IR 05000335/1993005
| ML17228A122 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/31/1993 |
| From: | Elrod S, Landis K, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A807 | List: |
| References | |
| 50-335-93-05, 50-335-93-5, 50-389-93-05, 50-389-93-5, NUDOCS 9304210043 | |
| Download: ML17228A122 (25) | |
Text
i gp,R RF.Cy, Mp0 UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-335/93-05 and 50-389/93-05, Licensee:
Florida Power
& Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 License Nos.:
DPR-67 and NPF-16 Facility Name:
St.
Lucie 1 and
Inspection Conducted:
Febru 2 to March 5, 1993 Inspectors:
~
~
S. A. El d, Seni Resident Inspector D te igned
. A. Scott, R
en Inspector Approved by:
. K. D.
La s, Chief Reactor Projects Section 2B Division of Reactor Projects SUMMARY Da e S gned ate igned Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review, surveillance observations, maintenance observations, fire protection review, onsite followup of events, followup of regional requests, and followup of corrective actions for violations and deviations.
Results:
Backshift inspection was performed on February 1, 3, 4, 5, 10, 14, 16, 17, 22, 24, 25, 27, 28 and March 2.
Plant operations area:
Operations generally performed well during the inspection period:
good steady-state control of Unit 1; good reaction to a Unit 1 control element assembly problem; excellent reduced inventory controls on Unit 2 (approximately 23 cumulative days);
93042i0043 93033l PDR ADOCK 05000335
good Unit 2 RCS walkdown that discovered low pressure, pressurizer instrument nozzle leak.
One exception to the good performance was a failure to follow procedure violation during Unit 2 cooldown resulting in inadvertent safety injection tank injection into the reactor coolant system:
VIO 389/93-05-01, Failure to Follow Cooldown Procedure (paragraph 3).
Surveillance area:
A number of important surveillances were performed in a professional manner.
No negative aspects were detected (paragraph 5).
Haintenance area:
Regarding major maintenance activities of the inspection period:
during the complex, month-long 2A1 reactor coolant pump (RCP)
repair, activities were overall well controlled and cautious with one exception.
A minor weakness was observed with moving the RCP motor during re-installation (paragraph 5);
and the 1A CCW and 2B Feedwater pump motors were satisfactorily replaced with refurbished motors.
These preventive maintenance activities will contribute to good equipment reliability.
(paragraph 5).
Engineering area:
Engineering strongly supported operations and maintenance in resolving RCP issues for the upcoming Unit 2 startup and long term RCP viabilit REPORT DETAILS Persons Contacted Licensee Employees D.
G.
J.
H.
C.
R.
R.
W.
J.
R.
H.
R.
J.
L.
G.
A.
L.
J.
C.
J.
D.
J.
W.
D.
E.
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 Holt, Plant Licensing Engineer HcLaughlin, Licensing Manager Madden,. Plant Licensing Engineer Henocal, Mechanical Maintenance Department Head Rogers, Instrument and Control Maintenance Department Head Scarola, 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 Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Personnel
- S. Elrod, Senior Resident Inspector
- H. Scott, Resident Inspector R. Crlenjak, Chief, Operational Programs Section, NRC Region II
- Attended exit interview 2.
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 - day 157.
The unit power output was reduced during the weekend of February 6 and 7 for condenser waterbox cleanin Unit 2 began the inspection period shut down.
The 2A1 RCP repair begun during the last inspection period continued through the end of the present period.
During this period, the 2B CCW pump motor and 2B-NFW pump motor were replaced due to the available forced outage time.
The unit was in reduced inventory condition from February 4 to February 25.
While returning to a
RCS fluid level above the RCP seal package (35.
feet), the licensee identified a crack in the 2A2 RCP shaft seal package vapor seal leakoff line.
Operations returned the RCS level to reduced inventory to accommodate repair (February 26 to February 27).
On Parch 2, while preparing for Unit 2 heatup, operations discovered a
slow leak in a pressurizer instrument nozzle.
The inspection period ended with CE replacing four pressurizer steam space instrument nozzles that they had previously replaced in 1988.
During this period, a special inspection was conducted on February 8 -
by P. T. Burnett and C.
W.
Rapp to review non-conservative errors in Unit 2 thermal power measurement due to coherent drift of six resistance temperature detectors.
The inspection results were reported in IR 335,389/93-03.
R.
V. Crlenjak, Chief, Operational Programs Section, NRC Region II, was onsite on February 12 for the IR 335,389/93-03 exit meeting.
His activities included a site tour, informal discussions with licensee management, and review of the issues being addressed.
During this period, a security inspection was conducted on February 8-12 by W. Tobin, accompanied by N. Ervin, NRR and A. Tillman, Region II.
The inspection addressed the licensee's Access Authorization Program and, mainly took place at FPL's Juno Beach corporate offices.
The inspection results were reported in IR 335,389/93-04.
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 properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates.
Some tours were conducted on backshifts.
The frequency of plant tours and control room visits by site management was noted to be adequat 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 that equipment material conditions were satisfactory:
Unit 2 CCW pumps, Unit
CCW pumps, Unit 2 LPSI pumps and 'SDC system, and Unit 2 containment penetrations.
b.
Plant Operations Review The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs, and equipment tagout records.
The inspectors routinely observed operator alertness and demeanor during plant tours.
They observed and evaluated control room staffing, control room access, and operator performance during routine operations.
The inspectors conducted random off-hours inspections'o 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):
2-1-35 2B CCW pump (clearance removed for testing),
and 2-2-86 Unit 2 pressurizer steam space sample line (LLRT testing).
(2)
On February 1, the licensee experienced an organizational interface problem related to the SIT isolation valves.
Operations violated the requirements of OP 2-0030127, Rev 46, Plant Cooldown - Hot Standby to Cold Shutdown, in that after stroke testing the SIT isolation valves in Node 5, l,icensed personnel left the valves in the open position usually found during power operation instead of the closed position they had recently been aligned to per paragraph 8.31.2 of the cooldown procedure.
Subsequent to the SIT valves being misaligned, as RCS pressure decreased during the plant cooldown, the SITs passively
injected approximately four percent of their volume to the RCS.
This injection did not cause a plant safety problem because the SIT contents were borated beyond the concentration for the required shutdown margin and the temperature of the fluid was nearly isothermal with the RCS, being only 3 degrees F cooler.
The only indication that a passive injection had occurred was that pressurizer level increased by over 10 percent.
Operators initially thought the pressurizer level increase was due to auxiliary spray being in service effecting the cooldown progression.
It was speculated that a bubble could have formed in the SG tubes or in the reactor vessel head region with abnormal contraction of the RCS volume.
The operators had followed cooldown rate limitations and had not expected what they were seeing.
Reactor vessel head voiding was excluded as a possible event based on head temperature values being within the expected range.
Operations moved to eliminate possible RCS voids in the SG tubes by repressurizing the RCS and operating the RCPs to sweep bubbles from the RCS.
Once the RCP sweep of the RCS was completed, the licensee re-initiated RCS cooldown.
During the second cooldown, pressurizer level was again noted to increase.
A supervisory operator noted that SIT pressures had followed plant depressurization.
With the SIT isolation valves closed, the pressure should have remained elevated.
Additionally, it was noted that the position indicating meters for the isolation valves were at the "full open" position.
The normal valve position indicating lights were not lit due to the'valve operator circuit breaker being racked out as required.
At this point, nearly two shifts after the valves had been inadvertently left open, the operators checked SIT isolation valve actual positions.
Re-energization and operational checks of the isolation valves confirmed that the valves were indeed in the wrong position.
The valves were placed in the correct position and cooldown was re-commenced.
There had been no air or nitrogen introduced into the RCS.
While there had been no major safety consequences of the mispositioned SIT isolation valves, control room operators had been unaware of the actual positions of the valves for a significant period of time.
The above mispositioning of the SIT isolation valves, an operator error, is violation 389/93-05-01, Failure to Follow Cooldown Procedure.
The licensee did not initially report this event.
In-House-Event Report 93-007, section VI, stated that the event was not reportable because:
RCS temperature decrease due to the SIT volume injection did not result in a mode chang Dumping of the SIT's added approximately -110 pcm of reactivity [increased shutdown margin].
RCS temperatur'e decrease due to the SIT's volume addition was three degrees F.
No emergency declaration was made nor required.
The plant was not placed outside of its design basis and, The injection did not occur as a result of a valid ESFAS signal.
Though not stated in the IHE report, the inspector found that TS did not require the SIT volume for Hode 5, the condition of the plant when the SIT isolation valves were left open, at the time of the SIT passive injection.
Further, TS 3.5.1 recognized that isolating the SITs was not required.
The TS stated, in part,
".In Hode 4 with pressurizer pressure less than'76 psia, the safety injection tanks may be isolated".
After further NRC review, the event was determined to be reportable. under
CFR 50.72 and supporting information.
The reportability was based on RCS parameters passively providing the "signal" for this passive subsystem actuation in lieu of an electronic signal usually associated with 10 CFR 50.72.
The typical ECCS actuation would involve an electronic sensor relaying system information that would initiate pump or valve operation when the system condition met some setpoint.
This actuation involved the passive release of a pressurized volume of borated water from the SITs after RCS pressure, external to the tanks, dropped below the internal tank pressure (approximately 240 psig).
When informed of the NRC opinion on the reportability, the licensee made a telephone report to NRC headquarters and initiated the LER process.
(3)
During the inspection period;- Unit 2 entered a reduced RCS inventory condition to support 2AI RCP work.
At 3:45 a.m.
on February 4, with both residents present, operators commenced reducing St. Lucie Unit 2 RCS water level to approximately one foot above the mid-hot-leg level to facilitate replacing the 2AI RCP pump rotor element.
The following completed items were observed by the inspectors prior to the licensee beginning the RCS level reduction:
Containment Closure Capability - Instructions were issued to accomplish this; men, tools, and instructions were on station.
RCS Temperature Indication - At least 48 normal Hode
CETs were available for indicatio RCS Level Indication - Independent RCS wide and narrow range level instruments, which indicate in the control room, were operable.
An additional Tygon tube loop level in the containment was manned during level changes and checked every two hours during static conditions.
Operators resolved any level reading differences conservatively.
RCS Level Perturbations - When RCS level was altered, additional operational controls were invoked.
At plant daily meetings, operations 'took actions to ensure that maintenance did not consider performing work that might effect RCS level or shutdown cooling.
Site TV monitor announcements discussed attributes of the reduced inventory evolution and reiterated that no work be performed without operations direct input.
RCS Inventory Volume Addition Capability
A second LPSI pump was available for RCS addition.
The "B" HPSI pump breaker was racked-in; a second HPSI pump breaker was racked out as required to meet TS LTOP requirements, but was otherwise available for service.
The "A" charging pump was available.
RCS Nozzle Dams - Due to the type of outage, the nozzle dams were not installed this time.
Vital Electrical Bus Availability Operations would not release busses or alternate power sources for work during this outag'e.
Pressurizer Vent Path - The manway atop the pressurizer has been removed to provide a vent path.
This was observed just prior to water level being reduced.
Operations exited Unit 2 reduced inventory conditions on February 25 at 10:08 p.m.
Operations re-established conditions for reduced inventory on February 26 following a crack being found in the 2A2 RCP vapor seal leakoff line.
A metallurgical evaluation concluded that high cycle fatigue of the 3/4 inch line induced the crack in the pipe next to a socket weld joint at the pump's suction cover.
This conclusion is consistent with the physical layout of the leakoff piping.
With both residents present, the unit re-entered reduced inventory at approximately 5:00 p.m.
on February 26.
Operations exited the Unit 2 reduced inventory condition on February 27 after satisfactory weld repairs had been made.
(4)
On February 8, with both resident inspectors observing, the 2AI RCP rotor was removed from the uncovered pump volute without
any safety problems.
The area around and above the pump lift site were properly cleaned and cleared prior to the lift such that foreign material would not enter the exposed RCS.
The lift itself was well controlled with appropriate health physics personn'el present.
No readily visible obvious indications of a problem were noted with the removed rotating =-element.
There were visual signs of some minor rubbing on the lower impeller wear ring, but this was'xpected with the vibration level seen prior to pump shutdown.
This rubbing was a symptom and not a cause.
A licensee technical team was present to inspect the element upon its removal.
Further pump disassembly findings are discussed in report paragraph 5.d.
On February 16, the RCP motor (105,000 pounds)
was successfully re-installed.
The overall safety aspects of the evolution were good.
Proper lift control and plant safety practices were followed.
Some negative aspects to this lift are discussed in report paragraph 5.d.
Engineering reviewed the events surrounding the 2A1 RCP shaft failure and a previous 1A1 RCP bent shaft problem that was experienced on Unit 1 during 1990.
The review results were captured in the following documents:
(a)
JPN-SENJ-93-001, Rev 0, February 26, 1993, Safety Evaluation for Deletion of RCP Seal Injection.
This
CFR 50.59 evaluation provided justification for discontinuation of RCP seal injection during operation.
(b)
JPN-PSLP-93-0146, Rev 1, February 26, 1993, Evaluation of the Recent RCP Shaft Problems and their Effects on Plant Operation.
This document assessed the significance to plant operation and safety of the recent RCP shaft problems.
Document (6)(a)
above concluded that due to recent, though incomplete, root cause analysis, the RCP seal injection was strongly implicated in the RCP shaft problems.
The seal injection system had been added for the economic reason of RCP seal longevity and not for safety purposes.
Removal of the system from its usual plant heatup and cooldown service would pose no safety problem.
Further, the evaluation concluded that seal injection should be discontinued for other than fill of the RCS and venting of the pumps.
The inspector found this conclusion consistent with past events.
The operations technical support staff has changed the Unit 2 procedures per the above recommendations.
Additionally, they issued a temporary instruction to monitor RCP seal performance during the upcoming startup.
The licensee plans to evaluate
the procedures during the startup and implement them for Unit
after that time.
Document (6)(b) above concluded 'that the effects of a RCP failure are safely mitigated with the previous design and operational controls in place. 'his had been supported by the last two RCP problems.
Hoth of these events had been controlled and are understood phenomena.
The evaluation cited eight other utilities that had similar vendor pump and shaft problems, none of which had significant safety impact.
(7)
On Harch 2, while preparing for Hode 4, the licensee identified leakage coming from under mirror insulation at the lower curvature of the Unit 2 pressurizer.
The plant was in Hode
with the RCS at 200 psig and 100 degrees F.
Further investigation revealed unexpected leakage from the pressurizer steam space instrument nozzles.
Three of four nozzles installed by CE in 1988 showed signs of leakage and the fourth had flowing leakage.
The four instrument nozzles had been replaced in 1988 because the previous ones were made of crack susceptible material.
At the end of the inspection period, CE and the licensee were evaluating the problem and preparing repair options.
The licensee planned to submit an information LER.
c.
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 revisions.
d.
Physical Protection The inspectors verified by observation during routine activities that security program plans were being implemented as evidenced by:
proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.
In summary, Operations generally performed well during the inspection period:
good steady-state control of Unit 1;
good reaction to a Unit
CEA 14 problem; excellent reduced inventory controls on Unit 2 (approximately
cumulative days);
and good RCS walkdown effort to identify leakage problems.
One exception to the good performance was a failure to follow procedure violation during Unit 2 cooldown.
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 results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following surveillance tests were observed:
a.
I&C 1-1400052, Rev 32, Engineering Safeguards System'Channel Functional Check (see paragraph 5.a)
b.
OP 2-22000508, Rev 3, 2B Emergency Diesel Generator Periodic Test and General Operating Instructions c.
OP 2-0310020, Rev 26, Component Cooling Water Normal Operation
[2B CCW pump return to service]
k Observed surveillances were professionally performed and were well coordinated.
5.
.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:
NPWO 0208/63 Replace Power Supply 409 for SG 2B Pressure ESFAS Actuation-.
During performance of IEC l-1400052 indicated in paragraph 4 above, power supply 409 was found out of specification.
This was replaced and tested under the administrative controls of the subject NPWO.
NPWO 4979/62 - 2B CCW Pump Overhaul.
Work continued on this pump this inspection period.
At the end of the last inspection period, attempted surveillance testing revealed a pump outboard mechanical seal leak.
This, along with a weeping seal cooling line leak, was repaired and the unit was satisfactorily retested.
NPWO 6160/66 - 2B Feedwater Pump Hotor Replacement.
This motor was replaced due to unusual motor noise and vibration.
The vibration was not of sufficient amplitude to warrant motor changeout at this time without this forced outage.
Hotor changeout had been planned for the normal unit refueling outage (fall 1993).
Since the duration of the RCP repair was of sufficient length, the licensee decided to replace the motor with a recently refurbished spare to reduce the refueling outage work load.
The motor air boxes on the Unit 2 feedwater motors had never been removed during previous motor work.
The large air boxes sit above
'the motor and cover the exterior of the windings.
The inside of the motor windings have been routinely cleaned and inspected.
Upon removal of the air box, the licensee found oil and grease buildup on the exterior of the windings.
The amount was not sufficient to cause immediate damage or an operability issue.
The licensee will consider inspection of the other non-safety related HFW motor winding exterior for the next refueling outage.
The Unit
HFW motor winding exteriors were inspected and cleaned two outages ago.
The inspectors observed replacement of the motor, taping of the motor leads, operational testing of the motor alone, and coupled motor-pump testing.
NPWO 6299/62 2A1 RCP Repair.
Under this broad NPWO most aspects of the RCP repair were covered.
As the licensee cautiously progressed stepwise through the repair, they would issue a scope change, much like a revision or separate section, to the work package.
The major scope changes covered major evolutions such as pump rotating element removal, element re-installation, motor re-installation, etc.
The NRC inspectors were present for the below listed evolutions.
The removed 2A1 RCP pump rotating element was sent to BI%W radiological repair facility this inspection period (the week
of February 8) for root cause evaluation.
B&W found a crack in the pump shaft slightly above the weld for the hydrostatic bearing drum upper side plate, which was attached to the shaft.
The side plate holds and positions the drum (or journal) in the hydrostatic bearing.
The crack was over halfway through the shaft.
There were some additional cracks noted in the weld for the upper side plate.
The B&W report I'and subsequent licensee root cause report] is planned to be issued after the end of this inspection period.
The actual pump element removal was well controlled with good health physics coverage.
The path for the lift was well thought out with good features in controlling radiological dose, loose contamination, and pump water drippage.
-"
B&W and BJ personnel assisted and participated in the new rotating element assembly and dimensional checks.
They were instrumental in providing continuity and expertise to the effort.
The attachment of the new hydrostatic bearing to the pump suction cover went extremely smoothly and the radiological control effort was good.
The licensee was capturing (by procedure)
much of the utilized information.
The new pump casing wear ring was installed and the cap screws with lock pins that hold the ring in the casing were pinned and staked to retain them in place.
The B&W representative and site gC personnel were present for this staking evolution.
This went smoothly with low radiological dose.
A special B&W provided cover/tool that covered the majority of the pump casing was excellent for ALARA considerations during all in-pump casing work.
The licensee constructed cleanliness covers that worked well in preventing foreign material entry.
During the motor installation, overall work control was good, but some negative aspects were present.
To save time, several removed motor support assembly pieces were installed on the motor prior to landing it.
Some of these pieces, namely an oil collection elbow on'he bottom of the motor and the CCW motor cooler piping, impeded motor installation.
Additionally, scaffolding was still around the motor installation site.
The pre-installed piping and the scaffolding interfered with the motor path due to the tightness of the space.
As the motor was entering its installed position, several adjacent existing pipes were contacted by piping preinstalled on the motor.
This contacted piping's insulation had to be removed for damage inspection.
No piping damage was found.
The scaffolding interfered with several points on the motor and with the CCW piping.
The scaffolding tore open bags over the end of the CCW piping flanged ends, which had no temporary blind flanges installed.
Trapped non-contaminated water in the
piping [from the coolers] spilled on the adjacent tools and pump/motor walkways.
This required additional health physics coverage since the water could spread any loose surface contamination.
At this point, the lift was halted and some of the interfering scaffolding was removed.
The removal of the scaffolding caused some minor concerns stemming from the potential personnel hazard due to falling scaffolding components.
In summary, although adequately executed and no equipment was immedi'ately jeopardized, the motor installation left room for additional pre-job scope work and preparation.
e.
NPWO 6084/65 Remove/Re-insulate/Re-install the 1A CCW Pump Motor.
The 1A CCW pump motor was shipped to Tampa for re-insulation of its windings.
This was performed, in part, as a demonstration for attendees at an EPRI motor overhaul conference in Tampa.
The inspector observed the satisfactory motor-to-pump coupling alignment and the operational check of the coupled unit.
The coupled pump test data indicated that unit was one of the smoother running pumps at the site.
f.
NPWO 0174/63 - Replace Timer Module on Unit
CEA 14.
On February 25, while performing a
CEA motion/alarm quarterly test per OP 1-0110050, operations could not drive Unit
CEA 14.
Appropriate TS directions were followed.
Troubleshooting indicated that the timer card had failed.
The above NPWO provided administrative guidance during the satisfactory timer module replacement.
Coordination between operations and 18C personnel was good.
In summary, regarding major maintenance activities during the inspection p'eriod:
during the complex, month-long 2Al RCP activities, repairs were overall well controlled and cautious with one exception.
A minor weakness was observed with moving the RCP motor during re-installation; and the lA CCW and 2B Feedwater pump motors were satisfactorily replaced with refurbished motors.
These preventive maintenance activities will contrubute to good equipment reliability.
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, control
of hazardous chemicals, ignition source/fire risk reduction efforts, and fire barriers.
A During this period, fire protection activity was satisfactory.
Onsite Followup of Events (Units 1 and 2)(93702)
Nonroutine plant events were reviewed. to determine the need for further or continued NRC response, to determine whether corrective actions appeared appropriate,'nd to determine that TS were being met and that the public health and safety received primary consideration.
Potential generic impact and trend detection were also considered.
With the exception of the Unit 2 SITs passive injection, the operational events that are discussed elsewhere in this report were handled satisfactorily.
Followup of Regional Requests (Units
and 2)
(92701)
During the course of the inspection period, the Regional NRC office requested surveys of security functions.
A letter dated February 12 requested a survey of gates at the site.
This survey was completed on February 19.
A letter dated Harch 2 requested an additional survey of site security activities.'his survey was completed on Harch 4.
Followup of Corrective Actions for Violations and Deviations (Units 1 and 2)(92702)
(Open) 50-335,389/92-21-07, Failure to Adequately Haintain Containment Vessel Integrity.
During this inspection period, the licensee's response to the subject vi'olation had to be modified and a temporary waiver of compliance generated.
FPL's initial response letter L-93-005, dated January 20, 1993, did not adequately address the TS aspects of the current containment condition.
FPL letter L-93-046, modifying their initial response was dated Harch 2, 1993.
Under the present interpretation of the TS, the existing Unit 1 TS 4.6. l.l.a. 1 required a waiver.
On February 16, 1993, the NRC granted a temporary waiver of compliance for.
the Unit 1 TS.
This violation remains open pending completion of corrective actions for both Units 1 and 2.
Exit Interview The inspection scope and findings were summarized on Harch 8, 1993, 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 licensee.
Item Number 389/93-05-01 paragraph 2.
Status open Description and Reference VIO Failure to Follow Cooldown Procedure, 335,389/92-21-07 open VIO Failure to Maintain Containment Integrity, paragraph 9.
Abbrev AC ALARA ATTN BJ BLW CC CCW CE CEA CET CFR DC DPR ECCS EPRI ESF ESFAS F
FPL HPSI ILC IHE IR JPE JPN LCO LER LLRT LPSI LTOP MFW No.
NPF NPWO NRC NRR OP pcm psia iations, Acronyms, and Initialisms Alternating Current As Low as Reasonably Achievable (radiation exposure)
Attention Byron Jackson (company)
Babcock and Wilcox (company)
Cubic Centimeter Component Cooling Water Combustion Engineering (company)
Control Element Assembly Core Exit Thermocouple Code of Federal Regulations Direct Current Demonstration Power Reactor (A type of operating license)
Emergency Core Cooling System Electric Power Research Institute Engineered Safety Feature Engineered Safety Feature Actuation System Fahrenheit The Florida Power
& Light Company High Pressure Safety Injection (system)
Instrumentation and Control In-House-Event Report
[NRC] Inspection Report (Juno Beach)
Power Plant Engineering (Juno Beach)
Nuclear Engineering TS Limiting Condition for Operation
Licensee Event Report Local Leak Rate Test Low Pressure Safety Injection (system)
Low Temperature Overpressure Protection (system)
Main Feed Water Number Nuclear Production Facility (a type of operating license)
Nuclear Plant Work Order Nuclear Regulatory Commission NRC Office of Nuclear Reactor Regulation Operating Procedure PerCent Milli (0.00001)
Pounds per square inch (absolute)
pslg PSL QC RCP RCS Rev RWT SDC SG SIT St.
TS VIO
Pounds per square inch (gage)
Plant St. Lucie Quality Control Reactor Coolant Pump Reactor Coolant System Revision Refueling Water Tank Shut Down Cooling Steam Generator Safety Injection Tank Saint Technical Specification(s)
Violation (of NRC requirements)
Docket Nos.
50-335, 50-389 License Nos.
DPR-67, NPF-16 Florida Power 5 Light Company ATTN:
J.
H. Goldberg President
- Nuclear Division P. 0.
Box 14000 Juno Beach, Florida 33408-0420 Gentlemen:
SUBJECT:
NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-335/93-05 AND 50-389/93-05)
This refers to the inspection conducted by S. A. Elrod of this office on February 2 to Harch 5, 1993.
The inspection included a review of activities authorized for your St. Lucie facility.
At the conclusion of the inspection, the findings were discussed with those members of your 'staff identified in the enclosed report.
Areas examined during the inspection are identified in the report.
Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.
Based on the results of this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of Violation (Notice).
The violation is of concern because control room operators were not aware of the positions of the Safety Injection Tank isolation valves for a significant period of time.
You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response.
In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence.
After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice,"
a copy of this letter and its enclosures will be placed in the NRC Public Document Roo MAR 81 ]gyp Florida Power
& Light Company Should you have any questions concerning this letter,'lease contact us.
Sincerely, C~g P~ +~ pixy Marvin V. Sinkule, Chief Reactor Projects Branch
, Division of Reactor Projects
Enclosures:
1. Notice of Violation 2.
NRC Inspection Report
REGION II==
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-335/93-05 and 50-389/93-05 Licensee:
Florida Power 5 Light Co 9250 West Flagler Street Hiami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St.
Lucie
and
License Nos.:
DPR-67 and NPF-16 Inspection Conducted:
Febru 2 to Harch 5, 1993 Inspectors:
~
~
S.
A. El d, Seni Resident Inspector D te igned
. A. Scott, R
en Inspector Da e S gned Approved by:
K.
.
La s, Chief Reactor Projects Section 2B.
Division of Reactor Projects SUHHARY ate igned Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review, surveillance observations, maintenance observations, fire protection review, onsite followup of events, followup of regional requests, and followup of corrective actions for violations and deviations.
Results:
Backshift inspection was performed on February 1, 3, 4, 5, 10, 14, 16, 17, 22, 24, 25, 27, 28 and Harch 2.
Plant operations area:
Operations generally performed well during the inspection period:
good steady-state control of Unit 1; good reaction to a Unit 1 control element assembly problem; excellent reduced inventory controls on Unit 2 (approximately 23 cumulative days);