the HX tubes should be cleaned every nine months (midfuel cycle).
At the time of the team inspection, the licensee was cleaning these tubes-during refueling outages (every 18 months).
The licensee also calculated that the maximum tubeside differential pressure should not exceed 10 psid at 11,000 gpm during normal operations.
The inspectors discussed the CCW HX performance tests and parameters measured that were used to determine tube cleaning times for HXs.
The licensee made conservative assumptions for the calculations of the worst-case flow conditions, e.g.,
pump curve assumes a 10 percent degradation of the pump, assumes lowest level intake/highest level discharge, assumes maximum friction for the concrete lined pipe, etc.
The licensee has taken the necessary actions to close this issue.
(Closed Units 1 and 2)
OBS 335,389/91-201-07, Heat Exchanger Operability Criteria.
This item addressed heat exchanger fouling, fouling control, cleaning and operability criteria.
These same
items were inspected and closed under OBS 335,389/91-201-06.
This item is closed.
(Closed Units 1 and 2)
OBS 335,389/91-201-08, Attention to Corrosion Control.
This observation stated that during the inspection, a 2-1/2 inch diameter carbon steel emergency fill line for Unit I spent fuel pool was being replaced with the same kind of material even though the piping had failed from internal corrosion.
The licensee had not planned to upgrade the piping material to achieve greater corrosion resistance.
The inspectors walk down of this line revealed that this 2-1)2 inch diameter piping runs vertically approximately 4 - 6 feet 'below the I-SB-21386 isolation valve and then runs approximately 70 feet horizontally and then turns up and has a threaded cap.
The leaking valve allowed water t'o leak into the horizontal piping causing pitting corrosion.
The licensee replaced the valve and conservatively replaced the piping from the valve and along all of the hor'izontal run (documentation was,reviewed by the inspectors).
Several facts support the judgmental decision to not change the material:
(1) the plant was not placed in an unsafe condition by the line leak or its replacement; (2) the line is normally dry which the replacement of the valve should insure; and (3) the line had survived 15 years without any problem.
Therefore, the inspector does not conclude that it was necessary to upgrade the piping material.
This item is closed.
(Closed -'nits 1 and 2)
OBS 335,389/91-201-09, Standards for Gearbox Internals Repair.
This observation involved the material condition of the vertically mounted gearboxes for manually operated Henry Pratt valves.
On valve SB21185 the team found that water had entered the gearbox through the position pointer hole and caused extensive internal rusting (valve remained operational).
There are 116 of these valves on Unit 1, 119 on Unit 2, and 7 are common.
All of these valves have been'reconditioned.
The valve position indicators were verified and modified so that they would retain their position.
Gearbox internals were checked, gearboxes were filled with grease, gaskets replaced, cover gaskets between position indicator and gearbox cover were replaced/evaluated.
All of this should prevent the corrosion.found by the team.
The inspectors walked down some of these valves and systems and found their apparent material condition acceptable.
The documentation for four of the valves, SB21185, SB21192, SB21239, and SB21234, was checked to verify that the valves had been reconditioned.
This.item is closed.
(Closed Units 1 and 2)
OBS 335,389/91-201-10, Rotary Strainer
,Gearbox Flooding.
This observation involved the identification of a design inadequacy with the manual operators for the Unit
ICW pump lubricating water Zurn strainers.
This inadequacy allowed rain
.
water to run down the guide tubes, collect on the rotary strainer
gearboxes, and enter the gearboxes through rusted seals.
The gearboxes were functional at the time of the inspection.
Since the inspection, all three Unit
ICW pumps have been modified so that they are self lubricating and no longer need the Zurn strainers.
Two 'out of three of the Unit 2 pumps have this same modification and the third is scheduled to be modified.
The Unit 2 strainer s did not exhibit this problem because they are in an enclosed, area.
The Zurn strainers no longer serve a safety related function after the conversion of the ICW pumps to self lubricating.
This item is closed.
(Closed - Units 1 and 2)
OBS 335,389/91-201-11, Design Failure Regarding. Zurn, Strainer Manual Operations.
This observation stated that it was not obvious to the licensee before the installation of the self-lubrication modification, that the inability to operate the Zurn strainers could have led to the failure of the ICW pumps.
This observation concerned Unit 1's ability to operate the back flush drain valves on the ICW lube water strainers.
During flooding conditions these back flush valves handles would be under several feet of water in a pit and would be difficult to operate.
In response to this item, the licensee revealed that they were aware that the strainers did perform a nuclear safety related function.
The Probable Haximum Hurricane flood level defined in'FSAR (section 3.4) results in submergence of Unit
ICW lube water strainers.
To address this issue, access holes and reach rods are available to allow the manual operation of the strainer wipers (but not the back flush valves).
If manual operation could not be achieved, a backup lube water system would have provided pressurized service water to the lube water and pumps.
The Unit 2 Zurn strainers are above this level and this concern does not exist.
All of the Unit 1 pumps have been converted to self lubrication, therefore the lube water strainers no longer perform a nuclear safety function.
The inspectors walked the system down'or both units.
This item is considered closed.
(Closed - Units 1 and 2)
OBS 335,389/91-201-13, Procedures and Training Review for Action V of GL 89-13.
This observation addressed discrepancies'n training material and an ONOP.
The same material was addressed in Deficiency Item 335,389/91-201-02, previously closed in IR 335,389/92-05 or OBS 335,389/91-201-12, previously closed in IR 35,389/92-18.
This item is closed; r
(Closed Units 1 and 2)
OBS 335,389/91-201-16,
'Revise Generic Letter Response on Inspection.
This observation involved a concern that the licensee was planning to examine less than 100 percent of the safety-related piping in the ICW system in future inspections.
The team observed that if this change in scope were properly managed-that it may be acceptable, however, this change would not be consistent with the licensee's response to the generic letter.
The
0-
team also found the inspections and resultant inspection reports were comprehensive and well done.
During this current inspection, it was noted that the.licensee continued to do 100 percent inspection.
The inspectors discussed the inspection methods and results with the licensee and concluded that the licensee would only propose a change if they could support it from a statistical and engineering point of view. If the licensee proposes this change from the generic letter response then notification will be made to the NRC through the licensing group.
The instructions to notify licensing if the maintenance group intends to do this is included in the task description of the preprogrammed work plan for both units that extends over a five year period and continues to automatically extend.
This plan, FYP 1081
'CW Piping Inspection and Repairs, has work order 92044199 for Unit
and 92006031 for Unit 2.
This item is closed.
(Closed - Units 1 and 2)
OBS 335,389/91-201-18, Repetitive Rework Program Limitations.
This observation stated that, on root-cause evaluations, it was observed that the program's usefulness was limited because it could not search for failures involving other similar components and that the failure criteria of four. times in twelve months was set at too high a threshold to identify all failure trends of interest.
The inspector'determined that the PassPort computer program at St.
Lucie is used to process plant work orders and track maintenance histor'y.
At the time of the team inspection, the maintenance history from the previous computer system had not been added to PassPort even though the PassPort functions that could be used to search for similar component failures were present.
The addition of this data was completed in September, 1992, and capability now exists for computer searches for similar component failures.
With respect to the failure criteria of four times in twelve months for a specific component being too high, the licensee has now lowered this number to three.
While it is not clear that three times per twelve months is a sufficiently low value, there is no data which identifies a specific correct number.
Some of the components are covered by NPRDS which will give a nationally based comparison of similar failures and identify whether this component has a below average, average, or an above average failure rate.
This item is closed.
(Closed - Units 1 and 2)
OBS 335,389/91-201-19, Assessment Program.
This same material was addressed in URI 335,389/91-201-01, Deficiency Item 335,389/91-201-03, and Deficiency Item 335,389/91-201-04, all previously closed in IR 335,389/92-05.
Having considered the closing of all the identified items to the satisfaction of the various inspectors, it is concluded that the licensee's assessment programs are satisfactory.
This item is close The licensee approached the service water inspection report comments in a
serious and business-like fashion.
Licensee documentation and resolution of these issues was excellent.
Followup of Inspection Identified Items (Units 1 and 2)
(92701)
(Closed Units 1 and 2)
URI 335,389/92-05-06, Evaluation of Whether Temperature Control Valves Should be Safety-Related or Not.
This item concerned the air-operated control system for CCW control valves I-TCV-14-4A and 14-4B.
These valves were located in redundant ICW system flow paths downstream of the CCWHXs.
The control systems, consisting of several air-operated components, detected CCW temperature at the CCWHX outlet, processed this temperature input through several air-operated components, and provided air pressure to position valves I-TCV-14-4A and 14-48.
There were minor differences between the Unit 1 and Unit 2 systems.
/
The inspector had observed in the field that the Unit 1 controls were exposed to the elements and were not shielded or otherwise protected from tornado/ hurricane damage as were the CCW pumps and ICW pumps.
The Unit 2 components were located inside a building.
The inspector also observed that PCN 005-190 upgraded some of these components from nonsafety-related to safety-related.
Additional review of the FSAR and vendor manuals, documented in IRs 335,389/92-05, paragraph 9,
and 92-16, paragraph 10, found that the only control system failure mode documented in the FSAR was "Loss of Instrument Air". If instrument air were not lost, failure of an individual nonsafety-related component could cause 'the associated control valve to close, causing inadequate ICW flow for that train.
The maximum air pressure allowed on some of the components was less than the instrument air supply pressure but no relief valves were provided as specified by the vendor manuals.
This condition was evaluated by members of the NRR staff and the NRC Region II supervisor.
Though not well stated in the licensing material, the NRC considered commercial air-operated equipm'ent to be as reliable as safety-related versions.
The separation between Unit 1 trains of control equipment, about 30-50 feet, was considered adequate to preclude common cause failures from external events.
The cooling water systems were redundant at the train level, therefore there was no need to consider component failures within the control systems themselves.
Based on this evaluation, the current configuration is considered acceptable.
This item is closed.
Exit Interview The inspection scope and findings were summarized on October 23, 1992, with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection results listed below.
Proprietary material is not contained in this report.
Dissenting comments were not received from the license V0
Item Number Status
Descri tion and Reference 335,389/91-201-01 closed OBS Component Cooling Water Heat Exchanger Heat Load Summary, paragraph 7.a.
335,389/91-201-02 closed OBS - Variations in Accident Heat Loads, paragraph 7.b; 335,389/91-201-03 closed 335,389/91-201-04 closed OBS-OBS Lubrication Water Header,.
paragraph
.
7.c.
Pipe Break of TCW Header, paragraph 7.d.
335,389/91-201-05 closed OBS GL 89-13 Review for Licensing Basis, paragraph 7.e.
335,389/91-201-06 closed OBS Component Cooling Water Heat Exchanger Cleaning, paragraph 7.f.
335,389/91-201-07 closed OBS - Heat Exchanger Operability Criteria, paragraph 7.g.
335,389/91-201-08 closed OBS 335,389/91-201-09 closed OBS Attention to Corrosion Control, paragraph 7.h.
r Standards for Gearbox Internals Repair, paragraph 7.i.
335,389/91-201-10 closed OBS - Rotary Strained Gearbox Flooding, paragraph 7.j.
335,389/91-201-11 closed OBS - Design Failure Regarding Zurn Strainer Manual Operations, paragraph 7.k.
335,389/91-201-13 closed OBS Procedures and Training Review for action V of GL,89-13.,
paragraph 7.1.
335,389/91-201-16 closed OBS - Revise Generic Letter Response on Inspection, paragraph 7.m.
335,389/91-201-18 closed OBS - Repetitive Rework Program Limitations, paragraph 7.n.
335,389/91-201-19 closed OBS - Assessment Program, paragraph 7.o.
335,389/92-05-06 closed URI - Evaluation of Whether Temperature Control Valves Should be Safety-Related or.Not, paragraph,389/92-20-01 open 335,389/92-20-02 open
,IFI - Heat Load Calculations and Resultant FSAR Changes, paragraph 7.b.
IFI TCV Condition Review, paragraph 3.b(7).
389/92-20-03 open IFI - Unit 2 CCW Throttle Valve, paragraph 3.b(8).
10.
389/92-20-04 open IFI - MFIV Testing Issues, paragraph 5.e.
Abbreviations, Acronyms, and Initialisms AC A/C AOV AP ASME Code AST BTU C
.
.CFR CS DC DEH DPR ECCS EDG EOP EPRI Eg ESF F
FCV FHB FPL FSAR GL gpm HCV HPSI HX I&C ICW IFI IHE INPO IR Alternating Current Air Conditioner Air Operated Valve Administrative Procedure American Society of Mechanical Engineers Boiler and Pressure Vessel Code Auto Stop Trip British Thermal Units Centigrade Component Cooling Water Control Element Assembly Control Element Drive Mechanism Control System Code of Federal Regulations Containment, Spray (system)
Direct Current Digital Electro-Hydraulic (turbine control system)
Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Emergency Diesel Generator Emergency Operating Procedure Electric Power Research Institute Environmentally gualified Engineered Safety Feature Fahrenheit Flow Control Valve Fuel Handling Building The Florida Power 5 Light Company Final Safety Analysis Report
[NRC] Generic Letter Gallon(s)
Per Minute (flow rate)
Hydraulic Control Valve High Pressure Safety Injection (system)
Heat Exchanger Instrumentation and Control Intake Cooling Water
[NRC] Inspector Followup Item In-House-Event Report Institute for Nuclear Power Operations
[NRC] Inspection Report
JPN LCO LPSI HFIV HMP MOV HP METE mv HV HW NCR NCV No..
NPF, NPRDS NPWO NRC NSSS NWE OBS ONOP OP PCH PCV PH psid psi9 PSL Pub.
gC RCO RCP REA Rev RTGB RWT SB SG SHB SNPO SOV SRO
- SRV St.
(Juno Beach)
Nuclear Engineering TS Limiting Condition for Operation Low Pressure Safety Injection (system)
Hain Feed Isolation Valve Mechanical Maintenance Procedure Motor Operated Valve Maintenance Procedure Measuring and Test Equipment millivolt Motorized Valve Megawatt(s)
Non Conformance Report NonCited Violation (of NRC requirements)
Number Nuclear Production Facility (a type of operating license)
Nuclear Plants Reliability Data System Nuclear Plant Work Order Nuclear Regulatory Commission Nuclear Steam Supply System Nuclear Watch Engineer Observations Off Normal Operating Procedure I
Operating Procedure PerCent Milli (0.00001)
Pressure Control Valve Preventive Maintenance Pounds per square inch (differential)
Pounds per square inch (gage)
Plant St. Lucie Publication guality Control Reactor Control Operator Reactor Coolant Pump Request for Engineering Assistance Revision Reactor Turbine Generator Board Refueling Water Tank Safety Train 8 Steam Generator Type of valve actuator Senior Nuclear Plant [unlicensed]
Operator Solenoid Operated Valve Senior Reactor [licensed] Operator Safety Relief Valve Saint Temperature Control Valve Turbine Cooling Water Technical Specification(s)
[NRC] Unresolved Item Volts Direct Current By Way Of Violation (of NRC requirements)