ML20137R952

Informs That Plant Performance Review of Listed Plants Was Held on 950316

ML20137R952
Person / Time
Site:	Saint Lucie, Surry, North Anna, Turkey Point, Crystal River
Issue date:	03/22/1995
From:	Verrelli D NRC (Affiliation Not Assigned)
To:	Merschoff E NRC (Affiliation Not Assigned)
Shared Package
ML20137R957	List: ML20137R952 ML20137R978 ML20138E944 ML20138E951
References
FOIA-96-485 NUDOCS 9704140307
Download: ML20137R952 (13)

Text

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-March 22, 1995 MEMORANDUM TO: Ellis W. Merschoff,. Director Division'of Reactor Projects (DRP)

Orig signed by David M. Verrelli

FROM:~ David M. Verrelli, Chief-Reactor Projects, Branch 2, DRP

SUBJECT:

PLANT PERFORMANCE REVIEW-A Plant' Performance Review for Branch 2 Plants was held on March .16,1995. A list of participants is attached as Attachment 1.

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For this review, the Senior Resident Inspector or his representative was chief spokesperson for integrating the results and assessment of performance. The

. Site Issues Matrix was used to identify any trends in licensee performance. 'A

, , Prado chart of the issues Matrix for each site is included as Attachement 2.

Other issues discussed included recent inspection findings, planned inspections and future licensee actions which would necessitate changes to the.

Master Inspection Plan.

North Anna .

The last SALP period ended on December 24, 1994. During the past three months 3

there has been no noted decline in performance in any of the four SALP Category 1 functional areas. Since the end of the SALP period the site

. declared a NOUE on March 1,1995, due to loss of the' Security System

. Uninterruptible Power Supply and a Notice of Enforcement Discretion was granted on February 3,1995, when industry identified the )otential for loss

of one. train of the Solid State Protection System. In bota cases, the

. licensee demonstrated prompt response. It was the consensus of the participants.that VEPC0 conducts thorough self-assessments and has a low threshold for' identifying safety issues. Further, no adverse effect in the Engineering area was noted even though routine contractor support has been U -essentially eliminated'over the past year. No changes to the MIP are recommended. For the period March 20 through May 12, a Resident Inspector from Surry (Tingen) will be detailed to North Anna to act as the Senior i Resident Inspector .while McWhorter is on rotational assignment to the Office

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.Surry j

-The last SALP ended January 21,.1995, and there have been no significant l events during the following two months'which would indicate a change in- i

. performance. As indicated. in that SALP,-altheugh the Maintenance area was a considered good,' major challenges include human performance and-equipment-i aging problems.- Thuse.we recommend that- the M:P be revised to add as Regional . j

. Initiatives. planned inspection effort in Maintenance Observations (IP 62703) i and BOP inspections (IP. 71500). - This would reduce the Core hours for a N+1' '

CONTACT: David M.-Verrelli, DRP (404)l331-5535 -

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plant. In addition, Surry will begin additional construction and transfer of spent fuel to their Independent Spent Fuel Storage Installation. Thus, appropriate inspections should be added to the MIP; Construction (IP 60849);  !

Security (IP S1001); Loading, Transfer, Surveillance and Direct Radiation (IP  !

60846). It is noted that the current ROI 0713 " Independent Spent Fuel i Storage Installation and Review Program," would require inspection for all transfers. At Vepco's estimate of 11-2 weeks per transfer and four-to-six  !

transfers during the next SALP cycle. we believe these total hours are  !

excessive. The ROI should be revised: ACTION: DRSS and DRP Branch Chiefs. l MIPs change request forms will be forwarded separately. l Turkey Point _

1 Turkey Point has performed well over the last nine months, with no major  !

indications of change in performance. Currently staffed at N+1, to program I resident inspector inspection efforts for a Category 1 performer we plan to I place a Resident Inspector on rotational assignment to the Headquarters Duty  !

Officer Staff for a period of six months beginning April 1, 1995 and a second Resident has been be providing assistance to the Resident Staff at Watts Bar, l j

The major inspection effort at Turkey Point for the future includes the initiation of our Service Water Inspection (reduced scope) and a Headquarters l Audit of seismic issues (51-46). This latter effort will entail a team visit i to Corporate for a week and on-site for a week. Region II shobld assign a Civil Engineer to this team. ACTION: DRS, identify inspector. No changes to the MlP are recommerded.

St. l.ucie After an unusually high number of reactor trips between November 1993 and June 1994. St. Lucie has performed well. The licensee has focused management attention to onsite activities; operations is taking more of a leadership role in acceptability of corrective actions: and all non conformance reporting has been consolidated into one system. There are no major efforts scheduled for St. Lucie. None are recommended.

Crystal River A special Plant Performance Review for Crystal River was performed on I January 10, 1995, and the results were presented to the licensee at a  ;

Management Meeting conducted on March 1, 1995. The staff concludes there is a

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definite decline in performance at Crystal River particularly in the i Engineering functional area. The licensee conducted a performance review by a 1 Hanagement Review Panel, and found our concerns to be valid and ceveloped a corrective action plan which was submitted to the NRC by letter dated March 10, 199S. The Staff should develop an Inspection Plan to be implemented for Crystal River. This should include inspection of the licensee's Action Plan I at appropriate milestones and assessment of its effectiveness. Also included i should be a schedule for resolution of outstanding technical issues such as Service Water operability, setpoint methodology, Makeup Tank, and BWST issues.

This plan should be developed by March 24, 1995.

Attachments: As stated (2)

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C. Casto A. ; Bel isle -

K.: Landis-M. Branch'

.R. McWhorter

S. Tingen T. Johnson R.~ Butcher

.R. Prevatte l L. Garner R. Schin '

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Plant Performance Review -

March 16, 1995 l List of Participants t ATTENDEES BY PHONE E. Merschoff,: DRP G. Belisle, DRP  ;

R. Cooper, Region I J. Norris, NRR  :

B.- Hallett, 'DRSS R. Prevatte, DRP J. Johnson, DRP R. Croteau, NRR i T. ' Peebles, DRS B. Buckley, NRR  :

<C. Casto, DRS D. McGuire, DRSS W. Rankin, DRSS T. Decker, DRSS K. Landis, DRP T. Johnson, DRP R.' Butcher, DRP M.' Miller, DRP M.' Branch, DRP D. Taylor, DRP L. Garner, DRP R. Schin, DRP L.:Raghavan, NRR ATTACHMENT 1

NORTH ANNA ISSUES BY ROOT CAUSE AND SALP AREA j

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ST. LUCIE ISSUES BY ROOT CAUSE AND SALP AREA C

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-March 16, 1995 ST LUCIE Integrated Plant Performance Review A. Current Plant Status. ,

Unit I has been operating at power since March 8. 1995. The unit'was returned to power following a short notice outage for pressurizer code  !

safety valve replacement. The next refueling' outage is scheduled for

. April 4.1996 ,

Unit 2 has been operating at power since February 25. 1995. The unit was returned to power following a reactor trip due to low steam generator water level resulting from a level transmitter failure. The ,

next refueling outage is scheduled for September 25, 1995. 4 B. Manaaement The current organization has been effective since September 1. 1994:

C. Plant Performance i

The units ex)erience an unusually high number of reactor trips (4) i between Marci 94 and June 94. However, during the past nine months, the l units have experienced two reactor trips - two unit shutdowns, one unit 1 off-line for maintenance and one loss of shut down cooling event.

Operator performance was good during th9 trips and shutdowns.

July 8, 1994 - Unit 2 was taken off line (Mode 2) when 2B1 RCP lower oil level indication failed, incorrectly showing leak.

Ju 14, 1994 - Unit 2 was shut down to allow repair of a stuck-closed reactor trip circuit breaker.

October 26.1994 - Automatic trip of Unit I due to arc-over from a ,

potential transformer in the switchyard which resulted  !

in a loss of' load.

February 21.1995- Automatic trip of Unit 2 when a SG water level l transmitter failed high. The failure resulted in a

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closure of a FRV. starving the SG for water and leading to a trip on SGWL.

February 27.1995- Unit I was shut down to replace pressurizer code safety. valves, which had been leaking by the seat since restarting from the Unit 1 outage in November.

March 4, 1995 - Unit 1 experienced a loss of shutdown cooling for approximately 14 minutes when a hot leg suction valve to the operating shutdown cooling train closed. Root cause has not been established; however. operator error in manipulating valves is the most likely cause.

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U. Performance Indicators-St. Lucie performance indicators indicate above average performance of both units, with a recent decrease in automatic scrams.

E . ' Enforcement Historv i No escalated enforcement in 1993 or 1994. .

F. Period ended May 1992 Period ended January 1994 SALP_

Operations 1 1 i i Maintenance 1 1

Engineering 1 1 Plant Support 1 Rad. Con. 1 Security 1 Emerg. Prep. 1

.SA/0V 1  ;

G. IRPQ INPO assessment March 1992 - Category 1 -

.INP0/WANO assessment April 1994  !

Next INP0 assessment scheduled for August-October 1995 l 1

H .- 1994 Precursor Events None  ;

I. Alleaations and DOL Cases l Six allegations are open: one negative performance appraisal: one i security guards - insufficient number, drinking. etc.: one fitness for duty - alcohol consumption; one attempt to coverup GL 79-02 bolting >

discrepancies: one ARMS room door left open and unattended: and one regarding weld repaires on CCW. No DOL cases are open.  !

J. Attachments

1. Organization Charts -

2. Power History Profiles

3. Issues Matrix l

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PLANT STATUS REPORT FOR ST. LUCIE (3/95)

. TABLE OF CONTENTS' h r

PART 11- FACILITY DESCRIPTION 11 FACILITY / LICENSEE................................. ..Page:2 ,

UTILITY SENIOR MANAGEMENT .................... ......Page.2-

,1.2 1.3 NRC1 STAFF.......................... ..................Page 2 1.4 LICENSE INFORMATION..................................Page 3 1.5 PLANT CMARACTERISTICS................................Page 3 ,

-1.6 'SIGNIFICANT DESIGN INFORMATION.......................Page 3 ,

t 1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS...........Page 8 1.8 PRESENT OPERATIONAL STATUS (Past Six-Months).........Page 9 l

. 1 9~

OUTAGE SCHEDULE AND STATUS...........................Page 12 3

PART 2 PLANT PERSPECTIVE 2.1 GENERAL PLANT PERSPECTIVE.................... ........Page 13 2.2 SALP HISTORY (Past Two SALP Periods)........ . .... ,Page 13

i. 2.3 ' SELECTED SALP AREA DISCUSSIONS .............. . .. .Page 13 i PART 3: SIGNIFICANT EVENTS 3.1 SIGNIFICANT EVENTS BRIEFINGS (Past 12 M6nths)........Page 20.

3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months)..........Page 20 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 SIMULAT0R........................... ........ .Page 21

<4 . 5 INPO ACCREDITATION. ......... .. . . .... ..... .Page 21 ,

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 j 1

L ATTACHMENTS i

1. PERFORMANCE' INDICATORS

2. ALLEGATION STATUS: '

3. :NRR OPERATING REACTOR ASSESSMENT

'4 ORGANIZATION CHARTS

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5. POWER HISTORY CURVES' 6 .- MASTER INSPECTION PLAN  ;

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'PIR:T- 1 ' F A'C I'L I T'Y 'D E S'C R I P.T I 0 N

- l'c1: 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)

~1 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 R. L. Dawson (Bob) - Licensing Manager-D. J. Denver (Dan) - Site Engineering Manager H. L. Fagley (Herman) - Construction Services Manager P. L. Fincher (Pat) - Training Manager-R. J..Frechette (Bob) - Chemistry Supervisor J. Marchese-(Joe) - Maintenance Manager W. L. Parks (Bill) - Reactor Engineering Supervisor C. A. Pell (Ash) - Outage Manager J. Scarola (Jim) - Operations Manager 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 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

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NRR:

.l 1 S. A. Varga (Steven). Director. Division of Reactor Projects-I/II..

(301) 504-1403' -i t ~ J.J A. Zwolinsky (John). Deputy Director. Division.of Reactor  ;

4 Projects-I/II.;(301) 504-1335) . '

D..B. Matthews.. Deputy Director. Project Directorate II-2.-  ;

4 (301) 415-1490. . .

.. J. A. Norris (Jan). Senior Project Manager. Project 3 Directorate 11-2. (301).504-1483 4

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- S. Israel (Sandy). -Reactor Operations Analysis Branch, ';

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-(301) 415 7573

- 1. 4 ' LICENSE INFORMATION l Unit 1 Unit 2 t Docket Nos. 50-335 50-389 i

. License Nos. DPR-67 NPF-16 Construction Permit Nos. CPPR-74 CPPR-144 f Construction Permit Issued 7/1/70 5/2/77 Low Power. License NA 4/83 Full Power License 3/1/76 6/10/83 Initial Criticality- 4/22/76 6/2/83 1st Online- 5/17/76 6/13/83

. Commercial Operation 12/21/76 8/8/83 1.5- PLANT CHARACTERISTICS i Description - Units 1 and 2 Reactor Type Combustion Engineering PWR. 2-loop-4- Containment Type Freestanding Steel w/ Shield Building Power Level- 830 MWe (2700 MWt)

Architect / Engineer Ebasco NSSS Vendor Combustion Engineering Constructor Ebasco Turbine Supplier Westinghouse Condenser Cooling Method Once Through  ;

-c Condenser Cooling Water Seawater  !

j '. 6 SIGNIFICANT DESIGN INFORMATION I 1.6.1 REACTOR INTEGRITY-Reactor Pressure Vessel-(RPV) 4-

With the present fuel type and maragement policy Unit 1 is l expected to reach a '40-year RPV life. On this unit, the fuel type j and management policy have been modified to make that RPV 11fe

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span possible. 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 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 c.eck valves and one closed MOV. High 3ressure safety inject. ion (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 hedders are isolated from containment by one closed MOV and a check valve in conjunction with a closed seismic piping system. CVCS has the normal complement of two automatic actuation isolation valves.

1.6.2 REACTOR SHUTDOWN Reactor Protection System The reactor protection system provides protection for the reactor fuel and its cladding by providing automatic reactor shutdowns (8 trips) based on input from reactor power. reactor coolant pressure, coolant temperature, coolant flow, steam generator pressure, and containment pressure. The RPS is a redundant four-channel system that operates on a two-out-of-four logic.

ATWS Protection ATWS protection, outside the normal reactor protection system, is initiated via the ESF pressurizer pressure signal. It actuates by opening contactors in the output of the CEA MG sets, thereby interrupting control element assembly power at its source. This protection has been installed on both units per CE the NSSS.

recommendations.

Remote Shutdown Facilities These facilities are located in the switchgear rooms beneath each

. unit's control room.

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 Byoass/ 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.

Auxiliary Feedwater System i

There are two motor-driven pumps on each unit with 100 percent capacity per pump. There is one steam-driven pump on each unit i va t'1200 percent capacity. Any of the three pumps can inject to either steam generator. Automatic initiation and faulted steam generator protectica are provided by each unit's Auxiliary Feedwater Actuation System provided by the NSSS.

Emeraency Core Coolina System  !

In each unit. there are two HPSI pumps and two LPSI pumps with no unit-to unit cross-connections. One pump of each type per unit will handle a postulated LOCA. The LPSI pumps also provide decay heat removal as required when the unit is shut down.

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 shutdovm 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 4 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 sta-ted by ESFAS.

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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.  !

Lto form water, thus preventing the buildup of hydrogen to.

potentially. explosive levels.  ;

1.6.5 ELECTRICAL POWER

'Offsite AC.

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' 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 l Onsite AC power is provided by four EDGs (two per unit). EDGs are l independent of other' plant systems except vital DC power for i control.of starting. A Station Blackout (SBO)' 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 i cross-connected to the safety-related swing bus if needed.

Instrumentation Power Each unit has four inverters, two powered from each vital DC l train. that provide four trains of instrumentation power. 1 Station Blackout Resolution Status

. Unit 2 is a four-hour "DC co)ing" plant per the original license ,

while Unit 1 is' subject to tie station blackout (SBO) rule of 10 I CFR 50.63. requiring additional licensee action (unit-to-unit cross-connect-of 4160V bus).

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i 7 i 1.6.6 SAFETY-RELATED COOLING WATER SYSTEMS Intake Coolina Water (Service Water)- 1 Intak'e 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 alpes pass under the beach to connect the ocean and canal. :Tle intake pipe ends in the Atlantic are covered by intake i structures (rebuilt in 1991) intended to limit flow velocities.

particularly vertical velocity, to reduce marine life entrapment. .

After use, ICW returns to the ocean through a Discharge Canal and l under-beach pipes.

Each unit has two trains of ICW plus a swing pump that can be I aligned to either train electrically and physically. The licensee i has converted the dee) draft ICW pumps from externally (water) 1 lubricated to self-lu)ricated to increase reliability of the )

lubrication water source. The 100 percent (each) capacity pumps j 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, primarily to control marine growth affecting the turbine ,

condensers, has also somewhat reduced marine growth affecting the i ICW system. l The ICW pumps move water through two trains of heat exchangers that cool component cooling water (CCW) and two trains of heat R exchangers that cool main turbine cooling water. During a Jostulated 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. 1 1

- 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 1 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, s I j

'l

s f

i 8.

i The swing pump can be aligned to either train. The 100 percent

'(each) capacity aumps drive water through the CCW/ICW heat i exchangers and tien on.to the heat loads, mainly the containment  !

. fan coolers and the shutdown cooling (decay heat) heat exchangers  ;

.(which also can operate as containment spray heat exchangers). 1 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 .f Wet storage capability exists up to the year 2002 (Unit 2) and 2007 (Unit 1).

1.6.8. INSTRUMENT AIR SYSTEM-

. Instrument air comprersors and driers, installed several years ago l cn each unit, provide all instrument air for Unit.2 and all but  ;

containment air for Unit 1. These have increased instrument air l reliability. ' Unit 1 also has instrument air compressors inside containment.

1.6.9 STEAM GENERATORS-  ;

Each unit has two large steam generators (SGs) rather than the.

three or four usually seen. The licensee has begun to focus on a Unit 1 SG replacement in 1997. The SGs are under construction at the B&W Canada shops and a site organization is functioning.

i 1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS Emergency Operations Facility: 10 miles West of site.

1-95/ Midway Rd. Exit Technical Support Center: Onsite. Adjacent to Unit 1 Control Room i

Operational Support Center: Onsite. 2nd floor of )

North Service Building i The last annual emergency preparedness exercise was held February 9. i 1994; Two followup items were ~ identified: one involving the definition l 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 experience with Hurricane Andrew in August.1992. Improvements include: j I

1

.j q

9- i 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 E0F and county emergency' facility.  ;

> Cellular phones with hardened antennas.

Hardened Local Government Radio antenna' ties.

1.8 PRESENT OPERATIONAL STATUS (3/9/95)

' Unit.1 is operating at 100% power and'has been operating since a reactor startup on March 8 following a short notice outage for pressurizer code ,

safety valve replacement.

Unit 2 is operating at 100 % power and has been operating since a .;

reactor startup on February 24 following a trip on February 21 due to an l

' instrument failure.

Availability Factors: 1 Unit 1 Unit 2  !

1991 81.0 100.0-1992 96.5 75.2 71.8 1993 74.0 1994 86.8 79.6 1995 (through 1/95) 100.0- 100.0 i Cumulative (through 1/95) 77.3 83.0 1 1.8.1 UNIT 1 OPERATING HISTORY (Past Twelve Months from 3/21/95)

Unit 1 operated continuously during the past 12 months with the i'

. following exceptions:

On March 28,1994. Unit 1 experienced an automatic reactor trip '

i 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. .

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 1' 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 I returned to power on April 4.  :

1994.

v

, l

i '

t 10-On June 6.1994. Unit ~ 1 tripped'during a severe thunderstorm.' .

The main transformer locked out the generator.- causing a reactor ,i

' trip. due to a phase differential on main generator transformer- .

~1A. This 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.  ;

The reactor was taken critical on June 8:-however, the licensee . '

. elected to remain off-line until . repairs were complcted to the 1A ,

main transformer. Unit I was placed on line on June 11. .

Unit l' reduced power and entered _ mode 2 on August 28 to repair a i<

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. j On October 26. the unit trisped from 100 percent power due to a loss of electrical load. T1is was the result of arc-over. in a

, potential transformer in the switchyard due to salt buildup. The ,

licensee then entered a unit refueling outage, which had been scheduled to begin four days later. The unit was returned to '<

service on November-29. j

'On February 21, 1995, the unit was removed from service for the replacement of pressurizer code safety valves which had.been leaking by the seat since shortly after startup in November. 1994'. l The unit was returned to service on March 8.  !

On March 4.1995, the unit experienced a 14 minute loss of 2 shutdown cooling. The apparent root cause was operator error by a j reactor operator placing one. loop of SDC in standby. The operator i apparently closed the suction valve to the operating vice standby. pump. The' operator in question has denied.the error.

The licensee is considering disciplinary action and has releived the operator of licensed activities.

i 1.8.2_ UNIT 2 OPERATING HISTORY (Past Twelve Months from 3/21/95) J Unit 2 operated continuously during the past 12 months with the following exceptions:

On March 16. 1994, during a unit refueling outage, the licensee ,

identified boron deposits indicative of leakage from one of four j pressurizer. steam space instrument nozzles. Licensee  ;

investigations: identified unacceptable linear indications in three j of four nozzle pressure boundary welds. The steam space nozzles i were constructed of-Inconel 690 and were installed in 1993 as I replacements for existing Inconel 600 nozzles. which had been -l found to be cracked. The new nozzles were attached with Inconel 600-equivalent weld material.- as 690-equivalent material was not i approved.for use at the time. The licensee determined that the ]

1

.. a .

n: ,

~4T ,

)

'. i 11 >

indications were the result of- Primary Water. . Stress Corrosion

' Cracking (PWSCC).

5 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-i 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 operating shutdown cooling trains. A second shutdown cooling loop was'in operation at the time: however, operators stopaed the i operating pump as a. precaution against damage after t1e unexpected i valve realignments. Operators assessed the situation and restored )

shutdown cooling in six minutes. 1 1

Unit 2 completed the refueling outage and was returned to power on l '

April 19. 1994.

On April 23,1994. Unit 2 triaped due t6 a RPS cabinet manufacturer's wiring error w11ch manifested itself during RPS' troubleshooting. The wiring error existed since the original manufacture of the cabinet.

Following Unit 2 trip stabilization of April 23. 1994, the steam bypass control system operated unexpectedly, resulting in a rapid j 7 degree cooldown and a resultant severe RCS shrink (pressurizer .

heaters deenergized on low pressurizer level). Prompt operator I action was taken to secure the cooldown. Unit 2 was returned to H 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 j 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.LCO 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. l On February 21 '1995, the unit tripped as a result of low steam j generator water level. The condition was the result of a '

.feedwater regulating valve closure after a steam generator water i

9 12 level control level transmitter failed high. The transmitter was replaced and the unit was returned to service on February 25.

1.9 OUTAGE SCHEDULE AND STATUS Unit l's last refueling outage began on October 26. 1994, and ended on November 29. 1994. Major activities included: refueling; reactor vessel nozzle and flange weld ISI inspection: installation of a permanent cavity seal ring; 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 in:,tances of reduced inventory / mid-loo) operations; replacement of ICW/CCW LOOP logic [HFA latching relays) wit 1 pull-to-lock switches:

removal [ collection] of Rx vessel neutron flux dosimetry; modification of CDG skids to allow access underneath; inspection of ECCS sump area; replacement of a main transformer: modifica' tion of containment spray NaOH addition piping; and mechanical, electrical, and I&C systems maintenance.

Unit 2's last refueling outage began on February 13. 1994, and ended April 17, 1994. Major outage activities included: 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

< ISC ystems maintenance. The next Unit 2 refueling outage is scheduled for Oc+ober. 1995.

PART 2 -

PLANT PERSPECTIVE 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 f6" the second 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 ' ' M.

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 SAQV PERIOD 5/1/89 - 1 1 2 1 1 1 1 10/31/90 11/1/90 -- 1 1 1 1 1 1 1

d 13 l 5/2/92 PLANT OPS MAINTENANCE ENGINEERING PLANT SUPPORT 5/3/93 - 1 1 1 1  !

1/1/94 1

l 2.3 SELECTED SALP AREA DISCUSSIONS (3/21/95)

Since the assessment of the SALP period ending in January.1994, there have been no events that should significantly change the overall 4 assessment of this facility. A new corrective action program, the St.

Lucie Action Report Star System, was implemented in July,1994. This )

program will be used to identify, review, analyze, resolve, track, and close out all plant discrepant conditions. It is intended to provide increased emphasis in this area.

Plant Onerations Summary of Previous Assesment Within the current SALP cycle, previous assessments have noted a potential decline in Operations' performance. Noted indicators included five reactor trips in the first six months of the cycle.

No common root causes were identified. Operator actions with regard to the noted trips were generally good. Two entries into  ;

reduced inventory operations during the Unit 2 outage were noted i as excellent. Procedural weaknesses which indicated a lack of rigor in the review process were noted. as was the fact that temporary changes to procedures were on the increase (indicating increasing attention to procedural adequacy).

Management activities in response to the increase in operational events was determined to be strong, with an increase in overall focus directed at plant operations. The corrective actions program was enhanced censolidating tens of programs into one which involves daily management reviews of all documented conditions.

The previous assessments concluded that Operations remained strong in t1e current period. that management actions were agressive in dealing with identified weaknesses, and that increased attention to procedural adequacy may be warrented. ,

Last Six Months The previous six months as shown a sharp decrease in the number of 4 reactor trips, with two having occurred: one due to salt buildup on switchyard components which led to a loss of electrical load on Unit 1, and one due to a level transm;tter failure which led to a low steam generator level trip on Unit 2.

4 .

14 q O'perator Performance 0perator performance has been noted to be good to excellent )

in evolutions such as post-trip response, startups. mid-loop  !

operations (during the Unit 1 outage), and in the i

' performance of surveillance testing. Several findings have l indicated potential weaknesses in attention to detail on the' j part of operators. 'They include .

. i e Failure to sample a SIT within the TS-required time.  !

frame. Second occurrance in two years. .

e Failure to identify an inoperable LPSI header pressure- J' control board indicator which had been failed in mid-range for approximately two weeks.

e- -Minor refueling machine errors of omission e Failure to identify / notify in response to Unit 1 hot leg stratification.

e Potential operator error in valve control manipulation which led to a loss of shutdown cooling on Unit 1.

An issue of a lack of professionalism and of a casual attitude toward E0Ps on the part of one individual was

. identified during operator examinations. The licensee prepared and executed an agressive remediation plan prior =to allowing the individual to return to watchstanding duties.

Strengths  ;

Strengths have been identified in the ability of the l Operations department to intgrate plant activities. Aspects  !

included multidisciplinary briefings prior to major evolutions (be they operations or maintenance evolutions),

and an increased involvement by Operations in the  ;

prioritization of maintenance activities.  !

Operations' management has played a major role in the identification and resolution of prominent problems.

including: 1 e 2B LPSI pump air-binding e- Pressurizu relief valve seat leakage j e Failure to .. ' ole SITS following volume additions  !

e Minimum temperature for criticality discrepancies e CVCS letdown control anamolies j In these and other. cases. Operations has expressed an unwillingness to accept stopgap maintenance measures and has demanded that historically poorly performing systems be made to operate correctly.

Weaknesses i

.]

.y . 5-. .- .,

,o 15 Weaknesses have been identified'in annunciator response procedures (several were discrepant either.in setpoint reference or in content), corrective actions- (a violation resulted from the licensee's failure to recognize the impact of.a failure to perform adequate surveillance testing on swing bus components), logkeeping.(a violation resulted from the modification. by one shift. of..another shift's log entries), and aspects of the Facility Review Group's activities (some members were identified as " going through the' motions" of review: however, the Plant General Manager was consistently _ cited as a strong presence who articulated' expectations and kept members on track).

Conclusion On balance.-Operations continues to be strong at St. Lucie.-

The licensee continues to be agressive in the identification and resolution of o)erational problems. In the last six months. operations las shown a new involvement in maintenance prioritization which has increased the safety perspective applied to maintenance activities.

Maintenance / Surveillance Summary of Previous Assesment Maintenance was assessed as category 1 in the previous SALP.

The previous assessments made during the current SALP cycle indicated that the performance level of maintenance activities had not abated. Strong performance had been noted in the support of the Unit 2 outage. and housekeeping and plant preservation activities were deemed good.

Last Six Months During the past six months, twenty-seven maintenance activities were observed in varying levels of depth. Two violations were cited; one involving the misuse of an unreviewed vendor technical manual and one involving a failure to perform an adequate independent verification of landed leads. Workers were generally found to be well-trained, conscientious, and skilled.

-Twenty-four surveillance activities were observed. No violations or major weaknesses were identified as a result.

Strengths TheUnit1o'utagewasconsideredamajorstrength.

The outage was-conducted in thirty-ff ve days, three 4

. -. - . . - . - - = - . . .

7 I [

16 days ahead of schedule ~. without a safety-significant-  ;

reduction in work scope. +

The licensee developed and imple' mented-a Critical-Maintenance Management program for.the' performance of -i maintenance within TS' ass. Maintenance activities. F performed under this program have been observed and' found to be well-planned and executed and have been '

performed after assessing the increased risk associated with the activity. '

The licensee's predictive maintenance. program has- .

continued to provide early indications of impending 1 failures. Most recently, the organization identified )

an unsatisfactory lug in cabling supplying one phase ,

of a CEA MG. ]

Weaknesses Isolated weaknesses have been identified both.by the j NRC and the licensee's OA organization. They include:

e A failure to properly incorporate changes into VTMs. Required FRG reviews were not performed.

e A failure to adequately define and perform independent verifications properly.

e A failure to properly implement elements of the site's welding program. This was identified by 0A and resulted in the Maintenance Manager issuing a stop work order, which was in place 4 for one week. while concerns were addressed.

Conclusion Maintenance continues to be performed at superior levels.

Planning and execution has improved through extensive planning efforts. The addition of the Critical Maintenance Management program has enhanced on-line maintenance by .

requiring extensive review and planning prior to work. 1 Surveillances continue to be performed well.

Enaineerina >

Summary of Previous Assesment The previous assessments for this SALP cycle concluded that engineering was generally strong. Good support of the Unit 2 outage was noted. as was good QA with respect to fuel  ;

fabrication and receipt inspection. Potential noted in.the area of vendor technical manuals. problems were '

i

-o

.{

f 17 Last Six Months a i

^

.The noted concerns with respect to VTMs were, in part.  !

validated in the maintenance area, where a violation 1

'resulted: . however, the violation was not reflective ~of a 1 failure on the part of engineering. Good support to the Unit 1 outage was noted, with engineering. personnel assuming  :

pivotal roles in the management of.the outage. One NCV was  ;

identified,. relating to the design of.Na0H supply piping.  :

however, the problem had existed since shortly after-  ;

construction and was appropriately addressed.  ;

Five plant modifications and several safety evaluations were ,

reviewed and were generally found to be thorough and l correct. The licensee's program for the control of containment coatings was reviewed and found to be .

satisfactory. Engineering involvement has been evident in each major plant challenge in the last six months.  ;

including:

e Apparent air-binding of the 2B LPSI pump i e 1A LPSI pump relief valve lift ,

o Unit 1 Pressurizer relief valve seat leakage  :

3 e Post-event reviews of loss of Unit 1 SDC e Unit 1 RWT leak repairs l Conclusion Engineering continues to perform well. No weaknesses have been identified in this functional area.

Plant Succort RAdj.ploaical Controls Previous assessments this SALP cycle indicated an effective program. Inspections this period indicate good control of

internal / external exposure and containment during outages.

ALARA initiatives were noted: robotics, submersibles, and telemetry. The licensee was noted to be ahead of most of the region in the use of cameras, video and wireless communications.

Emeroency Preoaredness The licerisee continues to maintain an effective EP program. l Security I

i -Security upgrades made prior to the last SALP were notable. The-licensee continues to maintain a very effective security program.

~

_J_. - . _ ,

1.

A

-)

- 18 i Fire Protection  ;

a The licensee continues to maintain an effective fire protection l program.

. l Housekeecina Housekeeping has been generally.very good.

PART 3 -

S'IGNIFICANT 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 '

l 3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months) .

Currently, there are no escalated enforcement actions pending at St.

Lucie.

PART 4 - STAFFING AND TRAIN-ING 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: (RC0, 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 j

• 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) .

[PL P Contractor Plant ersonnel (excluding 713- 122

' disci lines below)-

Training 63 0 Quality Assurance /ISEG/ SPEAK 0UT 49 0 x . .. . .. . - . . - . _

1 s

4 19 Materials Management 46 0 Security 11 122 Site Engineering 42 0

' _4 . 3 OPERATOR OUALIFICATION/RE0UALIFICATION PROGRAM (Past Two Years) 4.3.1 REQUALIFICATION PROGRAM NRC-administered requalification exams were completed in October.

1992. Results were good - 9 of 12 R0's passed and 12 of 12 SR0's passed. Three of the R0's failed the written exam and one also failed the JPMs. The program was rated satisfactory, i Requalification exams are currently in progress (10/94). To date.

20 of 24 SRO's and 17 of 20 R0's have passed all portions of the exams. Failures have included 5 written exams, 1 JPM. and 1 simulator failure. j 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 l upgrades and 2 R0s, and all passed. A hot license class of 15 i persons was started in late February, 1992 (14 still in class). l 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 j 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 l February 6, 1991. 3 of 3 operators who took the exam passed. On i June 6. 1991, one operator took the exam and passed. On February  !

10, 1993, all 12 operators who took the exam passed. One person j took the exam on February 9. 1994, and passed. No further Generic i 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 i

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 I

l

p .

S

.g

'20 i inspections in the form of operator . examinations at the simulator have i found no serious problems.

PART 5 INSPECTION ACTIV-ITIES 5:1' INSPECTION FOLLOWUP OPEN ITEMS

SUMMARY

'(UNITS 1 AND 2 COMBINED)  ;

(10/6/94)  !

Pre. Change from Division i .~ T_qtal Last Reoort 4

DRP 3 30 0

+

DRS- 0 7 -3

~

DRSS _H _2 0 l r

i Totals 3 39 -3 ,

Note: Each item that applies to both units is counted as one item.

'5 2

. MAJOR INSPECTIONS r I R- No .- QALq Tygg 89-02 1/89 RG-1.97 89-03 3/89 NDE  !

89-07 3/89 EO 89-09 3/89 Design Control ,

Maintenance Team Inspection 89-24 10/89 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)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 -INFRE0 VENT INSPECTION PROCEDURE STATUS No core modules are overdue at this time.

5.5 SIMS STATUS - OPEN TMI ITEMS

~There are_no cpen TMI items.

1

q' . l

. ATTACHMENT 3

?

NRR OPERATING REACTOR ASSESSMENT NRR ASSESSMENT FOR ST. LUCIE  ;

October:1994 CURRENT ISSUES

-Seismic USI A-46)issue = qualification on Unit'1of. is electrical and mechanical equipment' (GL 87-02 .The sta still not. resolved.

~1994 providing:a general framework of criteria which would resolve this issue. FPL ,

responded in May 1994 restating their previous position and stating.that they

> believe that further NRC requests for work, evaluations, or plant changes would

. provide no additional ~ safety benefit to their nuclear facilities. The staff is ,

.considering performing a backfit analysis to determine the possibility of ordering FPL to implement additional actions or accept the' licensees position. A third a alternative being evaluated is performance of a site inspection to determine if any s' ety-significant' issues exist in the areas of disagreement.  ;

a

-Unit =1 will be replacing steam generators in 1997. The licensee is well into l planning for the event. .j 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- y Lag issue.  !

)

-The plant continues to perform well. The latest SALP evaluation had ratings of 1 i in all categories.

l

Contact:

1 Jan A. Norris 504-1483 l

V- 6 +.: 9 -+iery  %  %'  % 9we*-