ML20137R960
| ML20137R960 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 10/31/1994 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20137Q937 | List: |
| References | |
| FOIA-96-485 NUDOCS 9704140312 | |
| Download: ML20137R960 (40) | |
Text
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1 REGION II .
P ATLANTA,. GEORGIA a
PLANT.-STATUS REPORT i
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C PLANT STATUS REPORT FOR ST. LUCIE (10/94)
TABLE 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 12 PART 2 PLANT PERSPECTIVE
- 2.1 GENERAL PLANT PERSPECTIVE............. .. .... .... .Page 13 2.2 SALP HISTORY. (Past Two SALP Periods) . . . . . . . . . . . . . . . .Page 13 2.3 SELECTED SALP AREA DISCUSSIONS ......................Page 13 r PART 3 SIGNIFICANT EVENTS 3.1- SIGNIFICANT EVENTS BRIEFINGS (Past 12 M6nths)........Page 20
. 3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months).... . ...Page 20 ;
l PART 4 STAFFING AND TRAINING
> 4.1 OPERATIONS STAFF - OVERALL. . .. ....................Page 20 ;
4.2 WORK FORCE ..........................................Page 20 :
4.3 OPERATOR QUALIFICATION /REQUALIFICATION PROGRAM.... ..Page 21 4.4 PLANT SIMULATOR.... ..................... . ........Page 21 4.5 INPO ACCREDITATION...... ........ . .... . . .. .. ..Page 21 j
- PART 5 - INSPECTION ACTIVITIES 5.1 OUTSTANDING ITEMS LIST
SUMMARY
................ ......Page 22 5.2 MAJOR INSPECTIONS................ ...... ... . .....Page 22 5.3 PLANNED TEAM INSPECTIONS........................ . ..Page 22 5.4 INFREQUENT INSPECTION PROCEDURE STATUS... ........ .Page 22 5.5 -SIMS STATUS (OPEN TMI ITEMS).... .. ..... ...... ...Page 22- ,
ATTACHMENTS
- 1. PERFORMANCE INDICATORS
- 2. ALLEGATION STATUS
- 3. NRR OPERATING REACTOR ASSESSMENT
- 4. ORGANIZATION CHARTS
- 5. POWER HISTORY CURVES
- 6. MASTER INSPECTION PLAN
p ,; j 2- l PART- 1- F A C I L I T Y.: 'D E S C R I P T I'0 N 1.1 FACILITY / LICENSEE FACILITY: St. Lucie Units 1 and 2 PLANT LOCATION: ~ Hutchinson Island near Port St. Lucie Florida LICENSEE: Florida Power and Light Co. (Corporate Office in Juno Beach, Florida)-
l'. 2 UTILITY SENIOR MANAGEMENT CORPORATE: .
J. L. Broadhead (Jim), Chairman of the Board and CEO J. H. Goldberg (Jerry), President. Nuclear Division ]
SITE:
D..A. Sager (Dave) - St. Lucie Plant Vice President C. L. Burton (Chris) - Plant General Manager L. W. Bladow (Wes).- Nuclear Assurance Manager H. F. Buchanan (Hank) - Health Physics Supervisor i R. L. Dawson (Bob) - Licensing Manager j D. J.-Denver-(Dan) - Site Engineering Manager l H. L. Fagley (Herman) - Construction Services Manager !
P. L. Fincher (Pat) - Training Manager R. J.-Frechette (Bob) - Chemistry Supervt v J. Marchese (Joe) - Maintenance Manager i W. L. Parks (Bill) - Reactor Engineering Supervisor 4 C. A. Pell (Ash) - Outage Manager l Scarola (Jim) - Operations Manager J.
J. A. West (Jeff) - Services Manager D. H. West (Dan) - Technical Manager C. H. Wood (Chuck) - Operations 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 B. A. Boger (Bruce), Acting Director DRP. (404) 331-5623 D. M. Verrelli (Dave). Branch Chief. (404) 331-5535 K. D. Landis (Kerry), Section Chief. (404) 331-5509 R. P. Schin (Bob). Project Engineer. (404) 331-5561 _i A. R. Long (Becky). Project Engineer (404) 331-4664 SITE:
R. L. Prevatte (Dick). Senior Resident Inspector. (407) 464-7822
-M. S. Miller-(Mark), Resident Inspector. (407) 464-7822 S
3 NRR:
S. A. Varga (Steven). Director. Division of Reactor Projects-I/II.
(301) 504-1403 J. A. Zwolinsky (John). Deputy Director. Division of Reactor Projects-I/II. (301) 504-1335 V. M. McCree (Victcr). Acting Director. Project Directorate II-2.
(301) 504-1485 [90 DAY DETAIL]
J. A. Norris (Jan). Senior Project Manager. Project Directorate 11-2. (301) 504-1483 AEOD:
S. Israel (Sandy). Reactor Operations Analysis Branch.
(301) 415-7573 1.4 LICENSE INFORMATION 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 l 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 i 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 RPV life
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span poss_ible. Presently, a program is evolving for RPV life -
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, performance of vessel fluence calculations, and determination of an optimum power profile for each core load.
Calculations using current methodology and uncertainty predict a significant RPV life extension, but not to 60 years. Excore dosimetry installed for the current cycle [with planned removal in- 4 October,:1994] will be used to reduce calculation uncertainty.
Due to different design and construction characteristics. Unit 2 RPV life expectancy exceeds 60 years. Low leakage core designs -
are now used for economic reasons, however the low leakage designs ,
provide even greater life expectancy. -
Reactor Coolant Pressure Boundary On this CE alant. 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- l channel system that operates on a two-out-of-four logic. l ATWS Protection ATMS protection, outside the normal reactor protection system. is initiated.via the ESF pressurizer pressure signal. It actuates by opening contactors in the output of the CEA MG sets. thereby 1 interrupting control element assemblyJower at its source. This 1
., protection has been installed on both units per CE, the NSSS.
recommendations.
. Remote Shutdown Facilities These facilities are located in the switchgear rooms beneath each
. unit's control room. ,
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5 1.6.3 CORE COOLING ,
Feedwater System The main feedwater pumps are motor driven with each delivering 50
- percent of the flow required for full power.-
Turbine Bynass/ Steam Dumo Caoacity
- 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 nine percent steam flow to the atmosphere. ;
5 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 1- either steam generator. Automatic initiation and faulted steam generator protection'are provided by each unit's Auxiliary Feedwater Actuation System provided by the NSSS.
Emeroency 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.
Decay Heat Removal 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.
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6 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 the recombiner, the recombiner units recombine hydrogen and oxygen
~to form water, thus preventing the buildup of hydrogen to !
potentially explosive levels.
'1.6.5 ELECTRICAL: POWER 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 power feeds from t1e station switchyard to the emergency busses.
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 (580) 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 Two trains of vital batteries per unit have been routinely tested for four-hour DC load profiles. Recently, due to cell replacement, they have been tested for three-hour battery capacity instead. The battery capacity test is harsher than the load profile test. There 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 3 train. that provide four trains of instrumentation power.
Stal. ion Blackout Resolution Status l
- 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). J 1
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7 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 Canal. The canal level varies with the tides since it-is filled by a level difference between the Atlantic Ocean and the canal. One 16-foot and two 12-foot diameter aipes pass under the beach to connect the ocean and canal. T1e intake pipe ends in the Atlantic are covered by intake structures (rebuilt in 1991) intended to limit flow velocities, particularly vertical velocity. to reduce marine life entrapment.
After use. 1CW 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 i using traveling screen debris protection. The intake canal structures adjacent to the ICW pump suctions are continuously injected with a hypochlorite solution td reduce marine growth in )
the associated piping and heat exchangers. Commencing 3/92. !
periodic injection of a clamicide at the intake structures, j primarily to control marine growth affecting the turbine j condensers. has also somewhat reduced marine growth affecting the ICW system.
The ICW pumps move water through two trains of heat exchangers l that cool component cooling water (CCW) and two trains of heat exchangers that cool main turbine cooling water. During a sostulated accident. water flow isolates from the turbine cooling leat exchangers. The discharge from the heat exchangers returns via the discharge canal to the ocean.
Increases in debris and silt in the heat exchangers during 1993 indicated that the intake canal needed dredging.
As of September 1993, the utility was routinely cleaning main condenser waterboxes at reduced power and obtaining necessary dredging permits from the state and Corps of Engineers.
- The canal was dredged in December 1993 and January 1994 with immediate results of reduced waterbox fouling.
Closed Coolina Water Systems Each unit has two trains of Component Cooling Water (CCW). The arrangement of two pumps and a swing pump mimics the ICW system.
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, 8 The swing pump can be aligned to either train. The 100 percent l (each) capacity Jumps drive water.through the CCW/ICW heat.
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 a variety of bearings, seals, and oil-coolers-for the HPSI. LPSI and CS pumps. -A non-safety-related portion of the CCW system cools reactor coolant pump seals and the spent fuel pool. This section isolates upon engineered safety features actuation.
1.6.7 SPENT FUEL STORAGE Wet' storage capability exists up to the year 2002 (Unit 2) and ;
2007 (Unit 1). 1
- 1.6.8 INSTRUMENT AIR SYSTEM Instrument air compressors and driers, installed several years ago !
on each unit. provide all instrument air for Unit 2 and all but containment air for Unit 1. These have increased instrument air reliability. Unit 1 also has instrument air compressors inside l containment. !
. 4 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. The SGs are under construction at i the B&W Canada shops and a site organization is functioning.
1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS Emergency Operations Facility: 10 miles West of site.
1-95/Hidway Rd. Exit Technical Support Center: Onsite. Adjacent to Unit 1 Control Room Operational Support Center: Onsite. 2nd floor of North Service-Building The last' annual emergency preparedness exercise was held February 9.
1994. Two followup items were identified: one involving the definition 4 of containment failure and one involving the need to demonstrate a protected area evacuation. An evacuation drill on September 30, 1994, satisfactorily demonstrated the accountability program. The next emergency preparedness exercise is scheduled for May. 1995.
Since-St. Lucie site has a high probability of hurricanes.
communications facilities were improved following the Turkey Point
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experience with Hurricane Andrew in August, 1992.' Improvements include:
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- High Frequency Auto-link with other FPL sites and NRC. ;
- Enhanced 900 MHZ System for site and mobile communications, with radios also in the licensee's EOF and county emergency facility.
Cellular phones with hardened antennas.
Hardened Local Government Radio antenna ties.
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1.8 PRESENT OPERATIONAL STATUS (10/5/94) ,
, Unit 1 is operating at 100% power and has been operating since a reactor ,
startup on June 8 following a reactor trip on June 7.
Unit 2 is operating at 100 % power and has been. operating since a i reactor startup on. July 15 following a July 14 shutdown to repair a ;
stuck-closed trip circuit breaker. ;
Availability Factors: l Unit 1 Unit 2 1991 81.0 100.0 1992 96.5 75.2 J 1993 74.0 71.8 1994 (through 8/94) 94.8 69.3 Cumulative (through 8/94) 77.3 82.4 l
1.8.1 UNIT 1 OPERATING HISTORY (Past Twelve Months)
Unit'l operated continuously during the past 12 months with the following exceptions:.
On November 1.1993. Unit 1 experienced a dropped rod event due, apparently, to a loose power supply card. The CEA was recovered without incident. ,
On January 1. 1994. SALP period 10 ended.
On January 9. 1994, the unit was manually tripped when the 18 Main Feedwater Pump spuriously tripped. Post trip response was normal and the unit was returned to power on January 10. On the first j attempt.at restart, the reactor failed to achieve criticality by i the time an all-rods-out condition was reached. The root cause i was the use of outdated core physics curves, which were updated.
The second attempt at startup was successful.
On March 28.1994. Unit 1 experienced an automatic reactor trip when a maintenance foreman opened the generator exciter breaker.
The worker'had been issued a clearance on the Unit 2 exciter breaker and_ mistakenly entered the wrong unit's exciter control cubicle.
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i 10 On April 2. -1994 the unit was returned to power: however, the- .
unit automatically tripped on April 3 from 19% power while-deenergizing a 4160 Volt non-vital bus to allow safe removal for maintenance of a failed startup transformer output breaker. The '
planned electrical lineup placed the A emergency bus on its EDG.
which was running at a different frequency from the grid. The paralleled CEA MG sets, now with different frequency drivers, developed circulating currents, resulting in several trip)ed circuit breakers. A partial reactor trip tripped the tur)ine. >
which tripped the reactor. Unit 1. returned to power on April 4.
1994.
On June 6. 1994. Unit 1 tripped during a severe thunderstorm.
The. main transformer locked out the generator, causing a reactor due to a phase differential on main generator transformer trip,This 1A. occurred as a result of an ap3roximately 8' length of flashing from an adjacent building whic1 was blown across two >
phases of the 1A main transformer output. The licensee conducted inspections and tests of the 1A and 1B main transformers and the main generator.-and performed repairs to the 1A main transformer. l The reactor was taken critical on June 8:.however, the licensee '
elected to remain off-line until repairs were completed to the 1A main transformer. Unit I was placed on line on June 11. ;
Unit I reduced power and entered mode 2 on August 28 to repair a ;
DEH leak. The unit was returned to power approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> ;
later on the same date.
1.8.2 UNIT 2 OPERATING HISTORY (Past Twelve Months) ;
Unit 2 operated continuously during the past 12 months with the l following exceptions: ,
On October 31. 1993, power was reduced to 45% to extend the fuel
. cycle to February 15, 1994. The downpower lasted until mid .
- December.
c On November 2. 1993. Unit 2 was manually tripped when operators noted increasing generator hydrogen temperature. The cause for ,
the noted condition was tied to a temperature control valve in the !
Turbine Cooling Water system which starved the generator hydrogen coolers of water. A contributor to this event was the operation of the system with only one pump while leaving both turbine lube !
< oil coolers in service. The procedure in place at the time of the ;
event did not recognize the potential for starving the hydrogen !'
coolers of TCW in such a lineup.
i- On November 3. 1993. Unit 2 was returned to power and operated at approximately 45% until December 13, when power was increased to j 100%. l, I
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11 On December 25, 1993, aower was reduced to 30%-in response to a condenser tube leak. Repairs were effected the same day and the unit was returned-to 100% power. ;
On February 13.1994. Unit 2 was shut down for the 1994 refueling outage. The outage lasted 65 days.
As a function.of the outage. Unit 2 entered reduced inventory conditions twice. The first occurrence began February 19 and supported reactor disassembly, reactor coolant pump seal package replacement, and the installation of steam generator nozzle. dams.
-The second occurrence commenced March 16 and sup3orted reactor vessel reassembly, reactor coolant pump seal paccage replacement, and steam generator nozzle dam removal. Coolant inventory was controlled well during these evolutions. ,
On March 16, 1994, the licensee identified boron deposits indicative of leakage from one of four pressurizer steam space '
instrument nozzles. Licensee investigations identified unacceptable linear indications in three of four nozzle pressure boundary welds. The steam space nozzles were constructed of Inconel 690 and were installed in 1993 as replacements for existing Inconel 600 nozzles, which had been found to be cracked.
The new nozzles were attached with Inconel 600-equivalent weld material, as 690-equivalent material was not approved for use at i the time. The licensee determined that the indications were the i result of Primary Water Stress Corrosion Cracking (PWSCC). l The licensee's corrective actions involved repairing all four nozzles by creating new pressure boundary welds at the exterior wall of the pressurizer. The new welds were of the Inconel 690- :
compatible material. During the repair efforts, region-based !
inspectors found that the overall repair effort was well controlled and that performance was good: however, one violation ;
was identified involving incorrect bevel angles on two weld preps. '
On March 18 Unit 2 experienced a six minute cessation of shutdown cooling when a misanalyzed clearance (tagout) resulted in :
automatic valve realignments that secured flow to one of two i operating shutdown cooling trains. A second shutdown cooling loop i was in operation at the time; however, operators stop)ed the !
operating pump as a precaution against damage after t1e unexpected valve realignments. Operators assessed the situation and restored i shutdown cooling in six minutes. :
Unit 2 completed the refueling outage and was returned to power on April 19, 1994. !
On April 23,1994. Unit 2 tripped due to a RPS cahir.et manufacturer's wiring error w1ich manifested itself during RPS troubleshooting. The wiring error existed since the original manufacture of-the cabinet.
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Following Unit 2 trip stabilization of April 23.'1994. the steam- .
bypass control system operated unexpectedly, resulting in a rapid
-7 degree cooldown and a resultant severe RCS shrink (pressurizer .
heaters deenergized on low pressurizer level). . Prompt operator action was taken'to secure the cooldown. Unit 2 was returned-to~ s power on April 26, 1994. ,
On July 9, 1994. Unit 2 turbine was shut down and reactor power reduced to Mode 2 because the 2B1 RCP lower oil level indication
-showed a leak. The sump was not leaking and an unusual failure in i the indication system was determined to be the reason for the.
indication. The reactor was returned to mode 1 and the turbine started up on July 10, 1994, {
On July 14.1994. Unit.2 was shut down to allow repair of a stuck . :
closed trip circuit breaker. Operators did not follow Unit 2 Tech !
Spec LC0 time requirements regarding shut down on July 14 to allow !
repair of a stuck-closed trip circuit breaker. The unit was restarted and placed on line on July 15. 1994, and has operated ,
continuously since that date.
1.9 OUTAGE SCHEDULE AND STATUS Unit l's last refueling outage began on March'29, 1993, and ended on May 28, 1993. Major outage activities included: refueling: steam generator ,
tube inspection and plugging: station blackout related electrical cross- l tie testing: Containment pressure sensing lines labelling and capping: '
Containment integrity violation corrective action (penetrations i J
identified, caps installed): safety-related breaker protective relays - !
rewired for " green slime": HFA latching relays verified operable; post- i accident containment water level monitoring system - magnetic reed i 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 l reduce vibration: and mechanical. electrical, and I&C systems j
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maintenance.
The next Unit 1 outage is scheduled to start October 30. 1994. It is currently being planned for 38 days. Major activities include:
refueling: reactor vessel nozzle and flange weld ISI inspection:
installation of a permanent cavity seal ring [at end of outage];
replacing reed switches for several CEAs: integrated safeguards test: '
steam generator tube inspection and plugging; steam generator sludge lancing; repair of refueling water storage tank: several instances of
. reduced inventory / mid-loop operations: replacement of ICW/CCW LOOP logic [HFA latching relays] with pull-to-lock switches: removal
[ collection] of Rx vessel neutron flux dosimetry: modification of EDG skids to' allow access underneath: inspection of ECCS sump area; and mechanical, electrical. and I&C systems maintenance.
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Unit 2's last refueling outage began on February 13, 1994, and ended April 17. 1994. Majoroutageactivitiesincluded: refueling; steam generator tube inspection and plugging: low pressure turbine blading !
replacement: emergency diesel generator inspection: replacement of two '
reactor coolant pump mechanical seals: and mechanical, electrical, and i I&C systems maintenance. The next Unit 2 refueling outage is scheduled
'for October, 1995. 1 PART 2 -
PLANT PERSPECTIVE l 2.1 GENERAL PLANT PERSPECTIVE A SALP presentation was conducted on February 15. 1994, covering the SALP period of May 3, 1992, through January 1, 1994. The facility was rated category 1 in all functional areas for the seccnd consecutive SALP ,
period.
In June 1994 St Lucie was dropped from the NRC management list of good performers after experiencing five unit reactor trips in the first half
, of 1994.
2.2 SALP HISTORY (Past 2 SALP Periods)
- The last SALP period. SALP Cycle 10 ended on' January 1, 1994. The current SALP period ends on July 1. 1995.
ASSMT. OPS RAD MNT/SURV EP SEC ENG/ TECH SA0V PERIOD 5/1/89 - 1 1 2 1 1 1 1 10/31/90 ,
i 11/1/90 - 1 1 1 1 1 1 1 )
5/2/92
! PLANT OPS MAINTENANCE ENGINEERINC PLANT SUPPORT 1 5/3/93 - 1 1 1 1 1/1/94 i
l 2:3 SELECTED SALP AREA DISCUSSIONS i i
Since the assessment of the SALP period ending in January,1994, there have been no events that should significantly change the overall '
l assessment of this facility. A new corrective action program, the St.
Lucie Action Report Star System, was implemented in July,1994. This 'l program will be used to identify, review analyze, resolve. track, and close out all plant discrepant conditions. It is intended to provide. '
increased em)hasis in this area.. The program is currently being run in i parallel wit 1 other existing programs until it is debugged. Full i i
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t 14 implementation-is planned by the end of 1994. To date. 215 items have been identified and 59 of these have been closed.
Plant Doerations' Operator performance has historically been excellent. Transients ,
and off-normal situations have been handled well by the operators.
Increased Reactor Trios Operators have responded well to 6 reactor trips since November, ,
1993. The dates and root causes are as follows: r 11/2/93 Unit 2 manual trip due to high generator cold gas' :
temperature. 0peration of TCW system with one pump :
and two TLO heat exchangers, erratic temperature control valve operation were root causes of condition. i 1/9/94 Unit 1 manual trip due to MFP trip. Cause of .
I electrical malfunction leading to MFP could not be-determined. Instrumentation deemed most probable !
causes for the trip were replaced. Autopsy of equipment inconclusive.
-3/28/94 Unit 1 automatic reactor trip when maintenance foreman l mistakenly opened generator exciter breaker on wrong i unit. Human error.
i 4/1/94 Unit I automatic trip due to inadequate electrical lineup which led to circulating currents betwr.:n CEA MGs. resulting in TCB trips. Jnadequate procedure review.
4/23/94 Unit 2 automatic trip cesed by preexisting RPS cabinet wiring error. Fabrication flaw dating from original manufacture.
6/6/94 Unit 1 automatic trip due to main generator lockout when severe thunderstorm blew debris across main transformer output. Weather-related.
e While the number of reactor trips is high. given the timeframe in which they occurred, only the 11/2/93 and 4/1/94 trips appear to be related in that both involved review of unusual operating lineups.
e The human error-related trip of 3/28/94 did not involve operators, o Two trips were related to equipment deficiencies: however, one involved a preexisting condition and one involved a '
l spurious..non-repeatable, failure.
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15 d The weather-related trip involved a piece of aluminum e
flashing, which was ripped from a building by high winds and blown across transformer terminals; it was not the result of
-a housekeeping problem.
e Operators performed well in responding to all trips, particularly the 4/23/94 trip, which was followed by a SBCS failure which resulted in an opening of 4 steam bypass .
control valves. Prompt operator action secured the ensuing cooldown.
e- The two procedure-related trips may be' indicative of a- .!
general lack of rigor in procedure review. The general topic of procedural adequacy is discussed below.
In conclusion, the recent increase in the number of reactor trips does not appear to be indicative of an overall declining level of performance; however, additional attention to the adequacy of
,. operations arocedures may be indicated. Operator performance
- following tie trips has been good, and, in two cases, operators '
properly inserted manual trips in response to blant conditions.
These actions indicated a good ability to quiccly assess plant conditions and to take manual action prior to automatic action.
~; Other Ooerational Observations A mispositioned valve was discovered on February 17, 1994 With !
Unit 2 in Mode 5 beginning a refueling outage, the licensee i discovered that the Unit 2 auxiliary spray would not work because ;
manual auxiliary s] ray isolation valve V2483 was mispositioned to l locked-closed and 1ad been in the incorrect position for about 13 !
, months. Operators had positioned and independently verified the i valve to be locked open in January. 1993. This was the first a mispositioned valve since the June 1991 SLIII for a mispositioned component cooling water valve. Management action in response to this event was swift and decisive. Disciplinary action was taken against the. operators involved and management expectations with regard to independent verification was reiterated. The insaectors have noted a positive effect of the management actions on tie general conduct of operations.
During the 1994 Unit 2 refueling outage the _ licensee entered reduced inventory conditions twice. In both cases. preparations and operator performance was excellent.
On August 29.'the resident inspector found that Unit I had the swing bus-1 AB aligned to DG 1A in order to >ermit work on j expansion joints in'the intake structure. Il 94-12 had found that i
.this alignment had not been tested to verify the load shedding and l sequencing feature. The licensee actions in the previous i violation had focused on amending surveillance procedures to test i these features during the next refueling outage and had not included measures to prevent placing the plant in this untested
=:- i
3 u 16 alignment. This item is unresolved awaiting the completion of' outage testing to determine the safety significance.
' Management routinely makes conservative decisions regarding plant
' operations to the extent that they recognize the conservative .
path. An example was.the decision to re) air the Unit 1-shutdown !
cooling suction isolation valve body-to-)onnet leak even though the leak rate was a fraction of that allowed by TS. Another example was the decision to remain off-line while repairs were completed on the 1A main transformer. The slowness to shut down 1 Unit 2 when TCB5 failed to trip was a noted exception from the -
historical performance. ,
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.
Procedural Adeauacy Recent inspections have noted a number of procedural deficiencies.
requiring Temporary Changes (TCslto be made before activities could proceed. While the majority'of the TCs involved items of marginal safety significance, in several of these procedures, the existence of the deficiencies in question were clearly the result of inadequate review. One recent review error. involving a transpositional error of fuel assembly coordinates in the refueling Recommended Move List. contributed to an attem)t to grapple two fuel assemblies simultaneously. As stated a)ove. ;
procedural inadequacy has been a contributor in two recent plant -
trips.
It has been noted that operators have correctly obtained TCs as required, as opposed to attempting work-arounds. This may be due.
in part, to recent management efforts to reinforce expectations l for procedure compliance and independent verification. However, the nature of the errors being identified suggests that attention l be paid to the licensee's procedure review process. l Manaaement Activities i Management has recently taken actions to refocus personnel i attention on day-to-day activities. Trips to other sites by plant l staff have been curtailed, as have visits by delegations from i other organizations-, All such activity is now subject to approval l by the site vice-3 resident. Additionally, the morning meeting format has been clanged to include a more detailed discussion of ,
plant operation and maintenance activities.
In. response to recent concerns over the adequacy of the licensee's i corrective action programs, site management has initiated a !
feasibility study on the topic of consolidating corrective actions I programs. The stated goal.is to reduce the number of individual programs in deference to a limited number of comprehensive l
j
l
~17 programs, thus' reducing the probability of inadequately ,
documenting or evaluating plant conditions. The adequacy of corrective actions has-been implicated in several recent issues. ,
including-e The adequacy of surveillance testing of the units' swing ICW and CCW pumps, in light of previous NRC findings on-the subject.
e . Damage to Unit 2 PORV tailpipe support's incurred d' og a:
water hammer event in 1993. The damage was identil . :d by NRC during an inspection during the 1994 Unit 2 outage. The
- licensee's inspections following the original event failed
< .to address these tailpipes. j
~The licensee's approach to the issue appears to be sound and
.potentially far-reaching.
Conclusions Although an increased number of challenges to plant operation have
- ~
occurred in the recent past, operator performance and the general conduct of operations has' remained strong. Management has been aggressive in addressing identifiable problems and their actions appear to be effective. Increased attention to the adequacy of normal operating and operational surveillance procedures appears to be warranted.
' Maintenance
. General Maintenance / surveillance went from a SALP category 1 to a category 2 three SALP_ periods ago: this broad category had been brought down by some inattention to detail in the mechanical area. This area then improved significantly and during the last two
~
assessment periods was again rated 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.has been effective in maintaining general plant 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 I Service Water), and recently )y NRC managers. The housekeeping _ :
and general plant coadition have been addressed with positive !
- statements in recent SALP reports.
l l'8' Since the units are located adjacent'to the Atlantic Ocean, in a salt-laden atmosphere, the licensee has had to aggressively pursue exterior equipment maintenance. Painting and in some cases metalizing of exterior equipment and of equipment that is exposed v to chlorides is a continuous aspect of. the preventive maintenance
< scheme.
Unit 2 Outaae Activities
. Unit 2 outage activities were generally handled well. Maintenance activities were well-coordinated and were supported by engineers 4
working out of the maintenance shops. Maintenance engineering involvement was instrumental in identifying and correcting a control wiring deficiency involving the Unit 2 swing ICW and CCW pum)s which prohibited the pumps from load shedding properly. The pro)lem had existed from unit construction.
Maintenance activities surrounding the repair of pressurizer level instrument steam space nozzles were found to be well controlled.
and performed. However, the NRC found two instances in which weld preps, accepted by the vendor's OC inspectors, possessed bevel angles' outside of the specified tolerances. Additional review found that the bevel angles were satisfactory for work but that plant engineering had specified an unnecessarily restrictive tolerance.
Enaineerina-Major modifications h;ve been few during the last several years. !
These included the redesign and repair of the cooling water ocean l intake structure. SB0 electrical wiring modifications, and <
changing ICW pump bearing water lubrication from external to self- l
- lubricating. Also, the four Unit 2 3ressurizer steam space 1 instrument nozzles were replaced wit 1 upgraded material (on !
3/25/93). The licensee installed the redesigned Unit 1 EDG radiator fan drivers in Spring 1993. Unit 1 steam generator i
, replacement is being planned for 1997.
The last SALP discussed )lant modifications without design a) proval. The licensee las taken positive measures to correct t11s practice, j Engineering support to the plant has been good. Staff engineers ;
< were available and on-site throughout the Unit 2 outage to support i PC/M work and were integral to the resolution of pressurizer steam !
cpace level instrumentation nozzle weld cracks. In fact, an ecqineer from site engineering was responsible for the identification of the boron deposits from the cracks. Engineering 4
.sup' ort was also noted in the leak repair of a Unit 1 shutdown coo.ing isolation valve body-to-bonnet leak. More recently.
- - timely engineering sumort was noted in response to the weather-
-related damage to the iA main transformer. s l l
. . . . - . ~. - . .
e .
i i
19 i 7
Recent reviews of the licensee's control of fuel quality indicated .l that Juno Nuclear Fuels and site Reactor Engineering personnel were heavily involved in reviews of vendor performance.
Additionally, Reactor Engineering and Nuclear Fuels engineers have :
supported control room operators during plant startups and j
shutdowns. j Recent inspection has indicated that potential problems exist in :
the area of vendor technical manual control. Additional 1
' inspection is planned in this area. l
- Plant Suocort Radioloaical Controls The radiological control program continues to be effective with R increased use of engineering controls and reduced respirator usage which were considered program strengths. External and internal exposures were well controlled. Worker adherence to RWPs anj radiological procedures was excellent. The licensee continues to reduce the contaminated area, and personnel contamination events are consistently below goals. Autiits were adequate; however, they ]
tend to be compliance based. Management continued to support l developmental training programs for health physics technicians.
The ALARA program was effective with several initiatives this period including use of robotics, new nozzle dams, and a reduction )
in microfiltration. The site HP organization maintains remotely )
controlled submersibles used both by St. Lucie and Turkey Point. l The licensee has recently placed an order for two robots to !
perform inspections inside the contairment biological shield at i power. ;
Radiological controls for the Unit 2 outage were noteworthy. The !
licensee made extensive use of closed-circuit cameras to remotely provide HP coverage while maintaining dose rates ALARA. Good HP i control of major evolutions, such as reactor vessel head lift. was also noted.
Emeraency Preoaredness The licensee continues to maintain an effective EP program.
1 Security ,
. Security upgrades made prior to the last SALP were notable. The !
licensee continues to maintain a very effective security program. I
<e Fire Protection
.The licensee continues to maintain an effective fire protection
.v - program.
l 1
( g ,'ie
20 Housekeenina Housekeeping has been generally very good.
PART 3 -
SIGNIFICANT EVENTS 3.1 SIGNIFICANT EVENTS BRIEFINGS (Past 12 Months)
Unit 1: None this period Unit 2: Failure of a GE AK-25 Trip Circuit Breaker 3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months)
Currently, there are no escalated enforcement actions pending at St. ;
Lucie.
The misalignment of bus 1AB to DG1A which could render the DG inoperable and the incorrect CR log entries in this issue are currently unresolved, awaiting refueling outage testing to determine safety significance.
This item may be the subject of an enforcement conference.
PART 4 -
STAFFING AND TRAINING 4.1 OPERATIONS STAFF - OVERALL (8/94)
Above average performance of the operations staff has been noted.
Control room demeanor of personnel is above average.
Number of Shifts: (RCO. SRO) Six shift rotation, 8-hour shifts: (NPO. ANP0 SNPO) Five shift rotation 8-hour shifts.
Number of SR0s: 22 active /21 inactive * / 43 total Number of R0s: 30 active /2 inactive / 32 total Total Licensed Operators: 52 active /23 inactive / 75 total
- 3 SR0s perform only R0 duties and maintain SR0 licenses active only for R0 duties. This practice is being reviewed by RII operator licensing.
4.2 WORK FORCE (8/94)
EL Contractor Plant personnel (excluding 713 122 disciplines below)
Training 63 0 Quality Assurance /ISEG/ SPEAK 0UT 49 0 e
21
- Materials Management
- 46' 0 Security: 11 -122 Site Engineering 42- 0 4.31 OPERATOR OUALIFICATION/REQUALIFICATION PROGRAM (Past Two Years) 4.3.1-REQUALIFICATION PROGRAM NRC-administered requalification exams were completed in October, 1992. Results were good - 9 of 12 RO's passed and 12 of 12 SR0's passed, Three of the RO's failed the written exam and one also failed the JPMs. The program was rated satisfactory.
Requalification exams are currently in progress (10/94). To date,.
20 of 24 SR0's and 17 of 20 RO's have passed all portions of the exams. Failures have included 5 written exams,1 JPM, and I simulator failure.
4.3.2 INITIAL EXAMS Previous initial operator exams were conducted on April 29, 1991.
Six.SR0 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 )assed. A hot license class of 15 persons was started in late rebruary, 1992 (14 still.in class).
The last initial exam was conducted in October 1993 - 10 of 10 prospective R0s passed. Initial exams are planned for October, 1994, with 3 R0s and 7 SR0 Upgrades planned 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. One person took the exam on February 9. 1994, and passed. No further Generic Fundamental Exams have been taken.
4.'4' PLANT SIMULATOR The simulator is on site'and fully. certified to meet ANSI /ANS 3.5, 1985.
4.5 INP0 ACCREDITATION
- All training programs are_ maintaining INP0 accreditation. The site specific simulator has been used for training since 1988 and has been
- fully certified for approximately 4 years. Eight separate NRC 5
U~ =
l 22-inspections in the' form of operator- examinations at the simulator have- i found no . serious problems. !
PART 5: IN.SPECTION A'CTIVITIES l 5.1 INSPECTION F0iiOWUP'0 PEN ITEMS
SUMMARY
(UNITS 1 AND 2 CGMBINED)
. (10/6/94) a Pre Change from
' Division & T1.Al 2 Last Reoort DRP 3- 30 0 l,
'DRS 0 7 -3 DRSS -J 2 J Totals 3 39 -3 Note: Each item that applies to both units is counted as one item.
5.2 ' MAJOR INSPECTIONS IR-No. Da.tg R T
89-02 1/89 RG-1.97 89-03 3/89 NDE 89-07 3/89 EQ 89-09 3/89 ' Design Control- i 89-24 10/89 Maintenance Team Inspection ;
89-27 11/89 E0P Followup 90-09 4-5/90 OSTI
. 91-03 2-3/91 EDSFI 91-18 9/91 MOV (no negative findings) 4 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
- . 94-11 5/94 MOV Followup 5.3 PLANNED TEAM INSPECTIONS None 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.
y ,9-,m' - w - yp ,"
- - . . - .. . . ~ _ . - - . - --
i
.: A l ATTACHMENT 3-NRR OPERATING REACTOR ASSESSMENT
].
NRR' ASSESSMENT FOR ST. LUCIE l October 1994 l
CURRENT ISSUES :
1
-Seismic ,
USI A-46)issue qualification on Unit 1ofiselectrical and mechanical still not resolved. The staffequipment (GLin87-02.-
issued a letter early ;
1994 providing a general framework of criteria which would resolve this issue. FPL -i responded in May 1994 restating their previous position and stating that they :
believe that further NRC requests for work, evaluations, or plant changes would j provide no additional safety benefit to their nuclear facilities. The staff is j considering performing a backfit analysis to determine the possibility of ordering. >
FPL to implement additional actions or accept the licensees position. A third alternative being evaluated is performance of a site inspection to determine if any safety-significant issues exist in the areas of disagreement.
-Unit I will be replacing steam generators in 1997.' The licensee is well into planning for the event. l
-An alternative. approach to.the resolution of the Thermo-Lag issue was proposed by l FPL. however, the staff did not pursue review of this performance based approach i based on Commission direction of this issue. The licensee is scheduled to submit to ,
the staff by early November 1994 a schedule and method for resolution of the Thermo- ;
Lag issue. .
i
-The plant continues to perform well. The latest SALP evaluation had ratings of 1 in all categories. ,
Contact:
Jan A. Norris 504-1483 1
l!
August 12 1994 1
. ST LUCIE Recent Sianificant Events / Findinas ;
Date Cause Identified Event / Finding 11/2/93 Operating Licensee Unit 1 manual. trip - abnormal turbine ,
f procedures cooling water lineup at reduced power :
1/1/94 - - SALP period ended 1/9/94' Equipment licensee Manual trip - feed. pump control circuit ;
failure failure 2/8/94 . - -
TPPR Conducted i 2/17/94' Operator Licensee Hispositioned valve discovered. Aux.
error 3ressurizer spray isolation valve had
)een locked closed (vice open) since .i 3/27/93. ,
2/28/94' Procedure & Licensee Inadecuate grappling of a fuel assembly operator / NRC causec by error in Recommended Move List J error and operator error in following i procedure (IR 94-09). Two related TS !
interpretation questions: Adequacy of a single. operator on refueling bridge >
during core alterations: and required level of review and approval of Recommended Move List.
3/7/94 Management NRC A nonconservative licensee entry into a :
decision TS LC0 action statement'for 1A EDG fuel oil tank level was identified by the NRC (IR 94-09).
3/16/94 Equipment Licensee A pressurizer instrument nozzle that had failure been repaired a year ago was found leaking. Failure a year ago was in Inconel 600 nozzle. The repair used an Inconel 690 nozzle and Inconel 182 shielded metal arc weld material. The repair was inspected by NRC, with 1 VIO for incorrect weld rod size. Current failure attributed to PWSCC of Inconel 182 shielded metal arc weld material. A new mod (re-using the Inconel 690 nozzles and an external'Inconel 690 weld) is being inspected by NRC (Crowley/Coley).
L: '.
O 3/16/94 Engineering NRC Regional inspector.had two violations:
error 1) corrective action for an 11/24/92 water hammer event-was done without '
documented instructions or procedures.
resulting in operating until 3/94 with .
five snubbers on the SRV and PORV ;
tailpipes inoperable. 2). Failure to write a nonconformance report for a damaged pipe support in March 1994.
3/28/94 Maintenance Licensee Unit 1 auto reactor trip. Maintenance error foreman opened generator exciter breaker
- on wrong unit. Operators had clearance on Unit 2.
3/29/94 Equipment Licensee Licensee discovered body-to-bonnet leak failure on non-isolable ten-inch shutdown cooling isolation valve. Leak rate about two drops /second (TS-allowable).
Licensee installed exterior clamp and )
leak repair compound on valve. !
4/2/94 Equipment Licensee Startup transformer output breaker l failure mechanically fails to open. Bkr j returned to mfgr for analysis.
4/3/94 Personnel Licensee Unit 1 auto reactor tr'ip from 19% power Error (Lack while deenergizing the 4160 Volt non-of. vital bus to allow safe removal of the sufficient failed SU Tx output breaker for depth in maintenance. The isolation placed the A i I
review of emergency bus on the EDG which was procedure running at a different frequency from l change) the grid. The paralleled CEA MG sets. l now with different frequency drivers. 1 developed circulating currents and several tripped circuit breakers. A partial reactor trip tri aped the turbine, which tripped tie reactor.
4/3/94 Personnel Licensee During testing for Unit 2 modifications error the licensee discovered that the 4160 V
[AB Bus) swing bus components [C ICW Pump and C CCW Pump] would not stri) from the bus upon undervoltage if tie bus were aligned to the B bus. A missing jumper wire in the switchgear (from initial construction) was the proximate cause. (SL4. Inadequate Corrective Action for 1992 NRC VIO for i inadequate surveillance test - IR 94-12) !
i i
s
t .
i 4/7/94 Personnel NRC Contractor personnel made and contractor ,
error OC accepted pressurizer nozzle weld prep that did not meet procedural requirements for bevel angle. Licensee- i engineering had specified overly tight ,
tolerances. (IR 94-10) 4/16/94 Equipment Licensee Cracked weld.in RCS pressure boundary - l' failure 3/4 inch instrument line attached to 2B1 12-inch safety injection header. i Licensee accomplished weld repair using ;
SI-to-loop check valve for isolation.
(IR 94-12) ,
4/21/94 Operator Licensee Unit 2 reactor power increased from 26 inattentive to 31% due to positive MTC and operator ness inattentiveness. (IR 94-12) 4/23/94 Mfg. error Licensee Unit 2 auto reactor trip from 30% power caused by RPS cabinet wiring error for trip bypass circuit, from original unit .
.i ,
construction. (IR 94-12) 4/23/94 Equipment Licensee Following unit 2 trip, steam bypass failure system operated unexpectedly and dropped RCS temp by seven degr.ees F, pressurizer i heaters turned off. Prompt operator )
, action was taken. Extensive mechanical '
repairs were required. Unit 2 was returned to power on April 26, 1994.
(IR 94-12) 6/6/94 Equipment licensee Unit 1 trip from 100% power during a
, failure severe thunderstorm when the main
- transformer locked out the generator, causing a reactor trip. The lockout occurred due to a phase differential on !
main generator transformer 1A. This l occurred as a result of an approximately 8' length of flashing, from an adjacent .
building, which was blown across two )
phases of the 1A main transformer l l output. The reactor was taken critical l on June 8: however, the licensee elected to remain off-line until repairs were !
completed to the 1A main transformer. i Unit I was placed on line on June 11.
1
[ ,
J_m 4: 1 e,,4mA_ s -4,eii..J.h e .a-,s.
f 7/9/94 Equipment Licensee Unit 2 turbine was shut down and reactor failure aower reduced to Mode 2 because the 2B1 RCP lower oil level indication showed a leak. The sump was not leaking and an unusual failure in the indication system was determined to be the reason for the indication. After repair, the reactor was returned to Mode 1 and the turbine started up on July 10. 1994. (IR 94-15) 7/14/94 Equipment Licensee During surveillance test, TCB 5 failed )
failure to open. It had stuck shut. A broken j piece of bakelite had fallen into the J trip mechanism.
7/14/94 Personnel NRC Operators did not follow Unit 2 Tech Error S)ec LC0 time re uirements regarding 'l slut down on Jul 14 to allow re) air of a stuck-closed trip circuit breacer.
The unit was restarted and placed on line on July 15, 1994. (IR 94-15) 8/12/94 Jersonnel NRC The licensee was unloading new fuel for Error Unit I with a hoist gra)ple that was !
missing the safety latc1 sleeve locating pin. -The safety sleeve functioned by friction only.
NRC CONCLUSION: The mispositioned valve and water hammer occurred over a year ago. None of the above personnel errors are similar. These events and findings may be precursors to declining performance. Further very close inspection and assessment is required.
~. .. . , . . -
y j-( ,
August 12, 1994 '!
ST LUCIE
$ -Recent Sianificant Events / Findinas !
3 DateL Cause Identified Event / Finding 11/2/93- Operating' Licensee Unit 1 manual trip abnormal . turbine
,. procedures- cooling water' lineup at reduced power .
?, 1/1/94 - - SALP period ended 7 1/9/94- Equipment licensee Manual trip - feed pump control circuit
- failure failure
' ~
2/8/94 - -
TPPR Conducted 2/17/94- Operator Licensee- Mispositioned valve dis' covered. Aux.
error aressurizer spray isolation valve had i Jeen locked closed (vice open) since 3/27/93.
- 2/28/94' Procedure & Licensee Inadecuate grappling of a fuel assembly l- operator /.NRC causec by error in Recommended Move List 4
error and operator error in following procedure (IR 94-09). Two related TS interpretation questions: Adequacy of a !
single operator on refueling bridge '
during core alterations; and required level of review and approval of Recommended Move List.
3/7/94- Management NRC A nonconservative licensee entry into a decision TS LCO action statement for IA EDG fuel oil tank level was identified by the NRC (IR 94-09).
3/16/94 Equipment Licensee A pressurizer instrument nozzle that had failure been repaired a year ago was found leaking. Failure a Inconel 600 nozzle. year The ago was repair in an used inconel 690 nozzle and Inconel 182 shielded metal arc weld material. The repair was inspected by NRC. with 1 VIO for incorrect weld rod size. Current failure attributed to PWSCC of Inconel
-182 shielded metal arc weld material. A new mod (re-using the Inconel 690 nozzles and an external Inconel 690 weld) is being inspected by NRC (Crowley/Coley).
3 ,
4 3/16/94 Engineering NRC Regional inspector had two violations:
error 1) corrective action for an 11/24/92 water hammer event was done without documented instructions or procedures, resulting in operating until 3/94 with five snubbers on the SRV and PORV tailpipes inoperable. 2) Failure to write a nonconformance report for a damaged pipe support in March 1994.
l 3/28/94 Maintenance Licensee Unit 1 auto reactor trip. Maintenance error foreman opened generator exciter breaker 1
- on wrong unit. Operators had clearance on Unit 2.
3/29/94 Equipment Licensee Licensee discovered body-to-bonnet leak failure on non-isolable ten-inch shutdown cooling isolation valve. Leak rate about two drops /second (TS-allowable).
Licensee installed exterior clamp and l leak repair compound on valve.
4/2/94 Equipment Licensee Startup transformer output breaker l failure mechanically fails to open. Bkr returned to mfgr for analysis. l 4/3/94 Personnel Licensee Unit 1 auto reactor trip from 19% power Error (Lack while deenergizing the 4160 Volt non-of vital bus to allow safe removal of the sufficient failed SU Tx output breaker for depth in maintenance. The isolation placed the A review of emergency bus on the EDG which was procedure running at a different frequency from change) the grid. The paralleled CEA MG sets, now with different frequency drivers, developed circulating currents and several tripped circuit breakers. A partial reactor trip tri) ped the turbine, which tripped tie reactor.
4/3/94 Personnel Licensee During testing for Unit 2 modifications error the licensee discovered that the 4160 V
[AB Bus] swing bus components [C ICW Pump and C CCW Pump] would not stri) from the bus upon undervoltage if t1e bus were aligned to the B bus. A missing jumper wire in the switchgear (from initial constrction) was the proximate cause. (SL4. Inadequate Corrective Action for 1992 NRC VIO for inadequate surveillance test - IR 94-12)
4 !
. i
.( ,
4/7/94. Personnel: NRC. Contractor personnel made and contractor !*
error OC accepted pressurizer nozzle weld prep that'did not meet procedural. i requirements for bevel angle. Licensee ,
engineering had specified overly tight' tolerances. (IR 94-10) l 4/16/94 Equipment Licensee. Cracked weld in RCS pressure boundary - ,
failure. 3/4 inch instrument line attached to 281 !
12-inch safety injection header.
Licensee' accomplished weld repair using 3 SI-to-loop check valve for isolation. 1 (IR 94-12) j 4/21/94 Operator Licensee Unit 2 reactor power increased from 26 inattentive to 31% due to positive MTC and operator ,
ness inattentiveness. (IR 94-12) ;
4/23/94 Mfg. error Licensee Unit 2 auto reactor trip from 30% power i caused by RPS cabinet wiring error for l trip bypass circuit. from original unit l' construction. (IR 94-12) 4/23/94 Equipment Licensee Following unit 2 trip, steam bypass failure system operated unexpectedly and dropped RCS temp by seven degrees F, pressurizer heaters turned off. Prompt operator action was taken. Extensive mechanical repairs were required. Unit 2 was returned to power on April 26, 1994.
(IR 94-12) 6/6/94 Equipment licensee Unit 1 trip from 100% power during a i failure severe thunderstorm when the main !
transformer locked out the generator. .
causing 'a reactor trip. The lockout !
occurred due to a phase differential on main generator transformer 1A. This 1 occurred as a result of an approximately 8' length of flashing. from an adjacent building. which was blown across two phases of the 1A main transformer output. The reactor was taken critical l on June 8;.however, the licensee elected to remain off-line until repairs were completed to the 1A main transformer.
Unit I was placed on line on June 11.
j
S ,
e i 7/9/94 Equipment Licensee Unit 2 turbine was shut down and reactor I failure )ower reduced to Mode 2 because the 281 ,
RCP lower oil level indication showed a !
leak. The sump was not leaking and an unusual failure in the indication system was determined to be the reason for the indication. After repair, the reactor '
was returned to Mode 1 and the turbine started up on July 10, 1994. (IR 94-15) 7/14/94 Equipment Licensee During surveillance test. TCB 5 failed failure to open. It had stuck shut. A broken piece of bakelite had fallen into the trip mechanism.
7/14/94 Personnel NRC Operators did not follow Unit 2 Tech Error Saec LCO time requirements regarding slut down on July 14 to allow re) air of a stuck-closed trip circuit breater.
The unit was restarted and placed on line on July 15, 1994. (IR 94-15) j 1
8/12/94 Jersonnel NRC The licensee was unloading new fuel for i Error Unit I with a hoist gra3ple that was !
missing the safety latc1 sleeve locating pin. The safety sleeve functioned by friction only.
I NRC CONCLUSION: The mispositioned valve and water hammer occurred over a year ago. None of the above personnel errors are similar. These events and findings may be precursors to declining performance. Further very close inspection and assessment is required.
- 4 # t#-
I FSC0001 INSPECTION FOLLOW-UP SYSTEM-POWER REACTOR REPORT NUMBER 1 02/21/95 SITE ITEM LIST PAGE 1 SORTED BY REPORT NUMBER SITE: ST LUCIE 050-00335 ST LUCIE I STATUS: OPEN SEVERITY:
050-00389 ST LUCIE 2 REPORT FROM: TO:
REPORT ON: ALL ITEMS OPN3 I/R P21/LER LATEST SEV/ REPORT CLOSEOUT CLSOUT AB!R (IFS NBR) SEQ TYPE LOG NBR REPORT SPL TRANSMTL STS PROJ/ACT* ORG TITLE STL1 91 011 1 VIO h S O f C. 3/1 05/17/1991 0 2232 FAILURE TO MAINTAIN THE OPERABILITY OF THE U STL2 91 011 O STL1 STL2 91-011 91-011 2 VIO h 7-O f[ [ 3/1 05/17/1991 0 O
2232 FAILURE "ID VERIFY VALVE POSITIONS IN PRESCRI STL1 STL2 92 018 92-018 2 IFI CILh t. Q[ 94-013 94-013 (6 09C/10/21/1992 0 O
2232 EVALUATE ADEQUACY OF ACCIDEIC PR3PARATIONS P STL1 STIJ 93-001 93-001 1 URI 93-001 93-001 02/23/1993 0 0
( '
PERABILITY DETERMINATION OF VALVES PER GL 9 STL1 93-012 1 VIO Ofi7 st 9 f '1 9 4C 4/1 06/21/1993 0 09/30/1993 2232 INADEQUATE LPSI PUMP MAItRENANCE PROCEDURE C STL2 93-025 1 IFI 12/01/1993 O EVIEW OPERABILITY OF UNIT 2 MOV MV-08-13 DU STL2 93-378* LER 93-007-00 prus 95' 05/21/1993 O @-C 7 L 2232 MANUAL REACTOR TRIP AFTER THE SIMULTANEOUS D I
STL1 93-379* LER 93-005-00 7 7 - o s/ (. 05/30/1993 0 2232 SHUTDOWN REQUIRED BY TS DUE TO AN UNLATCHED STL2 91-999* LER 93-008-00 M 576 d C11/02/1993 O 2:32 MANUAL REACTOR TRIP DUE TO HIGH GAS TEMPERAT STL1 STL2 94-004 94-004 1 IFI %-Cb 03/04/7994 0 -
O 2412 DEFINITION OF CONTAINMENT FAILURE STL2 94-008 1 VIO 9 I'" 4/1 04/08/1994 0 2312 FAILURE TO FOLLOW CORRECTIVE ACTION PROCEDUR STL2 94-008 2 VIO W 4/1 04/08/1994 0 2312 INADEQUAT TNSPECTION 8: EVALUATION OF WATERH STL1 94-008 3 URI q f- O O 04/08/1994 0 2312 QUALITY LEVEL OF PORV AND SRV DISCHARGE PIPI STL2 94-008 O STL1 94-010 1 VIO 4/1 04/28/1994 O 2312 FAILURE TO MEET WELD PREP DIMENSIONAL TOLERA STL1 94-011 1 VIO 4/1 06/02/1994 0 2313 INADEQUATE CORRECTIVE ACTION FOR MOVS WHICH STL1 94-011 2 IFI 06/02/1994 0 2313 INADEQUATE RECOGNITION OF MOV TEST PRESSURE 1 #
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INFORMATION ON THIS PAGE IS FOR O'F F I C I A L U S E_ ONLY ~.
02/21/95
- IF3COOO11 . INSPECTION FOLLOW-UP SYSTEM-POWER REACTOR REPORT NUMBER 1 SITE ITEM LIST ~ PAGE- 2.
SORTED BY REPORT NUMBER SITE:'ST LUCIE- 050-00335 ST LUCIE 1 STATUS: OPEN SEVERITY:
050-00389 ST LUCIE 2 REPORT FROM: TO:
REPORT ON: ALL ITEMS OPNG I/R P21/LER LATEST SEV/ REPORT CLOSEOUT- CLSOtJr . .
~ ABI.R - (IFS NBR) SEQ TYPE ~ LOG NBR REPORT SPL TRANSMTL STS PROJ/ACT* CRG TITLE.
......-- .............--.........................---...-.....--.-......---........-----..............................e......,........
~
STL1 94-011. 3 IFI 06/02/1994 O 13 JACK OF INSTRUCTIONS OR GUIDANCE FOR TRENDIN '
~
. (. { Og q i{ .d 4/1 05/20/1994 0 2232 INADEQUATE CORRECTIVE ACTION FOR PREVIOUS VI STL2 94-012-- -
O
,- STL1 94-013 2 ~ DEV- ' -
~~.dp 06/27/1994 0 2232 INADEQUATE EMERGENCY SUPPLIES'IN CONTROL ROO
'STL2" 794-013' O
-STL1 '94-019 2 URI 10/20/1994 0 hCCEPTABILITY.OFMAINTAININGANSROASANRO STL2 94-019 0
-STL1 94-019 3 IFI 10/20/1994 0 \ 2321 ONFLICTING PROCEDURAL GUIDANCE FOR ACTIVE 'L STL2 94-019 O STL1 94-021* LER 93-009-00 8 ~
11/17/1993 O N-O N 5t232 GINEERED SAFETY FEA*IURES ACTUATION DUE TO STL1 94-022 1 -VIO C1C M k N N. '
4/1 11/25/1994 0 2232 INADEQUATE CORRECTIVE ACTIONS TO NRC VIOLATI
- STL1 ' .94-022 2 VIO C[ cad W 4/1 11/25/1994 0 2232 IMPROPER MODIFICATION OF CONTROL' ROOM LOGS STL1 STL2 94-024 94-024 2 VIO kh -
4/1 12/14/1994 0 -
2232 INADEQUATE PROCESS FOR CHANGES.TO' VENDOR TEC i
STL1 94-063* LER 94-002-00 3 *hl YC- 01/13/1994 0 2232-INADVERTENT LOAD SHED OF THE 1A3 4160 VOLT B - ,
~STL2 94-077* LER 94 001-00 '[i) / C- 02/17/1994 0 2232 PRESSURIZER AUXILI ARY SPRAY OUT OF SERVICE C ~
STL2 94-110+ LER 94-002-0,0 900Y C 03/16/1994 0 2232 PRESSURIZER INSTRUMENT NOZZLE WELD CRACKING. ,
STL2 94-115* - 'LER 93-005-00 QfJN 01/12/1993 0 2232 HIGH' REACTOR COOLANT PUMP VIBRATION RESULTIN STL1 94-138* LER 94 003-00 (} {,0 ) C 04/23/1994 0 2232 AUTOMATIC REACTOR TRIP DURING FUNCTIONAL TES STL2 94-169* LER 94-003-00 ; -Is e e f (T-0 IC- 0 2232 AUTOMATIC REACTOR TRIP DURING FUNCTIONAL TES STL2 ~ 94-230* LER 94-004-00 ff[t?/ b 06/28/1994 0 2232 PLANT VENT WIDE RANGE GAS MONITOR CUT OF SER
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.INFORMATION ON THIS PAGE IS FOR O F F I'C I'A L USEl ONLY .
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INSPECTION FOLICW-UP SYSTEM-POWER RFACTOR REPORT NUMBER l' 02/21/95 - '
SITE ITEM LIST JPAGE 3. -
' SORTED BY' REPORT NUMBER x. -
SITE: zST LUCIE 050 00335 ST LUCIE 1 STATUS: OPEN. SEVERITYtL ~ ' '
050-00389 ST LUCIE 2 REPORT-FROM:. 'TO:
REPORT ON: ALL ITEMS OPNGI/R . P21/LER LATEST SEV/ REPORT . CLOSEOUT CLSOUT-~
ABBR' (IFS NBR). SEQ TYPE _ LOG NBR REPORT SPL STS .PROJ/ACT* --ORG ' TITLE
.............................. ......................'...'TRANSMIL .................._............_............. ..............................-
-ETL1 '94-300 .1'- IFI 11/17/1994 0 2324 PROCEDURAL GUIDANCE FOR REMOVAL OF RCPS PRIO'
.STt2 94-332* LER .. 94-006-01 9:4. t 4 C 07/14/1994 0 2232 TRIP, CIRCUIT BREAKER FAILURE DUE'TO A. BROKEN
~
. STL1- -_94 376* LER 94 008 00 Q("O9C 11/04/1994- -0 2232 INADVERTENT CONTAINMENT. ISOLATION SIGNAL 1
- c, STL1 95-004* 'LER 94-010 00- N3~ 11/24/1994 0 2232 INADVERTENT B TRAIN ENGINEERED SAFEGUARDS FE-
- STL1 '95-005*
LER '94-009-00 W@ 11/22/1994 0 2232 INADVERTENT SAFETY INJECTION ACTUATION SIGNA 4 . _
TUTAL OPEN ITEMS . 48 *IF ITEM IS OPEN. THE PROJECTED CLOSEOITT DATE .IS SHOWN TOTAL OPEN SEQUENCES ,37 .IF ITEM IS CLOSED. THE ACTUAL CLOSEOtTI DATE IS SHOWN; INFORMATION ON THIS PAGE IS FOR- 0FFICIAL USE ONLY .
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.___E_m._m_______.i___.__ _ ___._______________._______,.___i _ _ _ _ _ _ , _ _ , _ _ _ _ , _
y > jr IF500001 - INSPECTION FOLLOW-UP SYSTEM-POWER REACTOR REPORT NUMBER 1 01/09/95 SITE ITEM LIST PAGE 1 5ORTED BY REPORT NUM3ER SITE ST LUCIE 050-00335 ST LUCIE 1 STATUS. OPEN SEVERITY:
050-00389 ST LUCIE 2 REPORT FROM: TO:
REPORT ON ALL ITEMS OPfC I/R P2I/LER LATEST SEV/ REPORT CLOSE00T CL500T ABBR (IF5 NBR) SE0 TYPE LOG NBR REPORT SPL TPANSMTL STS PROLI/ACT* ORG TITLE
. [.f-( V C SIL 91-011 l' VIO [ta8 3/1 05/17/1991 0 c 2'FAILUPf
.,wc := mem ,
-4. t m , ,,.,,.a .% ] e y ,, O ~. MAINTAIN THE OPERABILITY,OF TH
/5' - t '/C STL1 91-4H - { 2 VIO 3/1 05/17/1991 0 2232' FAILURE TO VERIFY VALVE POSITIONS IN PRESCRI cj g _c</ ( 5?L2 si-611 , O f _
j _
0 STL1 93-001 1 URI 93 001 02/23/1993 0 2313 OPEPABILITY DETERMINATION OF VALVES PER GL 9 f STL2 93-001 -00 0 gM tl F 4TH n3;pj__? [ VIN g g /1 2 0 3 1 NADE00 ATE LPSI PUMP MAINTENANCE PROCEDURE C ~
STL2 93-025 1 IFI , y.T.N . 12/01 993ed g L M I- a 2313 REVIEW OPERABILITY OF UNIT 2 MOV MV-08-13 DU ft Ca-o.
STL2 93-378* LER 93-007-00) uk5/ 1993 0 (22^MANUALREACTORTRIPAFTERTHESIMULTANEOUSDN d SR - 5 07^* LG ^3 005 00h ) 05/30/1993 0'1910 2232 SHUTDOWN REQUIRED BY T5 DUE TO AN UNLATCHED
&#""2 0~S;I # "3 0% h 11/ 2/1 %
03/04/1994 0 W UAL REACM TRIP DUE TO HIGH CAS TEMPERAT M*
.du
- 5?L2 94-va 04-004 1 IFI 95' oNW oJL pf 'll oST 0
2412 DEFINITION OF CONTAINMENT FAILURE -
u
- STL2-9+-006-- 1-VIO-- '/)~-c h 4/1 04/08/1994 0 2312 FAILURE TO FOLLOW CORRECTIVE ACTION PROCEDUR STEz 94-vus YIb W ~' 4/1 04/08/1994 0 2312 INADEOUATE INSPECTION & EVALUATION OF WATERH STLT 94 009- - URI O 04/08/1994 0 23I2 OVALITY LEVEL OF PORY AND SRV DISCHARGE PIPI STL2 - 94-006 MA 0 STL1 94-010 1 VIO 4/1 04/28/1994 0 2312 FAILURE TO MEET WELD PREP DIMENSIONAL TOLERA STL1 94-011 1 VIO 4/1 06/02/1994 0 2313 INADE00 ATE CORRECTIVE ACTION FOR MOV5 WHICH STL1 94-011 2 IFI 06/02/1994 0 2313 INADEQUATE RECOGNITION OF MOV TEST PRESSURE 1
. c ".,
L5TLI: 94d11 ' .3 IFI 06/02/1994 0 2313 LACK OF INSTRUCTIONS OR GUIDANCE FOR TREW IN
_ 5ft1 94D 1 L VIO siV IM ' M e g 4/1 05/20/1994 0. - 2232 INADEQUATE CORRECTIVE ACTION FOR PREVIOUS VI
. hTL2 012),: i f' tM 0 M TLIL 94-013 '2 DEY 06/27/1994 0cdBA C. 2232 IMDECLaTE EMERGENCY SUPPLIES IN CONTROL R00-3R2- 94-013 - p 0 STL1 STL2 94-019 94-019 u 2 URI M* 10/20/1994 0 O
2321 ACCEPTABILITY OF MAINTAINING AN SRO AS AN RO-ST11 94-019 '3 IFI 10/20/1994 0 2321 CONFLICTING PROCEDURAL GUIDANCE FOR ACTIVE'L'
'5TL2 94-019 0 g- -r_-
STL1 94-021* LER 93-009 00 3 11/17/1993 0 2232 ENGINEERED SAFETY FEATURES ACTUATION.DUE.TD
'STLI. 2232 IEEOLWTE CCRRECTIVE ACTIONS TO NRC VIOLATI STL1 94-022 2 VIO 4/1 11/25/1994 0 2232 IMPRDPER MODIFICATI0H OF CONTROL ROOM LOGS:
4
- 3R1
-E2 --9024-i+ CM 2-Vie-4 J YS.c7C.N. 4/1 12/14/1994 0 0
2232 INADE00 ATE PROCESS FOR CHANGES TO VEW OR TEC-
- STL1 ~ $, ZP - LER- 00 ??? ^^ ,. N N 1/13/1994 0 2232 ISDVERTENT LOAD SHF.; 0F THE 1A3'4160 YOLT B STL F ' 94-077* LER. '94-001-00 ~ h a-,e 02/17/1994 0 2232 PRESSURIZER AUX 1LIARY SPRAY OUT OF SERVICE C-
.. Eb_? n' .110*_ LE9 "'-002-0 % 4_~M 7'd ) 03/16/1994 0 2232 PRESSURIZER INSTRUMENT N0ZILE WELD CRACKING I
(T1 S -.
^' n5* LEn n? "05 a0j.s"-oVV 01/12/1993 0 2232 HIGH REACTOR COOLANT PUMP VIBRATION RESULTIN STLI 94-138* LER 94-003-00 04/23/1994 0 2232 AUTOMATIC REACTOR TRIP DLRING FUNCTIONAL TES 8 94-169* LER Y 3-00 h k. % 0 2232 AUTOMATIC REACTOR TRIP DURING FUNCTIONAL TES STL2 94-230* LER 44-004-00 06/28/1994 0 2232 PLANT VENT WIDE RANGE GAS MONITOR DUT OF SER STL1 94-300 1 IFI 11/17/1994 0 2324 PROCEDLRAL GUIDANCE FOR REMOVAL OF.RCPS PRIO -l STLE ?! 23r tER - *4 GP9P--9ME 07/14/1994 0 2232 TRIP CIRCUIT BREAKER FAI'LLRE DUE TO A BROKEN (b744-4db IER % W2N 10/23/1994 0 2232 CONTAINMENT INTEGRITY OUTSIDE OF FSAR A55tMP STL1 94-376* LER 94-008-00 11/04/1994 0 2232 IMDVERTENT C0hTAIPMENT ISOLATION SIGNAL;
, 94-383*_ _ . _ LER 94-0%-01-N- 10/23/1994 0 2232 CONTAINMENT INTEGRITY OUTSIDE OF FSAR ASS W STL1 95-004* LER 94-010-00 11/24/1994 0 2232 INADVERTENT B TRAIN ENGINEERED SAFEGUARDS FE 2
.g; 44-F l__Js G X O A b -- 3 2 12.- T ~ d e p A . hg , CodM -
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wi Pp STL1 %-005* LER 94-009-00 11/22/1994 0 2232 INADVERTENT SAFETY INJECT 10R ACTUATION SIGM -
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TOTAL OPEN SE0VENCES 39 IF ITEM IS CLOSED. THE ACRIAL CLOSE0VT - DATE IS SHOWN-3 C_.__..______..-_..._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _
I e UNITED STATES 4 NUCLEAR REGULATORY COMMISSION -
[#pa8800
- ' k REGION 11 T o 101 MARIETTA STREET, N.W., SUtTE 2300 ,
j ATLANTA, GEORGIA 303234190
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September 19, 1994 MEMORANDUM TO: Gus C. Lainas, Assistant' Director for Region 11 Reactors Division of Reactor Projects I/II, NRR FROM: Bruce A. Boger, Acting Director Division of Reactor Projects, RII
SUBJECT:
i REQUEST FOR ASSISTANCE IN ADDRESSING ISSUES REGARDING ST LUCIE UNITS 1 AND 2 REFUELING PROCEDURES (TIA 94-023)
St. Lucie Inspection Report 94-09 contains two items which are unresolved ;
(Attachment 1) pending Technical Specification (TS) interpretations. The licensee had dissenting comments on these issues, as noted in the inspection report Exit Interview paragraph. The tuo items are:
- 1. URI 389/94-09-02, Adequacy of a single operator on the refueling bridge during core alterations - paragraph 4.a This URI involves interpretation of Unit 2 TS 6.2.2.d, which states:
"All CORE ALTERATIONS shall be observed by a licensed operator and supervised by either a licensed Senior Reactor Operator'or Senior Reactor Operator Limited to Fuel Handling who has no other concurrent responsibilities during this operation. The SRO in charge of fuel handling normally supervises from the 4 control room and has the flexibility to directly supervise at either the refueling deck or the spent fuel pool ."
During the St. Lucie Unit 2 fuel shuffle, on March 1,1994, the licensee had stationed one [ licensed) operator on the refueling bridge to perform refueling operations. This single licensed person, who was in constant communication with the refueling control desk in a control room annex, was performing actual refueling operations, which included operating the bridge and crane. The SRO in charge of the evolution was located remote from the refueling bridge, as is allowed by the TS and discussed in FPL and_NRC correspondence (Attachments 2 and 3).
The inspector questioned staffing adequacy because the operator had earlier _ attempted to grapple a fuel' bundle with the crane at incorrect coordinates due to a move list error. The single operator had not detected the error _ by cross check t,etween analog and digital positioning systems. The_ inspector questioned whether this one [though licensed]
person using the bridge and crane to perform core alterations met the TS requirement and the NRC's intent regarding a licensed operator observing core alterations.
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4 0
G. Lainas 2 The licensee's position was that " observed by a licensed operator" refers to the historical practice when nonlicensed persons, perhaps from a contract service company, actually performed the core alterations.
The licensee believes that ' performing' includes ' observing' when a licensed operator performs core alterations. The licensee stated that licensee and NRC correspondence-(Attachments 2 and 3), generated during the original Unit 2 licensing. process, supports their interpretation that a licensed operator performing core alterations constitutes the TS-required observer. The inspectors reviewed Attachments 2 and 3, and found that they appear to address tne location of the SR0 rather than the " observing - performing" question.
In addition to compliance with the TS, the inspectors had the following concerns with having only one person on the refueling bridge:
- There was no real-time independent verification of core alterations as they were performed. However, the core load was verified in detail by serial number, orientation, etc. when the core shuffle was complete.
- From the crane operating station on the bridge, the operator did not watch activity in the refueling canal. The operator could look down through plexiglass or move a few feet and look over the edge of the crane bridge with binoculars, but did not regularly do so. Also, there was a TV camera mounted near the bottom of the refueling mast, but it was not working. Thus the operator was, in a sense, driving 'on instruments only.'
Please provide an interpretation (with supporting considerations) of TS 6.2.2.d:
e Does " core alterations shall be observed by a licensed operator" refer to literally directly observing fuel move or does the phrase refer more to the process activities and supervision involved?
e Is the TS requirement based upon the assumption that contract or maintenance department personnel, requiring licensed operator oversight, perform fuel movement?
e Is the TS requirement based upon the need for real-time independent verification of core alterations or fuel movement?
e Does the TS require a second licensed operator, in addition to the (licensed] refueling machine operator, to observe fuel movement or other core alterations?
e If so, then does the TS require that supervision of core alterations be performed by.an SRO who is separate fr m the observer (i.e., a third person)?
E
1
.3 G. Lainas 3
- 2. URI 389/94-09-03, Adequacy of review and approval of refueling core :
alterations (licensee's Recommended Move List) - paragraph 4.a This URI involves interpretation of Unit 2 TS 6.8.1, 6.8.2, and 6.8.3 with regard to the licensee's " Recommended Move List."
l
- TS 6.8.1.a requires procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A. RG 1.33 recommends procedures for
" Preparation for Refueling and Refueling Equipment Operation" and ,
j for " Refueling and Core Alterations."
- TS 6.8.1.b requires procedures for " Refueling Operations."
l i
- TS 6.8.2 requires that each of those procedures, and changes thereto, shall be reviewed by the FRG and approved by the Plant General Manager prior to implementation.
- 'TS 6.8.3 allows temporary changes to those procedures provided:
- The intent of the procedure is not altered.
- Tha change is approved by two members of the plant l management staff, at least one of whom holds a Senior l Reactor Operator's license on the unit affected. l
- The change is documerted, reviewed by the FRG, and approved 1 by the Plant General Manager within 14 days of implementation.
The licensee's Recommended Move List (Attachment 4) was the document that detailed the fuel assembly and CEA mee sequence. It was developed during the core _ load development process and it identifieo, in order, each fuel assembly and CEA to be moved, the location from whi:h it was i to be moved, and the location to which it was to be moved. It not only addressed moves within the reactor vessel, but also moves between the fuel pool and reactor vessel, and moves within the fuel pool. It was invoked by Test Procedure 3200090, Rsfueling Operations, which also described steps necessary to deviate from [ change] the list (see Attachment 5). However, the Recommended Move List itself was not part of the test procedure and was not reviewed by the FRG or approved by the Plant General Mar.49er. Instead, it was approved by the Reactor Engineering Supervisor. Deviations from the Recommended Move List were approved by the reactor engineer on shift and the refueling coordinator (SRO).
During past refueling outages, many fuel or CEA movement sequence changes [as many as 90] have occurred due to equipment problems. ,
Historically,'.the Recommended Move List had been part of a procedure but change management was a huge burden and resulted in lergthy delays, tired operators, and wasted radiation exposure. The licensee de-proceduralized it to cope with these problems.
. i G. Lainas 4 The licensee now considers the Recommended Move List to be a non-procedure and therefore not subject to the TS 6.8.2 requirements for l review and approval of procedures and also not subject to the TS 6.8.2 ;
and TS 6.8,3 requirements for processing changes to procedures. The !
licensee stated that, since.the Recommended Move List's preparation, use, and modification were directed by a FRG-reviewed procedure, a FRG review should not be required for the list itself. Subsequently, the licensee stated that a telephone. review with other Combustion Engineering plants found that the licensee's position was common in the industry. l 1
'The inspectors.had the following concerns with the licensee's practice i of handling the Recommended Move List as a non-procedure: -l
- The Recommended Move List was an important document. It was used by reactor engineers and operators for performing safety-related activities. Errors in it could potentially lead to unsafe conditions of fuel arrangement. However, the licensee was l requiring less review and approval for the Recommended Move List l than for a safety-related procedure. l 1
The retention of a record of the Recommended Move List could be of significant value in determining the cause of an accident or malfunction, as described in ANSI 45.2.9 - 1979, Section 2.2.1.
' However, the licensee often issued a.new Recommended Move List and discarded the old one with no formal review and no record retention.
Please determine if the Recommended Move List is considered to be a procedure, subject to the requirements of TS 6.8.1, 6.8.2, and 6.8.3.
St. Lucie Unit 1 is scheduled to begin a refueling outage on October 31, 1994.
Please let me know if.you will not be able to respond to this request by that tine. If you have any questions concerning this request, please contact K. Landis (404/331-5509) or R. Schin (404/331-5561).
Docket No. 335 DPR-57 389 DPR NPF-15 Attachments: 1. Applicable portions of IR 50-335,389/94-09
- 2. Ltr. from FPL to NRC dtd. Sept. 22, 1981, regarding SRO Refueling Supervisor Attachments cont'd: (See page 5)
l,. ,: i e
i G. Lainas! -5 ;
- - Attachments cont'd
- 3. Ltr. from NRC.to FPL -
dtd.' Sept.'30, 1981,:
. ;regarding: Refueling SRO.
- 4. Recommended Move List
- 5. _ Applicable' portions of .
. Test Procedure 3200090,.
Refueling' Operations
.cc'w/ attachments:'
- J. Norris, NRR-T. Johnson,-Turkey Point SRI ,
S.. Elrod, St. Lucie SRI K.1Landis, RII ;
R Cooper, RII~
~
E. Greenman,.RIII B. Beach, RIV-
~ K. Perkins, WCFO S. Vias, TSS, RII- l t
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-Docket:Nos. 50-335, 50-389 License Nos. OPR-67. NPF-16 Florida Power & Light Company ATTN: J. H..Goldberg President - Nuclear Division P. O. Box 14000 Juno Beach, Florida 33408-0420 Gentlemen:
l 1
SUBJECT:
(NRC INSPECTION REPORT N05. 50-335/94-09 AND 50-389/94-09) I f
This refers to the inspection conducted by S. A. Elroo of this office on February 27 - Marcn 26. 1994. 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 i these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.
The enclosed Inspection Report identifies activities that violated NRC 4
requirements that will not be subject to enforcement action because the
- l'icensee's efforts in identifying and/or correcting the violation meet the criteria specified in Section VII.B. of the NRC Enforcement Policy.
Your attention is invited to two unresolved items identified in the inspection report. These matters will be pursued during future inspection.
-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 Room. {
Should you have any questions concerning this letter, please contact us.
Sincerely, b W$
David M. Verrelli, Chief i Reactor Projects Branch 2 i Division of Reactor Projects Attachment 1
Enclosure:
(See page'2) 1
%U6L Scool. \P-
- . . . -.. . . , . . . . . . . . , . . . . -. . _ . . - - . . - . . - . . ~ . . , . . . - - - - . . . . . . .
, p* me o n- UNITED STATES
./ NUCLEAR REGULATORY COMMISSION y*
- .. mEGION 11
- + -
V'( i '01 MARIETTA STREET. N.W.. sUtTE 2300 l ATLANTA GEORGIA 3E123 0190 N .. .. ) .
Report Nos.: 50-335/94-09 ana 50-389/94-09 Licensee: Florida Power & Light to 9250 West Flagler Street Miami FL 33102 50-335 and 50-389 License Nos.: OPR-67 and NPF Docket Nos.:
Facility Name: _St. Lucie 1 and 2
-Inspection Conducted: February' 27 26, 1994
- i. : .
Inspectors:
4 . b_ b, - March i a / , < i c4 S. A. Elroa. Senior Resident Inspector Date Signed
' ._, w T. Johnson, Senior Resident Inspector h -. i - > ; H Date Signed
" f. 1 h
[,( - ' - ;-
Date Signea e.(
- M. . S. Miller, Res1 dent'/ Inspector a #-P $7 y' Y .b_ ((
M. A. Scott, Res1 dent liispector Date Sig.ned j *
., I .
- i
}~ - ~.r n u
- %.as Date Signed L. Trocine, Resident inspector -
.A 4
- i. -l s > .. .
Date Signed R. Sc n, roject Engineer Approved by: fk///lu E8 9'[
Date Signed
.D/Lyndis,
[gReactorProjectsSection2B Chief Divistor. of Reactor Projects SUpttARY Scope: This routine resident inspection was conducted onsite in the areas of plant operations review, Unit 2 refueling observations, surveillance observations, maintenance observations, outage
- activities, and fire protection review.
l Backshift inspection was performed on February 28 and March 1, 2, 3, i 13, 15, 16, 17, 19, and 20.
i Attachment I
_C(Me62ACCO4 MPP . . -- .
t 1
2 Results: Plant Operations area:
Operators performed Unit 2 reduced inventory operations well.
Unit 1 operations continued to be good. One non-conservative licensee entry into a technical specification limiting condition for. operation action statement was. identified, involving emergency diesel generator fuel oil tank level.
Failure to follow refueling procedures resulted in a failed attempt to grapple a fuel assembly due to bridge mispositioning. (paragraphs 3 and 4) ,
Maintenance and Surveillance area:
Maintenance activities. both normal and outage related, were ;
generally conducted well. Several procedural weaknesses were identified and were addressed by the licensee. Surveillances were performeo satisfactorily; However, operator ano procedural weaknesses were identified during an EDG surveillance run.
(paragraphs 5. 6. and 7)
Plant Support area:
Health Physics coverage of outage-related maintenance was strong, as was health physics personnel response to a spill of potentially contaminated water. (paragraphs 3 and 6)
One non-cited violation (NCV) and two unresolved items (URIs) were identified:
NCV 50-389/94-09-01. Incorrect Grappling of a fuel Assemoly, paragraph 4.a.
URI 50-389/94-09-02. Adequacy of a Single Operator on the Refueling Bridge During Core Alterations, paragraph 4.a.
URI 50-389/94-09-03, Adequacy of Review'and Approval of Refueling Core Alterations, paragraph 4.a.
Attachment 1
l-8 above gallon numbers for each tank were convertea from feet and inches by the inspector.) The inspector founa no clear necessity or net safety benefit in pumping the 1A EDG-fuel oil tank level down below its TS-required minimum. In this case, placing the 1A EDG in a TS LCO action statement was a non-conservative action by the licensee.
i Also, the inspector found that the licensee tracked and reviewed overall unavailability of certain safety systems, but did not track or review overall time in LCO action statements for any safety systems. Unavailability and inoperability are substantially different. For example, in this case the 1A EDG was considered to be inoperable for eight hours but was also considered to be available during the same time.
- 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.
t In conclusion, operations for this inspection period were conducted satisfv.torily. Operator knowledge and control of Unit 2 reduced inventory operations were considered to be excellent. One licensee voluntary entrance into a TS LCO action statement, involving EDG fuel oil tank level, was considered to be non-conservative.
4 Unit 2 Refueling Observations (60710)
The inspectors reviewed the licensee's refueling activities and operations including surveillance testing, operating proceoures TS compliance, shift manning, reactor engineering involvement, management and supervision . oversight, plant conditions, housekeeping, and loose object control.
- a. Unit 2 Refueling and Core Shuffle l
The licensee commenced Unit 2 refueling and core shuffle activities on February 28, 1994. The inspectors monitored refueling from the control t'oom, the spent fuel area and the refueling bridge. During fuel movement, the. licensee controlled the move sequence by using a 4 Recommended Move List. This list was part of the core reload.PC/M 001-294 for Unit 2 Cycle 8. Fuel movement operations were controlled by procedures OP 2-1630024, Refueling Machine Operations, and Test Procedure 3200090, Refueling Operations. The test procedure referenced the Recommended Move List and described the
. steps necessary te deviate from this list.
On February 28, 1994, at 11:43 a.m. rrfueling operations were stopped during an attempt to grapple 1ssembly H08 in core location
<L Attachtent I l
T ,
i ;
9
- G11. - The hoist overload energized several times during the upward hoist motion attempts. The licensee discovered a typographical error in the Recommended Move List at steo 27. The core coordinate for..the bridge was listed as 787.71 and should have been 783.71.-
Consecuently, the bridge was misaligned by approximately 4 inches.
The licensee.surmisad that the grapple engaged the assembly off center and upward movement'was arrested due to actuation of the hoist overload. The refueling SRO directed reactor engineering to ,
check for aoditional errors in the Recommended Move List. Three i more errors were found and corrected.
In followup to this error, the inspector reviewed operating procedure No. 2-1630024. " Refueling Machine Operation". In order to assure the operation has the correct core location, a comparison check of rougn mechanical alpha-numeric grid coordinates was directed. -Then, a more exact coordinate was to be made using the digital bridge and trolley indicators. The coerator. during move.
numoer 27 for assemoly H08 in core location Gil, did not ensure that the two coordinates cnecked were in agreement prior to attempting to ,
grapple the fuel assembly. Consequently, the typographical error in the Recommended Fuel Movement List caused the operator to grapple the assembly in an incorrect position. ,
The licensee stated that the operator in question was recently qualified and his experience may have been a causal factor. Step 8.2.11.8.3.b of procedure 2-1630024 requires the operator to ensure that the mechanical indicator for the core coordinates agree with the bridge and trolley digital readouts. TS 6.8.1.a and b, and Regulatory Guide 1.33, Revision 2 February 1978. Appendix A, items 2k and 21 reouire procedures for refueling and core alteration to be written, implemented, and maintained. Due to the minor safety significance of this error and the licensee's prompt corrective action, this violation will not be subject to enforcement action because the licensee's efforts in identifying and/or correcting the '
violation meet the criteria specified in Section VII.B of the NRC' Enforcement Policy. The failure to adeouately follow procedure 2-1630024 in conjunction with the error in the Recommended Move List ce identified as NCV 50-389/94-09-01, Incorrect Grappling of a Fuel Assembly.
The inspectors reviewed the appropriate logs including the RC0 log book, the refueling log and others. During the February 28,.1994, !
- refueling error associated with step 27, the RCO log book stated l that the fuel movement had stopped (for almost 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />); houseer, i the reason was not stated. Further, the restart of refueling.(at approximately '3:52 pm) was logged in the RC0 log book. The inspectors discussed this issue with operations and plant management. I
. On March 1, from approximately 11:00 a.m. to 1:30 p.m., the inspectors observed refueling operations from the containment i
. including the refueling bridge and from the area of the spent fuel Attachment 1 ]
4 g -
--,y-- -
4 , , .-,e
- ,m - e ,,,. -
i 10 pool. During this time, an additional error in step 61 of the Recommended Move List was noted by the licensee in that the fus.i movement sheets incorrectly indicated that no'CEA was in the fuel assembly. The 1icensee corrected this error.
During this time, the inspector noted that only one licensed operator was on the bridge performing refueling operations. TS 6.2.2.d requires that all core alterations be observed by a licensed operator and supervised by an SRO with no concurrent 'l I
. responsibilities. This SRO may be in the control room, the.'
refueling bridge, ~or the spent fuel pool area. The inspector. j questioned.the validity of having only one person on the refueling i bridge, and whether this meets the intent of.a licensed operator
" observing core alterations". The licensee's position was that a
' single operator met this requirement. However, considering the error noted above, a second person checking or observing could have prevented this. Pending further NRC review. this issue is 1 identified as URI 50-389/94-09-02, Adequacy of a Single Operator on )
the Refueling Bridge during Core Alterations. )
The inspectors noted that the Recommended Move List and changes were not specifically reviewed by the FRG nor. approved by the Plant Manager, but instead were approved by the reactor engineering supervisor. Each movement is also a core alteration. TS 6.8.1 requires procedures for refueling operations and core alterations.
'TS 6.8.2 requires those procedures to be FRG reviewed and plant manager approved. Pending further NRC review, this issue is identified as URI 50-389/94-09-03, Adequacy of Review and Approval of Refueling Core Alterations.
The inspectors discussed these concerns with licensee management and l on March 2, at about 10:30 am, the licensee suspended refueling i operations. The licensee initiated the following corrective actions:
- Revision of Test Procedure 3200090 to incorporate the Recommended Move List in the procedure and to track changes to ,
the Recommended Move List in an Appendix to the procedure. j Revalidation of the Recommended Move List. !
FRG review and approval of the Recommended Move List per-TCs 2- 1 94-076 and 077. .
Initiation of a formalized deviation sheet signoff for-Feel
. Movement Changes. l Documented qualifications of each refueling operator.
Implemented-infrequent evolution process, including detailed i' briefing, per AP.0010020.
Stressed the importance of RCO log keeping during briefings, i Added a second person on the refueling bridge to ensure proper i fuel movements. l The inspector met with licensee management and attended the morning ;
shift briefings on March 3. The inspectors verified corrective l Attachment 1 !
11 l
actions and observed portions of the continuing refueling operations.
l The inspectors al'so reviewed QA activities assoc 1ated with the Unit 2 refueling. Based on discussions with QA management personnel, the inspector oetermined that QA had performed audits, surveillances and performance monitoring of refueling activities including:
new fuel receipt- ,
refueling preparations,
- TS compliance, !
monitoring of refueling activities in the control room, on the refueling bridge and in the SFP,
- procedure review, and CEDM unlatching.
Independent OC verification of the final core configuration and QA i review of core physics testing were planneo. QA/QC did not identify l any deviations, violations, or problem areas. The inspectors <
2- observed that QA/QC were not present during the February 28, 1994, i error nor during the times the inspectors were present in the i refueling areas and facilities.
- b. CEA Shuffle Following correction of the refueling process, the inspector '
monitored portions of the CEA shuffle on March 10. After completing i
- the fuel assembly shuffle per the approved Recommended Move List, !
the licensee moved CEAs to their new required positions. The i inspector noted that, toward the end of the CEA shuffle, operators found that two CEAs had been mis-located. The reactor engineer then made changes to the core load procedure to locate and move CEAs to
- correct the condition. The inspector verified that the orocedure j allowed the reactor engineer to make these changes.
- c. Core Load Verification i
Inmediately after the CEA shuffle, the inspector observed the Unit 2 '
' core load verification. This evolution was conducted from the refueling crane, using an underwater camera suspended by a pole from the crane handrail and.two video displays on the crane deck. I Licensee personnel involved in the evolution included an SRO.in charge, an RO crane operator, a reactor engineer, and a quality l control inspector. The operators positioned the camera while then i engineer and QC inspector each read and recorded the fuel assembly and CEA numbers. They also nada a video tape record of this evolution.
l The inspector 'noted that, while the numbers on the CEAs and new fuel assemblies were clearly legible, many of the numbers on the partially used fual assemblies were obscured by corrosion and small flakes of loose metallic oxidation (the engineer stated that this ;
Attachment 1 l
4 12 was from the CEA shuffle) and were very difficult to read. The engineer and QC inspector had to discuss and relook at many such numbers before they agreed on what the number was. After both had i viewed, recorded, and agreed upon all CEA and fuel assembly numbers, l 1
4 they compared their recorded numbers with the approved core map from the core load procedure. Three of the fuel assembly numbers did not match. Then the camera was repositioned to each of those three fuel l assemblies until the reactor' engineer and the QC inspector agreed with the nu:abers from the approved core load map. 1 The inspector concluded that the licensee's core load verification -
was adequate but was hampered by fuel assembly numbers being obscured by corrosion and small flakes of loose metallic oxidation.
. In conclusion while evolutions were generally' conducted satisfactorily, the inspectors found several aspects of the Unit 2 refueling operation to be of concern. These concerns were relayed to the licensee, and plant management aceouately addressed the issues. Failure to properly prepare and follow refueling procedures resulted in a failed attemot to grapple a fuel assembly due to bridge mispositioning. Questions related to TS-required leveis of staffing on the refueling bridge resulted in a URI.
- 5. Surveillance Observations (61726) l l
Various plant operations were verified to comply with selected TS ;
requirements. Typical of these were confirmation of TS compliance for l reactor coolant chemistry, RWT conditions, containment pressure, control i 4
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, remoi-
. 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. OP 1-2200050B, "1B Emergency Diesel Generator Periodic Test and i General Operating Instructions" The inspector witnessed the perfomance of IB EDG surveillance test performed March 16. The test was perfomed satisfacterily; however, the inspector noted weaknesses associated with operator performance and procedural adequacy. ;
In preparing to perfom the surveillance test, step 4 of the subject procedure requires that the water level in both EDGs' radiator expansion tanks be checked. The inspector noted, immediately prior to the perfomance of this step, that the water level in the 181 expansion tank was out-of-sight high in the tank's level sight glass (the procedure required that the level be visible between two points marked on the sight glass). The inspector witnessed the SNPO perfoming this evaluation to observe the sight glass and initial Attachment 1
i
) 20
]
- 9. Exit Interview The inspection scope and findings were summarized on April 25, 1990, 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 j comuments were received from the licensee.
I The licensee took issue with NCV 389/94-09-01. In this instance, an 1 operator mispositioned the refueling machine and failed to grapple a fuel
- assembly due to incorrect coordinates in the Recomunended Move List. The -
licensee stated that, while a cross check of machine coordinates following the move may have prevented the failed attempt to grapple, such j a cross check was not procedurally required.
i The licensee also took issue with URI 389/94-09-02. In this case, the t
inspector questioned whether a single licensed operator, performing core i alterations on the refueling bridge, met the intent of the TS requirement 4,
for a licensed operator to " observe" core alterations. The licensee's position was that a licensed operator performing core alterations constituted the TS-required observer. The licensee indicated that they 5 possessed NRC correspondence, generated during the original Unit 2 licensing process, which supported their interpretation.
The licensee also took issue with URI 389/94-09-03. In this case, the inspector found that the Reconumended Move List (for fuel shuffle) was not reviewed by the FRG and was not approved by the plant manager. The licensee stated that the Recomunended Move List's preparation, use, and '
i modification were directed by an FRG-reviewed procedure and that an FRG review should not be required for the list.
Item Number Status Description and Reference i 389/94-09-01, open NCY - Incorrect Grappling of a Fuel Assembly, paragraph 4.a.
389/94-09-02 open URI - Adequacy of a Single Operator on the i Refueling Bridge During Core Alterations,
- paragraph 4.a.
389/94-09-03 open URI - Adequacy of Review and Approval of-L Refueling Core Alterations, paragrapit4.a.
- 10. Abbreviations. Acronyms, and Initialisms
. AFW Auxiliary Feedwater (system)
ANps Assistant Nuclear plant Supervisor '
CCW Camponent cooling Water CEDM Control Element Drive Mechanism CET Core Exit Thermocouple CFR Code of Federal Regulations CVCs Chemical & Volume control system Attachment 1
- _ -~- - , _ ~ . ., , . . _ _ _ ,,,m.,. _,.._. , . .. . , . - . . - - ,
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. WholqleA Powem & LioHT coMPA**v i
1 Snotenber 22s.1981 k-81-415 1
i i
!: Mr. James P. O'Reillly, Director, Region II
[ Office of Inspection ~ and Enforcement U. 5. Nuclear Regulatory Commisston 101 Marietta Atlanta, Georgia StreeteJutte 303D3. 3100 4
1 L
Dear Mr. 0'Reilly:
Re: St. Lucie Unit l1 i
Docket No. 50-335 -
' $20 Refueling Supervisor IE Circular 80-t1 i
NRC IE Circular No. 80-21 states that the NRC interpretation of the term '
" supervising the core alterations from the refuell.ng l ..
! The St. Lucte productive. Plant staff feels that this interpretation is counter-j The existing staffing which has been utilized for the past meets, as a minimum, the intent of the Circular for i
1) much better overall control and coordination. Maintaining all refue)ing stationesusing the refueling status board and is in consta 4
instrumented to be the center of cverall plant operationsAddttto .
Placing theof SR0 on the refuelling l deck removes his from the mainstream .
communications.
awareness of overall piant status, and information, and would-limit his plant operAtton.
\
2) 1.
h rapidly to_the spent fuel pool area where fuel m occurring. ,
i 3)
- St. Lucie uttitres licensed operators on the refueling machine
, th'd spent fuel machine and ~on the communication needset in monitor wide range nuclear inscruisentation.
l
.may employbe non.)intended tcensed fueltot provida more supervision at those utilities w handlers.
extSting arrangweent exceous tne intent of tne Circular.If so, it is felt t 4
O tachment 2 4'
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. e. O'Reilly. Otractor 1 4
, 4)
Plectng tne'.SRO in enarge of fuel nanoling continuously refueling on ena decx is not:conststent witn corporate ano regulatory etes. ALARA poli For the above reasons, and our opinion that acherence to the state interpretation would detract from, ratner than enhance the safe fuel. It is our intent to conduct refueling operations innandling .
accoroanc of policy and the requiromants of the Tecnnical Specificationse with past ;
. Requiring the refueling areas is more conducive to safe described in the NRC Circular, o allfuel !
\' i As a result of a telephone conversation on September \
Dance of your staff, it is our unoerstanding.thatAq gh regarding the stationing of the SRO in charge of fue ng I. .
room._ We furthertunderstand "the control Inspectors of this concurrenc..that e. you will inform the site NRC Resident Very truly yours, ;; ..
- d. .dll $-
e Robert E. Uhrig Vice President Advanced Systems & Technology REU/PXG/ ras '
Attachment cc: Harold Reis. Esquire l Attachment 2
.- i i
FROM.USNRC'sT. LUCIF A M C' * ^"* " ~
j.- % !
. 3 ., % ! UNITED STATES e
a ,4 v< [ ,i, NUCLEAR REGUL ATORY COf.if,1;35iOT4 I.' REGION 66 ,
% ej/ sot uanssiva ev . m w.. syste stoo ng ATLANTA. GEoROlA 20203
' *. . . . '*' i 8V C LJ (10 '
SEP 3 0 : set g 581 t
ce.,. " "+;;. . . , _
i Florida Powsr and Light Company ATTN: Dr. rt. E. Uhrig. Vice President, Advanced Systems and Technology -
P.O. Box 529100 '
Miami, FL 33152.
Gentlemen:
Subject:
~
IE Circular 0/21 ., ,
i' Thank you for your letter of September 22, 1981 which confirms your !
conversation with Mr. H. C. Dance of our staff.
to require freedom the "quickly:
to move Refueling SR0" toareas.
to all refueling supervise from the control room with theW We appreciate your coope\
ration with us. '
Sinc ly, f
.s.,f/..
n ,
s f 'J a
au'l J. fK 1Vogg, Chief' '
j Reactor Projects Branch 2. .
{ Division of Resident and-i Reactor Project Inspection cc: C. M. Weth i Nat Weems.y, Plant Manager Manager QA Construction Attachment 3 e
i
Ngo teu cr se ST. LUCIE PLANT '
i PREOPERATIONAL TEST PROCEDURE NO. 3200090r MEYlSION 6 '
REFUELING OPERAT16N APPENDIX E RECOMMENDED MOVE UST EXAMPLE DATA BHEET,
- i Prem i 6 v.
see e aammy w= erie Orani Core isemesirreusvi spr i nPs. unner Cere,armeeTre , spP seen 1 78 ft) Re , CEA MOVE 1M 1 43 E31 918 I GEA MOVE.1M
!. 3 20 Ll7 I RIO I .
CEA MOVE.1M
- i. 4 113 LA l l 02 CEA MOVE 1M i 5 tot L11 L17 s
=^ MOVE.W t G21 270' L2 i e a' B57.21 West
! Z37 < EnnseCemes aVamos l' KW l
7 G31 851 748.8 799.01 West ZS4 answo Cemes a vertsel 8 GRE 270* X11 1887A4 4 799.90 i Weet 1 i.- .333
"- . i G Weines .
- 9 GBR 270' L20 800.111742.60 e u Weet .
'F M6 Ernstunnem o verseet .
10 G36 IN L9 < W Mi808.15 ) West . X84 1 Enswo Camere is Verseel c 11 G25 370' N11 806.4 1 799At West . . X33 oEnews Camera e Verseal .
12 Gas KW J11 792.00l 7ee.07 ' West '
t T37 Enews Cemem e Womes L 13 Git tw i Lta i,aaa =ifin.si West i 734 o= _m Camen s vases i
14 000 E70' We k m ** l S40As i West i TER Enewe Gamese a Vemens
! 15 MOR 20 270' R20 1 818.88i 742.74 f 15 MDB IM X7 L13 i m a= 791A1 W 55744 SILS N11 , 808.4 7"M W i
17 , .G77 rW v. ..it -- Wee , nr .ne.e Carmem . =_
is Moe 42 90' 516 788_"' 7" " J11 7ms na , ,w 73337i
- - 15 M01 113 90' G2 7" == 557.18 LS ' -^^! 008.15 ,
W EO G71 90'. G4 7""'i m." West RS4 . Enews Qamere le Womes
- 21 G75 90' D3 755.17 848.08 West R3R , Enews Cemen te Wereeni j 22 G71 00* D19 78= "5 750A7 West N37 I Enewe Gemem a vessel 23 000 00* C18 751.04 ' 780.0e West '
l N34 Enswo Cemem a vessei
} 34 073 27D* V10 'i841.15 t788 % West i '
M35 Enews Camere a Verseal
{ 33 078 270' WiB 848.39;i758.021 West 1
' 530 Enews Camere a Womem 24 MOS 100 270' L7 v 500.06 815.3 m an 887.11 i L2 W 27 MOS 24 i 270" Gil l 783.71 790.96 -
i 811 1742.81799A1
) at G57 270' W PRIOR TO LT. ^J'PLE i es ' 78&S7il N 81 West N30 Enews Camers a vernom
~
as -H07 55 IW R11 315A1 798.86 K11 857A4 ,7am a= ,
I 80 -938 W Prem TU LBdORAPPLE 21 E70' L15 ' " ^ " 753.51 L50 - 800.11 7'" ==
I 144 31 =G54 siv- RB 91E18 N.=1
- West AAE7 EfE Queem W Werbeel 33 Mit t IFU" RE 818.5 557.84 = a=
L7 815.5 . 1A4
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" YI7 Enews camsele veses:
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o Attachment 4 i
4 e.
FROM USNRC ST. LUCIE 07/29/94 00: 46 P. 3
. .,%,,-,.- +- .u.e---*--* ** ~
_ _ . __ ._ _ _ _ _ _._- . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ ~ . .
.. rege is cr o2 ST. LUCIE PLANT PREOPERATIONAL TEST PROCEDURE NO. 3200090, REVISION 6
- REFUELING OPERAT10N l 12.0 DETAILED PROCEDURE
j% Nhk J 12.1 The Operations Supervisor has reviewed the status of all CORE ALTERATIONS, relateo systems, as well as tne overall piant status, and :
authorizes the commencement of fuel movement.
i verified by Date / /
L Operations Supervisor 12.2 All required personnel are on station.
! Verified by Date / /
J 12.3 All fuel and insert moves will be directed from the Refueling Control Center in -
the following manner. ,
- 1. The Recommended Move List will be used as a move sequencing guide i
to refueling.
- 2. Deviations in the Recommended Move List sequence are permitted and altamate locations may be utilized as temporary locations prowded the following are observed:
A. Sources, or fuel assemblies meeting the minimum bumup requirements of 9.8.1 RX-A10, RX Y10 (PSL 1) or RX-A10, RX-Y12 (PSL 2) If required, will be located in before any other fuel moves are permitted.
B. Movement of an assembly is in accordance with the Fuel Assembly i
- Storage Table (F.A.S.T.).
! C. Verify that the mast orientation is correct to support the new move.
D. Verify that as a result of removing an assembly, no other assemblies become free atanding.
- E.' Verify that inserting an assembly into a new location in the core and !
[ ungrappling it would not cause it to be a free standing assembly.
F. Verify that moving an assembly into a spent fuel Rack does not violate spent fuel pool region requirements or funnel requirements.
Attachment 5 Igad 684S13 Port 01 l a id WdEZ:Ed P661-9T-80
i
Pcge 20 of 52 ST. LUC!E PLANT
- PREOPERATIONAL TEST PROCEDURE NO. 3200090 REVISION 6
- REFUELING OPERATION
) 12.0 DETAILED PROCEDURE: (continued) 12.3 (continued)
- 2. (continued)
! G. Any deviation is approved by the Reactor Engineer on shift and the Refueling Coordinator (SRO).
i H. If the deviation does affect the FRG approved Final Core Loading !
Pattom, reactivity conservatism shall be ensured and FRG re approval obtained prior to core verification.
- 3. The Refueling Control Center will inform the station conducting the move which assembly is to be moved, it's present location as well as where it j is to be moved and changes in Refueling Machine mast onentation if required.
. 4. The station performing the move will acknowledge the directions issued ;
by the Refueling Control Center prior to any movement. For the i operator's convenience a Fuel Movement Log similar to that provxied in this procedure will be provided for recording the instructions transmit %s i by the Refueling Control Center.
12.4 Refueling Control Center- Operating Personnel Responsibilities
- 1. Coordinate the movement of all fuel and core components. Refer to
{ Appendices C and D for insert and CEA transfer guidance.
- 2. Receive notification of core component movement and acknowledge
- such notification by core component serial number (s), originating location, pasent location, core coordinates, and orientation of the Refueling Machine mast.
- 3. Verify Bridge and Trolley coordinates (hoist position upon insertion of a fusi assembly) stated by Refueling Machine Operator are valid for the core coordinates in the refueling sequence for the appropriate step, record on the Fuel Movement Log.
- 4. Track completion of each transfer by filling out the Fuel Movement Log.
The Fuel Movement Log will then be used by Reactor Engineering to comple's Appendix B, the final fuel transfer. sequence at the conclusion of the fusi move, then update the Fuel Status Magnet Board.
Attachment 5 -
._._.._______J_~'i______*f__~1_1T_____________