Text

Provides Info Requested by 960208 Memo from J Stolz Re Review of Spent Fuel Pool Practices & Current Licensing Basis
	ML20137R883
Person / Time
Site:	Saint Lucie
Issue date:	03/27/1997
From:	Norris J; NRC (Affiliation Not Assigned)
To:	James Shea; NRC (Affiliation Not Assigned)
Shared Package
ML20137Q937	List: IR 05000335/1995014; IR 05000335/1996022; ML20137Q928; ML20137Q944; ML20137Q952; ML20137Q999; ML20137R008; ML20137R041; ML20137R279; ML20137R538; ML20137R587; ML20137R823; ML20137R883; ML20137R903; ML20137R914; ML20137R927; ML20137R960; ML20137R967; ML20137R973; ML20138G413;
References
	FOIA-96-485 NUDOCS 9704140278
	Download: ML20137R883 (20)
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MEMORANDUM TO:

Joseph W. Shea, Project Manager Project Directorate I-2

= Division of Reactor Projects - I/II i

Office of Nuclear Reactor Regulation FROM:

Jan A. Norris, Sr. Project Manager Project Directorate 11-1 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation

SUBJECT:

ST. LUCIE UNITS 1 AND 2 - SPENT FUEL POOL SURVEY j

This memorandum provides the information requested by the February 8, 1996, memorandum from John Stolz regarding a review of the spent fuel pool practices and current licensing basis.

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Attachment:

St. Lucie SFP Survey

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Docket Nos.

50-335 and 50-389 9704140278 970327

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PEWt FOIA BINDER 96-485 PDR

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3 ST. LUCIE SPENT FUEL POOL SURVEY l

A.

Spent Fuel Pool (SFP) System Design UNIT 1 i

l' The system is composed of heat exchanger, filter, ion exchanger, pump suction strainer, ion exchanger strainer, pumps, piping and valves. The system has only one train of components. The cooling portion of the fuel pool system is a closed loop system consisting of two balf capacity j

pumps and one full capacity heat exchanger. For normal refueling discharge conditions, one fuel pool pump and the fuel pool heit i

exchanger are in service. During abnormal refueling conditions, such as full core discharge, two fuel pool pumps and the heat exchanger are in service. The system is manually controlled from a local control panel.

High fuel pool temperature, high and low fuel pool water level, and a 4

low fuel pool pump discharge pressure alarms are announciated in the i

control room. Makeup to the fuel pool comes from the refueling water i

tank. The heat exchanger is cooled by component cooling water.

The

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system is designed to provide a minimum of 9 feet of water above the top i

of the fuel during handling and storage operation.

l UNIT 2 The system is composed of heat exchangers, filter, ion exchanger, pump suction strainer, ion exchanger strainer, pum~ps, piping and valves. The system has only one train of components..The cooling portion of the fuel pool system is a closed loop system consisting of two half capacity pumps and two full capacity heat exchangers.

Full capacity condition corresponds to the design condition of a full core placed in the spent fuel pool seven days after reactor shutdown, in adtches, the most recent of which has been cooling for 90 days.

For normal refueling discharge conditions, one fuel pool pump and the fuel pool heat exchanger are in service. During abnormal refueling conditions, such as full cora discharge, two fuel pool pumps and the heat exchanger are in service.

The system is manually controlled from a local control panel. High fuel pool temperature, high and low fuel pool water level, and a low fuel pool pump discharge pressure alarms are announciated in the control room. Makeup to the fuel pool comes from the refueling water tank. The heat exchanger is cooled by component cooling water.

The system is designed to provide a minimum of 9 feet of water above the top of the i

fuel during handling and storage operation.

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I L T J ~h St. Lucie 1 B.

SUMMARY

OF CLB REQUIREMENTS RE: SPENT FUEL POOL DECAY HEAT l

REMOVAL / REFUELING O'FFLOAD PRACTICES 1.

Technical Specification limits are provided for:

TS 3.9.3: 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months minimum decay time.

TS 3.9.5: Direct communications between the control room and the refueling station during core alterations, s

TS 3.9.6: Manipulator crane shall be used to move fuel assemblies and be operable.

TS 3.9.7: Crane travel with heavy loads (> 2000 lbs.) over irradiated fuel is prohibited.

TS 3.9.11: Minimum water level 23 feet above the top of irradiated fuel in the SFP.

j TS 3.9.12: At least one fuel pool ventilation system shall be operable.

TS 3.9.13: Maximum load for the spent fuel cask r:rane shall not exceed 25 tons.

TS 3.9.14: Decay fuel assemblies for 1180 hours0.0137 days 0.328 hours 0.00195 weeks 4.4899e-4 months (1490 hours0.0172 days 0.414 hours 0.00246 weeks 5.66945e-4 months for >one-third core) prior to movement of the spent fuel cask into the fuel cask compartment.

2.

The fuel pool system is designed to provide shielding for irradiated fuel so that personnel dose rates do not exceed 2.5 mrem /hr; maintair, pool temperature below 150 *F under offload conditions; maintain purity and clarity of the SFP, refueling cavity, and refueling water tank water; and maintain water level 9 feet above the irradiated fuel during transfer operations.

3.

Design heat load for the normal batch discharge case assumes 18 batches of 80 assemblies discharge to the SFP in 18 month intervals, followed by a discharge of 80 assemblies after

.150 hours0.00174 days 0.0417 hours 2.480159e-4 weeks 5.7075e-5 months of decay. With a sing le pump and heat exchanger in operation, the system can maintain SFP temperature below 134 *F.

Time to-boil assuming cooling was completely lost at the maximum temperature is 13.43 hours4.976852e-4 days 0.0119 hours 7.109788e-5 weeks 1.63615e-5 months . A full capacity pump is available should j

the first pump fait. IFSAR Section 9.1.3.21 Normal discharge heatload is 16.42 x 10' i

Blu/hr. (Staff rerack safety evaluation dated 3/11/88) i Does the licensee consider the failure of the fuel pool heat exchanger credible. Having a I

single heat exchanger does not provide for single failure (this component is passive)

The FSAR describes the normal batch discharge case as a one third offload in March the licensee plans to effload a full core, is it and abnormal offload or do they "normally" off load a full core, if so, change the FSAR.

4.

Design heat load for the abnormal batch discharge case assumes 18 batches of 80 assemblies discharge to the SFP in 18 month intervals, followed by a discharge of 217 assemblies with 169 hour0.00196 days 0.0469 hours 2.794312e-4 weeks 6.43045e-5 months of decay. With both pumps and a single heat exchanger in operation, the system can maintain SFP temperature below 151 *F. Time-to-boil assuming cooling was completely lost at the maximum temperature is 5.04 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The capability to withstand a single failure criteria was not assumed (FSAR Section 9.1.3.21. The heat load for the abnormal case is 33.70 x 10' Btu /hr. [ Staff rerack safety evaluation dated 3/11/88) 1 The staff also accepted a single failure of the SFPCS pump with a full core in the SFP. The i

e-i maximum temperature reached 167 *F under these assumptions. [ Staff rarack safety evaluation dated 3/11/88)

- The licensee's FSAR does not describe this scenario (full core offload - single' failure). The licensee should be questioned whether a SFPCS single failure under full core offload heatload is part of their licensing basis.

5.

The storage capacity for Unit 1 SFP is 1706 fuel assemblies (7 2/3 cores).

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Boron concentration shall be maintained at a minimum of 1720 ppm.

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7.

The spent fuel poolis designed to withstand the steady state water temperatures of 217 'F.

8.

Makeup sources to the SFP are from: refueling water storage tank, city water storage tank, city water storage tanks via portable fire pump, and the primary water tank. A seis mic i

Category I source is available from the intake cooling water inter tie (salt) at 150 gpm [FSAR 9.1.3.4.51.

l Lining up seismic makeup using the refueling water tank is complicated. The PM should review the procedure to ensure it exists and that the licensee trains on it periodically.

9.

No other implicit or explicit prohibitions exist within the CLB against performing a full core j

offload for any given refueling outage.

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Discrepancies:

None. However, see comments in each section above.

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St. Lucie 2 B.

SUMMARY

OF CLB REQUIREMENTS RE: SPENT FUEL POOL DECAY HEAT j

REMOVAL / REFUELING O'FFLOAD PRACTICES 1.

. Technical Specification limits are provided for:

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1

. TS 3.9.3: 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months minimum decay time.

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TS 3.9.5: Direct communications between the control room and the refueling station during core alterations.

TS 3.9.6: Manipulator crane shall be used to move fuel assemblies and be operable, j

TS 3.9.7: Crane travel with heavy loads (> 1600 lbs.) over irradiated fuel is prohibited.

TS 3.9.11: Minimum water level 23 feet above the top of irradiated fuel in the SFP.

TS 3.9,13: Maximum load for the spent fuel cask crane shall not exceed 100 tons.

TS 3.9.14: Decay fuel assemblies for 1180 hours0.0137 days 0.328 hours 0.00195 weeks 4.4899e-4 months (1490 hours0.0172 days 0.414 hours 0.00246 weeks 5.66945e-4 months for >one third core) prior to movement of the spent fuel cask into the fuel cask compartment.

The PM should ask why there isn't a fuel building ventilation TS similar to Unit 1 TS 3.9.12, 2.

The fuel pool system is designed to provide shielding for irradiated fuel so that personnel j

dose rates do not exceed 2.5 mrem /hr; maintain pool tem erature below 150 'F under offload conditions; maintain purity and clarity of the SFP, refueling cavity, and refueling water tank water; and maintain water level 9 feet above the irradiated fuel during transfer operations.

3.

Design heat load for the normal batch discharge case assumes 11 batches of 80 assemblies discharge to the SFP in 18 month intervals, followed by a discharge of 80 assemblies after 120 hours0.00139 days 0.0333 hours 1.984127e-4 weeks 4.566e-5 months of decay. With a single pump and heat exchanger in operation, the system can maintain SFP temperature below 131 'F with a CCW temperature of 100 'F. Time-to-boil assuming cooling was completely lost at the maximum temperature is 12.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . A full capacity pump is available should the first pump fail. [FSAR Section 9.1.3.11 Normal r

discharge heatload is 16.42 x 10' Btu /hr.

1 4.

Design heat load for the full core discharge case assumes 11 batches of 80 assemblies discharge to the SFP in 18 month intervals (the most recent has decayed 90 days), followed by a discharge of 217 assemblies with 168 hours0.00194 days 0.0467 hours 2.777778e-4 weeks 6.3924e-5 months of decay. With both pumps and a single heat exchanger in operation, the system can maintain SFP temperature below 148 'F with a CCW temperature of 100 'F. Time-to-boil assuming cooling was completely lost at the maximum temperature is 3.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . The capability to withstand a single failure criteria was not assumed. The heat load for the abnormal case is 30.3 x 10' Btu /hr [FSAR Section 9.1.3.1). A single failure was analyzed for this heat load case. The maximum pool temperature under full core offload heatload was found to be less than 160 'F (FSAR 9.1.3.31 5.

. Piping and components in the SFPCS are Quality Group C, seismic Category 1, designed for a temperature of at least 200 'F. [FSAR Section 9.1.3.2.1, and Table 9.16.)

6.

Normal makeup sources to the SFP are from the refueling water storage tank and the primary water tank. Three million gallons of makeup are also available from the city water j

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.. i storage tanks, condensate storage tank, domineralized water tank, and others. A seismic i

Category I source is also' available through hoses from the intake cooling water header.

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[FSAR Section 9.1.3.3.11 7.

- No implicit or explicit prohibitions exist within the CLB against performing a full core offload for any given refueling outage.

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i Discrepancies:

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.. 1.f 4 a4 SPENT FUEL STORAGE DATA TABLE Fact 11ty Nesw t St. Luete Unit Number: Unit 1 i

t Licensee's SFP Contact Names M. P. Sharp Telephones (407) 694-3340'

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SFF Related Technical Parameters:.

Limiting Value or Conditions i

i Specifications i

Electrical Power Systems -

Specifies reqstred A.C. power during l

Shutdown (3.8.1.2) movement of irradiated fuel or crane j

operation with loads over the SFf Decay Time (3.9.3) k72 hours prior to fuel movement l

Crane Travel - Spent Fuel Storage Loads >2000 1he shall not be moved.

i Pool Building (3.9.7) over irradiated fuel assemblies in' the storage pool i

Storage Pool Water Level (3.9.11)

Maintain 223 feet water over fuel seated in the storage rocks Fuel Pool Ventilation System -

One fuel pool ventilation system Fuel Storage (3.9.12) operable whenever irradiated fuel is i

in the spent fuel pool Spent Fuel Cask Crane (3.9.13)

Maximum load handled by cask crane shall be s25 tons Decay Time - Storese Pool Irradiated fuel assemblies shall have

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(3.9.14) decayed 21130 hours or 21490 hours

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f prior to movement of ceak into cask l

compartment Fuel Storage Criticality (5.6.1.e Maintain k,e 50.95, describes nominal and S.6.1.b) storage pitch, pool baron 4

concentration >1720 ppm, boraflex i

installed th Region 1 and Region 2 l,

storage rocks; specifies fuel assembly enrichment / exposure limits for storese in Region 1 and Region 2 Fuel Storage Drainese (S.G.2)

Fuel pool can*not be drained below elevation 56 feet 4

F.uol Storage Capacity (5.6.3)

Storage capacity is s1706 fuel assemblies SFF Structure Location: Above grade in fuel Seismic Classification of SFP handling building (FHB). Fuel Structure and Bu11 dinar FRB & SFP j.

pool floor elevation is 21.S';

designed as a seismic Class I cask area floor alevation is structure (UFSAR 3.4.1.1.2); Spent 18.0' (8770-0-074 Rev. 10) fuel rocks designed to seismic Category I requirements (UFSAR 9.1.2.2.3)

Gross SFF Volume 47008 f t' (including cask storage area) to SFF Temperature for Stress Analysis 60' normal water level. Derived Normal Operating Thermal loads from drawings 8770-4965 Rev. 1&

analysed with 150' F water at well 4

3770-G-074 Rev. 10.

and 32' F external air temperature:

Accident conditions used bulk water

. temperature of 217' F with external air temperature of 40* F. Both 4

analyses assumed linear thrernal gradients. (PSL1 rerock license amendment, Safety Analysis Report, June 12, 1987, pages 4-9 & 4a10)

Leakage Collection Liner Type: Stainless Steel type Leakage Monitoring: Network of i

304: fuel pool floor 0.25" plate, stainless steel ongles attached to liner walle 0.188" piste, cask the outside of the pool liner walls pit floor 1.0" plate. (8770 4965 and the underside of the pool liner Rev 1 + FSAR page 9.1-4a) floor (8770-0-830 sh.2, Rev 2 & 8770-0-494 Rev S).

Drainage Prevention Location of Bottom Draics: None.

Elevation of Gate Botton Relative to (8770-G-830 sheet 4 Rev. 1 Stored Fuelt Gets bottom is at i

8770-G-830 sheet 1, Rev.

4, and elevation 36.2S' (8770-0-830 sh. 2).

i sheet 2. Revt 2)

This is above the top of fuel seated in the racks.

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a Page 2 of a Siphon Prevention Lowest Elevation of Connected Anti-Siphon Devices: Fuel pool return Piping Reistive to Fuel: Above line has 0.5" hole and purification top of fuel. Fuel pool cooling suction line hes 0.25" hole placed l' suction line penatrates pool below normal water level.

liner at elevation 56.0', return (8770-G-078, sheet 160, Rev. 9) line penetrates pool liner at elevation 59.25' (8770-G-830 sheet 1).

Fuel pool purification syst em piping penatrates fuel pool liner at an elevation of 56.0' and 59.0' (8770-G-830 sheet

2) Top of fuel assenely seated in storage rac.ks is -35.0'.

Make-up Capability Safety-Relat ed Source: Intak e seismic Classification and Quality cooling water.

Group: Intake cooling water makeup capability is Seismic Category I Normat Source: RWT or FWT group C.

(8770-G-082, sh. 1. Rev 43) depending on fuel pool boron concentration (OP 1-0350020 Rev.

21, page 11).

Reactivity Limits on k, and Enrichment: For Soluble Boron Crodit for Accidents:

both fuel pool regions k, 50.95 Yes, assembly misload (PSL1 rarack with the pool flooded with license unendment, Safety Analysis unborated water. Fresh fuel Report, June 12,1987, pages 3-2 & 5-limited to 56.5 w/c; Region 2 has 8).

additional restrictions based on T.S. Figure L 6 1 Reactivity Control Solid Neutron Poisons: Boreflex Number of Fuel Storage Zones: Two sheets placed between storage based on assembly burnup and initial cells in both Region 1 and 2.

enrichment.

Ehered or Split Spent Fuel No. of SFPs: One No. of SFPs Receiving Discharge from Pools a Single Unit: One; all Unit 1 fuel is in Unit 1 pool.

SFP Design Inventory Cases Normal: 1520 assembites (PLA Emergency / Abnormal: 1657 assemblies submittal to support PSL1 fuel (PLA submittal to support PSL1 pool serack, pages 3-28 & 3-31, rarack, pages 3-28 & 3 31, June 12, June 12, 1987).

1987)

SFP Design Heat Load Normal: 16.42E6; 13 3. 3* F with 1 Emergency / Abnormal: 33.71E6; 150.8' (MBTU/hr) and Temperature fuel pool cooling pump. (PLA F with 2 fuel pool cooling pumps;

(*T )

submittal to support PSL1 fuel 167' F with 1 pump in operation pool rarack, page 3-33, June 12, (Safety Eval. by NRR related to 1987)

License Amendment 91, March 11, 1988)

SFP Cooling System No. of Trains: 2 pumps in Licensed to Withstand Sin 61e Active parallel; I heat heat exchanger.

Component Teilure: Yes. See section 5.2.1, Heat Removs1 Cacab1111I, from No. of SFPs Served by Each Train:

SER issued by NRC office of NRR one (8770-G 078, sh. 140, Rev 9) related to Amendment 91 to Unit 1, dated March 11.1988.

Electrical Supply to STP Qualification and Independence of Load Shed Initiators: Undervoltage Coolir:s System Pumps Power Supply: SFP Cooling pump or overcurrent.

1A is a load on the essential portion of 480V meter control (8770-0-275 sheet 1 Rev. 12, & sheet conter 1A-8. SFP Cooling yump 18 8, Rev. 8) is a load on the essential section of motor control conter 18-8.

These MCC's are not class 1E.

(8770-0-275 sheet s, Rev. 8)

Seckup SFP Cooling System Name: None.

Qualificationi N/A.

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Fase 3 of 4 SFP Heat Exchanger Cooling System Names Component Coolins Qualification: Some portions of CCW Water (8770-0-Os3, sheet 1, Water important to SFP coolins are seismic Rev 42)

I safety class C; others are safety 1

class D.

j Secondary Coolins Water System Name: Intake Cooling Water Qualific ation: Setemic I safety l

Loop (8770-G*082, sheet 1, class C Rev, 43)

Ultimate Heat Sink (UHS)

Type: Atlantic Ocean / Bis Mud UHS Design Temperature:

95* F (UFSAR Creek

p. 9.2-2)

SFP Cooling System Heat Design Heat capacity (BTU /hr):

Type: tube and shell Exchanger Performance 32.0E6 (Bishest Capability Heat SFP Side Flow: 1.50E6 lbm/hr Cooling Water Flow: 1.78E6 lbm/hr Exchanger if not identical)

STP Temperature: 150' F Cooling Water Inlet Temp: 100* F (8770-2017 Rev. 2)

SFP Cooling Loop Return Temp:

Coolins Watir Outlet Temp: 118*

128.7* F STP Reisted Cor 41 Room Parameter (s): Fuel Fool Hish/ Low setpoint: 1 2" from nominal level, Alarme Level, Fuel Fool Aish 137.5* F,18 pois, pump trips,110* F, Temperature, Fuel Pool Pump

<13800 cim, 23600 spa or s2850 spa, Discharge Header Pressure-Low, as established by Chemistry Dept.

(ONOP 1*0030131, Rev. 62)

Fuel Fool Pumps Motor overload, i

Fuel Pool Room High Temperature, Fuel Fool Exh. HVE Low Flow /Hotor Overload, CCW Flow to Fuel Fool Heat Exchanger High/ Low, Noble Gas Radiation Alert.

Location of Indications SFP Level: None SFP Temperature: Local readout (8770-G-078, Sheet 140, Rev. 9) j STP Cooling System Parameter (s): None other than Independence: Independent electrical Automatic Pump Trips the electrical trips listed trips for each pump. (8770-0-275, above.

sheet 8. Rev 8)

SFP Boiling:

Staff Acceptance of non Seismic Off site Consequences of SFP Boilins SFP Cooling System Based on Evaluated: Yes.

(L-87-537, December Seismic Category I SFP 23, 1987, Attachment 6)

Ventilation Systemt Fuel pool cooling system and fuel pool If Yes, Was Filtration Credited: No, ventilation system are not seismic category I. (8770-0-879 Rev. 29 & 8770-G-125 Sh. FS-N 3)

STP/Reactar System Separation of SFP Operating Floor Separation of Units at N lti-Unit Separation from Portion of Aux, or Reactor Sites:

St. Lucie Units 1 & 2 have Bids. that contains Reactor separate fuel handling buildings and Safety Systems: SFP area

. ventilation systems.

completely enclosed, ventilation system directs air to THB stack Heavy Load Handlins SFP Area Crane Qua11tled to Routine Spent Fuel Assembly Transfer Sinsio Te11ure Proof Standard IAW to ISFSI or Alternate Wet Storage NUREG-0612 and/or NUREG-0554: No.

Location: No (FSAR Tables 9.1-6 and 9.6-1) m

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Pase 4 of 4 Operatins Practices Administrative Control Limit (s)

A&ainistrative Control Limits for SFP for SFP Temperature durins cooling System Redundancy and SFP Refuelinst None based on most Make-up System Redundancy: OF 1-recent Rev, to fuel shuffle 1600023, Rev, 58, pase 9, requires procedure.

Fuel Fool Cooling & Purification Sy* tem to be in normal operation Frequency of Full-Core off-loedst prior to beginning refuelins 550% of outeses evolution. This means that electric power required to be available to Type of Off-load Performed during both fuel pool cooling pumps (OP 1-most recent refuelinsi partial 0350020, Rev. 21, pase 2 & 3).

No core off-load (fuel shuffle) requirements for redundancy of makeup source.

Administrative Controla on Irradiated Fuel Decay Time prior to Transfer from Reactor Vessel to SFP: Yes. (OP 1-1600023, Rev. 58, page 20 of 50, Surviellances Perforand Durina Refuelina)

For Unite with planned refueling outases scheduled to begin before April 30, 1996, type of Off-load planned for next refueling and planned shutdown date: Full core; expected shutdown 4/29/96.

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SPENT FUEL STORAGE DATA TABLE i

Facility Name: St. Lucie Unit Number: Unit 2 Licensee's 5FP Contact Name: M. P. Sharp Telephone: (407) 696-3340 STP Related Technical Parameters:

Limiting Value or Condition:

Specifications A. C. Sources - Shutdown Speciftee required A.C. power during (3.8.1.2) movement of irrediated fuel or crane operation with loads over the fuel storage pool.

Decay Time (3.9.3)

Reactor subcritical 272 hours0.00315 days 0.0756 hours 4.497354e-4 weeks 1.03496e-4 months prior to fuel movement in RFY.

Crane Travel - Spent Fuel Storage Loade >1600 1he prohibited from Pool Building (3.9.7) travel over fuel assemblies in fuel storage pool.

Water Level - Spent Tuol Storage Maintain 123 feet water over top of Pool (3.9.11) irradiated fuel seated in storese rocks.

5 pent Fuel Cesk Crane (3.9.12)

Maximum load handled by cask crane shall be $100 tons.

Fuel Storese Criticality Maintain k, 50.95, specifies nominal (5.6.1.a) pitch of assemblies in storage rocks, requirse pool boron concentration 21720 ppm, defines Reston I and Reston Il enrichment /burnup requirements for storase.

Fuel Storese Drainsse (5.6.2)

SFP shall not be drained below elevation 56 feet.

Fuel Storage Capacity (5.6.3) 5FP shall contain s1076 assemblies, SFP Structure Location: Above grade in fuel Seismic Classification of SFP handlins buildins (FHB). Fuel Structure and Buildins: THB & SFP pool floor elevation is 21.50';

designed as setemic Class I structure cask area finor elevation la (UFSAR 3.8.4.1.3 & 2998-0-078 sheet 17.5'.

(2998-G-073 Rev. 16 &

140, Rev, 5).

Spent fuel racha 2998-0 074 Rev. 12) designed to seismic Catasory I requirements (UTSAR 9.1.2.1) l Gross SFP Volumei 52609 ft' (including cask storase area) to 5FP Temperature for Stress Analysis:

i 60' normal water level. (2998-3FP destaned for a water temperature j

6564 Rev. 3 & 2998-0-074 Rev.

of 212* F durins the winter. (UFSAR j

12)

p. 9.1 Sa)

Leakase Collectiot.

Liner Type 304 Stainless steel Leakage Monitoringt Network of j

(UFSAR p, 9.1 4); pool liner stainless steel angles attached to I

wetla 0.188" plate. pool floor the cutside of the pool liner walls liner 0.625" Cesk area floor and underside of the pool liner 4

piste 1.0",

cask area well piste floor, (2998-0-894 Rev. 9) 0.5" (2998-0-830 sheet 1, 1

2998 6951 Rev. 3, 2998-6952 l

Rev. 4

& 2998 6953 Rev. 3)

Drainase Prevention Location of Bottom Draine: None.

Elevation of Gate Bottom Relative to (2998 0-s30 sheet 1, Rev. 7)

Stored Fuel: Above top of stored fuel, Gate bottom elevation is 36.25' (2998 6951 Rev. 3).

Unit 2 fuel assemblies are 158.5" long.

Top of fuel seated in the storage rocke la elevation -35.2'.

(2998-18511 Rev. 0) i l

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l Page 2 of 4' Siphon Prevention Lowest Elevation'of Connected Anti-Siphon Devices: ' Fuel poo'1'.

Pipins Relative to Fuel. Above cooling return line hae 0.5" holo'

j top of fuel.< Fuel pool cooling '

pieced 1.0* below the normal pool auction line penetrates pool water level. Fuel pool purification liner et elevation $4.0' (2998-section line hoe a 0.25" siphon i

1-6953 Rev, 31; return line breaker hole placed 1.21' below the penetrates fuel pool liner at-normal pool water level. (2998-0-078

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' elevation 59.25' (2998 6952 Rev.

eheet 140, Rev. 5)

4) : Fuel pool purification.

system piping penetrates fuel pool liner at an elevation of

$6.0' and 59.0* (2998-6951 Rev, 3 & 2998-7415 Rev.2).

Top of fuel storage rocks is ~36.25'.

Make up Capability --

Safety Related Source: Intake Seismic Classification and Quality i

4 coolins water Group: Intake coolins water makeup

}

l capability is Beismic category I Normal Source: RWT or PWT group C.

(2998-0-082 sheet 2, Rev.~

4 depending on fuel pool baron 40)'

concentration. (OP 2-0350020 Rev. 17, page 10)

Reactivity Limits on k, and Enrichment: For Soluble Boron Credit for Accidents:

i both fuel pool regions k,50.95 Yes. (Safety Evaluation prepared by

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with the pool flooded with NRR for PSL2 rerack license 3

unborated water,t Fresh fuel amendment. Section 2.1.3)

I limited to 54.5 w/o; Region II has additional restrictione based

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l on T.S. Figure 5.6-1.

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Reactivity Control Solid Neutron Poisons:

No.

Muinber of Fuel Storage Zones Two Region I cells contain unpoisoned based on assembly burnup and initial SS L-shaped inserts. Racks use enrichment.

l flux trap design, Shared or Split Spent Fuel No. of SFPs: One No. of SFPs Receivins Discherse from i

Pools a Single Unit: One; all Unit 2 fuel is in Unit 2 pool.

SFP Design Inventory cases Normel: 964 assemblies (12 Eewrsoney/ Abnormal: 1113 assemblies refuelans batches) with the most comprisina 11 refuelins batches, each recent refuelins batch cooled for of which was dischersed following an 5 days; other batches dischersed 18 month fuel cycle and a full core-followins an 18 month fuel cycle, offlood of 217 assemblies which has (CE letter L-CE-10558, September cooled for 7 days. (L-CE-10558) 7, 1984) l STP Design Heat Load Normalt 16.9E6 BTU /hr: <13 7' F Emergency / Abnormal: 31.7E6 BTU /hr j

(MTU/hr) and Temperature with one pump in operation.

(150' F with both opent fuel pays

')

(*F ) (from Safety operating.

l Evaluation by Office of NRR

.i supporting rereck of the _

St. Lucie Unit 2 fuel pool, October 16, 1934) i s

+

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=

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m s-Pese 3 of 4 P

SFP Cooling System No, of Trains: 2 pumps and 2 heat Licensed to Withstand Single Active exchangers, Either pump can Component Failures Not explicitly sesve either heat exchanger, mentioned in rerack Safety Evaluation prepared by NRR to support fuel pool No. of SFPs Served by Each Train:

tereck, issued October 16,1984, one (2998-G-078 sheet 140, Rev.

FPL's rerack PLA submittel presented S) results of both norinal and abnormal core offloads assweins a sinslo failure. Earlier SE's (NUREG-0843,

p. 9-5) give 160* F as expected teep, i

followins a full core offlood with 1 fuel pool cooling pump in operation.

Electrical Supply to SFP Qualification and Independence of Load Shed Initiators: Undervoltase Cooling System Pumps Power Supply: STP Coolins pump 2A or t,vercurrent, is a load on the essential portion of as0V motor control (2998-G-275 sheet 39, Rev. 3, sheet conter 2A-8.

STP Cooling pump 2B 42, Rev.4 & 2998-0-275 sheet A, is a load on the essential Rev. S + 2998-G 274 Rev. 12 &

portion of motor control center 2998-0-274 sheet 2, Rev. 5) 28-8.

Fuel Pool cooling system is Class IE.

~

Backup SFP Cooling System Name: None, Qualification. N/A SFP Heat Exchanser Cooling System Name: Component Cooling Qualification: Seismic I safety Water Water class C (2998-G-083 Sh.1, Rev. 31)

Secondary Coolins Water System Name: Intake Cooling Water Qualification: Seismic I safety Loop class C (2998-0-082 Sh. 2. Rev. 40)

Ultimate Heat Sink (UHS)

Type: Atlantic Ocean / Big Hud UHS Design Temperature: 9 3* F Creek (UFSAR

p. 9.2*1a)

SFP Cooling System Heat Design Heat Capacity (BTU /hr):

Type: tube and shell j

Exchanser Performance 32.0E6 (Highest Capability Heat SFP Side Flow: 1.50E6 lbm/hr Cooling Water Flow: 1.78E6 lbm/hr l

Exchanser if not identical) l STP Temperature: 150* F Cooling Water Inlet Temp:

100* F (2998 15609, Rev.0)

SFP Coolins Loop Return Temp:

Coolins Water Outlet Temp: 118* F 128. 7* F 1

SFP Related Control Room Parameter (s): Fuel Pool Pump Setpoint: 18 pets, N/A, 23700 spa or Alatus Discharge Header Pressure Lo, 52850 spm, 110* F, 0.08" ws or 1130 Fuel Fool Pump overload, H1/Loscfm t136* F or 26" devsetton in CCW Flow to fuel Pool Heat pool water level frees nominal value (ONOP 2-0030131, Rev. S0)

Exchanger, Fuel Pool Room Temp.

(2 channels).

Hi, Fuel Pool Exhaust fans Lo Flow / Overload. Fuel Pool High/ Low Level or High Temp (2 annunc.

channels)

Location of Indications STP Level: Local scale SFP Tanperature: Local readout (2999-0-078 sheet 140, Rev. 5 and 299in-G-078 sheet 100)

)

SFP Cooling System Parameter (s): None other than Independence: Independent electrical Automatic Pump Trips the electrical trips listed trips for each pump. (2998-0-275

above, sheet 23, Rev 4, sheet 39, Rev. 3, and sheet 42.

Rev. 4) 1

's Page 4 of 4 STP Boiling:

Staff Acceptance of non-Seismic off-site Consequences of SFP Boiling STF Cooling System Based on Evaluated:

No.

Seismic Category I SFP-Ventilation system: Fuel Pool

Yes, Was Tiltration Credited

Cooling System is Seismic Category I. (299s-0-078 sheet 140 Rev. 5) Portions of tt-Tuol Fool Ventilation System esa Selenic Class I, safety clas-(2998-G-g73 Rev. 22 and 299L J-s79 sheet 3 Rev. 20)

STP/ Reactor Systen separation of SFP Operating Floor separation of Units at Multi-Unit Separation from Portion of Aux, or Reactor Sites:

St. Lucie Units 1 & 2 have Blds, that contains Reactor separate fuel handling buildings and Safety Systems: STP area ventilation systems, completely enclosed; ventilation system directs air to FEB stack.

l Beavy Load Handling SFP Area Crane Qualified to Routine spent Fuel Assembly Transfer

]

1 Single Failure Proof Standard IAW to ISTSI or Alternate Wet Storage NUREG-0612 and/or NUREG-0554:

Location: No I

No. (FLO-2998-751 and FSAR

]

section 9.1.4.3.2) j Operating Practices Administrative Control Limit (s)

Administrative Control Limits for SFP for SFP Temperature during Cooling System Redundancy and SFP Refueling: Yes, ensure fuel pool Make-up System Redundancy: OP 2-temperature 5150* F.

1600023 Rev. 39, pages 25 & 26 (OP 2-1600023 Rev. 39, page 26) requires that both fuel pool cooling pumps end related systems be availabl e. Makeup source from the

)

Frequency of Full-Core off-loads:

RWT to t)e fuel pool is also required 550% of outages to be available.

a Type of Off load Performed during most recent refueling: full aars offload Administrative Controls on Irradiated Fuel Decay Time prior to Transfer from Reactor Vessel to 5FP: Yes.

(Page 19 of OP 2-1600023 Rev. 39)

For Units with planned refueling outages scheduled to begin before April 30, 1996, type of Off-load planned for next refueling and planned shutdown date N/A; next Unit 2 refueling outage tentatively scheduled for 4/97, i

I'

.it 5 -n SPENT FUEL P0OL CURRENT LICENSING BASES REVIEW REPORT ST. LUCIE UNITS 1 AND 2 To verify that St. Lucie i and 2 comply with the current licensing bases (CLB) regarding the spent fuel pool (SFP), the Project Manager conducted an audit on March 26 and 27, 1996. The results of the audit.are presented below.

St. Lucie 1

SUMMARY

OF CLB REQUIREMENTS RE: SPENT FUEL POOL DECAY HEAT REMOVAL / REFUELING OFFLOAD PRACTICES AND VERIFICATIONS 1.

Technical Specification limits are provided for:

TS 3.9.3: 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months minimum decay time.

Verification:

Incorporated in operating procedure OP 1-1600023, Rev.

58, page 20 of 50, Step 2E TS 3.9.5: Direct communications between the control room and the refueling station during core alterations.

Verification:

Incorporated in GP 1-1600023, Rev. 58, page 20 of 50, Step 2D TS 3.9.6: Manipulator crane shall be used to move fuel assemblies and be operable.

Verification: This requirement is for the pr~ essure vessel, not for the SFP.

TS 3.9.7: Crane travel with heavy loads (>2000 lbs.) over irradiated fuel is prohibited.

Verification:

Incorporated in OP 2-1600023, Rev. 58, page 15 of 50 TS 3.9.ll:. Minimum water level 23 feet above the top of irradiated fuel in the SFP.

Verification:

Incorporated in OP 2-1600023, Rev. 58, page 20 of 50, Step 2C TS 3.9.12: At least one fuel pool ventilation system shall be operable.

Verification:

Incorporated in OP l-0350030, Rev. 8, page 8 of 12, Step 7.2.5C TS 3.9.13: Maximum load for the spent fuel cask crane shall ad exceed 25 tons.

Verification: No procedure, however, St. Lucie has never used the crane.'

TS 3.9.14: Decay fuel assemblies for 1180 hours0.0137 days 0.328 hours 0.00195 weeks 4.4899e-4 months (1490 hours0.0172 days 0.414 hours 0.00246 weeks 5.66945e-4 months for >one-third core) prior to movement of the spent fuel cask into the fuel cask compartment.

Verification: This requirement relates to the cask operation.

2.

The fuel pool system is designed to provide shielding for irradiated fuel so that personnel dose rates do not exceed 2.5 mrem /hr; maintain pool temperature below 150 'F under offload conditions; maintain purity

and clarity of the SFP, refueling cavity, and refueling water. tank water; and maintain water level 9 feet above the irradiated fuel during transfer operations.

Verification:

-The 2.5 mrem /hr is assured by maintaining water level a minimum of 9 feet above the irradiated fuel -

-Maintaining temperature below 150 degrees F - the licensee committed to have a procedure in place before the outage to read like the Unit 2 procedure. The relevant Unit 2 procedure is OP 2-1600023, Rev. 58, page 26 of 69.

-Maintaining purity and clarity of the SFP follows the Scheduling Procedure C-01, Rev 42, page 7 of 9.

Also the Performance Procedure C-61, Rev 7,. page 1 - 4 of 4.

-Minimum cover of 9 feet is assured by physical configuration and sizes of equipment. The actual minimum cover is 9'- 8".

Project Manager verified this by examining the actual equipment and the design drawings.

3.

Design heat load for the normal batch discharge case assumes 18 batches of 80 assemblies discharge to the SFP in 18 month intervals, followed by a discharge of 80 assemblies after 150 hours0.00174 days 0.0417 hours 2.480159e-4 weeks 5.7075e-5 months of decay. With a single pump and heat exchanger in operation, the system'can maintain SFP temperature below 134 'F.

Time-to-boil assuming cooling was completely lost at the maximum temperature is 13.43 hours4.976852e-4 days 0.0119 hours 7.109788e-5 weeks 1.63615e-5 months .

A full capacity pump is dischargeheatloadis16.42x10[ ail.

[FSAR Section 9.1.3.2] Normal available should the first pump Btu /hr.

[ Staff rerack safety evaluation dated 3/11/88]

J Verification:

the licensee could not produce a copy of the original calculations, but committed to perform a new set of calculations.

i Does the licensee consider the failure of the fuel pool heat exchanger credible.

Having a single heat exchanger does not provide for single failure (this component is passive).

Verification: The licensee does not consider the failure of the heat l

exchanger credible.

Some years ago, the heat exchanger was taken out of i

service for maintenace. During that time the licensee installed and operated a temporary heat exchanger.

The FSAR describes the normal batch discharge case as a one-third i

offload.

In March the licensee plans to offload a full core.

Is it and i

abnormal offload or do they "normally" off load a full core.

If so, change the FSAR.

Verification: Normal offload is 1/3 core. During the upcoming outage l

(starting on 4/29/96) Unit 1 will off-load full core to perform reactor vessel weld examination.

4.

Design heat load for the abnormal batch discharge case assumes 18 batches of 80 assemblies discharge to the SFP in 18 month intervals, followed by a discharge of 217 assemblies with 169 hour0.00196 days 0.0469 hours 2.794312e-4 weeks 6.43045e-5 months of decay. With both pumps and a single heat exchanger in operation, the system can maintain SFP temperature below 151 *F.

Time-to-boil assuming cooling u

e i

was completely lost at the maximum temperature is 5.04 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The capabilitytowithstanda'singlefailurecriteriawasnotassumed[FjAR i

Section 9.1.3.2).

The heat load for the abnormal case is 33.70 x 10.

Btu /hr.. LStaff rerack safety evaluation dated 3/11/88]

j

'Verificatnon: The Project Manager reviewed the calculations in support 1

of the above temperatures.

i

'The staff also accepted a single failure of the SFPCS pump with a full core in the SFP. The maximum temperature reached 167 'F under these assumptions. [ Staff rerack safety evaluation dated 3/11/88) 1 The licensee's 'FSAR does not describe this scenario (full core offload -

single failure). The licensee should be-questioned whether a SFPCS single failure under full core offload heatload is part of their 4

licensing basis.

Verification: The scenario.is described in the SER for Amendment #91

)

.(rerack amendment), Section 5.2.1, Heat Removal Capability.

5.

The storage capacity for Unit 1 SFP is 1706 fuel assemblies (7 2/3 o

cores),

i Verification: At the time of the audit, Unit I had 964 assemblies in the SFP.

Unit I will reach 1700 assemblies in the year 2006.

6.

Boron concentration shall be maintained at a minimum of 1720 ppm.

i Verification: The licensee could not produce a procedure assuring thats 4

1 figure, but committed to have one in place prior to the upcoming outage.

1 7.

The spent fuel pool is designed to withstand the steady state water 1

temperatures of 217 'F.

Verification: The Licensee produced a set of calculations showing 5%

safety margin for the most limiting condition using 217 degrees F.

8.

Makeup sources to the SFP are from: refueling water storage tank, city water storage tank, city water storage tanks via portable fire pump, and the primary water tank. A seismic Category I source is available from i

the intake cooling water inter-tie (salt) at 150 gpm [FSAR 9.1.3.4.5].

Verification: Refueling Water Tank is used when boron concentration is less than 2100 ppm.

Primary Water Tank is used when boron concentration is greater than 2100 ppm. OP 1-0350020, Rev. 21, page 11 of 25, steps 8.5.1 and 8.5.2.

Lining up seismic makeup using the refueling water tank is complicated.

The PM should review the procedure to ensure it exists and that the licensee trains on it periodically.

Verification: Seismic makeup to SFP is from ICW not RWT.

Lining up is not complicated and is included in the licensee training. Off-Normal Operating Procedure ONOP 1-0350030, Rev. 8, page 8 of 12.

9.

No other' implicit or explicit prohibitions exist within the CLB against performing a full core offload for any given refueling outage.

Verification: That is a correct statement.

Discrepancies:

i

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- l

.However,-'see comments in'each'section above. -

i 4

.None.

' Verification:l:A11tcomments have been addressed.

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' St. Lucie 2

- B. ~

SUMMARY

OF CLB REQUIREMENTS RE: SPENT FUEL POOL DECAY HEAT REMOVAL / REFUELING OFFLOAD PRACTICES AND VERIFICATIONS 1.

Technical Specification limits are provided for:

I TS 3.9.3: 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months minimum decay time.

Verification: OP 21600023, page 19 of 69 q

TS 3.9.5: Direct communications between the control room and the refueling station during j

core alterations.

Verification: OP 21600023, page 19 of 69 TS 3.9.6: Manipulator crane shall be used to move fuel assemblies and be operable.

Verification: This TS pertains to the pressure vessel, not SFP,

' TS 3.9.7: Crane travel with heavy loads (> 1600 lbs.) over irradiated fuel is prohibited.

Verification: OP 21600023, page 15 of 69 TS 3.9.11: Minimum water level 23 feet above the top of irradiated fuelin the SFP. Verifica tion:

OP 2-16000 23, page 18 of

'69 TS 3.9.13: Maximum load for the spent fuel cask crane shall not exceed 100 tons.

Verifcation: No procedure. FPL is not using the crane.

TS 3.9.14: Decay fuel assemblies for 1180 hours0.0137 days 0.328 hours 0.00195 weeks 4.4899e-4 months (1490 hours0.0172 days 0.414 hours 0.00246 weeks 5.66945e-4 months for >one-third core) prior to movement of the spent fuel cask into the fuel cask compartment.

Verification: Unit 2 does not have TS 3.9.14. This is Unit 1 TS.

The PM should ask why there isn't a fuel building ventilation TS similar to Unit 1 TS 3.9.12.

Verification: They do have it under Shield Building Ventilation System, TS 3/4 6.6.1: two independent trains. OP 21600023, page 26 of 69 2.

The fuel pool system is designed to provide shielding for irradiated fuel so that personnel j

dose rates do not exceed 2.5 mrem /hr: maintain pool temperature below 150 'F under offload conditions: maintain purity and clarity of the SFP, refueling cavity, and refueling water tank water; and maintain water level 9 feet above the irradiated fuel during transfer operations.

Verification:

4 i

-The 2.5 mrom/hr is assured by maintaining water level a minimum of 9 feet above the Irradiated fuel i

1

-Maintaining temperature below 150 degrees F the licensee committed to have a procedure in place before the outage to read like the Unit 2 procedure. The relevant Unit 2 procedure is OP 21600023. Rev. 58, page 26 of 69.

1 Maintaining purity and clarity of the SFP follows the Scheduling Procedure C-01, Rev 42,

~

i (e

c i-i j

page 7 of'9 ' Also the Performance Procedure C 61, Rev 7, page 1 4 of 4.

I

. iMinimum cover of 9 feet is assured tiy physical configuration and stres of equipment.

' The actual minimum cover is 9'. 8". Project Manager verified this by examining the actual equipment and the design drawings.

[

L 3.

Design heat load for the normal batch discharge case assumes 11 batches of 80 assemblies discharge to the SFP in 18 month intervals, followed by a discharge of 80 assemblies after j

120 hours0.00139 days 0.0333 hours 1.984127e-4 weeks 4.566e-5 months of decay. ' With a single pump and heat exchanger in operation, the system can maintain SFP temperature below 1310F with a CCW temperature of 100 *F. Time to-boil assuming cooling was completely lost at the maximum temperature is 12.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . A full i

capacity pump is available should the first pump fail. [FSAR Section 9.1.3.11 Normal i~

discharge heatload is 16.42 x 10' Btu /hr.

i Verification: Project Manager reviewed the calculations and confirmed the design figures.

l l

1 l

' 4.

Design heat load for the full core discharge case assumes 11 batches of 80 assemblies i

discharge to the SFP in 18 month intervals (the most recent has decayed 90 days), followed by a discharge of 217 assemblies with 168 hours0.00194 days 0.0467 hours 2.777778e-4 weeks 6.3924e-5 months of decay. With both pumps and a single -

heat exchanger in operation, the system can maintain SFP temperature below 148 'F with a CCW temperature of 100 #F. Time to-boil assuming cooling was completely lost at the maximum temperature is 3.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months . The capability to withstand a single failure criteria was i

not assumed. The heat load for the abnormal case is 30.3 x 10' Btu /hr [FSAR Section 9.1.3.11. A single failure was analyzed for this heat load case. The maximum pool 4

temperature under full core offload heatload was found to be less than 160 'F [FSAR j

9.1.3.31..

Project Manager reviewed the calculations and confirmed the design figures.

i Verification: ~

[

5.

Piping and components in the SFPCS are Quality Group C, seismic Category 1, designed for

[

a temperature of at least 200 *F. [FSAR Section 9.1.3.2.1, and Table 9.1-6.]

Verification: Project Manager reviewed the calculations and confirmed the design figures.

6.

Normal makeup sources to the SFP are from the refueling water storage tank and the F

primary water tank. Three million gallons of makeup are also available from the city water storage tanks, condensate storage tank, domineralized water tank, and others.' A seismic Category I source is also available through hoses from the intake cooling water header.

[FSAR Section 9.1.3.3.11 Verification: Refueling Water Tank is used when boron concentration is less than 2100 ppm. Primary Water Tenk is used when boron concentration is greater than 2100 ppm. OP

!l 2-0360020, Rev 17, page 10 of 19, steps 8.4.1 and 8.4.2. Also Drawing 2998-G-082, Rev. 40, Sheet 2 f,

7, No implicit or explicit prohibitions exist within the CLB against performing a full core offload j

for any given refueling outage.

- Verification: That is a correct statement.

Discrepancies:

' None.

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i.j REGION II-1

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ATLANTA,. GEORGIA i

PLANT STATUS REPORT 5

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_UC. _:

8 1

Units 1 and 2 l

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February, 1996 q

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. PLANT STATUS REPORT FOR ST. LUCIE TABLE OF CONTENTS 1

/PARTc1' FACILITY DESCRIPTION:

1.1 FACILITY / LICENSEE.....................................Page 2

l 1.2 ; UTILITY SENIOR MANAGEMENT

...........................Page 2

1.3 NRC STAFF....................,...'..:.................;Page 21 31.4-LICENSE INFORMATION................................ 4Page 3-

. i

'1.5- -PLANT CHARACTERISTICS;................................Page'3 1

1.6.

SIGNIFICANT DESIGN INFORMATION......................Page 3; i

1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS...........Page 8-

1. 8 - PRESENT OPERATIONAL STATUS (Past Six Months).........Page 9~

'1.9 OUTAGE SCHEDULE AND STATUS.............:...........-...Page 10:

i PART.2 PLANT-PERSPECTIVE:

l t

>2 1-GENERAL PLANT PERSPECTIVE...............

............Page 11

. i 2.2' : SALP HISTORY '(Past Two SALP Periods).................Page 11 2.3 SELECTED SALP AREA DISCUSSIONS

......................Page 11

'PART 3 SIGNIFICANT EVENTS

.3.1

.SIGNIFICANT EVENTS BRIEFINGS'(Past 12 Months)........Page 16-3.2 ENFORCEMENT STATUS / HISTORY (Past 12 Months)...,.,....Page 16 PART 4 V STAFFING AND TRAINING 4.1 OPERATIONS STAFF - 0VER h...........................Page 16 4.2.

WORK FORCE

...........................................Page.17 4.3 -OPERATOR QUALIFICATION /REQUALIFICATION PROGRAM.......Page 17 1

4.4 PLANT SIMULATOR............................

..........Page 17-4.5 INPO ACCREDITATION...........................'........Page 17 PART 5

. INSPECTION ACTIVITIES' 1

C 5.1 OUTSTANDING ITEMS L 3T-

SUMMARY

.......................Page 18 5.2 MAJOR I NSDECT I 0NS.................................... Pa ge 18 j

5.3 PLANNED TEAM INSPECTIONS...............

.............Page 18 l

i 5.4. INFREQUENT INSPECTION PROCEDURE STATUS...............Page 18 1

5.5 SIMS-STATUS (OPEN TMI ITEMS).........................Page 18 ATTACHMENTS--

9

~

L1)

PERFORMANCE INDICATORS i

2. ' ALLEGATION STATUS-3,

.NRR OPERATING REACTOR ASSESSMENT:

.4 ORGANIZATION CHARTS 5.

POWER HISTORY CURVES 6.

MASTER INSPECTION PLAN (NOT INCLUDED)-

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SITE ACTIVITY SCHEDULE ~

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~ SITE INTEGRATION-MATRIX L

9.

PERFORMANCE' ANALYSIS GRAPH.

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2 PART 1-FACIL-ITY DESCRIPTION 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) 1.2 UTILITY SENIOR MANAGEMENT CORPORATE:

J. L. Broadhead (Jim). Chairman of the Board and CEO J. H. Goldberg (Jerry). President. Nuclear Division SITE:

W. H. Bohlke (Bill) - St. Lucie Plant Interim Vice President C. L. Burton (Chris) - Services Manager L. W. Bladow (Wes) - Nuclear Assurance Manager R. E. Dawson (Bob) - Business Manager D. J. Denver (Dan) - Site Engineering Manager A.

DeSoiza (Andy) - Human Resources Manager P. L. Fincher (Pat) - Training Manager T. G. Kreinberg (Tom) - Nuclear Materials Management Superintendent J.

Marchese (Joe) - Maintenance Manager C. A. Pell (Ash) - Outage Manager L. A. Rogers (Lee) - Systems and Com3onent Engineering Manager J.

Scarola (Jim) - Plant General ianager E. J. Weinkam III (Ed) - Licensing Manager J. A. West (Jeff) - Operations Manager 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 E. W. Merschoff (Ellis). Director DRP. (404) 331-5623 K. D. Landis (Kerry). Branch Chief. (404) 331-5509 L. S. Mellen (Larry). Project Engineer. (404) 331-5561 E. Lea (Edwin). Project Engineer. (404) 331-3641 SITE:

M. S. Miller (Mark). Senior Resident Inspector. (407) 464-7822 S. S. Sandin (Steve). Acting Resident Inspector. (407) 464-7822 i

~.

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.NRR:

-l

1 D. B. Matthews, Director. Project Directorate 11-2',

(301) 415-1490 i

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

't AE00:.

S.'. Israel (Sandy) Reactor Operations Analysis Branch, (301) 415-7573

'1.4 LICENSE INFORMATION-i Unit 1 Unit 2 l

Docket Nos.

50-335 50-389 i

License Nos.

OPR-67 NPF-16 R

Construction Permit Nos.

CPPR-74 CPPR-144 Construction Permit Issued 7/1/70 5/2/77.

Low Power License NA 4/83 Full Power License 3/1/76 6/10/83 Initial Criticality 4/22/76 6/2/83 List Online 5/17/76 6/13/83 Conrnercial Operation 12/21/76 8/8/83 1.5-PLANT CHARACTERISTICS

' Descriotion Units 1 and 2 Reactor Type.

Combustion Engineering PWR, 2-loop Containment Type Freestanding Steel w/ Shield Building Power Level 830 MWe (2700 MWt)

Architect / Engineer-Ebasco NSSS Vendor Combustion Engineering 1

' 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) j

.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 T

and management policy have been modified to make that RPV life j~i span possible. Presently, a program is evolving for RPV life extension beyond the projected 40 years, potentially to 60 years, 1

via a~ flux' reduction program. A flux reduction program has started'with the addition of eight? absorbers in core corner p

Ya i

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i 4

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.

'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.

1 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 sr!.np suctions are isolated from the containment sump by one closed M0V in i

conjunction with a closed seismic piping system. The CS headers

'I 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 auWric actuation isolation valves.

-1.6.2 REACTOR SHUTDOWN i

Reactor Protection System The reactor protection system provides protection for the reactor fuel and its cladding by providing automatic reactor shutdowns based on input from reactor power. reactor coolant pressure, coolant temperature, coolant flow, steam generator pressure.

containment pressure, turbine hydraulic fluid pressure, and, in Unit 2 only. Component Cooling Water flow to reactor coolant pumps. The RPS is a redundant, four channel system that operates on a two-out-of-four logic.

ATVS 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.

reccmmendations.

Eggle Shutdown Facilities These facilities are located in the switchgear rooms beneath each unit's control room.

l 1.6.3 CORE COOLING' q

Feedwater System 1

C, 5

The main feedwater pumps are motor driven with each delivering 50 percent of the flow required for. full power.

Turbine Bvoass/ 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 1

Unit 2 has two valves per train.

Each unit has the capability of dumping nine percent steam flow to the atmosphere.

Auxiliary Feedwater System There are two motor-driven pumps on each unit with 100 percent capacity per pump. There is one steam-driven pump on each unit with 200 percent capacity. Any of the three pumps can inject to either 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 Coolino 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.

Hydrocen Control-

i 6

i Post-LOCA containment hydrogen control 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, f

1.6.5 ELECTRICAL POWER Offsi te_A,.[

J 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 y

miles West of the )lant site. There are two independent offsite i

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 (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, following a cell l

replacement. they have been tested for three-hour battery capacity instead. The battery capacity test is harsher than the load profile test and is intended to more accurately reflect expected i

usage. 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.

L Instrumentation Powar Each unit _ has four inverters, two powered from each vital DC train, that provide four trains of instrumentation power.

Station Blackout Resolution Status Unit 2Lis 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).

l t,

N 7

i 1.6.6 SAFETY-RELATED COOLING WATER S' STEMS Y

Intake Coolina Water (Service Water)

Intake cooling water (ICW) for each unit originates in the unit-common Intake Canal. The canal level varies with the tides since it is filled by a level difference between the Atlantic Ocean and

{

the ICW pumps. One 16-foot and two 12-foot diameter pipes pass under the beach to connect the ocean and canal. The 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 entra) ment. After use. ICW j

returns to the ocean through the Disc 1arge Canal and under-beach

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pipes.

Each unit has two trains of ICW plus a swing pump that can be.

l aligned to either train electrically and physically.

The licensee has converted the dee) draft ICW pumps from externally (water) lubricated to self-luaricated to increase reliability. The 100 percent (each) capacity pumps take suction from the intake canal via a canal intake structure using traveling screen debris protectio 1.

The intake canal structures adjacent to the ICW pump suctions are continuously injected with a hypochlorite solution to i

reduce marine growth in the associated piping and heat exchangers.

The ICW pumps move water through two trains of heat exchangers that cool component cooling water (CCW) and two trains of heat exchangers that cool main turbine cooling water.

During a

)ostulated accident, water flow isolates from the turbine cooling 1 eat exchangers. The discharge from the heat exchangers returns via the discharge canal to the ocean.

Closed Coolina Water Systems j

Each unit has two trains of Component Cooling Water (CCW). The f

arrangement of two aumps and a swing pump mimics the ICW system.

The swing pump can 3e aligned to either train. The 100 percent (each) capacity aumps 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 i

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).

i

8' l

1.6.8 INSTRUMENT AIR SYSTEM Instrument air compressors and driers on each unit provide all instrument air' for Unit-2 and all but containment air for Unit 1.

' Unit I hasLinstrument 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 1998. - The SGs are under construction at i

the B&W Canada shops and a site organization is functioning.

l 1.7-EMERGENCY RESPONSE FACILITIES / PREPAREDNESS Emergency Operations Facility:

10 miles West of site, 3

I-95/ Midway Rd. Exit Technical Support Center:

Onsite. Adjacent to Unit 1 Control Room j

Operational. Support Center:

Onsite. 2nd floor of North Service Building

]

The last annual emergency preparedness exercise was in February.1996.

This exercise was formally evaluated by the NRC.

Since St. Lucie site has a high probability of hurricanes.

1 communications facilities were improved following the Turkey Point experience with Hurricane Andrew in August,1992.

Improvements include:

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.

1 Cellular phones with hardened antennas, j

Hardened Local Government Radio antenna ties.

1 1.8 PRESENT OPERATIONAL STATUS

)

Availability Factors:

Unit 1 Unit 2 1991' 81.0 100.0

.1992-96.5 75.2 1993 74.0 71.8 1994 86.8 79.6 4

1995.(through 7/95) 93.9 98.3

' Cumulative (through 7/95) 77.7 83.7 i

4. '

l 9-i 1.8.1 UNIT 1 OPERATING HISTORY (Past Twelve Months from 1/25/96) l I

Unit 1 operated continuously during the past 12 months with the following exceptions:

3 On February 21. 1995, the unit was removed from service for the replacement of pressurizer code safety valves which had been l

leaking by the seat since shortly after startup in November. 1994.

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

j however. the licensee determined that he was responsible. He resigned from the company. The unit was returned to service on March 8. 1994.

On July B.1995. the unit tripped during turbine valve surveillance testing.

It returned to power on July 12, 1995.

]

On August 1. 1995, the unit was shutdown as a result of Hurricane Erin. Due to a series of equipment problems and personnel aerformance issues, the unit remained shut down for 73 days.

3roblems encountered during the shutdown included a maintenance-induced RCP seal failure, discovery of two inoperable PORVs due to maintenance errors during refurbishment, a loss of inventory event j

while pl?cing shutdown cooling in service due to lack of margin to relief valve lift setpoint and complicated by an excessive blowdown value, inadvertant saraydown of the Unit 1 containment.

catastrophic failure of the 13 EDG, and leaking pressurizure code i

safety valve flange leakage. The unit returned to power on 1

October 12.

{

l On November 16. the unit was manually tripped when a feedwater 1

regulating valve failed to the 50% position, resulting in low I

steam generator water level. The root cause of the failure was i

determined to be a faulty power supply. The power sup]ly was 1

replaced and the unit was returned to service on Novem)er 18.

i 1

On January 22, 1996, operator error resulted in an excessive dilution event which resulted in reactor power accending to 100.2%. -The operator in question apparently left the control room while dilution was in progress without informing other watchstanders of the evolution in progress. The operator was removed from licensed duties and tie final disposition of the j

event is pending.

1.8.2 UNIT 2 OPERATING HISTORY (Past Twelve Months from 1/25/96)

Unit 2 operated continuously during the past 12 months with the following exceptions:

1

.I

4 10 On February 21, 1995, the unit tripped as a result of low steam generator water level. The condition was the result of a feedwater regulating valve closure after a steam generator water level control level transmitter failed high. The transmitter was replaced and the unit was returned to service on February 25, 1995.

On April 25, 1995, the unit was shutdown for approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to replace a main turbine DEH power supply.

On August 1.1995, the unit was shutdown as a result of Hurricane Erin.

It was restarted on August 4. 1995, but operated at reduced

)ower from August 17 through 29. 1995, to clean condenser water aoxes and repair equipment problems.

On October 9. the unit entered a refueling outage. The outage was complicated by the discovery of leaks in RCS flow transmitter taps at the loops, a reactor flange 0-ring leak discovered during repressurization, and the failure of one stage of an RCP seal package.

The unit returned to power on January 1. 1996.

The unit was manually tripped from approximately 35% power on January 5 due to high generator hydrogen temperature.

The root cause of the event was improper o)eration of a turbine cooling water temperature control valve w11ch supplied cooling water to the hydrogen coolers. Post-trip review resulted in the discovery of clogged steam generator water level transmitter sensing lines which resulted in artificially low levels being indicated when steam generators were isolated upon turbine trip. The lines were blown down and the unit was returned to service on January 7.

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 instances of reduced inventory / mid-loo) operations: replacement i

of ICW/CCW LOOP logic [HFA latching relays) wit1 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:

replacement of a main transformer; modification of containment spray NaOH addition piping; and mechanical, electrical, and I&C systems maintenance.

The next Unit I refueling outage is scheduled for April

29. 1996.

Unit 2's last refueling. outage began on October 9. 1995 and ended January 1. 1996. Major outage activities included:

refueling: steam generator tube inspection and plugging: low pressure turbine blade replacement: emergency diesel generator inspection: replacement of three

11 reactor coolant pump mechanical seals; and mechanical, electrical, and I&C systems maintenance. The next Unit 2 refueling outage is scheduled for April 15. 1997.

PLANT PERSPECTIVE PART 2

2.1 GENERAL PLANT PERSPECTIVE A SALP board meeting was conducted on January 18. 1996, covering the SALP period of January 2.1994, through January 6.1996.

The facility was rated category 1 in the areas of Plant Support and Engineering and 2 in the areas of Operations and Mainenance and Surveillance. The latter 4

scores were a decline from the previous SALP cycle, when the facility was rated category 1 in all areas.

2.2 SALP HISTORY (Past 2 SALP Periods)

The last SALP period. SALP Cycle 11. ended on January 6. 1996.

The current SALP period ends (tentatively) in June.1997.

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 5/2/92 PLANT OPS MAINTENANCE ENGINEERING PLANT SUPPORT 5/3/93 -

1 1

1/1/94 1/2/94 -

2 2

1 1

1/6/96 2.3 SELECTED SALP AREA DISCUSSION Since July 1995, there has been a series of events that led to questioning the plants overall performance. These have included:

A Unit 1 turbine trip due to procedural weakness, operator performance and supervisory oversight.

e The attempt to restage an RCP seal using inadequate and inappropriate procedural guidance. The evolution was compounded by failing to follow as)ects of the guidence that did exist, which led to the failure of tie second and third stage seals.

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A main steam isolation signal due to an operator failing to block'-

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the MSIS signal during a cooldown when an annunciator indicated.

J that the block was enabled..This' failure occurred dispite the fact that that'the operator's attention was directed to the-1 annunciator on at least two different occassions.

' e' Both pressurizer power operated relief valves being.found inoperable due to incorrect assembly during a refueling outage.

The conditions had existed for approximately 10 months.

l

An loss of RCS inventory due to a shutdown cooling relie'f valve.

e

= which lifted and then failed to reseat due to incorrect setpoint margins (a generic problem involving several valves). The licensee had sufficient evidence that this generic condition existed, but had failed to act promptly to evaluate the conditions.

?

The spraydown of containment due to an inadequate procedure and' e

operator error coupled with an existing operator-work-around.

j

.1 These and several'other recent deficiencies involving weak

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. general ~ 1ack of procedural compliance, equipment failures, procedures,{

and personnel errors clearly indicated that the plant's past high level of performance had declined.

j 1

These and other problems led to several plant management changes, an overall evaluation of the recent plant problems by a plant-requested independent assessment team, and a root cause evaluation by the NRC.

In a meeting with the NRC on August 29, 1995, the licensee committed to use the results of the independent assessment team to develop an action plan for improvement.

Plant Ooerations Summary of Previous Assessment The previous SALP assessment concluded that Operations remained strong. that management actions were aggressive in dealing with identified weaknesses, and that attention to detail was a continuing challenge for the licensee.

Summary of the Most Recent SALP

'The' board concluded that licensee performance had declined in the most recent SALP period. The board found that day-to-day j

activities were conducted with a degree of complacency.

i

. Corrective actions. management involvement and communication of ex)ectations, attention to detail, procedural-adequacy and ad1erence. and operator workarounds were similarly considered to be challenges to licensee performance.

4

Y 4-5 13-Maintenance / Surveillance q

Summary of Previous Assessment

)

Maintenance was assessed as category 1 in the previous SALP.

Assessments made early in the most recent cycle; indicated that the H

. performance level of maintenance activities had not abated.

Summary of the Most Recent SALP The board concluded that performance in this functional area had declined. Areas.of concern included.the existance of long-standing equipment problems and a sense that management

)

-expectations were either low or not adequately enforced.. Of:

'l 1

particular concern was the fact that equipment failure factored into 6 unit trips during the SALP cycle. Additionally, worker adherence to procedures, and the quality and adequacy of J

procedures was found to be a challenge to performance.

1 Enaineerina Summary of Previous Assessment The previous assessments for this SALP cycle concluded that engineering was generally strong, Good support of the 31 ant was cited, as was the quality of engineering products,

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to the site and in submittals to the NRC.

Summary of the Most Recent SALP i.

The board concluded that Engineering continued to perform at a superior level. Continued support to the plant, as well as adequacy in safety and o>erational evaluations were identified.

In addition. tie licensee's activities at the 4

engineering materials laboratory and in the developement of j

maintenance specifications were seen as strengths.

PART 3

SIGNIFICANT EVENTS 3.1 SIGNIFICANT EVENTS BRIEFINGS (Past 12 Months)

Unit 1:

95-08, 3/22/95. Failures of Rosemount Transmitters due to Gas Permeation of Monel Diaphragms Unit 2:

None.

I 3.2' ENFORCEMENT STATUS / HISTORY (Past 12 Months).

e SL III Violation (550.000 CP) for violations associated with inoperable Unit 1 PORVs f

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Predecisional Enforcement Conference held. SL IV violation issued for failure to take prompt corrective action for issues relating to relief valve lift and blowdown setpoint values which resulted in a loss of Unit 1 RCS inventory while on shutdown cooling.

PART 4

STAFFING AND TRAINING 4.1 OPERATIONS STAFF - OVERALL (9/95)

Average performance of the operations staff has been noted.

Control room demeanor of personnel is above average.

Number of Shifts:

(RCO, SRO) Five shift rotation, 8-hour shifts; (NPO, ANPO, SNPO) Five shift rotation. 8-hour shifts.

Number of SR0s:

38 active /13 inactive / 51 total Numb'.tr of R0s:

23 active /1 inactive / 24 total Totbl Licensed Operators:

61 active /14 inactive / 75 total 4.2 WORK FORC[ (2/96)

Plant personnel (including 787 1

disciplines below)

Breakdown by Maior Oraanization FPL Contractors 0)erations 128 0

C1emistry 20 0

Health Physics 73 0

Maintenance 311 60 0utage Management 21 0

Nuclear Material Management 36 0

Site Engineering

50 0

Juno Engineering Security 9

120 QA/0C 37 0

Includes Reactor Engineers. System Engineers, and Test Engineers 4.3 OPERATOR 00ALIFICAT10N/REQUALIFICAT10N PROGRAM (Past Two Years) 4.3.1 REQUALIFICATION PROGRAM Last Inspection - 9/26/94. Inspection Report 50-335,389/94-19 Next Inspection - 10/96 4.3.2 INITIAL EXAMS

?

1 15 Last Exams 10/17/94 -

2 R0 2 passed for 100%

9 SR0 9 passed for 100%

i Next Exam 3/25/96 -

6 R0 l

l 4.4 PLANT SIMULATOR The simulator is on site and fully certified to meet ANSI /ANS 3.5. 1985.

4.5 INPO 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 5 years. NRC inspections in the form of operator examinations at the simulator have found no serious i

problems.

INSPECTION ACTIVITIES PART 5

5.1 INSPECTION FOLLOWUP OPEN ITEMS

SUMMARY

(UNITS 1 AND 2 COMBINED)

(10/6/94)

Pre Division Change from Division

_25 1995 Total Last Reoort DRP 4

34 18 DRS lQ 4

14 Total 14 37 51 Note:

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

5.2 MAJOR INSPECTIONS IR-No.

Qata lyng 89-02 1/89 RG-1.97 89-03 3/89 NDE 89-07 3/89 EQ 89-09 3/89 Design Control 89-24 10/89 Maintenance Team Inspection 89-27 11/89 E0P Followup 90-09 4-5/90 OSTI 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 95-05 6/95 Engineering

f

'. 4 16 95-16.

9/95.

PORV Special Inspection 96-01.

1/96 Dilution Event Spectial Inspection 5.3 PLANNED TEAM INSPECTIONS None 5.4 INFREQUENT INSPECTION PROCEDURE-STATUS No core inspection procedures are overdue at this time.

5.5' 'SIMS' STATUS - OPEN TMI ITEMS There are.no open THI items.

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PLANT STATUS REPORT.

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f-s P_LANT STATUS REPORT FOR ST. LUCIE (9/95)

TABLE OF CONTENTS'

- - - EDWIN UPDATE *****

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 PART 3 SIGNIFICANT EVENTS 3.1 SIGNIFICANT EVENTS BRIEFINGS (Past 12 Months).......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 SIMULATOR.......

............Page 21 4.5-INP0 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 ATTACHMENTS 1.

PERFORMANCE INDICATORS 2.

-ALLEGATION STATUS 3.

NRR-OPERATING REACTOR ASSESSMENT i

4.

ORGANIZATION CHARTS 5.

. POWER HISTORY CURVES 6.

-MASTER INSPECTION PLAN-1

l i

2 PART 11- -FACILITY DESCRIPTION L1

- 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) - Services Manager L. W. Bladow (Wes) - Nuclear Assurance Manager

]

-H. F. Buchanan (Hank) - Health Physics Supervisor 1

R. L Dawson (Bob) - Licensing Manager-

)

i:

D. J. Denver (Dan) - Site Engineering Manager 1

H. L.~Figley (Herman) - Construction Services Manager i

P. L. Fincher (Pat) - Training Manager R. J. Frechette-(Bob) - Chemistry Supervisor P.

Fulford (Paul) - Operations and Testing Support Supervisor J.

Maichese (Joe) - Maintenance Manager 4

W. L. Parks (Bill) - Reactor Engineering Supervisor C. A. Pell (Ash) - Outage Manager L.

Roger: (Lee) - Systems and Com)onent Engineering Manager J.

Scarola (Jim) - Plant General,ianager J. A. West (Jeff) - Operations. Manager C. H. Wood (Chuck) - Operations Supervisor L3 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

- i SITE:

'R.'t;. Prevatte (Dick). Senior Resident Inspector. (407)'464-7822 M. S. Miller (Mark), Resident-Inspector, (407) 464-7822 F

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3 NRRi 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 D. B. Matthews Deputy Director Project Directorate II-2.

(301) 415-1490 J. A. Norris (Jan). Senior Project Manager Project Directorate II-2. (301) 504-1483 AE00:

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 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 DescriDtion Units 1 and 2 Reactor Type Combustion Engineering PWR, 2-loop Containment Type Freestanding Steel w/ Shield Building Power Level 830 MWe (2700 MWt)

Architect / Engineer Ebasco NSSS Vendor Combustion Engineering Constructor Ebasco Turbine Supplier Westinghouse Condenser Cooling Method Once Through Condenser Cooling Water Seawater 1.6 SIGNIFICANT DESIGN INFORMATION 1.6.1 REACTOR INTEGRITY Reactor Pressure Vessel (RPV)

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

\\

4 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 c1eck valves and one closed M0V. High 3ressure safety injection (HPSI) low pressure safety injection (_ PSI). and containment spray (CS) pumps' common containment sump suctions are isolated from the containment sump by one closed MOV in conjunction with a closed seismic piping system.

The CS headers are isolated from containment by one closed MOV and a check valve in conjunction with a closed seismic piping system.

CVCS has the normal complement of two automatic actuation isolation valves.

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

ATWS Protection ATWS protection. outside the normal reactor protection system, is initiated via the ESF 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.

I 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 There are two motor-driven pumps on each unit with 100 percent capacity per pump. There is one steam-driven pump on each unit with 200 percent capacity. Any of the three pumps can inject to either steam generator. Automatic initiation and faulted steam generator protection are provided by each unit's Auxiliary j

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 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.

,p0

.j 1

6 1

1 HydroaenCon_tgl

,i Containment hyd' ogen 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 j

manner, the temperature of containment atmosphere flowing through 1

the recombiner the recombiner units recombine hydrogen and oxygen to form water, thus. preventing the buildup of hydrogen to i

i potentially explosive levels.

t 1.6.5 ELECTRICAL POWER 1

Offsite AC

. The station switchyard is connected to the transmission system by three independent 240 KV lines that share a right of way and i

interconnect with FPL's grid on the mainland approximately 10 miles West of the )lant site. There are two independent offsite j,

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 (SB0) cross connection is installed and tested. This cross-connection serves the emergency i

busses directly and reduces cross-connect time to less than 15 i

minutes.

DC Power Two trains of vital batteries per unit have been routinely tested i

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 train, that provide four trains of instrumentation power.

Station Blackout Resolution Status j

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

.l while Unit 1 is subject to tie station blackout (SBO). rule of 10 l

CTR 50.63 requiring additional licensee action (unit-to-unit i

cross-connect of 4160V bus).

.l I

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I 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.

l After'use, ICW returns-to the ocean through a Discharge Canal and'

-under-beach pipes.

Each unit has two trains of ICW plus a swing pump that can be aligned to either train electrically and physically, The licensee has converted the dee) draft ICW pumps from externally (water) lubricated to self-lu)ricated to increase reliability of the-lubrication water source. The 100 percent (each) capacity pumps take suction from the intake canal via a canal intake structure using traveling screen debris protection. The intake canal structures adjacent to the ICW pump suctions are continuously injected with a hypochlorite solution to reduce marine growth in the associated piping and heat exchangers. Commencing 3/92, 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 ICW system.

The ICW pumps move water through two trains of heat exchangers that cool component cooling water (CCW) and two trains of heat exchangers that cool main turbine cooling water. During a Jostulated accident water flow isolates from the turbine cooling i

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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The swing pump can be aligned to'either train. The 100 percent (each) capacity aumps 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).

.1.6.8 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 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.

1.7 EMERGENCY RESPONSE FACILITIES / PREPAREDNESS Emergency Operations Facility:

10 miles West of site.

I-95/ Midway Rd. Exit Technical Support Center:

Onsite. Adjacent to Unit 1 Control Room Operational Support Center:

Onsite. 2nd floor of North Service Building The last annual emergency preparedness exercise was in May. 1995. This exercise was not formally evaluated by the NRC. The next emergency i

.' preparedness exercise is scheduled for February, 1996.

-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:

High Frequency Auto-link with other FPL sites and NRC.

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i y

9-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.

1 18 PRESENT OPERATIONAL' STATUS- (3/9/95)-

.l

Unit 1 has been operating at full power since-The unit was shutdown on August 41 as a result of Hurricane Erin. A series of problems including RCP seal failure.' both PORVs inoperable due to incorrect assembl. SDC relief valve problems, associated problems with R

several other rel ef valves, inadvertent spraydown of the containment.

catastrophic failure of IB emergency diesel generator, and a leaking flange on a pressurizer safety valve resulted in the unit being shutdown-

]

for-days. While the unit was down, a large number of operator-work-arounds and other plant deficiencies were corrected. The next refueling outage is scheduled for April 4.1996.

Unit 2 was shutdown on April _25 for approximately seven hours to replace a main turbine digital-electro hydraulic power supply. The unit was down power for several days in June and July to clean condenser water boxes.- The unit was shutdown on August 1 as a result of Hurricane Erin.

It restarted on August 4~.

Power was reduced from August 17 through 29 1

to clean condenser water boxes and repair various secondary plant deficiencies.

The next refueling outage is scheduled for October 9,1995.

i Availability Factors:

)

Unit 1 Unit 2 i

1991 81.0 100.0 1992 96.5 75.2 i

1993 74.0 71.8 1

1994 86.8 79.6 1995 (through 7/95) 93.9 98.3 4

Cumulative (through 1/95) 77.7 83.7 1.8.1' UNIT 1 OPERATING HISTORY (Past Twelve Months from 8/1/94)

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

following exceptions.

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 0.005 hours 2.97619e-5 weeks 6.849e-6 months later_ on the same'date.

On October 26, 1994 the unit tripped from 100 percent power due to a loss of electrical load. This 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 I

scheduled to begin four' days later. The unit was returned to service on November 29.

10 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 shutdown cooling. The apparent root cause was operator error by a reactor operator placing one loop of SDC in standby.

The operator 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 relieved the operator of licensed activities.

On June 11. 1995. the unit was down powered to 40 percent to

-jumper out a cell on IB safety related battery.

On July 8.1995, the unit tripped'during turbine valve surveillance testing.

It returned to power on July 12.

On August 1. 1995, the unit was shutdown as a result of Hurricane Erin. Due to a series of equipment problems and personnel performance issues. the unit was not restarted until 1.8.2 UNIT 2 OPERATING HISTORY (Past Twelve Months from 8/1/95)

Unit 2 operated continuously during the past 12 months with the following exceptions:

On February 21, 1995, the unit trirped as a result of low steam generator water level. The condition was the result of a feedwater regulating valve closure after a steam generator water level control level transmitter failed high. The transmitter was replaced and the unit was returned to service on February 25.

On April 25. 1995. the unit was shutdown for approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to replace a main turbine DEH power supply.

On August 1, 1995 the unit was shutdown as a result of Hurricane Erin.

It was restarted on August 4 but operated at reduced power from August 17 through 29 to clean condenser water boxes and repair equipment problems.

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 instances of reduced inventory / mid-loo) operations: replacement of.ICW/CCW LOOP logic [HFA latching relays) wit1 pull-to-lock switches:

. -. ~

1 11<

removal- [ collection] of Rx' vessel neutron flux dosimetry; modification

'of EDG skids-to allow access underneath: inspection of'ECCS_ sump area:

replacement of a main transformer; modification of containment spray Na0H addition piping: and mcchanical, 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.

I&C systems maintenance. The next Unit 2 refueling outage is scheduled-

.for:0ctober, 1995.

PART 2

PLANT PERSPECTIVE 12.1 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 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 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 11/1/90 -

1 1

1 1.

I 1

1 5/2/92 PLANT OPS MAINTENANCE ENGINEERING PLANT SUPPORT 5/3/93 -

1 1

1/1/94 2.3 SELECTED SALP' AREA DISCUSSIONS (9/1/95)-

. Since July 1995, there has been a. series of events that led to questioning the plants overall performance. These have included:

a Unit'1; turbine. trip.due to procedural weakness. operator performance and

12 supervisory oversight; the attempt to restage an RCP seal using inadequate and inappropriate procedural guidance which led to the failure of the second and third stage seals, a main steam isolation signal due to inappropriate operator response, an inadvertent reactor protection system actuation due to inattention to detail by an operator, both 3ressurizer relief valves being inoperable due to incorrect assem>1y during a refueling outage, an inoperable shutdown cooling relief valve due to incorrect setpoint margins (a generic problem involving several valves), the spray down of containment due to an inadequate procedure and operator error cou) led with an existing operator-work-around. These and several otler recent deficiencies involving weak procedures, a general lack of procedural com)liance, equipment failures, and personnel errors clearly indicate tlat the plants past high level of performance has declined.

Both units were shutdown on August 1 for Hurricane Erin. Unit 2 immediately restarted but Unit I remained shutdown for days due to the above problems.

The above problems have led to several plant management changes, an overall evaluation of the recent plant problems by a plant requested independent assessment team and a root cause evaluation by the NRC.

In a meeting with the NRC on August 29, the licensee committed to use the results of the independent assessment team to develop an action plan for improvement.

Plant Ooerations Summary of Previous Assessment 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 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 sindicating 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, consolidating tens of programs into one which involves daily management reviews of all documented conditions.

The >revious assessments concluded that Operations remained strong in t'e current period, that management actions were aggressive in dealing with identified weaknesses, and that increased attention to procedural adequacy may be warranted.

Last Six Months

13-The' previous six months has.shown an increase in personnel errors involving, the failure to follow procedures. inattention to detail, the failure to maintain awareness of-equipment status.'and.

weaknesses in.logkeeping. Only one reactor trip a turbine trip t

due'to operator error, occurred during.this time span. Operator-response to that event was excellent. 20verall response to plant startups, shutdown. power maneuvers has been good. Several findings indicated weaknesses in personnel performance, procedural.

-adequacy, inattention to detail, weak logkeeping, cauipment failures, poor communications.'and living with operator-work-arounds. They include:

e Overpressurizing the main generator-e Not. logging equipment out of service o

Starting a LPSI pump with the suction valve closed e

Overfilling PWT e

Spray down of Unit 1 Containment Improper staging of RCP seal resulted in seal. failure e

e Failure to block MSIS actuation e

Turbine trip due to operator error e

STAR /NCR not evaluating past operability e

Temporary modification not shown on CR drawing e

Loss of SDC. operator closed suction isolation valve Weak annunciator response on loss'of SDC e

e Operator failed to identify level out of sight on EDG cooling water tank ~

e Spent fuel pool housekeeping e

Failure of SGWL Rosemount transmitter (maintenance) e 2B LPSI pump found airbound e

Failure to sample SIT within TS required time frame following volune addition (second occurrence in 2 years) e Failure to identify and analyze hot leg flow stratification Strengths Strengths have been identified in operator response to trips, transients. and power maneuvers. Post job or evaluation briefings have overal1 been timely and thorough with the exception of several recent events.

Weaknesses See paragraph 1 above.

Conclusion Operations performance has declined in the past six months.

Operators respond well to events but do not always have a questioning attitude, appear to have lapses in procedural use and compliance, and are not_ identifying and forcing plant support organizations to correct plant deficiencies.

-~

.e i

I 14 Logkeeping and attention to detail have led to an increase in errors.

Maintenance / Surveillance i

u L

Summary of Previous Assessment

]

Maintenance was assessed as category 1 in the previous-SALP.

i The previous assessments made during the current SALP cycle indicated that the-performance level of maintenance activities had not abated. Strong performance had been I

noted in the support of the Unit 2 outage.~and housekeeping and plant preservation activities were deemed good.

Last Six Months a

4 During the past six months. 24 maintenance activities were observed in varying levels of depth. One violation involving the installation of incorrect size motor overload l

heater was identified. Three potential violations involving inadequate surveillance, inadequate post j

maintenance tests, and two inoperable PORV are currently being evaluated. Two non-cited violations involving j

inadequate control on jumpers were identified. Workers were found to be well skilled and trained overall.

Problems have l

been noted in procedural adequacy and use.

1 Twenty-two surveillance activities were observed. Two non-cited violations involving the failure to perform surveillance within specified time limits were identified.

These were the result of a weak surveillance tracking system.

Strengths The. licensee continues to use and improve on their online maintenance procedure and implementation.

Overall maintenance activities performed under this program were well planned and executed. The craft work force is motivated and overall skill level is high. The licensee has completed the development of their maintenance rule and it will be in place and i

operating by.the end of September.. The predictive maintenance organization continues to provide early

. indication of pending failure and assists in root 4

cause evaluation of equipment failures.

Weaknesses Weaknesses have been identified in the.following areas:

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15 Proceduraladeq$acy i

e Procedural comp 1ance l

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Installation of incorrect parts.

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Personnel errors in work performance e

Surveillance tracking system e

Equipment failures e

Control of lifted leads / jumpers e

Communications Conclusion j

Maintenance performance has declined.

Equipment failures

,l have impacted plant operation. Craft personnel are not identifying and correcting procedural deficiencies and are using procedures as 9meral guidance..' Individual and group 3erformance is generally excellent to high visibility jobs, i

aut attention to detail appears to lapse on routine work.

Enoineerina l

Summary of Previous Assessment l

The previous assessments for this SALP cycle concluded that i

engineering was generally strong. ' Good support of the Unit i

2 outage was noted, as was good 0A with respect to fuel noted in the area of vendor technical manuals. problems were fabrication and receipt inspection.

Potential

')

Last Six Months The noted concerns with respect to VTMs were. in part.

i validated in the maintenance area, where a violation i

L resulted; however, the violation was not reflective of a

~

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 4

identified, relating to the design of NaOH supply piping, however, the problem had existed since shortly after construction and was appropriately addressed.

4-Five plant modifications and several safety evaluations were reviewed and were. generally found to be thorough and correct. The licensee's program for the control of 3

containm?nt 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 e

1A LPSI pump relief valve lift e

Unit 1 Pressurizer relief valve seat leakage e

Post-event reviews of loss of Unit 1 SDC

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Unit 1 RWT leakirepairs

-Conclusion i

Engineering continues to perform well. No weaknesses have been identified in this functional area.

P1 ant Sucoort.

)

Radioloaical Controls Previous assessments this-SALP cycle indicated an effective l

program.

Inspections this period indicate good control of-internal / external exposure and containment during outages.

i ALARA initiatives were noted: robotics, submersibles, and i

telemetry. The licensee was noted to be ahead of most of-j the region in the use of cameras, video and wireless communications.

Emeraency Preoaredness The licensee continues to maintain an effective EP program.

Security Security upgrades made prior to the last SALP were notable. The i'

licensee continues to maintain a very effective security program.

Fire Protection

)

i The licensee continues to maintain an effective fire protection program.

Housekeeoina Housekeeping has been generally very good.

SIGNIFICANT EVENTS PART' 3

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.

i STA'FFING AND TRAINING

'P.A R T.

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4.1 OPERATIONS STAFF - OVERALL (9/95).

E Average performance of the operations staff has been noted. Control room demeanor of personnel is above average.

4

. Number of Shifts:

(RCO, SRO)' Five shift rotation. 8-hour shifts: (NP0. ANP0. SNPO) Five i

shift rotation. 8-hour shifts.

Number of SR0s:

38 active /13 inactive / 51' total Number of R0s:

23 active /1 inactive / 24 total-Total Licensed Operators:

61 active /14 inactive / 75 total l

4.2 WORK FORCE (8/94) f E!L Contractor P1 ant personnel (excluding 699 122 disciplines below) t

. Training 64 0

(

1 Quality Assurance /ISEG/ SPEAK 0UT 39 0

Materials Management 47 0

. Security 11 122 Site Engineering 48 0

4.3 OPERATOR OUALIFICATION/REQUALIFICATION PROGRAM (Past Two Years) 4.3.1 RE00ALIFICAT10N PROGRAM 1

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 R0'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.

I 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.

'4.3.2 INITIAL EXAMS Previous initial operator exams were conducted on April 29. 1991.

i.

Six SR0 upgrades were examined, and all six passed. Additional exams were completed October 25. 1991. Six operators. 2 SRO upgrades, and 1 instant SR0 were examined. All passed. The last initial' exam was' given April 27 through May 1.1992, to.6 SR0 upgrades and 2 R0s. and all )assed. A hot license class of 15 persons was started in late r bruary. 1992 (14 still in class).

e

1 i

18 I

The last initial exam was conducted in October 1993 - 10 of 10 prospective R0s passed.

Initial exams are planned for.0ctober, i

1994, with 3 R0s and 7 SR0 Upgrades planned 4.3.3 GENERIC FUNDAMENTAL EXAM l

On an NRC administered Generic Fundamental Exam on June 6. 1990, 6 i

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 i

fully certified for approximately~ 4 years.

Eight separate NRC inspections in the form of operator examinations at the simulator have i

found no serious problems.

INSPECTION ACTIVITIES PART 5

5.1 INSPECTION FOLLOWUP OPEN ITEMS

SUMMARY

(UNITS 1 AND 2 COMBINED)

(10/6/94) j Pre Change from Division

,,Q Tg_tal Last Reoort DRP 3

30 0

i DRS 0

7

-3 j

1 DRSS.

1 2

1 l

Totals 3

39

-3 Note:

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

5.2 MAJOR INSPECTIONS i

IR-No.

QMg Tyng 89-02 1/89 RG-1.97 89-03 3/89 NDE 89 3/89 EQ 89-09 3/89 Design Control 4

'I

19 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 M0V (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 INFREQUENT INSPECTION PROCEDURE STATUS i

No core modules are overdue at this time.

5.5 SIMS STATUS - OPEN TMI ITEMS There are no open TMI items.

~ f i

a ATTACHMENT 3' i

NRR OPERATING REACTOR ASSESSMENT' NRR A?2SSMENT FOR ST. LUCIE October-1994 i

'CURREkT: ISSUES.

-Seismic qualification of electrical and mechanical equipment (GL 87-02.

l J USI A-46). issue on Unit 1 is still not resolved. The staff issued a letter in early

j

.1994 providing a general framework'of criteria which would resolve this issue.

FPL i

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 i

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 alternative being evaluated is performance of a site inspection to determine if any safety-significant issues exist in the areas of disagreement.

I

-Unit I will. be replacing steam generators in 1997.. ' lhe licensee is well into planning for the event.

n An alternative approach to the resolution of the Thermo-Lag issue was. proposed by i

FPL. however, the staff did not pursue review of this performance based approach 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.

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

~

Contact:

Jan A. Norris 504-1483

)

-F

i hf if f August 28, 1995 MEMORANDUM T0:

John A. Zwolinski, Deputy Director Division of Reactor Projects I/II, L. '

FROM:

Ellis W. Merschoff, Director Division of Reactor Projects

SUBJECT:

REQUEST FOR ASSISTANCE IN ADDRESSING ISSUES REGARDING ST.

LUCIE EMERGENCY DIESEL GENERATOR FUEL OIL TRANSFER SYSTEM LEAK ISOLATION AND USING OPERATOR ACTION IN PLACE OF AUTOMATIC ACTION (TIA 95-013)

'Recently, the 2B ' Emergency Diesel Generator (EDG) fuel' oil (FO) transfer system developed a leak at St. Lucie Unit 2.

The licensee's actions in response to this event included isolating the leak to minimize environmental contamination. The licensee performed this action under the provisions of l

10 CFR 50.59. The licensee's actions in this regard have given rise to generic questions involving the relationship between PRA evaluations and 10 CFR S0.59 requirements. The background on the issue and specific questions j

arising from it are detailed below.

1 System Descriptinn The St. Lucie EDGF0 transfer system (for a given train) consists of a FO tank, a transfer pump, a day tank mounted on each of two EDG engines (two engines per EDG unit), and associated piping and valves. The transfer scheme involves the pumping of F0 from the storage tank, via the transfer pump, through piping from the F0 building to the EDG building and then to the day tanks. The day tanks' contents are then pumped directly to the EDG engines.

The piping from the transfer pump discharge to the day tank is normally unisolated with the exception of normally closed solenoid valves at the day tanks. When the EDG is running, F0 is drawn from each day tank until low 7

level signals open the solenoids, allowing a gravity feed of F0 from the FO tank to the day tanks. Should level continue to fall, low-low level conditions in the day tanks initiate a start signal to the transfer pump to increase the makeup rate'.

i Condition Description l

Over the course of several days, the licensee noi:d a decrease in 2B EDGF0 inventory and suspected that a_ leak had developed. Through increased monitoring, the licensee determined the leak to be in the piping between the

.F0 transfer pump and the day tanks. As the piping was below grade, rapid 1

identification and correction of the leak was impossible.

To terminate the release of approximately 15 gallons per day of F0 to the environment through the leak, the licensee proposed operating with an 6

w_ n---------

t 9

J. Zwolinski 2

isolation valve at the discharge of the F0 transfer pump closed (the valve is normally locked open). As a compensatory measure, the licensee proposed dedicating a non-licensed operator to the task of responding to open the valve should the EDG start. The operator would have no concurrent event response role (e.g. fire brigade); however, he would have non-response duties to perform during the course of a shift. Additionally, the licensee proposed revising a number of procedures to include the requirement of opening the 1

valve in the event of an EDG start.

Safety Evaluation The licensee elected to perform the actions described above under the auspices of 10 CFR 50.59. The Safety Evaluation (SE) performed pursuant to the code noted that two new failure modes were created by the proposed action. The first involved a failure of the operator to arrive at and open the subject valve prior to the associated EDG's day tanks emptying.

The second involved a mechanical failure that precluded the opening of the valve.

The licensee performed a PRA study of the proposed change which indicated that an approximately 6 per cent increase existed in the estimated frequency (per The SE went on to year) of the loss of the EDG and the associated safety bus.

state that procedures would be revised, operators trained, overall awareness heightened, and, as a result, no net increase in the probability of failure of a component important to safety would result from the proposed change.

Questions In light of the licensee's conclusions, we propose the following questions:

1.

Is the attached 10 CFR 50.59 FPL Safety Evaluation (JPN-PSL-SENS-95-013) considered acceptable?

2.

From a PRA perspective, is it possible to completely mitigate a risk, once introduced?

Is the licensee's position (that the risk of operator failure / error can 3.

be mitigated, probabilistically, through procedures and training) valid?

Do probabilistic estimations of operator error rates presuppose the existence of procedures and training and, if so, can one then take credit for them in a deterministic mitigation of risk?

Can 10 CFR 50.59 requirements (that the probability of failure of 4.

components important to safety not be increased if no unreviewed safety question is deemed to exist) be satisfied if new failure mechanisms are added to a previously reviewed system?

PRA insights are beginning to provide a more structured evaluation 5.

process for proposed changes to facilities and, as a result, are showing that changes (in a 10 CFR 50.59 context) present finite, although small, increases in the probabilities of failures.

Is there a threshold value of increased probability (representing " negligible" or " insignificant" increases) below which 10 CFR 50.59 criteria (for demonstrating that

i J. Zwolinski 2

isolation valve at the discharge of the FO transfer pump closed (the valve is normally locked open). As a compensatory measure, the licensee proposed dedicating a non-licensed operator to the task of responding to open the valve should the EDG start. The operator would have no concurrent event response role (e.g. fire brigade); however, he would have non-response duties to perform during the course of a shift. Additionally, the licensee proposed revising a number of procedures to include the requirement of openf ag the valve in the event of an EDG start.

Safety Evaluation The licensee elected to perform the actions described above under the auspices of 10 CFR 50.59. The Safety Evaluation (SE) performed pursuant to the code noted that two new failure modes were created by the proposed action. The first involved a failure of the operator to arrive at and open the subject valve prior to the associated EDG's day tanks emptying. The second involved a mechanical failure that precluded the opening of the valve.

The licensee performed a PRA study of the proposed change which indicated that an approximately 6 per cent increase existed in the estimated frequency (per The SE went on to year) of the loss of the EDG and the associated safety bus.

state that procedures would be revised, operators trained, overall awareness heightened, and, as a result, no net increase in the probability of failure of a component important to safety would result from the' proposed change.

Questions In light of the licensee's conclusions, we propose the following questions:

1.

Is the attached 10 CFR 50.59 FPL Safety Evaluation (JPN-PSL-SENS-95-013) considered acceptable?

2.

From a PRA perspective, is it possible to completely mitigate a risk, once introduced?

3.

Is the licensee's position (that the risk of operator failure / error can be mitigated, probabilistically, through procedures and training) valid?

Do probabilistic estimations of operator error rates presuppose the existence of procedures and training and, if so, can one then take credit for them in a deterministic mitigation of risk?

4.

Can 10 CFR 50.59 requirements (that the probability of failure of components important to safety not be increased if no unreviewed safety question is deemed to exist) be satisfied if new failure mechanisms are added to a previously reviewed system?

5.

PRA insights are beginning to provide a more structured evaluation process for proposed changes to facilities and, as a result, are showing that changes (in a 10 CFR 50.59 context) present finite, although small, increases in the probabilities of failures.

Is there a threshold value of increased probability (representing " negligible' or " insignificant" increases) below which 10 CFR 50.59 criteria (for demonstrating that

1 J. Zwolinski 3

unreviewed safety questions do not exist) are satisfied?

6.

The response to a related TIA from Region III, transmitted via letter from you to Edward Greenman' dated June 23, 1993, stated in part that "NRR has no particular objection to the use of PRA in 10 CFR 50.59 evaluations.but recommends that it play a supportive role, in conjunction with other inputs, such as engineering judgement and operating experience."

In the given case at St. Lucie, when PRA insights provide information counter to (as opposed to supportive to) the 10 CFR 50.59 conclusions, is it appropriate to accept deterministic conclusions over the PRA-indicated increase in probabilities of failure?

This request has been discussed with J. Norris of the NRR staff.

If you have any questions concerning this request, please contact M. Miller (407/464-7822) or K. Landis (404/331-5509).

Docket No. 50-335/389 License No. DPR-67/NPF-16 Attachments:

1.

FPL Safety Evaluation JPN-PSL-SENS-95-013 2.

NRC IR 50-335, 389/95-14 cc w/atts:

R. Cooper, RI W. Axelson, RIII J. Dyer, RIV K. Perkins, WCF0 S. Vias, RII J. Norris, NRR l

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- REVIEW AND APPROVAL RECORD 1

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TITLE 10CPR50.59 BVALUATION OPEtATION WITH DIESIR. OIL TRANSFER PUMP :3 l

. DISCHARGE 1$0LN!10N VALVE V17216 CLOSED i

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10crE50 39 ETALU1 TION POR OPERATION WITE DIESEL OIL TR&BSFER PUMN 25 DISCEARGE Is0LATION YALVE V17216 CLOSED i

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1.e 3333333g This safety evaluaties is to deaumont the aseeptability of plaat i

aparaties with Diesel oil Transfer Puay (Dotp) 25 disobarge isolation valve V17215 in the CLosID position.

compensatory measures shall be i

established' to open the valve upon operaties of the SE Baergemsy i

Diesel semerater (EDs).

v1? sis is normally a LocEED orEN valve; however, due te a suspected leak in the underground piping devastream l

ef the valve it is desired to isolate the piping until the leak is 1

identified and repairs are made or the line has been replaced.

Isolation of the line will provost the loss of an estimated 15 gallons 4

per day of diessi fuel oil to the environment.

i Talve V17218 is leested in line I-3"-DD-14 whisk oonamots the Dorps to i

the at EDs Day Tanks.

This line is elassified as safety slass three (3), seismie elass I; therefore, this evaluation is ' olassified as l

Safety Related.

I:'

This evaluation concludes that operation of the plant with valve V17216 in the CLOSED position does not impact plant safety and does not constitute an unreviewed safety question mer require a change to

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the teshaical spesifiestions.

This conclustos is esattagent upon implementation of the following aparating restrictions and seapeseatory actions:

operating personnel shall be instructed to open valve vi7314 as seem as possible and within 20 minutes of any unplammed starting of the 25 EDet prior to closing v17214 and at least tries amok shift, verify i

that the 25 EDS day tanks are each filled to A 220 gallons (93%

4 full per local level indication);

valt>- V17214 must be manually opened prior to any plaaned opeanEEen of the 23 EDS or anytime faal oil makeup is required fam y SE EDS day taaks; instractions shall be provided to all appropriate plant persommel l

regarding the above.

This evaluation does met address system operability and plant j '

operation during repair or replacement of the subject pipe.

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JFfRSL EENSM413. Est.s Pass 4etis 1

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,.0 neaaripklam and Purpose The underground portion of the pipeline between DOTP as and the day 4

j tanks for the at 3DG is suspected of leaking at a rate of approximately 15 gallons per day.

The exact location of the leakage is currently umidentified and efforts are underway to looste the leak such that the line can be repaired or replaced.

The purpose of this evaluation is to allow the plant to contiane operation with the DOTP j

23 discharge isolation valve (Y17216) la the CLOSED position, thus isolating the fuel oil leak to the environment.

Compensatory actions are identified in section 9.

3.0 Lineasing neguirampman j

valve Y17318 is part of the diesel generator fuel oil system that transfers fuel from the Diesel oil storage Tanks (DOSTs) to the day tanks.

Per FSAS Section s.5.4.1 the diesel fuel oil storage and transfar system is designed to perform the following fumatiossa j

l a) provide oil storaga capacity for at least 7 days power operation of one emergency diesel generator set; I

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b) maintain fuel supply to at least one diesel generater set, assuming a single active or passive failure of the system ooincident with loss of offsite power; i

l c) meet seissio Category I and quality eroup C requirements; and d) withstand maximum flood levels or tornade wind loadings without loss of function.

i l

The system is broken down into two subsystems (& & 3).

Emen subsystem a

sessists of a DosT, a D0fy, two day tasks and asseeisted valves, pipias and instrumentation.

Daring normal operation subsystem &

i serves diesel generator A and subsystem a serves diesel generator 3; however, the two subsystans osa be cross-ooanooted at the discharge of the transfer pumps.

Technical specifications 3.s.1.1 and 3.s.1.2 idestify the operability requirements of the diesel generators.

& similar evaluation was performed for omit 1 in 1992 (referemoe 3).

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Talve V17215 is leosted in line Z-ta-Do=14 whist oonamote the DOTys to the 2B EDS day tanks.

This line is olassified as safety class three (3.), seismia elass E.

Under normal operating oonditions, vi7ats is in a w.rmn cyss position and provides a flow path for diesel fuel oil to the 35 EDS day tanks from the as DOTp and the DOST.

system operation is described below.

i The susties of port sa is eemmeeted to the 23 Dost via liams I-3"-DO-6 s a and maanal valve vi7sta.

The disobarge of the SS DOTP is osanooted to 25 EDS Day Tsaks 231 and 232 via transfer lines I-1-1/2"-

D0-12, I-2"-Do-14, I-1-1/3"-De-tso, I-1-1/3"-De-asa; oheek valves

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ESF. 0 Passsetis V17314 4 VS9299; manual imelation valves V17315, Y17318; and seleasid 4

j valves 83-59-131 & sE-89-182.

The manual valves in the fler path from j

the DOST to the EDG Day Tanks are mermally leaked opea.

solenoid valves 33-59=131 & $5-59-132 are loosted in the diesel generater building upstrema of the day tanks and provide automatie isolaties of i

the day tanks v'em the prescribed fuel oil level is obtalmed.

Level I

Switches L8=59-0193 $ Es-89-0373 etart norP as and open tae assestated day taak solenoid valve when the day taak level deeresses to 23.5" 3

3 (223 gallons).

Level Switches L5-59=4205 & LS-59=0363 step the DOTP 4

and elene the seleasie valve when the day tank level increases to 32.8" (saa galloss).

rhe above operation is automatie.

The system operation proposed by this safety evaluation would be the same as described above with the ozoopties of the 25 DOTP discharge 4

isolation valve V17218, whish will be elesed.

closing of valve V17315 l

will isolate the as 300 Day Tanks from the DOTP's discharge and the Dosts.

Operating perseasel will be instrusted to provide for the opening et valve V17216 in the event of a 23 EDe ante start.

Assuming an initial day tank fuel volume of sie gallons, the 300 oculd l

run approminately las atautes at full lead without replenishing the i

day tank.

This is based en the is cylinder engine which is the i

limiting fastors 320 gallons initial day tank fuel. volume 15 gallons unusable day tank volume (reference 4) 304 gallons usable day tank volume

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223 gallons day taak auto fill level l

2.4 gpa nazimum fuel consumption rate j

(based on referense 4 values) 304 gal /2.4 gym = 126.7 miantes of operaties e

i After apprezimately 40 minutes of operaties, the DOTP would be l

automatically started as a result of a low day taak level (310 - 223 j

i

= 97 galleas fuel volume between Dort start / step setpointe esasumed at l

2.4 gym).

Plant operations Department has indicated that sa operator cam reopend to the starting of the SS sDe and open valve V17 sis within 26 minutes.

Thus, the DOTP will met automatically start and rua against shutoff head prior to the opening of Y17318.

Based on a is gal / day leakage rate and the system eenfiguration, the i

sine et the suspected hele in the pipe is estimated te be less than 1/16# diameter (reference 3).

The underground portion of I-8"-Do=14 is at plant elevaties 13'-6" (referomoe 7) which is about 8' below grade.

36 reeamt study (referease 6) measured Tresad water levels in the visimit to 14' beter grade,y of the Unit a EDS building at approaimately 13' well below the subject pipe.

Addhtissally, filtration is i

provided devastreau of the day tanks.

Therefore, based en the estimated size of the hele and Ic.ation of the piping, the possibility l

ef the introduction of foreign material such as sand er ground water is considered to be very small.

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JPN-PSLSDiS48 413. Rev. 6 Pass 6 et18 operability of the subjoet pipe has beer, addressed in the referesse 5 STAR.. The suspected underground leak has been quantified at apprezimately is gal / day.

The 23 DWP has a design flow rate of as GPM (referesse 1) and provides sufflaient flow margia te deliver fuel to the 23 EDe to maintain the required fuel oil level in the day tanks.

risk assessment was conducted by FPL's Paa group.

This assessment h ad the baseline Unit 2 781 model to estimate the change in frequency of loss of the 233 4.15W bus with a less of grid initiating event and the addities of two mer 23 EDS failure modes (i.e., failure of the EDG fuel oil manual isolation valve to eyes and failure of the operator to open the elesed isolation valve).

A non-removery probability of 3.01E=3 was used for the operator failing to open the fuel oil isolation valve.

This probabilitw was based en the es-eastrel medel of C801 using a 120 minute available time and a se minute mesa response time.

Two cases vara assessed:

case 1:

Baseline PSA model case Case 3:

Baseline medel with the additional failure modes for the is EDO (manual fuel oil isolaties valve failing to opes and operator failing to open the valve).

The estimated frequeasy for each osse is as followes Case is 1.733-3/yr case 2 1.e4E-3fyr i

This indicates that the additional failure modes resulting from tha elesed fuel oil isolation valve results la as approximate at change in the estimated frequency per year of loss of the Unit 2 233 4.16kT bus.

l sinntaar i

Based em the above seamario, sufficient time esists for an operator to open valve 717216 prior te DOTP 25 automatically startlag to replenisk EDS 23 day tanks te metaal levels and suffielest margia esists fres 4

the 23 DOTP to deliver the required flow rate of fuel to the 33 EDG, considering,the empested grense leakage loss.

Implemmataties of the actione required in sostica 9.0 will provide fumatitaal espabilities equivalent to the original configuration.

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FAILURE c1033 SYMPTotes & EFFacTG moos Less of Fuel supply to sDG *sF V17316 Fails Operater Fails EDS 33 Failure Due To Fuel to open te open valve starvatien 12ter Appres. 2 hrs; EDs 21 hvailable as amargeasy AC Power G,,17 Y17ats rails valve Failure Same as Above to.opea

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There are me operattag restriations (mede restrietions) en the plaat while valve Y1721s is maintained la the cLossp posities.

This i

etnisaties Sees require eenpensatory motions which are identified in section 9.

7.0 affnet am Tashminal sneelfiantiamm The proposed activity will have me effect en p1' ant Technical J

spesifientions.

operability of the diesel fuel oil transfer systema is i

assured by virtue of the seaponsatory actions presaribed 47. this i

evaluaties.

Case valve vi731s is opened the fuel eit system will effectively be retarmed to its origiasi desiga seafiguraties sad will t

operate is its aeraal automatie mode.

3.0 unenwimwas safatw anamtlan nata-4mmtiam With respect to Title it of the cede of Federal Regulations, Part i

54.89, a proposed change shall he deemed to involve an unreviewed i

safety questions (1) if the probability of securresse er the esasequemees of an accident er malfaaetica of equipment iWt to i

safsty previews 1y evaluated in the satety Analysis asport may be Saaressed, er (til if a possibility for am mooisent er asituastiam of a different type than any evaluated previously in the safety Analysis

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asport any be areated, or (iii) if the margia of safety as defined la i

the bases for any Technical specificaties is reduced.

Based upon the aheve evalaations, it saa be deseastrated that plaat operaties with vaive visest in the crasap posities to isolate the DoeT from the 4

potentist

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ask pese pipe leak and the stated acapeasatory actions in place sees ask unregissed safety questies as defined by 14CFRSS.59 j

heesume eneh of the seves questions presented below eaa De 1

appropriately answered l

1)

Does the proposed activity lacrease the ehdff ty of oesurrence af en mentesat powrieasly evaluatea in the SART The proposed estivity involves the a trata of the EDS fuel oil spetaa.

ps&R seeties 13.10 describes the unit response to a staties h.ackout event.

i The prehability of a station blackset has set been insressed siaea the operators are capable et assuring that valve V17814 will be opetet prior to the starting of DOTP 23.

Therefore, 1

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there is no increase in the probability of eoourrence of am soaident j'

previously ammirsed in the saa.

i 2)

Does the proposed eetivity lacrease the consequences of en ecclemat previously evaluated La the SAnt b

The acasequeases of an assident previously evaluated in the Sha have not been imoreased since the performanae and operation of the SS sDs j

will met be impacted by this ehange.

haditionally, this okange will i-met arente a new path for uneentrolled radiomotive releases and will e

not adversely affect any radiation monitoring equipment er equipment which is relied upon to mitigste radiological sensequences of an seoident.

3)

Does the proposed estivity inczmase the probability of occurrence i

of a smalfunction of equipment Laportant to safety previaanly evalasted la the saRF The proposed activity slightly alters the method for initiating fuel l

flow from the DDets to the 2De Day Tanks.

Valve 717216 is normally a LOCKED OPEN valve that does not require any actuaties is order to.

i ensure a flew path from the Dosts to the sa 30s day tanks.

This l

evaluaties allers vi716 to be placed in the CEd8ED posikien provided the identified eenpensatory actions are implemented.

These j

L compensatory actions assure the reliability of the EDs fuel ett supply.

Additiemally, ones vi7 ass is opened, the fuel oil treasfer 1

system fumetions as originally designed.

as identified in section 5 of this evaluation, the failure of V17316 te opea (due to either valve or operator failure) is possible.

Such a failure would result in the less of the 23 BDe due to fuel starvation after appromirately two hours of operation.

A risk j

assessmaat was condusted by ppL's Pen group to determine the change in the reliability of the 3 side eloctrical power system following impleasatation of the specified easpensatory motions.

siase the EDO system is emir required to perform its safety fumaties following a lose of offsite poser to the safety electrical buses, failures of the erstem were taken in osajuncties with a less of offsite power.

Za the proposed eenfi aties, the shange in frequency of a less of the 3 side elastri power is slightly increased; however, this small ineresse'is met considered significant when oespied with the t

i fast that plant,.zhem will he modified to provide for operators who wi1Eh spesially instructed to open vi7 sis am seen as possible and witk&gt 26 minates after an unptammad start of the 23 EDS.

Based i

on the 'abees, it osa be,oonoluded that the probability of eesarresse of a malfumation of equipaast important to satety previously evaluated la the safety analysis report has not been increased.

4 4)

Does the proposed activity Lacrease the

w'mm w n of a malfinactica of equipseat liiwM st to safety prwrtanely evaluated la the SAny i

~ The sensequeases of a malfamation 'of equipment important to safety previously evaluated in the S&R have met been increased sinoa the l

4 mest limiting failure would result in the loss of a single EDS which is sa analysed event.

No other safety systems or equipasst required j

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for aseident mitigation er radiaties avaitering are impasted.

ll Does the proposed eativity armate the possibility at es escidest E1 at a ditterant typs tbas any previously enniuated in the RARt a failure medes and effeets maalysis has been performed for the proposed estivity.

This maalysis (see sostion 5) has identified two potential failures which would result la the failure of va7315 to l

eyes.

Failure of the valve te open would, after appreminatel hours, result in the less of the 2B BDs due te fuel starvaties.y two i

The i

less of a single EDs is an analysed event.

We other failure medes j

have been identified for the proposed activity.

Based en the aheve, j

the possibility of an aseident of a different type than any l

previously evaluated in the safety analysis report does met exist.

1 i

4)

Does the proposed activity czaste the possibility et a differnst type at aalfunction at equipment important te safety them any previously evaluated in the MART l

As stated in discussions aheve, a failure modes and effects analysis has been performed for the proposed activity.

This e.malysis has identified two potential failures which eve 14 ressit in the failure i

of V17315 to eyes.

Such a failure would ultimately'reamit in the less of the SE EDS, due to fuel starvaties.

The less of a single 3Ds 4

is an analysed event.

No other failure medes have boom identified for the preposed activity.

Additionally, essept for the operater j

acties to Laitially opea V17315, the operaties of the fasi eil transfer systen is met impacted.

We other systems are effected by the proposed activity.

Based en the above, the possibility of a l

malfunction of equipment important.te safety of a different type them

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any previously evaluated in the safety analysis report has not been L

acented.

7)

Does the proposed activity modues the marysm of safety as defined La the basis far any technics 1 speafficatiaat j

The proposed activity does met reduee the nazgia of safety as defined l

in the basis for may technical specification siaea the med astivity does not impact EDO eparability (Technical spesif tiens 3.8.1.1 and 3.8.1.3).

The sempensatory actions required by this 4

evaluaties ensure a reliable supply of fuel oil to the day tasks of the as EDS and, upon the opening of Y17316, the fuel til transfer j

system wi11 faaeties as designed.

nasemmicy locFase.ss allees changes to a famility as described in the ska if they de not involve sa unreviewed safety question er if a change in i

-the Technical spesifications is met required.

As shows la the preeeding scotions,.the proposed change does met involve en unreviewed safety quen,ilen because each somesta as posed by secrR58.se that portasas to unreviewed safety questions can be appropriately answered and a chaage to a Toshaisal spesification is met required; therefore, prior Mac approval is not regaired. '

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1.

Operatiaq personnet shall be instrusted to ensure that vifats is opened-as seen as possible and within 20 minutee of any umpiammed starting of the SS EDS.

2.

Prior to closiaq T17215 and at least twice sack shift, verify that the sa SDe day tanks are each filled to a 320 gallons (93% fall per

,i local level indication).

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3. Talve Y17 sis must be manually opened prior to any planned operation of the 23 Diesel Generator er any time fuel oil makeup is required j

for the 25 Diesel Generator day taaks.

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4. Review & revise plant precedures and conduet operator trainin6'as j

spyropriata.

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5.

Restore V17216 to its sermal LOCESD OPES positica as seem as.,,

j practical after the completion of any leak repairs or line l

replacement and before the completies of the mest refueling outage.

l Metes

This evaluation does not address system operability and j

plant operation during repair or replasement of the subject 1

i P Pe.

i 10.0 anfaramaam 1

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1) St. Lucie Unit 2 FSAR, Amendment 9 i

3

2) St. Luole Unit a Technical specifications, Amendment 75 i

3).7PN-PSL-SENS=93=014, Rev. 4 l

4) Calenlation PSL-177M-90=025, Rev. 3 l

8) STAR 950713

6) Contamination Asseemment aspert St. Luole Power Plant Unit 3 i

M g r semerator Diesel Peel Storage Tanks, Atlanta Testing &

magia.e=Ing, S.pt.am

., 1. 4 l

7) Drawing 2998-4-174, Rev. 14

8) Drawing 2998MB-046, Sk. 1, Rev. 17 i

9) Drawing 1998=G-096, St. 2, Rev. 5 11.0 attaahneman J

pone i

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UNITED STATES i

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NUCt. EAR REGULATORY COMMISSION REGloN 11 i

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101 f.1ARIETTA STREET. N.W,. sulTE 2900 i

ATLANTA. GEORGIA 3(XI23-o190 j

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August 22, 1995 Florida Power and Light: Company ATTN: Mr. J. H. Goldberg President - Nuclear Division t

.P. O. Box 14000 Juno Beach,-FL.33408-0420 I

SUBJECT:

NRC INSPECTION REPORT N05. 50-335/95-14 AND 50-389/95-14

)

Gentlemen:-

i This refers to the inspection conducted on July 2 f.hrough July.29,1995, at l

the St. Lucie facility.. The purpose of the inspection was to determine j

whether activities authorized by the license wees conducted safely and in accordance with NRC requirements. At the conclusion of the inspection, the findings were discussed with'those members of your staff identified in the j

enclosed report.

l l

Areas examined during'the-inspection are identified in the report. Within l

these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of

]

. activities in progress.

-]

Within the scope of the inspection, violations or deviations were not identified.

)

In accordance with.10 CFR.2.790 of the NRC's " Rules of Practice," a copy' of this letter and'its enclosure will be placed in.'the NRC Public Document Room.

1 Should you have any questions concerning.this letter, please contact us.

Sincerely, j

erry andi, Acting Chief I

ReactorWrojects Branch 2 i

Division of Reactor Projects Docket Nos. 50-335, 50-389

. License Nos. DPR-67, NPF-16 1

Enclosure:

NRC Inspection Report ec w/ enc 1: See page 2 ATTACHMENT 2~

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cc.w/encle D. A.:. Sager:

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Vice President St.. Lucie Nuclear Plant 1

P.50. Box 128-Ft. Pierce,-FL' 34954 0128-p LH. N.iPaduano, Manager Licensing and Special Programs

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Florida Power' and. Light Company

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P.: 0., Box.14000.

?Jun'o ' Beach, ; FL - 33408 0420 j

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C. L; BurtonL Plant' General Manager.

- St. Lucie' Nuclear Plant i

L PJ 0. Box 128.

Ft.~ Pierce, FL: 34954-0128 l

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Robert E. Dawson Plant Licensing Manager St. Lucie Nuclear Plant

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P. 0. Box 128

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Ft. Pierce, FL 34954-0218 J. R. Newman, Esq.

Norgan, Lewis & Bockius t

1800 M. Street, NW-

. ashington,~ D. C.

20036.

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~ John'~T. Butler, Esq.

. Steel. Hector and Davis 4000= Southeast Financial Center Miami, FL-33131-2398 Bill:Passetti.

.0ffice.of Radiation Control Department of Health and-Rehabilitative Services I

1317 Winewood Boulevard

. Tallahassee, FL 32399-0700 Jack Shreve'.

Public Counsel.

Office of the Public Counsel c/o The Florida-Legisiature-

'111 West Madison Avenue,--Room 812 1

Tallahassee; FL 32399-1400-E cc w/enci cont'd:

SeepageL3

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cc w/enci cont'd:

Joe Myers.: Director 1 j

Division of Emergency Preparedness

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. Department of Community Affairs 32740 Centerview Drive i

. Tall ahassee, L FL. 32399-2100 i

Thomas R..L. Kindred j

. County l Administrator

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St. Lucie County

' 2300 Virginia Avenue

~Ft. Pierce,'FL 34982 1

Charles B.:Brinkman Washington Nuclear Operations ABB Combustion Engineering, Inc.

12300-Twinbrook Parkway, Suite 3300 Rockville. MD 20852 9

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,;NITED STATES' NUCLEAP REGULATORY COMMISSION AEG;CN11

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'01 MAniETTA STREET. *4.W., SUITE 2900 j

ATLANTA. GEORGIA 30323 0199

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Report Nos.:

50-335/95-14 and 50-389/95-14 Licensee:

Florida Power & Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:

50-335 ana 50-389 License Nos.:

DPR-67 and NPF-16 Facility Name:

St. Lucie 1 and 2.

Inspection Conducted: July 2 through July 29, 1995 Lead Inspector:

-I e

L Fi4C R. Prevattt. Senior Repident Date Signed Inspector M. Miller, Resident inspector 8

Y Approved by:

K. dandis, Chief D4te Signed Reactor Projects Section 2B Division of Reactor Projects 1

SUMMARY

Scope:

This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, engineering support, plant support, review of nonroutine events, followup of previous inspection findings, and other areas.

1 Inspections were performed during normal and backshif t hours and on weekends and holidays.

Results:

Plant operations area:

Operations continued to perform well. Operator response to a reactor trip on July 8 was excellent. Operations response to deficiencies identified during plant systems walkdowns was satisfactory.

4

t 2

l

' Maintenance and Surveillance area:

Maintenance performance was found to be good.

Critical maintenance on the IB Auxiliary Feeowater Pump was performed very well; in contrast. a lack of proper planning and preparation resulted in increased out of service time for preventive maintenance on the 2C Auxiliary Feedwater Pump. A personnel error during main turbine trip surveillance testing resulted in a trip on Unit 1.

An I&C procedural weakness was identified during testing of the 2B Diesel Fuel Oil Day Tanks.

Engineering area:

i Performance in this area continued to be satisfactory.

Plant Support area:

Performance in this area continued to be satisfactory.

In the areas inspected, violations or deviations were not identified.

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REPORT DETAILS

' l.

.. Persons Contacted t

Licensee Employees R. Ball, Mechanical Maintenance Supervisor

E. Benkin, Plant Licensing Engineer -

W. Bladow, Site Quality Manager L. Bossinger Electrical Maintenance Supervisor H. Buchanan, Health Physics Supervisor

C. Burton, St. Lucie Plant General Manager R. Dawson, Licensing Manager

.D. Denver, Site Engineering Manager J. ' Dyer, Maintenance Quality Control Supervisor H. Fagley, Construction. Services Manager P. Fincher, Training Manager

R. Frechette. Chemistry Supervisor K. Heffelfinger, Protection Services Supervisor i

J. Marchese. Maintenance Manager W. Parks, Reactor Engineering Supervisor

C Pell, Outage Manager 1

L. Rogers, Instrument and Control Maintenance Supervisor D. Sager, St. Lucie Plant Vice President j

J. Scarola, Operations Manager J. West, Site Services' Manager C. Wood, Operations Supervisor W.-White, Security Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.

NRC Personnel

M. Miller, Resident Inspector

R. Prevatte Senior Resident Inspector

S. Sandin, Senior Operations Officer, AE00

Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.

2.

Plant Status and Activities a.

Unit 1 Unit 1 entered the inspection period at full power. A reactor trip was experienced on July 8 due to personnel error during a surveillance test. The unit achieved criticality on July 11 and was placed back on-line on July 12. The unit remained at full power for the balance of the period.

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2 b.

Unit 2 Unit 2 operated at essentially full power throughout the period until a planned power reduction on July 23 for conoenser waterbox cleaning. The unit was maintainea at approximately 60 to 70 per cent power during the cleaning, and was returned to full power operation on July 28.

c.

NRC Activity

. 5; Landis, Acting Chief, Reactor Projects Branch 2, NRC Region 11, visited the site on July 14. His activities included meetings with licensee management and a review of resident inspection activities.

R. P. Carrion of the Division of Radiological Safety and Safeguards, NRC Region 11, conducted an inspection of the licensee's chemistry program with the NRC Region II Mobile Laboratory on July 17 and 18.

His activities are documented in Inspection Report 95-13.

3.

Plant Operations a.

Plant Tours (71707)

The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.

The inspectors also determined that appropriate radiation controls were properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously.

During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates.

Some tours were conducted on backshifts. The' frequency of plant tours and control room visits by site management was noted.

The inspectors routinely conducted main flow path walkdowns of ESF, ECCS, and support systems. Valve, breaker, and switch lineups as well as equipment conditions were randomly verified both locally and in the control room. The following accessible-area ESF system and area walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:

1)

Unit 1 Boric Acid Makeup The inspector found major flowpath valves properly aligned.

1 i

3 2)

Unit 1 Auxiliary Feedwater The inspector found major flowpath valves properly aligned.

Corrosion was found breaking througn exterior paint on welded joints on either side of V09303 and on the downstream side of V9104. These conditions were brought to the attention of the system engineer for resolution.

Additionally, the inspector examined the governor valve stems of turoine-driven auxiliary feedwater pumps 1C and 2C for evidence of corrosion that could inhibit free movement as identified in NRC Information Notice 94-66, Supplement 1.

No significant evidence of corrosion was identified on either i

stem. The inspector discussed the issue of stem corrosion with the AFW system engineer and found that the issue was being considered and tracked under STAR 950496 and that the system engineer was extremely knowledgeable of the issue.

3)

Unit 2 Auxiliary Feedwater The inspector performed a walkdown of the Unit 2 AFW System in j

the CST area, AFW Pump Rooms, Steam Trestle area, and the Unit 2 Control Room. All valves in the above areas were in the proper position for current plant conditions.

General and i

specific comments are itemized below.

l a)

General Comments:

(1) Nameplate identification inconsistent with description in operating procedure.

b)

Operating Procedure No. 2-0700022, Rev 35, " Auxiliary Feedwater - Normal Operation:"

(1) SE-08-1 and V08660 were listed as located in the 2C AFW Pump Room on the alignment of Steam Supply System when, in fact, they were.in the 2A/2B AFW Pump Room.

(2) V09149, V09150, V09542, V09543, V09313, V09314, V09540, V09541, V09133, V09134, V09544, V09545 V09155, V09156, V09546, V09547 were LOCKED CLOSED valves.

Initial lineup per the OP was CLOSED only.

(3) V09540 and V09541 were LOCKED CLOSED with no valve label or position tag attached.

They_ appeared to be replacement valves.

These conditions were referred to the licensee for correction.

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Unit 2 Component Cooling Water

The inspector verified.the major CCW flow paths, reviewed

. applicable procedures and walked ~down' the system in the CCW Surge Tank area. Unit 2 Control. Room HVAC' area and the CCW structure. All' valves in the above areas were in.the proper position for. current plant conditions.

General -and specif'ic comments are itemized below.

a)

General Comments:

(1) Nameplate identification inconsistent with descriptions in the system operating procedure.

q (2) Description of' valves differ between Administrat he Procecure No. 2-0010123, Rev 67, " Administrative

'l Control of Valves. Locks and Switches." Appendix I I

and Operating Procedure No. 2-0310020. Rev 32,

" Component Cooling Water - Normal Operation."

(3) Tag missing on SH21339 (8" Drain SS-21-1B) ICW System b)

Operating Procedure No. 2-0310020, Rev 32, " Component Cooling Water - Normal Operation:"

4 (1) V14101 & V15536 were initially aligned to the CLOSED j

position; however, both had a handwheel locking device installed with no associated tag indicating LOCKED CLOSED.

1 (2) Line 4"-FP-126 upstream of V15536 (Fire Protection j

System to CCW surge tank) painted blue instead of red l

1 as on Unit 1.

(3) V14559 (LS-14-6B lower isol) omitted from initial lineup.

(4) V14438 (2A CCW HX outlet piping high point vent) omitted from initial lineup.

[

(5) 5814439 was initially aligned to the closed position; however, a handwheel locking device was installed with an associated tag inoicating LOCKED CLOSED.

This valve was also shown in Administrative Procedure No. 2-0010123, Rev 67, " Administrative Control of Valves, Locks and Switches," Appendix I as LOCKED CLOSED.

(6) V14187 (Chemical Feed Tank outlet) tag not attached.

(7) V14188 did not have a LOCKED CLOSED tag as shown in the initial alignment.

1

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c)

Off-Normal Operating Procedure No. 2-0030131. Rev 49,

" Plant ' Annunciator Summary:"

(1)

Identified sensino element for alarm S-12 as PT l 88, vice PIS-14-8B as indicateo on CWD.

(2)

Identified sensino element for alarm S-42 as TIS 29-2B1/2B2. vice TIS-14-29-181/1B2 as indica'ted on CWD.

(3)

Identified control room indication as " Check FIS 10A on RTGB-206" vice FIS-14-10B for alarm S-25.

d)

FSAR Table 9.2-7. " Component Cooling Water System Instrumentation Application:"

(1)

Identified CCW Hx Shell Side Outlet Radiation Recoroers as RR-2G-1,-2, vice RR-26-1,-2 as shown on CWD.

(2)

Identified Fuel Pool HX Outlet Temperature Tag Number as TE-14-2, vice TE-14-20 as shown on CWD.

(3)

Identified RCP & Motor Cooling Water Outlet total Combined Flow tag number as FIS-14-15F. vice FIS i 15B and the instrument range as 0-1500 gpm vice 0-4 2000 gpm.

(4)

Identified RCP & Motor Cooling Water Outlet Seal Cooler HX Tag Number as TDIS, vice TIS.

These conditions were referred to the licensee for correction.

b.

Plant Operations Review (71707)

The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions. This review included control room loas and auxiliary logs, operating orders, standing orders, jumper logs, and equipment tagout records. The inspectors routinely observed operator alertness and demeanor during plant tours. They observed.

and evaluated control room staffing, control room access, and operator performance during routine operations. The inspectors 4

conducted random off-hours inspections to ensure that operations and security performance remained at acceptable levels. Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures. Control room annunciatur status was verified.

Except as noted below, no deficiencies were observed.

4 i

L 6

1)

Vehicle Accident in plant Discharge Canal On July 9. an automooile was inadvertently driven into the plant disenarge canal. The automobile was occupied by three teenagers, who later reported that they were looking for a place to surf.

The occupants escaped by crawling out of the windows just prior to the vehicle being sucked into the 12' discharge pipe which routes water from the discharge canal, under the beach, into the Atlantic Ocean.

The automobile subsequently became lodged in the discharge pipe at a "Y" which split the 12' pipe into two discharge paths.

The obstruction created by the vehicle did not adversely affect safety at the f acility, as a 16' pipe also existed parallel to the 12' pipe.

The combined discharge capacity was more than

-sufficient to pass the effluent from both units' ICW pumps without raising disenarge canal levels to a level which would i

have resulted in a spillover of water into the adjoining mangroves.

The vehicle was removed by a combination of divers, who repositioned the cicle, and a tug boat, which pulled the vehicle from the pipe.

The vehicle was subsequently raised and removed from the area.

2)

Unit 1 Restart The inspector observed activities associated with the approach i

to criticality of Unit 1 on July 11. The evolution was supported by a reactivity manager, Reactor Engineering, and plant management. The inspector verified that ECCs were prepared correctly and were within periods of applicability,

{

that a 1/M plot was being prepared and maintained, and that control room staffing was adeouate and controlled.

Overall, the evolution was performed in a professional manner. The unit was placed on-line at 12:35 a.m. on July 12.

3)

CEDM Cooling Fan Failure j

On July 22 Unit I control room operators noted that HVE-21B, the B CEDM cooling fan,-had tripped off and.that HVE-21A, the standby fan, had started. Subsequent testing indicated that the motor for HVE-218 would start and run; however, amperege readings indicated the fan to be running at no-load conditions.

A containment entry and inspection revealed that the fan had failed catastrophically,.resulting in a. low air flow trip.

The fan in question was one of two designed to draw air from i

the reactor cavity around the CEDMs, pass the air through coolers, and discharge it to the containment environment. One fan was required at all times for power operation, and a loss of both fans required the unit to be suberitical within 45 l

7 minutes per ONOP 2-2000030. Rev 9. " Loss of Reactor Cavity, Reacter Support. CEDM. or Containment Cooling Fans."

The failure resulted in the cocking of the fan at an angle from horizontal. cocking of the motor shaft /f an shaf t at the coupling, damage to the variable vane linkage and supports, damage f pitot tubes in the discharge plenum. and damage to pillow olock bearings supporting the motor /pumo union. At the point :f failure, parts were dislodged and thrown from the unit. :reating holes in the fan shroud and in the screen which coverec the f an discharge. The licensee found debris scattered about the area surrounding the fan. The debris which was ejecteo did not damage adjacent equipment.

At the close of the inspection period, the licensee was attempting to oetermine root causes and corrective actions.

Corrective action options includeo repair at reduced power, repair curing a shutdown. and repair during the upcoming Unit 2 refueling outage.

c.

Plant Housekeeping (71707)

Storage of material and components, and cleanliness conditions of various areas throughout the f acility were observed to determine whether safety and/or fire hazards existed.

No violations or deviations were identified.

d.

Clearances (71707)

The inspector reviewed clearances 2-95-04-052, 2-95-06-106,and 2 06-095.

All tags were in place and components were found to be correctly positioned.

e.

Tecnnical Specification Compliance (71707)

Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.

These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.

Instrumentation and recorder traces were observed for abnormalities. The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened. The inspectors verified that related plant procedures in use were adequate, complete, and included the most recent revisions.

1)

Elevated Sea Water Temperature On July 7, the licensee noted that increased sea water temperatures were approaching the operating limits for the Unit 2 ICW/CCW heat exchangers. Sea water temperature had reached

t 8

approximately 87'F.

Control room operating curves for the heat exchangers wnich plotted maximum allowable intake temperature against existing neat exchanger-differential pressure, were clamped such that intake temperatures in excess of 88'F would result in heat exchanger inoperability.. Qual heat exchanger inoperability would have necessitated entry into TS 3.0.3, requiring a unit shutdown.

I The licensee's immediate actions were to check the calibration of the installed temperature indicators on the B heat exchanger (the higher reading of the two) and to install.a more accurate, digital, temperature indicator in its place.

The inspector observed portions of the calibration and data gathering effort and noted good involvement by the NPS, who sought to ensure that limits were not being violated.

The M&TE employed for the measurements was verified to be within its calibration interval. The inspector spoke to control room operators about the issue and found that they had been issued clear instructions to commence a unit shutdown should. temperature exceed 88'F.

1 The more accurate temperature instruments indicated that intake temperature plateaued at approximately 87'F.

Concurrently, Engineering began to develop new operating curve.s which incorporated actual heat exchanger performance data (e.g.

number of tubes plugged. actual pump degradation values) to arrive at new temperature / flow relationships.

As a result, Engineering determined that the maximum allowable temperatures for each heat exchanger exceeded 89'F at conditions of greatest flow. The inspector discussed the methodologies employed in deriving the curves with Engineering personnel and found them to be acecptable.

f.

Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems 1)

QA Audit Review (40500) a)

The inspector reviewed Q.A. Audit QSL-0PS-95-14

Corrective Action" dated June 29, 1995. This audit evaluated the implementation and effectiveness of the plant's corrective action program. The report found that the program was effectively implemented but identified three areas that needed improvement. These included:

e The database did not provide accurate information regarding the responsibility for and current status of pending corrective actions. Changes that occur in status were not always consnunicated to the STAR

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Coordinator.

i 9

e Several instances were identifieo where STARS reou1 ring work or repair on ASME Section XI j

components were not routed to the ANil or ISI

]

Coorcinator.

)

1 The authentication process for STARS that become o

cuality records was not clearly delineated. This resuitec in some STARS in the quality records system not meeting procedural and quality records j

reautrements.

The audit appeared to be detailed and provided management with a clear understanding of the current STAR system status.

b)

The inspector reviewed 0A Audit QSL-0PS-95-13, which summar1:ec cerformance monitoring activities in the areas of ILRT/LLRT programs. CMM, corrections of discrepant field conoitions. Maintenance Department corrective actions. M&TE programs, and protected area controls.

In general, the audit found the subject activities to be performed satisfactorily. The. inspector noted that a number of minor changes in M&TE control and storage methods resulted from one of the PMONs and that the nature i

of the changes appeared to offer opportunities for greater control of M&TE. The inspector concluded that the audit was both detailed and multidisciplinary.

2)

Post-Trip Review (92901)

The inspector attended a meeting, conducted on July 21 by Operations management, which discussed the Unit 1 High Pressure trip discussed in paragraph 4.b, below.

This was the second such neting following an automatic trip, and was designed to elicit comments from plant operations and support personnel on ways to avoid similar trips in the future.

Presentations covered the circumstances surrounding the event, the effect on the unit, preliminary lessons learned and an open discussion of options to prevent recurrence. The meeting was heavily attended and input and exchanges were frank. The inspector concluded that this practice continues to provide plant.

management with practical options for reducing the number of automatic trips in the future.

g.

Followup of Operations LERs (90712)

(Closed) LER 50-389/94-006, Rev 1. " Trip Circuit Breaker Failure due to a Broken Piece of Phenolic Block Lodged in the Trip Latch Mechanism"

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- The licensee provided the. subject LER-as informational following the failure of a TCB to open during RPS logic matrix testing in July,-

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1994.

The incident wnich prompted the LER is. descr1beo in IR 94-15.

The licensee's corrective actions involved a replacement of the -

subject TCB. an inspection of the remaining Unit 2 TCBs and CEA MG c

output breakers, an inspection of Unit I TCBs (discussed in IR 94-24), and an evaluation of the use of a locking compound on cutoff i

switch phenolic block. screws to prevent the backing out of the' l

screws (believed to be responsible for the subject failure).

]

The licensee's corrective actions have been completed. No similar conditions were noted in TCB inspections and' no loose screws were -

found.

The licensee and the vendor concluded that the application

]

of locking compounds was not necessary. -The licensee determined that routine, periodic.. inspections would suffice to detect-loosening of the subject screw. The inspector concluded that the licensee's actions were appropriate to the c1rcumstances.

)

Revision I to'this LER also documented a failure to perform a TS j

required' shutdown as a result of an inoperable TCB channel. This aspect of the event was documented as VIO 94-15-01.

The licensee's corrective' actions were found to be satisfactory and the violation was closed in IR 94-24. This item is closed.

h.

Self Contained Breathing Apparatus (SCBA) Needs and Availability Survey (71707, 64704) i The following information was provided by the licensee in response to a questionnaire prepared by NRC Region II:

i)

Facility Name, l

St. Lucie Nuclear Power Plant 2)

Event (s) which require operators in the control room to wear SCBA to safely operate / shutdown the plant.

FSAR states chlorine but chlorine is no longer stored or used onsite.

j 3)

For the limiting. event, does the licensee have SCBAs available for each staff member filling a required position for operation or safe shutdown?

5 SCBAs stored in each Control Room.

4)

' Are all staff members filling required positions for operations or safe shutdown.SCBA qualified?

No', but licensee has plans that will qualify required operations personnel by July 31, 1995.

4

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Are SCBAs readily available at requirec use location.

Yes 6)

Have provisions been provided for special needs associated with SCBA use, i.e., eye glasses with face mask inserts.

l i

No, on eye wear.

Licensee will correct by July 31, 1995.

7)

What is the minimum number of spare air bottles for each user, j

None provided in Control Room.

Stored in fire house and RCA.

B)

Has the licensee established plans to protect personnel not assigned a SCBA?

Yes.

If emergency responder will be SCBA qualified.

9)

Does the licensee have SCBAs available for NRC use?

None specifically assigned to NRC, but available for issue at HP.

10)

Initials of each resident and indicate if he/she is SCBA qualified.

RLP - Yes, MSM - Yes 11)

If not qualified, discuss steps necessary to have residents SCBA qualified with your Branch Chief.

N/A

12) Comment field.

Chlorine not onsite - FSAR will be corrected next update.

4.

Maintenance and Surveillance a.

Maintenance Observations (62703)

Station maintenance activities involving selected safety-related systems and components were observed / reviewed to ascertain that they were conducted in accordance with requirements. The following items were considered during this review: LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were perfomed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required. Work requests were reviewed to detemine the status of outstanding jobs and to ensure that priority was assigned to safety-

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l 12 related eouipment.

Portions of the following maintenance activities were observeo:

1) 2C Aux 111ary Feedwater Pump Preventive Maintenance The insoector observed an oil change on the 2C AFP, conducted per PWO 62/4389.. Work was performed in accordance with 2-M-0018. Rev 42, " Mechanical Maintenance Safety-Related Preventive Maintenance Program." The inspector verified that proper replacement oil was used. that the old oil was free of visible -

contaminants, that the final oil level was adequate, and that the new oil filter was a direct replacement for the old one.

1 The inspector also observed the lubrication of the turbine's trip throttle linkage, performed under PWO 62/4421, and verified that the proper grease and graphite spray was used.

The inspector found that the quality of the work performed was satisfactory; however, the timeliness of the work was found to suffer from inadequate prior planning.

The work had been scheduled to begin at midnight on July 18.

In support of the evolution, Operations declared the subject AFP OOS at 9:20 p.m.

on July 17.

At 1:00 a.m., an electrician arrived at the work site to disconnect a lube oil immersion heater which required removal for the oil change to take place.

This task was completed in approximately five minutes.

At approximately 3:10 a.m., mechanics arrived to perform the oil change. As a result, the subject pump was out of service for approximately six hours before the subject task was begun in earnest.

The inspector discussed the timeliness of the maintenance with Maintenance Supervision, who stated that the personnel involved in the oil change had questioned a procedure revision which changed the specification of the lubricating oil from that used the last time they had performed the task. Additional complications were experienced in employing the licensee's new PASSPORT system to obtain spare bottles and jugs to support the work. It was acknowledged in these discussions that the job was not properly pre-planned / pre-staged, and that the confusion could have been dealt with prior to the initiation of work.

Given the licensee's development of a critical (on-line) maintenance process, the inspector reviewed AP 0010460, Rev 3,

" Critical Maintenance Management."

In general, the procedure required that work on TS equipment, involving a voluntary

entrance into a TS AS, be preplanned and expedited. However, the inspector noted that section 3.1.3 of the subject procedure stated that the procedure need not apply to " Routine preventive maintenance on equipment required more frequently than 18 months that is not risk significant..." The subject maintenance activity constituted a quarterly PM and therefore j

was outside the requirements of the procedure. The inspector discussed the' issue with licensee management, who. acknowledged i

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l 13 the apparent dichotomy between the CMM process's mandate that time in a TS AS be minimizeo for some maintenance evolutions but not for others. The licensee stateo that they would consider the issue.

The inspector concluded that no regulation was violated, as the licensee was well within the A0T for the 2C AFP and the maintenance in question was performed satisfactorily and within the bouno of the licensee's programs and procedures.

However, the inspector founo that preplanning for the evolution was poor and unnecessarily increased the out of service time for the 2C s

AFP.

2)

Auxiliary Feeowater Pump 1B Critical Maintenance The inspector observed maintenance activities performed on the 1B AFP on July 20. The work was conoucted under the guidance of AP 0010460. Rev 3. " Critical Maintenance Management."

Specific observed activities includeo:

e PWO 61/4933 - Replacement of pumo bearing Trico oilers with indicating sight glasses and installation of oil sample test fittings. The replacement was conducted per 1 MMP-09.01. " Auxiliary Feedwater Pumps lA and IB Disassemoly, Inspection. and Reassembly Mecnanical Maintenance." and Procurement Engineering evaluation 036912. The inspector verified that the installation was conducted satisfactorily and in accordance the governing documents.

PWO 61/4974 - 1B AFP coupling and thrust bearing checks.

e The subject activity was conducted under 1-MMP-09.01,

" Auxiliary Feedwater Pumps lA and 1B Disassembly, Inspection, and Reassembly Mechanical Maintenance." The inspector observed coupling disassembly and cleanup, pump thrust bearing endplay measurement, coupling reassembly and final torquing. The inspector noted that pump endplay was acceptable (.006") and that the mechanics performing the work properly reassembled and torqued the pump coupling. The torque wrench was verified to be in calibration.

Overall, the inspector found that the maintenance evolution 'was perfomed very well. Jobs were worked concurrently, QC coverage was detailed and thorough, parts and tools were adequately prestaged, and the evolution was completed expeditiously. The inspector noted that the time the component was 005, including the post-maintenance surveillance run, was only approximately eight hours.

14 3)

PWO 64/4966 Unit 2 Plant Vent.WRGM Loss of Counts c

The. inspector observed portions of the troubleshooting effort in response to a failure of the Unit 2 WRGM.

I&C personnel performing the evolution were found to be very knowledgeable of the equipment's construction and operation.

Trouoleshooting was methodical and thorough.

M&TE used,n the effort was verified to be within its calibration interval. -The source of the failure was determined to'be a high voltage power supply to the unit's detector.

I b.

Surveillance Observations (61726) l Various plant operations were verified to comply with selected TS reauirements. Typical of these were confirmation of TS compliance 1

for reactor coolant chemistry, RWT conditions, containment pressure,

'ontrol room ventilation, and AC and DC electrical sources. The c

i inspectors verified that testing was performed in accorcance with adeouate procedures, test instrumentation was calibrated, LCOs were met. removal and restoration of the affected components were accomplished properly, test results met requirements and were l

reviewed by personnel other than tne individual directing the test, and that any deficiencies identified during the testing were L

properly reviewed and resolved by appropriate management personnel.

The following surveillance tests were observed:

4 1)

OP 10030150, Rev 74, " Secondary Plant Operating Checks and Tests, Section 8.2 through 8.8 Turbine Trip Test."

f The inspector attended the prejob briefing and found that the procedural steps, requirements and precautions were discussed in detail with all personnel involved in the test.

L The inspector then observed the overspeed, thrust bearing and

~

low vacuum trip tests. The low bearing oil pressure trip could not be done since valve V22174, low bearing oil pressure trip drain valve could not be operated.

PWO #74457 was attached to the valve indicating that work was needed.

The other above tests were completed satisfactorily.

The operator then proceeded to test the 20/ET, EH Fluid Trip Header Solenoid valve and the 20-1/0PC and 20-2/0PC Overspeed o

Protection Solenoid. valves. This test consisted of opening the i

EH test header valves to the solenoid under test; unlocking and closing the EH inlet isolation valve under test; inserting and turning the trip test key.

4 This test was completed satisfactorily on 20/ET.

When the second solenoid valve was tested, the operator opened the EH test header valve, V22493, and unlocked, but did not close, the solenoid inlet isolation valve V22482 as required by the procedure. After unlocking and removing the lock he laid doun

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t 1

l 15 c

1 1

the lock, read the procedure, and then inserted the test key into the 20-1/0PC test switch and turned it to the test

. osition. A loud noise was noted as the governor valves went p

shut, the turbine tripped, and the main steam safety valves..

t i-opened.

I The inspector and the NWE then went to Unit I control room.

In the control room, the operators responded to the event as required by E0P-01, " Standard Post Trip Actions." All rods inserted and' equipment responded to the event as designed. The reactor tripped on High Pressurizer Pressure as a result of the E

Gov 6rnor and Reheat valves going shut.

Steam Generator "A" i

experienced a high level, but operator action isolated feed and the level was restored to normal. Overall, operator response to the event was considered excellent.

The N!.0 performing the surveillance test openly acknowledged that he inadvertently failed to close the EH inlet isolation valve V22482 per procedural step 8.6.5.(B) while performing the j

solenoid valve tests and that this resulted in tripping the unit. The NWE supervising the test stated that he became too involved in radio communications with the control room and did not verify that each step was completed in sequence.

The inspector also noted that procedural step 8.6.5.B and several other steps contained two required actions in one procedural step and that this may have led to the error. He also noted that the use of hand held radios vice sound powered head sets for comununications may have been a contributing factor.

The unit was placed in a stable plant condition using 1-EOP-02,

" Reactor Trip Recovery." A decision was then made to accomplish several outstanding maintenance activities prior to plant restart. This work included:

e Relocate Channel "D" NIS jump'er from the control room to the Reactor Building Keyway area e

Rework 3 CEA reed switches l

e Repair 1A FW Regulating valve e

Inspect / repair RCP vibration probe Repair RPS Channel "C" Wide Range NIS (failed low after e

reactor trip) e Repair Main Generator excitation power supply e

Repair loose connection on 18 Motor Generator set e

Stroke test M-08-8 e

Repair M-09-6 e

Cleaning Main Condenser Water boxes Al and B2 e

Other minor maintenance activities The above work activities, except the NIS Channel "C" Wide Range, were completed by the noming of July 9.

Complettom of

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the repair to NIS Channel "C" Wide Range, and concerns relating to high discharge canal levels resulting from unusually high

-tides.and an automooile lodged in a discharge canal. pipe (discussed in paragraph' 3.b.1), delayed reactor restart until July 11.

The inspector reviewed the above work activities and found them satisfactory. The reactor trip package was also reviewed and it was determined that all issues had been satisfactorily J

resolved to permit plant restart.

2)

OP 1 0700050, Rev 50, " Auxiliary Feedwater Periodic Test" The inspector observed the surveillance test. conducted per the above proceoure, on the IB AFP following CMM work discussed in J

paragraph 4.A.2. above. The test involved an ASME Section XI i

code run of the suoject pump. The inspector noted that the operator conducting the test locally had procedure in-hand and that M&TE employed for obtaining vibration and temperature data was within its calibration interval. The required time interval was observed prior to data collection (5 minutes),

a i

discharge pressure was greater than the minimum specified for compliance with TS (1342 psig), and results were satisfactory (3241.7 ft developed head).

3)

OP 2-2200050B, Rev 20. "2B Emergency Diesel Generator Periodic j

Test and General Operating Instructions" The inspector witnessed portions of this test, conducted July

26. The test involved a fast start of the 2B EDG to satisfy TS surveillance requirement 4.8.1.1.2.a.4, which required that the EDG achieve rated speed and voltage within 10 seconds at least once per 184 days.

The inspector witnessed pre-start checks performed by the SNP0 and found them to be performed satisfactorily with procedure in-hand. The inspector observed the EDG start and examined the operating machines for signs of previously unidentified leaks.

None were noted. The machines started and loaded satisfactorily, with a start time of 9.65 seconds.

4)

EDG Day Tank Level Switch Surveillance 1

The inspector observed portions of surveillance tests, performed in accordance with 1&C Procedure 2-1400064L, Rev 32,

" Installed Plant Equipment Calibration (Level)," Appendix 8,'

Tab 10. " Diesel 011 Day Tank Lo/Lo level Verification," to verify day tank level switch setpoints on the 28 EDG day tanks.

The tests were performed by attaching tygon tubes to drain valves located, hydraulically, at the bottoms of the day tanks and routing the tubes vertically to the tops of the tanks.

w..

.4

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l 17 1

Rulers were then located next to the tubes to provide local level indication in the tanks to assess alarm setpoints.

The test methodology for testing hi/hi. level alarms was to i

align the temocrary standpipes with their respective day tanks 2

and manually operate the tanks' fill. solenoid valves to admit fuel until the hi/hi level alarms were received.

The inspector noted that the I&C personnel performing the tests were sensitive to the fact that indicated level increase rates would accelerate as the levels approached the tops of the tanks, as-i the tanks were horizontally oriented cylinders. Nonetheless, while filling the 2B1 day tank, the level in the tygon tube l

rose rapidly and resulted in a small spill (approximately two 1

cups) of FO. The spill was quickly terminated, contained to a i-small area around the day tank, and cleaned up by the I&C personnel performing the test. Additionally, the h1/h1 level alarm aid not energize. Upon inspection, it was noted that a PWO tag was hung on the level alarm, indicating inoperability of either the circuit or the sensor.

The I&C personnel performing the test acknowledged not checking the PWO tag prior to beginning the test. Testing of the 10/10 level alarms resulted in satisfactory. results.

The inspector discussed the performance of the test with I&C personnel, who stated that the hi/hi level alarm did not energize due to the fact that the 2B2 day tank hi/hi alarm was energized as a result of performing the same test on it previously. As the hi/hi level alarms had no reflash capability, the second day tank's alarm could not annunciate.

I&C personnel conceded that the governing procedure was inadequate to test the hi/hi alarms as written, and stated that 1

the procedure would be revised. Possible new test methodologies included:

Testing the second tank's alarm after the first tank's e

alarm had cleared due to engine fuel consumption, or Performing the test by monitoring level switch output e

state, as opposed to the alarm annunciator I&C personnel stated that the PWO which was written to document hi/hi level switch inoperability was most probably the result j

of a similar failure in a similar test. The inspector concluded that the F0 spill could have been avoided if either the tygon tubing had been run further in elevation above the day tank or if the workers performing the test had recognized that the level switch they were testing would not result in annunciation due to the alara condition in the 2B2 day tank.

In reviewing the governing procedure, the inspector noted the

)

following weaknesses:

i y

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- se y

2.,,-o

.-.__.__.,..___.________________._______m.._

i 18 The title for Tab r10 of the procedure (" Diesel Day Tank Lo/Lo Level Verification") was misleading in that hi/h1 level alarm verification was also included. This point was reinforced in the bocy of the proceoure in step 8.2 when personnel were directed to pince a measurement scale from 20" to 25" up the sight glass, when hi/hi level alarm verification would also require a measurement scale at approximately 34".

Personnel performing the observed test showed foresight in extending the measurement scales along the full length of the sight glasses, The procedure directed that tygon tubes be taped to the e

top of the day tanks. The physical arrangement of the day tanks' overflow lines was such that the FO level could increase approximately l' above the tops of the tanks prior to the overflow being directed away, increasing the j

potential for spills.

l The inspector. concluded that the performance of the subject surveillance test suffered from procedural weakness and an inadequate pre test observation of the component to be tested.

5)

Containment Anomalies Inspection - Unit 2 The inspector accompanied Unit 2 NL0s on an inspection of accessible containment areas on July 25.

Damage to HVE-218, described in paragraph 3.b.3, above, was noted.

The status of a packing leak from V8453, a root valve for B channel SG level and pressure instruments, was inspected and found to be unchanged.

Several instances of boric acid buildup on i

instrument tubing was also noted. Otherwise, no adverse conditions were identified. The inspector found that the NL0s conducting the inspection proceeded swiftly but were thorough in their inspections, allowing for a comprehensive tour while maintaining dose rates ALARA.

5.

Engineering Support (37551)

A.

Safety Evaluation JPN-PSL-SENS-95-013 The inspector reviewed the subject SE, prepared to allow operation with a manual isolation valve closed in the 28 EDG F0 line from the D0ST to the day tanks. The configuration was proposed when the a leak was detemined to exist in the underground line between the two tanks.

The action was designed to minimize the amount of F0 released to the environment until the leak could be identified and corrected.

As a compensatory measure, the licensee proposed dedicating an NL.0 to the task of opening the closed valve in the event of an EDG start. The licensee calculated that the EDG day tanks contained enough FO to allow 126 minutes of EDG operation at full, load before

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19 j

4 a transfer of FO was required. The. licensee then specified that the NLO would be required to open the valve within 20 minutes of an EDG start.

Procedures were revised.to include direct' ion to open the valve on an EDG start. and.aoministrative controls were put in place to ensure that the NLO would not be required to perform any other

'immediate response duties. Additionally, the licensee perfomed a response time test, placing the operator at the G-2 warehouse (as far away from the EDG as he could credibly be in the PA) and requiring the NLO to proceed to the valve and open it. The NLO performed' this task in approximately seven _ minutes.

In considering the issue, the licensee employed PRA' techniques to L

estimate the increase in the risk of the loss of the 2B3 bus due to a failure of either the operator to open the valve or a failure of the valve to be able to be opened. The licensee concluded that the increase.in procability was-approximately 6 percent. However, in i

considering 10 CFR'50.59 criteria, the licensee concluded that no increase in the prooability of failure of a component important to safety was created by the proposed action.

The inspector questioned the licensee on this issue.

The licensee explained that a deterministic conclusion of no increased probability was reached when the existence of procedural guidance and heightened awareness was balanced against the approximate 6 percent increase in failure j

probability presented by the two new failure _ modes.

In the context of regulatory compliance, the inspector noted that 10 CFR 50.59 was written in terms of absolute increases in the probabilities of failure represented by a proposed change. The inspector continued to question whether 10 CFR 50.59 criteria could ever be satisfied when new failure modes are imposed on a previously reviewed system (i.e whether added risk, once qualitatively L

established, could be completely mitigated). The inspector concluded that insufficient guidance existed from a regulatory j

perspective to take inunediate issue with the licensee's rationale.

i Further, the inspector concluded that the licensee had taken prudent i

measures to ensure the continued operability of the 28 EDG while minimizing the FO leak's effect on the environment. The inspector referred the question to NRR for resolution.

i J

6.

Plant Support (71750)

a. -

Fire Protection During the course of their nomal tours, the inspectors routinely examined facets of. the Fire Protection Program. The inspectors -

reviewed transient fire loads, flammable materials storage, housekeeping, control hazardous chemicals, ignition source / fire risk reduction efforts, fire protection training, fire protection system surveillance program, fire barriers, fire brigade qualifications, and QA reviews of the program. No deficiencies were identified.

I 20 b.

Physical Protection During this inspection, the inspector toured the protected area and noted that the perimeter fence was intact and not compromised by erosion or disrepair. The fence fabric was secured and barbed wire was angled as required by the licensee's Physical Security Plan (PSP).- Isolation zones were maintained on both sides of the barrier and were free of objects which could shield or conceal an individual.

The inspector observed personnel and packages entering the protected area were searched either by special purpose detectors or by a physical patdown for firearms, explosives and contraband. The processing and escorting of visitors was observed.

Vehicles were searched, escorted, and secured as described in the PSP.

Lighting of the perimeter and of the protected area met the 0.2 foot-candle criteria.

In conclusion, selected functions and equipment of the security program were inspected and found to comply with the PSP requirements.

c.

Radiological Protection Program Radiation protection control activities were observed to verify that these activities were in conformance with the facility policies and procedures, and in compliance with regulatory requirements. These observations included:

Entry to and exit from contaminated areas, including step-off pad conditions and disposal of contaminated clothing; e

Area postings and controls; Work activity witt.ir. rsdiation, high radiation, and e

contaminated areas; Radiation Control Area (RCA) exiting practices; and, e

Proper wearing of personnel monitoring equipment, protective o

clothing, and respiratory equipment.

No violations or deviations were identified.

7.

Exit Interview The inspection scope and findings were summarized on July 27, 1995, 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. Dissettting comeents were not received from the licensee.

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21 IY.21 Item Number Status Descriotion LER 50-389/94-006, Rev 1

. Closed

'" Trip Circuit Breaker Failure due to a Broken l

i Piece of Phenolic Block-Lodged in the Trip Latch Mechanism", paragraph 3.g.2).

p 8.

Abbreviations, Acronyms, and Initialisms

'AE00.

' Analysis and Evaluation of Operational Data, Office for (NRC)

AFP-Auxiliary Feedwater Pump i

AFW.

Auxiliary Feedwater (system)

ALARA As-Low as Reasonably Achievable (radiation exposure) i ANII Authorized Nuclear Inservice Inspector ASME Code American Society of Mecnanical Engineers Boiler and Pressure Vessel Code CCW Component Cooling Water CEA Control Element Assemoly CEDM.

Control Element Drive Mechanism CIS Containment Isolation System CMM Critical Maintenance Management CWD Control Wiring Diagram DG Diesel Generator ECC Estimated Critical Concentration ECCS-Emergency Core Cooling System EDG Emergency Diesel Generator E0P Emergency Operating Procedure ESF Engineered Safety Feature i

ESFAS Engineered Safety Feature Actuation System F0 Fuel Oil

)

FSAR Final Safety Analysis Report FW Feedwater gpa Gallon (s) Per Minute.(flow rate)

HVAC Heating Ventilation and Air Conditioning HVE Heating and Ventilating Exhaust (fan, system, etc.)

HX

. Heat Exchanger ICW Intake Cooling Water ILRT Inte rated Leak Rate Test (ing)

IR-(NRC Inspection Report ISI Inservice Inspection (program)

JPN (Juno Beach) Nuclear Engineering LC0-

' TS Limiting Condition for Operation LER Licensee-Event Report i

LLRT

' Local Leak Rate Test MP.

Mechanical Maintenance Procedure MV Motorized Valve NIS Nuclear Instrumentation System NLO -

Non-Licensed Operator NPS

. Nuclear Plant Supervisor i

NRR-INtc Office of Nuclear Reactor Regulation

l

,e 22 NWE Nuclear Watch Engineer DNOP Off Normal Operating Procedure 005 Out Of Service

'OP Operating Procedure OPS Operations PMON Performance Monitoring PORY Power Operated Relief Valve PRA Probabilistic Risk Assessment psig Pounds per square inch (gage)

-PSL Plant St. Lucie PWO Plant Work Order QA Quality Assurance QC Quality Control QSL Quality Surveillance Letter RCP Reactor Coolant Pump RPS Reactor Protection' System RTGB Reactor Turbine Generator Board RWT Refueling Water Tank

.SCBA Self Contained Breathing Apparatus SG Steam Generator SNP0 Senior Nuclear Plant (unlicensed] Operator TCB Trip Circuit Breaker TS Technical Specification (s)

WRGM Wide Range Gas Monitor 4

O t

ML20137R883

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