ML20138G494
| ML20138G494 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/31/1993 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20138F638 | List: |
| References | |
| FOIA-96-485 NUDOCS 9705060312 | |
| Download: ML20138G494 (27) | |
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REGION II ATLANTA, GEORGIA PLANT STATUS REPORT 6
ST. LUCIE October, 1993 N
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. BINDER 96-485 PDR
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PLANT STATUS REPORT PLANT STATUS REPORT FOR ST. LUCIE UNITS 1 AND 2 (10/93)
TMLE OF CONTENTS PART 1 FACILITY DESCRIPTION 1.1 FACILITY / LICENSEE.............. .. ... .............Page 2 1.2 UTILITY SENIOR MANAGEMENT ..........................Page 2 1.3 NRC STAFF....... ........ ... ... ........... . . .Page 2 1.4 LICENSE INFORMATION.... .. ................. .. .. ..Page 3 1.5 PLANT CHARACTERISTICS............................. ...Page 3 1.6 SIGNIFICANT DESIGN INFORMATION........................Page 3 1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS.... .. . .Page 8 1.8 PRESENT OPERATIONAL STATUS (Past Six Months)..... .Page 9 1.9 OUTAGE SCHEDULE AND STATUS. . .. .. .. . .. .......Page 10 PART 2 PLANT PERSPECTIVE 2.1 GENERAL PLANT PERSPECTIVE............ . ...........Page 11 2.2 SALP HISTORY (Past Two SALP Periods). . ...... .Page 11 2.3 SELECTED SALP AREA DISCUSSIONS . ....... ... ... ....Page 11 PART 3 SIGNIFICANT EVENTS 3.1 SIGNIFICANT EVENTS BRIEFINGS (Past 12 Months)... ....Page 14 3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months).. ... ...Page 15 PART 4 STAFFING AND TRAINING 4.1 OPERATIONS STAFF - OVERALL. . .......................Page 15 4.2 WORK FORCE ..........................................Page 15 4.3 OPERATOR QUALIFICATION /REQUALIFICATION PROGRAM.......Page 15 4.4 PLANT SIMULATOR... ................ ...... ...... ...Page 16 4.5 INP0 ACLREDITATION, ........ ..................... ..Page 16 PART 5 INSPECTION ACTIVITIES 5.1 OUTSTANDING ITEMS LIST
SUMMARY
............ .. .......Page 16 5.2 MAJOR INSPECTIONS......... ............... ..........Page 17 5.3 PLANNED TEAM INSPECTIONS................. ..........Page 17 5.4 INFREQUENT INSPECTION PROCEDURE STATUS. .... ........Page 17 5.5 SIMS STATUS (OPEN TMI ITEMS). ......... ..............Page 17 ATTACHMENTS
- 1. PERFORMANCE INDICATORS
- 2. ALLEGATION STATUS AND
SUMMARY
- 3. NRR OPERATING REACTOR ASSESSMENT J
2 PART 1- FACILITY DESCRIPTION 1.1 FACILITY /LICENdEE FACILITY: St. Lucie Units 1 and 2 PLANT LOCATION: Ht'.chinson Island near Port St. Lucie Florida LICENSEE: Fl:"ida Power and Light Co. (Corporate Office in Juno :
Beach, Florida) 1.2 UTILITY SENIOR MANAGEMENT CORPORATE:
J. L. Broadhead (Jim). Chairman of the Board and CEO J. H. Goldberg (Jerry). President, Nuclear Division SITE: (effective 10/1/93)
D. A. Sager (Dave) - St. Lucie Plant Vice President C. L. Burton (Chris) - Plant General Manager H. F. Buchanan (Hank) - Health Physics Supervisor R. E. Dawson (Bob) - Maintenance Manager PENDING SELECTION - Nuclear Assurance Manager H. L. Fagley (Herman) - Construction Services Manager P. L. Fincher (Pat) - Training Manager R. J. Frechette (Bob) - Chemistry Supervisor J. B. Hosmer (John) - Site Engineering Manager L. L. McLaughlin (Lamar) - Licensing Manager J. Scarola (Jim) - Operations Manager C. A. Pell (Ash) - Services Manager D. H. West (Dan) - Technical Manager J. A. West (Jeff) - Operations Supervisor E. J. Wunderlich (Erwin) - Reactor Engineering Supervisor 1.3 NRC STAFF REGION II. Atlanta. GA:
S. D, Ebneter (Stew). Regional Administrator (404) 331-5500 L. A. Reyes (Luis). Deputy Regional Administrator. (404) 331-5610 l
' E. W. Merschoff (Ellis). Director DRP. (404) 331-5179 :
J. R. Johnson (Jon). Deputy Director DRP. (404) 331-5623 M. V. Sinkule (Marvin). Branch Chief. (404) 331-5506 K. D. Landis (Kerry). Section Chief. (404) 331-5509 R. P. Schin (Bob) Project Engineer. (404) 331-5561 !
A. R. Long (Becky). Project Engineer. (404) 331-4664 l SITE:
S. A. Elrod (Steve). Senior Residont Inspector. (407) 464-7822 M. S. Miller (Mark). Resident Inspector. (407) 464-7822
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NRR.
S. A. Varga (Steven). Director. Division of Reactor Projects-l/II, l (301) 504-1403 G. C. Lainas (Gus). Assistant Director for Region II Reactors.
(301) 504-1453 H. N. Berkow (Herb). Director Project Directorate II-2.
(301) 504-1485 J. A. Norris (Jan). Senior Project Manager. Project 1 Directorate 11-2. (301) 504-1483 AE00:
S. Israel (Sandy). Reactor Operations Analysis Branch.
(301) 492-4437 -
1.4 LICENSE INFORMATION i Unit 1 Unit 2 Docket Nos. 50-335 50-389 License Nos. DPR-67 NPF-16 Construction Permit Nos. CPPR-74 CPPR-144 Construction Permit Issued 7/1/70 5/2/77 Low Power License NA 4/83 Full Power License 3/1/76 6/10/83 Initial Criticality 4/22/76 6/2/83 1st Online 5/17/76 6/13/83 Commercial Operation 12/21/76 8/8/83 1.5 PLANT CHARACTERISTICS Descriotion Units 1 and 2 -
Reactor Type Combustion Engineering PWR 2-loop Containment Type Freestanding Steel w/ Shield Building ;
Power Level 830 MWe (2700 MWt)
Architect / Engineer Ebasco NSSS Vendor Combustion Engineering Constructor Ebasco Turbine Supplier Westinghouse Condenser Cooling Method Once Through '
Condenser Cooling Water Seawater 1.6 SIGNIFICANT DESIGN INFORMATION 1.6.1 REACTOR INTEGRITY Reactor Pressure Vessel (RPV)
With the present fuel type and management policy. Unit 1 is expected to reach a 40-year RPV life. On this unit, the fuel type and management policy have been modified to make that life span possible. Presently, initial planning is in progress for RPV life
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4 extension beyond the projected 40 years, potentially to 60 years. '
via a flux reduction program. A flux reduction program has started with the addition of eight absorbers in core corner positions. This program continues to be evaluated.
Due to different design and construction characteristics. Unit 2 RPV life expectancy exceeds 60 years.
Reactor Coolant Pressure Boundary On this CE 31 ant. ECCS-to-RCS injection points are isolated by at least two cleck valves and one closed MOV. High 3ressure safety injection (HPSI), low pressure safety injection (_ PSI), and containment spray (CS) pumps' common containment sump suctions are isolated from the containment sump by one closed MOV in conjunction with a closed seismic piping system. The CS headers are isolated from containment by one closed MOV and a check valve in conjunction with a closed seismic piping system. CVCS has the normal complement of two automatic actuation isolation valves.
1.6.2 REACTOR SHUTDOWN Reactor Protection System The reactor protection system provides protection for the reactor .
fuel and its cladding by providing automatic reactor shutdowns (8 '
trips) based on input from reactor power reactor coolant ,
pressure, coolant temperature, coolant flow, steam generator pressure, and containment pressure. The RPS is a redundant four- ;
channel system that operates on a two-out-of-four logic.
ATWS Protection ATWS protection, outside the normal reactor protection system, is initiated via the ESF nressurizer pressure signal. It actuates by opening contactors in the output of the CEA MG sets, thereby interrupting control element assembly power at its source. This protection has been installed on both units per CE, the NSSS.
recommendations.
I Remote Shutdown Facilities !
These facilities are located in the switchgear rooms beneath each unit's control room.
l 1.6.3 CORE COOLING
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Feedwater System The main feedwater pumps are motor driven with each delivering 60 percent of the flow required for full power.
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5 Turbine Bvoass/ Steam Dumo Canacity Each unit has five steam bypass valves. providing 45 percent of total capacity.
Unit I has one atmospheric dump valve per train (two trains) and Unit 2 has two valves per train. Each unit has the capability of dumping.eight percent. steam flow to the atmosphere.
Auxiliary Feedwater System There are two motor-driven pumps on each unit with 100 percent capacity per pump. There is one steam-driven pump on each unit with 200 percent capacity. Any of the three pumps can inject to either generator. Automatic initiation and faulted generator protection are provided by each unit's Auxiliary Feedwater Actuation System provided by the NSSS.
Emeraency Core Coolina System In each unit, there are two HPSI pumps and two LPSI pumps with no unit-to-unit cross-connections. One pump of each type per unit will handle a postulated LOCA. The LPSI pumps also provide decay heat removal as required when the unit is shut down.
As indicated above, the LPSI pumps also provide decay heat removal as required when the unit is shut down by taking suction from the RCS (hot legs), passing the fluid through the shutdown cooling heat exchangers, and returning it to the RCS (cold legs). The heat removing medium is CCW - discussed in section 1.7.6 below.
Shutdown cooling flow path overpressure protection is provided by automatic isolation valves and various relief valves in the system.
1.6.4 CONTAINMENT Pressure Control / Heat Removal There are two containment spray pumps and four containment fan coolers available per unit to suppress pressure spikes and cool the containment. One CS pump and two fan coolers will handle a postulated LOCA. There are no unit-to-unit cross-connections.
This engineered safety feature is automatically started by ESFAS.
Hydroaen Control Containment hydrogen control post-LOCA is accomplished on each unit by two trains of hydrogen recombiners located on the operating deck inside containment. By elevating, in a controlled manner, the temperature of containment atmosphere flowing through
6 the recombiner. the recombiner units recombine hydrogen and oxygen to form water, thus preventin potentially explosive levels.g the buildup of hydrogen to 1.6.5 ELECTRICAL POWER l Offsite AC The station switchyard is connected to the transmission system by three independent 240 KV lines that share a right of way and interconnect with FPL's grid on the mainland approximately 10 miles West of the )lant site. There are two independent offsite i power feeds from t1e station switchyard to the emergency busses, i
Onsite AC Onsite AC power is provided by four EDGs (two per unit). EDGs are independent of other plant systems except vital DC power for control of starting. A Station Blackout (SB0) cross connection is installed and tested. This cross-connection serves the emergency busses directly and reduces cross-connect time to less than 15
, minutes.
DC Power i
Two trains of vital batteries Jer unit are routinely tested for l
four-hour DC load profiles. Tiere are four normal chargers per unit with swing chargers available for service. Non-safety batteries can be cross-connected to the safety-related swing bus if needed.
Instrumentation Power Each unit has four inverters, two powered from each vital DC train, that provide four trains of instrumentation power.
L Station Blackout Resolution Status Unit 2 is a four-hour "DC co)ing" plant per the original license while Unit 1 is subject to t1e station blackout (SBO) rule of 10 CFR 50.63 requiring additional licensee action (unit-to-unit cross-connect of 4160V bus).
An EDSFI team inspection was satisfactorily completed in March.
1991 with no major adverse findings.
1.6.6 SAFETY-RELATED COOLING WATER SYSTEMS Intake Coolina Water (Service Water)
Intake cooling water (ICW) for each unit originates in a common canal called the Intake Cancl. The canal level varies with the
7 tides since it is filled by a level difference between the Atlantic Ocean and the canal. One 16-foot and two 12-foot diameter Jipes pass under the beach to connect the ocean and canal. T1e piae ends in the Atlantic are covered by intake structures (re)uilt in 1991) intended to limit flow velocities, particularly vertical velocity. to reduce marine life entrapment. '
After use. ICW returns to the ocean through a Discharge Canal and under-beach pipes.
Each unit has two trains of ICW plus a swing pump that can be aligned to either train electrically and physically. The licensee has converted the dee) draft ICW pumps from externally (water) lubricated to self-lu)ricated to increase reliability of the lubrication water source. The 100 percent (each) capacity pumps take suction from the intake canal via a canal intake structure using traveling screen debris protection. The intake canal structures adjacent to the ICW pump suctions are continuously {
injected with a hypochlorite solution to reduce marine growth in the associated piping and heat exchangers. Commencing 3/92. l periodic injection of a clamicide at the intake structures. '
primarily to control marine growth affecting the turbine i condensers. has also reduced marine growth affecting the ICW l system. I i
The ICW pumps move water through two trains of heat exchangers !
, that cool component cooling water (CCW) and two trains of heat j exchangers that cool main turbine cooling water. During a
)ostulated accident. water flow isolates from the turbine cooling leat exchangers. The discharge from the heat exchangers returns via the discharge canal to the ocean.
This system was inspected by an NRC headquarters team which found that the system would perform its function, however potential enforcement issues required additional follow up in February, 1992. Other issues have been satisfactorily closed after additional followup.
Increases in debris and silt in the heat exchangers indicate that the intake canal needs dredging. ;
This was planned for Spring of 1993 during the Unit 1 l refueling outage, but the utility failed to plan for >
environmental permits. 1 As of September, 1993, the utility is routinely cleaning main condenser waterboxes at reduced power and applying ;
high-level attention to obtaining necessary dredging permits from the state and Corps of Engineers.
Closed Coolina Water Systems 4
. Each unit has two trains of Component Cooling Water (CCW). The ,
arrangement of two aumps and a swing pump mimics the ICW system.
The swing pump can ]e aligned to either train. The 100 percent
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i (each) capacity.) umps drive water through the CCW/ICW heat ;
i exchangers and tien on to the heat loads, mainly the containment !
fan coolers and the shutdown cooling (decay heat) heat exchangers (which also can operate as containment spray heat exchangers). :
Additionally. CCW cools HPSI. LPSI, and CS pump bearings, seals. !
- and oil coolers. A non-safety-related portion of the CCW system- !
! cools reactor coolant pump seals and the spent fuel pool. This '
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section isolates upon engineered safety features actuation.
i 1.6.7 SPENT FUEL' STORAGE l Wet storage capability exists up to the year 2002 (Unit 2) and
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2007 (Unit 1). ,
[ 1.6.8 INSTRUMENT AIR SYSTEM '
- Instrument air compressors and driers installed several years ago 2
provide all instrument air for Unit 2 and all but containment air i
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for Unit 1. These have increased instrument air reliability.
Unit 1 also has instrument air compressors inside containment.
1.6.9 STEAM GENERATORS )
Each unit has two large steam generators (SGs) rather than the three or four usually seen. The licensee has begun to focus on a Unit 1 SG replacement in 1997.
1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS Emergency Operations Facility: 10 miles West of site.
I-95/ Midway Rd.. Exit Technical Support Center: Onsite. Adjacent to Unit 1 Control Room Operational Support Center: Onsite. 2nd floor of North Service Building l The last annual emergency preparedness exercise (partial government participation) was held June 23. 1993 and again featured stand-ins for !
all principal players. It had one exercise weakness - emergency-
- o>erations facility (EOF) activation was delayed pending the arrival of ;
tie recovery manager. The utility has since trained several interim :
recovery managers and conducted a callout EOF activation drill on August i
- 26. 1993, to demonstrate that the weakness was corrected. The next 4 previous emergency drill was held February 12. 1992, and featured stand-ins for all principal players. It was rated fully successful. A previous emergency drill was held March 20-21, 1991. That exercise was also fully successful and was observed by representatives from Russia. 1 The next EP exercise is scheduled for February 9. 1994.
Since St. Lucie s1te has a high probability of hurricanes.
9 communications facilities were improved following the Turkey Point experience with Hurricane Andrew in August.1993. Improvements include:
High Frequency Auto-link with other FPL sites and NRC.
Enhanced 900 MHZ System for site and mobile comminications, with radios also in the licensee's EOF and county emergency facility.
Cellular ahones with hardened antennas.
Hardened ocal Government Radio antenna ties.
1.8 PRESENT OPERATIONAL STATUS (10/6/93)
Unit 1 is operating at 100% power.
Unit 2 is operating at 100% power.
Availability Factors:
Unit 1 Unit 2 -
1991 81.0 100.0 1992 96.5 75.2 1993 (through August) 66.7 60.6 Cumulative (through Aug.) 76.3 82.7 1.8.1 UNIT 1 OPERATING HISTORY (Past Six Months)
Unit 1 shut down for a scheduled refueling outage on March 29.
1993 and restarted on May 28, 1993.
Unit 1 began a forced shutdown on May 30. 1993, due to indications of an unlatched control rod that was found during routine low power physics testing.
Following correction of the unlatched control rod, repair of the RCP 1A2 shaft seal, and emergent repairs to the main condenser boot seal. Unit 1 was returned to power on June 22.
Control Element Assembly #3 dropped during exercising on August
- 26. 1993. It was promptly recovered.
On September 18 and again on September 20 and September 22. 1993.
Unit 1 was manually tripped (from 75. 63, and 11% power) due to jellyfish clogging the intake travelling screens, which required immediately stopping the affected circulating water pumps. Unit 1 operated at various reduced power levels for about two weeks due to the unusual numbers of jellyfish.
Other power reductions involved cleaning condenser water boxes and repairs to the 1A2 circulating water pump.
1.8.2 UNIT 2 OPERATING HISTORY (Past Six Months)
On January 13. 1993. Unit 2 was manually shut down to repair the 2A1 reactor coolant pump (high vibration due to cracked shaft).
The vibration monitor had provided early warning; and licensee
t 4 10 analysis determined that, had the shaft com)letely broken while operating, it would not have resulted in a _0CA. The licensee made the following changes to preclude recurrence: extensive vibration and temperature instrumentation moaification/ addition, RCP seal injection procedures changed. The licensee is having the cracked shaft analyzed and expects results by late Summer. Unit 2 '
was restarted on March 31, 1993.
While Unit 2 was shut down for the RCP 2A1 repair, four leaking pressurizer steam space instrument nozzles were discovered and repaired. The Inconel 600 nozzles that had cracked were replaced with Inconel 690 nozzles. Licensee analysis determined that these cracks would not have resulted in a catastrophic failure or LOCA.
On May 21,1993, Unit 2 was manually tripped from 72% power by operators in response to seven CEAs dropping into the core. The cause was found to be electrical ground faults in five CEA control wires in two modules (tubes) in one shield building penetration.
The unit was restarted on May 25, 1993.
On August 9,1993, Unit 2 was taken off line because of steam generator chemistry problems resulting from a condenser tube leak.
The unit was repaired and back in service on August 11.
Since completion of the Unit 2 refueling outage on July 8,1992, '
there have been an increased number of trips and forced shutdowns.
All were due to equipment problems except one forced shutdown that was, in part, due to operator error. Each was different and no trends were apparent.
Unit 1 Unit 2 reactor trips 1 auto 1 auto 2 manual forced shutdowns 1 3 The licensee responded positively to this string of problems as a possible maintenance trend and has implemented some conservative short term corrective actions.
1.9 OUTAGE SCHEDULE AND STATUS
. Unit l's last refueling outage began on March 29, 1993, and ended on May l 28, 1993. Major outage activities included: refueling: steam generator l
tube inspection and plugging: station blackout related electrical cross-tie testing: Containment pressure sensing lines labelling and capping:
Containment integrity violation corrective action (penetrations identified, caps installed): safety-related breaker protective relays -
I rewired for " green slime": HFA latching relays verified operable; post-accident containment water level monitoring system - magnetic reed switch system installed: Mod to stop auxiliary building exhaust fan upon SI installed: radiation monitors replaced for liquid release to CCW and batch liquid release system: safety-related motor bearing alarm setpoints reduced per vendor request: EDG fan drive modification to
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reduce vibration: and mechanical electrical, and 1&C systems maintenance.
Unit 2's last refueling outage began on April 20. 1992, and ended on June 26, 1992. Major outage activities included: refueling: steam generator tube inspection and plugging: low pressure turbine blading replacement; emergency diesel generator inspection: integrated leak rate test; replacement of two reactor coolant pump mechanical seals; and mechanical, electrical, and I&C systems maintenance. The next Unit 2 refueling outage was originally scheduled to begin October 5,1993, but .
the licensee has changed it to February 15. 1994 with power redcuctions I in October and November, 1993, to stretch the operating cycle.
PART 2 -
PLANT PERSPECTIVE 2.1 GENERAL PLANT PERSPECTIVE St. Lucie continues to be an above average plant with few problems. A SALP presentation was conducted on June 30. 1992, covering the SALP period of October 31. 1990, through May 2. 1992. The facility was rated a category 1 in all functional areas. 4 2.2 SALP HISTORY (Past 2 SALP Periods)
J The last SALP period, SALP Cycle 9. ended on May 2,1992. The current SALP period ends on January 1. 1994.
ASSMT. OPS RAD MAT /SUV EP SEC ENG/ TECH SAQV PERIOD 11/1/87 1 21 1 1 2 1 1 l 4/30/89 ,
5/1/89 - 1 1 2 1 1 1 1 10/31/90 j 11/1/90 - 1 1 1 1 1 1 1 5/2/92 4 Note: (I) - Improving Trend 2.3 SELECTED SALP AREA DISCUSSIONS Since the assessment of the SALP period ending in May 1992, there have been no events that should significantly change the overall assessment of this facility.
Plant Ooerations Operator performance has historically been excellent and has continued to be SALP category 1: transients and off-normal situations have been handled well by the operators. Operator
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12 l performance was professional and quick in response to several Unit 2 post-outage transients last-year (1992) and more recently to a dropped CEA.
Operator error contributed to the forced shutdown of Unit 2 on ;
November 24. 1992. A leaking pressurizer safety valve required 1 operators to routinely cool the quench tank (by filling / draining). l One operator inadvertently overfilled the quench tank, which caused a safety valve to lift and the quench tank rupture disc to rupture.
Valve position checks (referenco June, 1991 SLIII) - were a symptom of insufficient management attention in this specific i
- area, as differentiated from the excellent management attention to l other areas. Since then, there have been no deficiencies noted in l valve positions. '
, The February. 1993, preparations for Unit 2 reduced inventory were excellent. Several Unit I reduced inventory conditions occurred during the Sproing.1993. refueling outage. Preparations were again thouough.
) Radiolooical Controls Two SALP periods ago, radiological controls went from a category 2 l to a category 1 and remained there during the last SALP period.
At the end of the recent SALP period, radiological control initiatives were judged to be impressive by health physics inspectors. There has been no reduction in the licensee's effort noted this current SALP period.
Maintenance / Surveillance Maintenance / surveillance went from a SALP category 1 to a category ,
2 two SALP periods ago: this broad category had been brought down by some inattention to detail in the mechanical area. This area improved significantly during the last assessment period to a SALP category 1. Performance during this SALP period has not degraded.
Housekeeping is above average. Implementation of a Plant Manager's List and a material condition group reporting to the plant general manager is improving general plant general condition and appearance. A team inspects the plant each week and generates a corrective action list that is reviewed each week. This program has resulted in significant rewards and has generally reversed degrading conditions. .
Overall plant physical condition has been rated as good to excellent by several team ins)ections (e.g.. MTI OSTI. EDSFI, and
. Service Water), and recently )y NRC managers. The housekeeping
- and general plant condition have been addressed with positive statements in recent SALP reports.
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13 Since the units are located adjacent to the Atlantic Ocean, in a salt-laden atmosphere the licensee has had to aggressively pursue j exterior equipment maintenance. Painting of exterior equipment '
and of equipment that can be reached by chlorides via the ventilation systems is a continuous aspect of the preventive maintenance scheme. 4 The chloride affect on equipment has prompted thought and action l in the following areas: !
electrical conduit in ground or exposed to the environment.
electrical box seals and ventilation.
reinforcement bar in concrete structures and supports. )
replacement of carbon steel components with more corrosion l resistant materials, and ~
lagging that traps moisture and salts on carbon steel !
piping.
Maintenance departments added component engineers to the shops in I 1990. This has enabled shops to significantly improve maintenance l and surveillance procedures and focus on component weaknesses. ;
There has been a low turnover rate in all disciplines. !
During this SALP period, two violations were identified relating l to interface control with contractors. The licensee is still working on corrective actions. i Equipment failures since the June. 1992, restart of Unit 2 have caused an unusually high number of power reductions / shutdowns j early in the fuel cycle.
Emeroency Precaredness The licensee continues to maintain an effective EP program.
Security Security upgrades made prior to the last SALP were notable. The licensee continues to maintain a very effective security program. j Enaineerina/ Technical Suonort Major modifications have been few during the last several years.
These included the redesign and repair of the cooling water ocean ;
intake structure. SB0 electrical wiring modifications, and changing ICW pump bearing water lubrication from external to self- !
lubricating. Also, the four pressurizer steam space instrument l l
14 nozzles were replaced with upgraded material (on 3/25/93). The licensee installed the redesigned Unit 1 EDG radiator fan drivers in Spring 1993. Unit 1 steam generator replacement is being planned for 1997.
All training programs have received INPO accreditation and the site specific simulator has been fully operational for approxi-mately 3 years: three separate NRC inspections in the form of operator examinations at the simulator have found no serious problems.
The last SALP discussed )lant modifications without design approval. The licensee las taken positive measures to correct this practice.
The licensee is addressing the recent number of equipment failures by increased equipment inspections and by improving equipment reliability. For example: in response to recurring vibration I problems. the licensee has redesigned the Unit 1 EDG fan drive system and tested a prototy)e offsite. The modification was successfully installed in t1e Spring.1993, outage. For safety-related motors. licensee engineering and quality assurance are overseeing a periodic rewinding and certification program at a non-certified vendor.
Safety Assessment /Ouality Verification Management continues to make conservative decisions regarding plant operations. Holding a startup to fully repair a Shield Building door is a good example.
The Sensitive System Program has identified numerous items and procedures that can cause plant trips or perturbations. often in a non-obvious manner. This program now requires special study.
preparation, and management involvement prior to maintenance on those items.
The program for conduct of infrequently performed tests or evolutions at St. Lucie Plant has dramatically improved the performance of these activities by requiring special planning and management involvement prior to the test or evolution.
PART 3 -
SIGNIFICANT EVENTS 3.1 SIGNIFICANT EVENTS BRIEFINGS (Past 12 Months)
Unit 1: None this period Unit 2: None this period
15 3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months)
Currently, there are no escalated enforcement actions pending at St.
Lucie.
PART 4 -
STAFFING AND TRAINING 4.1 OPERATIONS STAFF - OVERALL (9/93)
Above average performance of the operations staff has been noted.
Control room demeanor of. personnel is above average.
Number of Shifts: (RCO. SRO. SNP0) Six shift rotation.
8-hour shifts. (NPO. ANPO) Five shift rotation 8-hour shifts. [some in training]
Total Licensed Operators: 67 (55 active /12 inactive)
Total number of SR0s: 45 (4 with engineering degrees and 1 with other degree)
Number of Active SR0s: 29 (4 with engineering degrees and 1 with another degree)
Total number of R0s: 22 RCO (no degrees)/(1 inactive) 5 SRC0 (stand RO watch. 0 with engineering degrees) 4.2 WORK FORCE (9/93)
FPL Contractor .
l Plant personnel (excluding 682 282 disciplines below)
Training 61 6 i Quality Assurance 47 0 J
Materials Management 55 0 Security 10 144 Site Engineering 42 0
- Approximately 20 positions throughout the organization are open and being filled.
4.3 OPERATOR OUAllFICATION/REOUALIFICATION PROGRAM (Past Two Years) 4.3.1 REQUALIFICATION PROGRAM NRC-administered requalification exams were completed in October.
1992. Results were good - 9 of 12 R0s passed and 12 of 12 SR0s passed. Three of the R0s failed the written exam and one also
16 failed the JPMs. The program was rated satisfactory.
4.3.2 INITIAL EXAMS Previous initial operator exams were conducted on April 29. 1991.
Six SRO upgrades were examined, and all six passed. Additional exams were completed October 25. 1991. Six operators 2 SRO upgrades, and 1 instant SRO were examined. All passed. The last initial exam was given April 27 through May 1.1992, to 6 SRO upgrades and 2 R0s. and all passed. A hot license class of 15 persons was started in late February, 1992 (14 still in class).
The next initial exam is scheduled for October 1993 for 10 of these trainees.
4.3.3 GENERIC FUNDAMENTAL EXAM On an NRC administered Generic Fundamental Exam on June 6. 1990. 6 of the 10 St. Lucie operators who took the exam passed. On February 6. 1991. 3 of 3 operators who took the exam passed. On June 6. 1991 one operator took the exam and passed. On February
- 10. 1993, all 12 operators who took the exam passed.
4.4 PLANT SIMULATOR The simulator is on site and fully certified to meet ANSI /ANS 3.5, 1985.
4.5 INP0 ACCREDITATION All programs are accredited. An INPD accreditation team inspection (15 l people) occurred during the week of 2/25/91. The results were that all I programs remained accredited. Another team was on site the week of April 19, 1993. St lucie will be considered by the accrediting board on ,
November 18, 1993. Continued accreditation is anticipated. l l
i PART 5 -
INSPECTION ACTIVITIES l 5.1 INSPECTION FOLLOWUP OPEN ITEMS
SUMMARY
(UNITS 1 AND 2 COMBINED) 9/20/93 Pre Change from Division 1 Total Last ReDort DRP 3 28 -2 DRS 1 3 0 ,
1 DRSS J J 0 I Totals 4 36 -2
Il 5.2 MAJOR INSPECTIONS IR-No. Date TY22 86-08/86-07 3-4/86 EO 88-08 04/88 E0P 88-15 06/88 OA Eff.
12/88 RER 89-02 1/89 RG-1.97 89-03 3/89 NDE 89-07 3/89 EQ 89-09 3/89 Design Control 89-24 10/89 Maintenance Team Inspection 89-27 11/89 E0P Followup 90-09 4-5/90 OSTI I 91-03 2-3/91 EDSFI 91-18 9/91 MOV (no negative findings)91-201 9-10/91 Service Water Inspection 92-14 7/92 Emergency Preparedness Program 92-17 7/92 EDSFI Followup 93-01 1/93 Check Valves 5.3 PLANNED TEAM INSPECTIONS MOV team inspection - not currently scheduled.
5.4 INFREQUENT INSPECTION PROCEDURE STATUS No core modules are overdue at this time.
5.5 SIMS STATUS - OPEN TMI ITEMS There are no open TMI items.
ATTACHMENT 2 ST LUCIE OPEN ALLEGATIONS AS OF 10/07/93 ALLEGATION: RII-93-A-0147 FACILITY: ST LUCIE 1 DATE RCVD: 930727
SUBJECT:
SAFETY OF PLANT AFTER SECURITY PERSONNEL LAYOFF DUE DATE: 931027 DAYS OPEN: 58 ACTION PNDG: AP:DRSS/NMSS SCP[UE OUT '.
REDUCTION IF FORCE ISSUE TO SEE WHAT LAYOFF PLAN IS AND DETERMINE IF ANY FOLLOWUP INSP WARRANTED ACTION DIV/LCA: [DRSS/NMSS]
DIV./ARP DATE: DRP/PB2 ARP 7/29/93 ;
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I
e ATTACHMENT 3 NRR OPERATING REACTOR ASSESSMENT NRR ASSESSMENT FOR ST. LUCIE OCRTOBER 5, 1993
- 1. CURRENT OPERATING STATUS During September 1993, the operation of both units was affected by an unusual infostation of jellyfish which were plugging up the intake screens. Unit 2 had to reduce power and Unit 1 had to shut down for several days.
- 2. CURRENT ISSUES
-Seismic qualification of electrical and mechanical equipment (GL 87-02.
USI A-46) issue on Unit 1 is still not resolved.
-Unit I will be replacing steam generators in 1997. The licensee is well into planning for the event.
-In August, 1993, the plant hosted a visit of a Russian delegation headed by Victor Chernomyrdin, Prime Minister of the Russian Federation.
Russian visitors were accom)anied by Ivan Selin, NRC Chairman. William White. Deputy Secretary of Energy and Stewart Ebneter, Region II Administrator.
-The plant continues to perform well. The latest SALP evaluation gave had ratings of 1 in all categories. St. Lucie received a " good performer" letter from NRC for the second year in a row.
Effective October 1993, the licensee announced several major personnel cher.ges at St. Lucie. The major changes include:
C. Burton is now the Plant General Manager J. Scarola is now the Operations Manager J. Hosmer is now the Site Engineering Manager l
Contact:
I Jan A. Norris 504-1483 l
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4
' #yks"
- a ARB MEETING August 29, 1996 id T Pp g WARNING THIS DOCUMENT CONTAINS ,(/fc^
SENSITIVE ALLEGATION INFORMATION '
IT CAN NOT BE DISSEMINATED OUTSIDE THE NRC RII 96 A 0180 8/22/96 ST. LUCIE 50-335, 389 A REVISION TO THE EMERGENCY PLAN WAS PROCESSED AND PLEMENTED WHICH IN THE ALLEGER'S OPINION DECREASES THE PLAN'S EFFECTIVEN S. 10 CFR 50.54q REQUIRES PRIOR NRC APPROVAL IN SUCH CASE BUT THIS HAS NO BEEN OBTAINED.
THE DECREASE IN EFFECTIVENESS RESULTS FROM DE TING THE POSITION OF THE MANAGER. NUCLEAR EMERGENCY PREPAREDNESS AND SFERS ALL ASSOCIATED RESPONSIBILITIES TO THE SITE SERVICES MANAG ;
AP: F g([L Q f f- pb LEAD DIVISION / BRANCH:
LICENSEE REFERRAL: '
h N/
OI/AP: o /,/-['.
RECOMMENDED PRIORITY: d'k SAFETY SIGNIFICANCE:
DOL /AP:
GENERIC IMPLICATIONS:
COMPLETION DATE:
l ARB ATTENDERS ORA DRP DRS DNMS
[ ] EVANS' [ ]JAUD0N [ ]GIBSON [ ]MALLETT )'
[ ]DEMIRANDA [ ]LANDIS [ ]VERRELLI [ ] COLLINS
[ ]IGNATONIS [] [ ]BARR
[] [] OI
[ ]MCNULTY i
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1$K * .: . c Sep: ember 19,1906 232srv.
. . . .. REGION ll-STATUS OF ESCALATED ENFORCEMENT A4150ftSYith i ?
7 E. LICENSEE RESPONSES PENDING %ifg',.;.jp55 h m - -- -_:: - m LICENSEE FActJTY --
i (HQ ES) (BRANCH CHIEF)
$$r-DESCRIPTION STATUS
- -$.i]?' ($p9 AS[$ENM.1Y
.-1 ! W DATE)
EA NO.
EICS NO.
TIRELINES S
- =
3 FPL i
ST. LUCE MULTIPLE EXAMPLES OF INADEOUATE 50/59 REVIEWS. PANEL OCNDUCTED $ SL4 - EA '49* 3 (JEa/ATS) (LANDIS) ON 07/10/98 AND CONCLUDED A PEC WAS APPROPIRATE. OF THE FOUR EX, EXIT: 9&E 049 *D9' _
! THE PANEL CONCL EX A WAS A SL3, EX B, C, AND D WOULD BE NON. 07/12/98 P ESCALATED. CPEC TO BE CONDUCTED IN CONJUCTION WITH EA 94238.
CPEC SCHD FOR 08/19f96 AT 1:00 PM. CACUS DEETERMINED 3 ISSUES WERE ISSUED-09/19/96 i
[0 NOT VIOS REMANNO EDG ISSUE SL3. SUBMIT TO OE FOR FORMAL REVIEW. RESP DUE: C RECAUCUS ON 06/2248 FOR EDG VIO REVIEW - SL3 WCP. SENT TO STAFF 10f20/96 $
FOR COWJENT C8f29/98. R2 CONC AND SENT TO OE ON 08/30/98. OE
- RECOMMENDED DISCR BASED ON NRC INVOLVEMENT. PROV TO RW FOR CONC ON 09/10/96. ENISSUED 09/12/96 EAISSUED 09/19198. ACTION C
t PENDING: UC RESP PENDING U FPL. ST. LUCIE INADEOUATE CONFIGURATION MANAGEMENT-MULTIPLE EXAMPLES. PAMEL 5 SL4 EA 94236 *49' (MAS /ATB) (LANDIS) CCNDUCTED ON 07)C3/96 AND RECOMMENDED A St3 PROBLEM AND PEC- RA EXIT: 96-E 046 *D9*
ATTENCED PANEL EXIT WITH Ll0 ON 07/09/91 HOLD RPT AND ANY ACTON 07/12/96 TO SCHD PEC UNTiL PANEL ON 50.59 ISSUES IS CONDUCTED ON 07/10/98. ISSUED:
POSSIBLY COM8NE PECs. CPEC SCHD FOR 08/19796 AT 193 PM. CAUCUS 09/19/96 DETERMINED -2 SL4s AND AN NCV. RECAUCUS ON 08/22/96 FOR 50.59 RESP DUE:
ISSUES SENT TO STAFF FOR COMMENT ON 06/29/96. REO CONCURRENCE 10/20#86 AN SENT TO OE ON 08/3C/91 R2 CONC ON 09f10/96 - EN ISSUED ON 09/12/98.
EA ISSUED 09/19/96 ACTIDN PENDING: LIC RESP PENDING. 2' I
t T,
ei--
. C l e
s al ol tills DOCUMENT CONTAINS PREDECISIONAL INFORM ATION - IT CANNOT BE 5!
DISCLOSED OUTSIDE THE NRC WITHOUT TIIE APPROVAL OF THE REGIONAL ADMINISTRATOR cj C
- NOTES: 1 DIVISION 2-HQtOE 3-EICS 4-03 5-RESPONSE NEEDED 6-OmER
- Page 16 '
T 1 i kI m ,, m, ei o,
DALL, 9/26/96 - approx 11:15 am Male caller.
Wanted to s)eak with person he talked to a.few weeks ago regarding drums in RCA, same t1ing happening. nothing had changed.
Transferred call to Mark Miller.
Caller hung up after Mark identified himself.
Called back identified as .
Did not want to talk to Mark. Said the guy he had talked to was a regional guy. Said it was general knowledge that ins)ectors on site had been around a while, problems had been around a while, notling had changed. Stated "You know what I mean." ,
I responded that I did not know what he meant but if he could give me a description of person or time frame of when he talked to this person I may be able to i&ntify the person he originally talked to. He was unable to do this so I explained that Mark was the Senior Inspector and responsible for and had probably been advised of his previous conversation.
He said he did not want to go through the whole thing again but decided to go ahead and talk to Mark. '
Transferred caller to Mark.
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11/4/96 I
l ST. LUCIE ALLEGATION FOLLOW-UP
SUMMARY
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Case No. Ril-96-A-0180 l
Preliminary disposition of 15 alleaation items: l Substantiated: Items 1 *, 2, 3, 5, 6, 7, 8,10,' 12*
NOT Substantiated: Items 4,9,11,13,14,15
- Substantiated as an issue and categorized as a " Program Weakness", but no regulatory basis was identified for a violation.
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l ALLEGATION AC ::0N P_AN CASE N0: RII A-96-0180 FACILITY: St. Lucie Plant INSPECTION REPORT NO.: 50 335. 389/96-18 DOCKET NUMBERS: 50 335. 50 389 l
Tvoe of Insoection: Special/ Announced /Back Shift / Normal Shift l
Submitted by: J. L. Kreh Date: October 7 - 18. 1996 Accomoanying Personnel: D. M. Barss (NRR)
Alleoation to be Resolved: The alleaer asserts that 15 acoarent violations of Federal recuirements with respect to the licensee's emergency oreparedness Drogram exist or have existed durino the period 1994-1996. The alleoation includes details and sucoorting documentation.
(XXX) Inspector is familiar with ROI 1030. Revision 8 [X] Yes [ ] No (XXX) Locations / specific sites to be visited: St. Lucie Plant. Juno Beach Coro. Office (XXX) Time period to be covered: 1994-Present (XXX) Documents / activities to be reviewed: SEE ATTACHMENT (XXX) Persons to be contacted and/or interviewed: SEE ATTACHMENT (XXX) List of questions to be answered / approach to use: SEE ATTACHMENT (XXX) Limitations / areas to be avoided: No carticular limitations (alleaer has aareed in writina that he has no obiection to NRC's disclosure of his identity durina review of the subject allecation)
( ) Instructions by Branch Chief:
Approved by: l Branch Chief Date l
Attachment:
Details for Allegation Action Plan (Case No: RII-A-96-0180) j i
Distribution:
\\
Approving Branch Chief: K. P. Barr Division Director: A. F, Gibson Original to Division Allegation File y\ l Copy to EICS SAC: 0. DeMiranda y V
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ATTACHMENT DETAILS OF ALLEGATION ACTION PLAN Case No: RII-A-96-0180 The 15 alleged violations of Federal requirements involving the licensee's emergency preparedness program will be reviewed on their merits as potential violations, using applicable regulatory requirements [ including, but not limited to. 10 CFR 50.47(b). 10 CFR 50.54(q). 10 CFR 50.54(t). Appendix E to 10 CFR Part 53. the FSAR, and Tech. Specs.] and the various requirements specified in the licensee's Radiological Emergency Plan (REP). The following list presents details of the documents and activities to be reviewed, persons to be interviewed. and specific approaches to be used for each of the alleged concerns (the numbers correspond to those used in the alleger's detailed report):
- 1. Com]are staffing used in drills and NRC-evaluated exercises to actual bacc-shift staffing levels used in the Control Room. In particular, it appears that the licensee may be using an " extra" SR0 during evaluated exercises to allow the NPS/EC to delegate communications duties in a manner that does not happen on at least some of the back shifts.
- 2. Review in detail the licensee's augmentation process and records of drills and exercises involving off-hour augmentation, including (a) the notification process (both automated and manual). (b) availability of responders, and (c) estimated and measured travel times. i
- 3. Interview at least one (several if possible) NPS/EC to determine how the licensee would meet the commitment in Section 2.4.4 of the REP, which states (without elaboration) "In the event that the OSC becomes ;
untenable the Emergency Coordinator will. designate an alternate location." Review any guidance or training information provided to operations on this matter.
- 4. Inspect to ascertain whether the licensee has a supply of " additional beepers [that] can be quickly assigned if required in an emergency". as specified in REP Section 4.6. Inspector judgment will be required to determine what quantity of spare beepers would be adequate.
- 5. Review EPIP 3100034E " Maintaining Emergency Preparedness - Emergency Response Plan Training". Review (a) who should be trained according to the REP and the training procedure, and whether those individuals have.
in fact, received training for their ERO roles: (b) the adequacy of the training as currently provided to ERO personnel: and (c) opportunities for ERO personnel to participate in drills and exercises as part of their training.
- 6. Review training program and records to determine whether specialized initial training and periodic retraining is being provided to the categories of personnel specified in Section IV.F of Appendix E to 10 CFR Part 50.
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- 7. Review training records for TSC staff for calendar year 1994.
- 8. Review licensee's mechanism for addressing the requirement in REP Section 7.3.2 that "on-site Emergency Response Organization personnel are informed of relevant changes in tne Emergency Plan and EPIPs."
- 9. Review commitments and processes for providing critiques of all ERO training, including specialized initial training, periodic retraining, exercises, and drills.
- 10. Discuss with licensee management the evolution of, and rationale for.
the status of the Recovery Plan (actually a relatively detailed procedure current version dated 5/31/93) as a " stand-alone",
uncontrolled document rather than an EPIP. Review applicable REP commitments to determine whether licensee has failed to establish appropriate implementing procedure (s) in this respect.
- 11. Discuss with licensee management the evolution of, and rationale for, the status of the St. Lucie Plant Emergency Response Directory as a !
" stand-alone" document rather than an EPIP. Review applicable REP commitments to determine whether licensee has failed to establish appropriate implementing procedure (s) in this respect.
- 12. Review methodology for emergency preparedness problem identification and correction. Through documental review and discussion with licensee representatives, track a representative selection of identified problems i through the process to determine adequacy. l 1
- 13. Review REP and EPIP revision process and representative examples to I determine whether changes to these documents have been implemented prior to CNRB review and approval.
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- 14. Review adequacy of 0A program with respect to 10 CFR 50.54(t) and REP !
Section 7.3.4 requirements regarding annual audits of the EP program. l Interview auditors and review their qualifications to assess the EP !
area. Review audit plans and checklists. ;
- 15. With the assessment of item 13 completed, review the specifics of the I change process for Revision 30. Did the licensee conduct an adequate 50.59 review? Should the organizational change which eliminated the
! position of Manager. Nuclear Emergency Preparedness have been submitted l to the NRC for prior approval under the provisions of 10 CFR 50.54(q)?
, If the change crocess is considered adequate, do we agree that the l
review conclusions were acceptable and did not decrease the effectiveness of the REP? (This part of the allegation will probably be the most time-consuming and subjective. The alleger's discussion of this item is very detailed, consuming 28 of the 84 pages of his report.)