IR 05000250/1995019

Insp Repts 50-250/95-19 & 50-251/95-19 on 951015-1118.No Violations Noted.Major Areas Inspected:Plant Operations Including Operational Safety & Plant Events;Maint Including Surveillance Observations;Engineering & Plant Support

ML17353A480
Person / Time
Site:	Turkey Point
Issue date:	12/04/1995
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A478	List: IR 05000250/1995019 ML17353A475
References
50-250-95-19, 50-251-95-19, NUDOCS 9512180410
Download: ML17353A480 (44)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30m4199 Licensee:

Florida Power and Light Company 9250 West Flagler Street Hiami, FL 33102 e,S REco

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Report Nos.:

50-250/95-19 and 50-251/95-19 Docket Nos.:

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspection Conducted:

October 15 through November 'j8, 1995 Inspectors:

+ +

/A T.

P. Johnson, nio esident Date S gned Inspector B.

B. Desai, Resident Inspector W. P; Kleinso

, Senior Reactor Inspector Approved by:

K.

D. Landis, Chief Reactor Projects, Branch

Division of Reactor Projects

/z Date Si ned SUHHARY Scope:

This resident inspection was performed to assure public health and safety, and it involved direct inspection at the site in the fol.lowing areas:

plant operations including operational safety and plant events; maintenance including surveillance observations; engineering; and plant support including radiological controls, chemistry, fire protection, and housekeeping.

Backshift inspections were performed in accordan'ce with Nuclear. Regulatory Commission inspection guidance.

Results:

Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe plant operations.

The inspectors identified the following two non-cited violations:

Non-Cited Violation (NCV 50-250,251/95-19-01)

Failure to Adequately Configure Several Valves in Their Required Positions, (section 3.2.3).

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95i2i804i0 95i204 PDR ADOCK 05000250

PDR

.Non-Cited Violation (NCV 50-250,25}/95-.1P-02)

Failure to Adequately Install and Test a Halon Hodi.fication (section 6.2. 1).

During this inspection period, the inspectors had comments in the following functional areas:

Plant 0 erations Licensee response (including operations, event 'yesponse team, and management)

was very good" to a Unit 3 manual.;r'e'actor trip (section 3.2. 1).

Two temporary system alterations were 'ap'propriately implemented and the number of temporary system alterations open remained low Q(rection 3.2.2).

Two licensee-identified configuration control problems resulted in a non-cited violation.

Further, minor weakness pertaining to control room logging and a revision to an operating procedure were noted (section 3.2.3).

The inspector concluded that the Post Accident Sampling, Hydrogen Monitoring, and Containment Ventilation*systems were aligned as required by current plant conditions (section 3.2.4).

lhe licensee's outage critique was thorough and appeared effective (section 3.2.5).

The inspectors plan to monitor the effect of staff reduction of approximately five percent on plant performance (section 3.2.6)

and corporate and site senior management changes (section 3.2.7).

Operator response to a steam generator level control.failure was app'ropriate and timely (section 4.2.4).

Maintenance t

Inspector observed station maintenance and surveillance testing activities were completed in a satis'factory manner (sections 4.2. 1 and 4.2.2).

Licensee attempts to retrieve a bolt from the 3B intake cool,ing, water pump motor cable conduit were aggressive:.

Although the bolt was

'ot retrieved; the evaluation and planned corrective action pertaining to foreign material exclusion were adequate

'(section 4.2.3).

Aggressive troubleshooting activities by instrument and control personnel identified the cause of the steam generator level control problem.

(section 4.2.4).

Breaker maintenance activities were accomplished with well written and concise procedures (section 4.2.5).

Reactor protection system "testing was well performed with excellent communications and

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coordination (section 4.2.6).

Actions related to the 48 Reactor Coolant Pump low oil level alarm were well planned, coordinathd, and implemented (section 4.2.7).

Minor weakness pertaining to preventive maintenance of the Unit 3 Intake Area Gantry Crane were noted (section 4.2.8).

A minor weakness pertaining to vendor oversight as it related to Instrument Air System maintenance was noted (section 4.2.9),

Maintenance of the ultimate heat sink was noteworthy (section 4.2. 10).

En ineerin The post-accident sampling system engineer was very knowledgeable and exhibited a strong sense of ownership (section 3.2.4).

A walkdown of.

the modifications to the Instrument Air system and compressors was performed and no significant deficiencies were identified (section

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5.2. 1).

The Spent Fuel Pool design description in the Updated Final Safety Analysis Report did not reflect the current practice of a full core off-load; however, decay heat removal capability remained unaffected.

The licensee plans'o update the Updated Final Safety Analysis Report to better reflect current practice as well as design bases (section 5.2.2).

Routine reports and a licensee event report regarding a Unit 3 manual reactor trip and a Halon check valve issue were thorough, timely, and accurate (section 5.2.3).

Plant Su ort An incorrect fire suppression (Halon) system check valve orientation resulted from both an inadequate modification installation and inadequate testing in 1986.

This issue is a non-cited violation (section 6.2. 1).

Emergency plan changes for a motorcar race-track wi'thin the emergency planning zone appeared appropriate.

However, issues associated with formal notification by the state to the Federal Emergency Nanagement Agency are still under review (section 6.2.2).

The licensee was responsive to inspector questions pertaining to observed fire drills.

Further, the licensee took appropriate corrective actions following an unsatisfactory fire drill when a fire brigade member did not respond (section 6.2.3).

Although fire protection issues occurred during the period, (including an inadvertent Halon discharge, an incorrect Halon check valve installation, and fire brigade'staffing not being met for a short period),

the inspectors concluded that the fire protection program remained effective based on overall fire protection response and based on the organizations'ggressive correction actions.

The license demonstrated effective at-power containment entry control, and good team wbrk was noted among all organizations involved (section 6.2.4).

The Unit 3 Cycle 15 refueling outage exposure was low.,

indicating excellent'icensee performance (section 6.2.5)'.

'-'An'mergency plan drill was well conducted (section 6.2.6).

TABLE Of CONTENTS 1.0 Persons Contacted

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1.1 1.2 1.3 Licensee Employees

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NRC Resident Inspectors

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Other NRC Personnel on Site

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2.0 Plant Status...........

2.1 Unit 3..

2.2 Unit 4 3.0 Plant Operations

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4.2 Inspection Findings

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5.1 Inspection Scope

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5.2 Inspection Findings 6.0 Plant Support

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Inspection Findings

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REPORT DETAILS 1.0 Persons Contacted Licensee Employees T. V.

R. J.

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Abbatiello, Site guality Manager Acosta, Company Nuclear Review Board Chairman Balaguero, Technical Department Supervisor Banaszak, Technical Department Manager Bohlke, Vice President, Engineering and Licensing Geiger, Vice President, Nuclear Assurance Goldberg, President, Nuclear Division Hartzog, Business Systems'anager Heisterman, Maintehance Ha'nager Higgins, Outage Manager..

Hollinger, Training Manager Hovey, Site Vice-President Huba, Procurement Supervisor Jernigan, Plant General Manager Johnson, Operations Manager Jurmain, Electrical Maintenance Supervisor Kaminskas, Services Manager Knorr, Regulatory Compliance Analyst Koschmeder, Acting Instrumentation and Controls Maintenance Supervisor Kundalkar, Engineering Manager Lindsay, Health Physics Supervisor Harcussen, Security Supervisor Miller, Acting Projects Supervisor Paduano, Manager, Licensing and Special Projects Plunkett, President, Nuclear Division (effective 3/1/96)

Prevatt, Operations Support Supervisor Rose, Nuclear Materials Manager Singer, Operations Supervisor Steinke, Chemistry Supervisor Symes, guality Manager, Juno Beach

Tomaszewski, Acting Technical Manager Waldrep, Mechanical Maintenance Supervi.sor Warriner, guality Assurance Supervisor Weinkam, Licensing Manager Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.

1.2 NRC Resident Inspectors

• B B

• T P

Desai, Resident Inspector Johnson, Senior Resident Inspector

1.3 Other NRC Personnel on Site

• K. D. Landis, Chief, Reactor Projects Branch 3, Division of Reactor Pro'jects L.

R. Moore, Region II Inspector

• W.

P. Kleinsorge, Senior Reactor Inspector R.

P. Carrion, Senior HP Inspector

Attended exit interview (Refer to section 7.0 for additional information.)

Note:

An alphabeti.cal tabulation of acronyms used in this report is

. listed in section 8.0 of this report.

2.0 Plant Status a'~.

2.1 Unit 3 2.2 At the beginning of this reporting period Unit 3 was returning to full power from a refueling outage.

The following evolutions occurred on this unit during this period:

The unit reached 100%

power on October 15, 1995, On October 17, 1995, the reactor was manually tripped due to problems with control rod power supply.

The unit was brought critical on October 17, 1995 and reached 100%

power on October 18, 1995.

On November 7, 1995 the unit was reduced to 80% power to effect repairs on the 3C Steam Generator Level Control System.

The unit was returned to 100% power on the same day and operated at 100% power for the remainder of the report period.

Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near 100% reactor power and had been on line since March 12, 1995.

The unit operated at or near 180% for the entire report period.

3". 0 Plant Operations (40500 and 71707)

3. 1 Inspection Scope The inspectors verified that the licensee operated the facilities safely and in conformance with regulatory requirements.

The inspectors accomplished this by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and technical specification compliance, review of facility records, inspections of outage activities, and evaluation of the licensee's management critique.

The inspectors reviewed plant events to determine facility status and the need for further followup action.

The significance -of these events was evaluated along with the performance of the

3.2 3.2.1 appropriate safety systems and the actions taken by the li,censee.

The inspectors ver-ified that required notifications were made to the NRC and that licensee followup including event chronology, root cause determination, and corrective actions were appropriate; The inspectors also performed a review of the licensee's self-assessment capability including PNSC activities, gA/gC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicators.

Inspection Findings Unit 3 Manual Reactor Trip At 4:49 a.m.

on October 17, 1995, with Unit 3 at 100% reactor power, control room operators initiated a manual reactor trip due to indications that four control rods dropped into the reactor core.

Operators received annunciator alarms 87/1 and B9/4 indicating a rod drop and a

RCC urgent failure, respectively.

Operators confirmed that rods K2, B6, F14, and P16 (Control Bank B, Group.2)

had dropped, and thus the operators entered procedure 3-0NOP-028.3, Dropped RCC.

(The ONOP required a manual reactor trip if three or more control rods are dropped).

Thus, a manual reactor trip was initiated, and operators entered procedure 3-EOP-E-O, React'or Trip or Safety Injection.

Conditions were normal on the trip.

All rods inserted as expected, and AFW automati.cally started on low steam generator levels due to the level shrink.

RCS temperature and pressure were maintained by dumping steam to the atmosphere.

The licensee initiated a

CFR 50.72 notifi.cation at 5:53 a;m.,

and called the inspector at home.

The licensee also initiated a'ondition report (No. 95-1047),

an event review team followup, and a

CFR 50.73 LER (No,95-007).

The licensee inspected the 2BD rod control power cabinet for any abnormal indications.

This cabinet supplies power to group 2 rods for control bank 8, control bank D,

and shutdown bank B.

The rods that dropped were group 2 of control bank B.

The licensee noted that local alarms indicated a possible blown fuse; or a bridge thyristor failure; or a phase, a control regulation, or a firing card failures.

Further, a small amount of water (less that a half of cup)

was observed dripping from two concrete patches in the ceiling above the cabinet, onto the cabinet, and inside the cabinet.

Inside the cabinet, the water was observed on several cards, including the control bank B group 2 circuit cards which control the stationary coils and moveable coils.

Thus, the licensee suspects that the wetted cards caused the affected four control rods'tationary and moveable coils to de-energize, dropping the rods into the cor The licensee inspected the cable spreading room (CSR)

and noted water on the floor in the area surrounding a room air conditioning cooler drip pan (directly over the 2BD power cabinet located in a

room below.

The water'as from excessive condensation from an open CSR door.

The door was opened after an inadvertent Halon discharge that occurred the previous day (see section 6.2. 1 of this report).

Because only one of the Halon main bottles had discharged, the licensee decided to keep the CSR room open for personnel safety reasons.

The Halon vendor had been contacted and had recommended this action based on the possibility that the undischarged halon bottle could discharge into the room at any time.

The licensee posted security and fire watches to monitor the CSR room and door.

Operator tours were maintained through a back door via the RCA.

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The high humidity in the CSR caused excessive condensation which caused the drip pan to overflow onto the floor.

The licensee checked the drains to be clear 'however, they are currently reviewing the drain and drip pan design.

The water on the floor (approximately several gallons) apparently leaked into a hilti-bolt anchorage and through the concrete floor onto the RCC cabinet below.

There were two grout repair areas directly above the RCC which were. dripping.

The licensee surmised that the hilti-bolt anchorage went through 7 inches of the 8 inch concrete floor, resulting in necessary repairs in the RCC room ceiling.

Thus, water leaked around the anchor stantions, into the hilti-bolt anchorages, and then through the grout repair areas and onto the 2BD RCC cabinet.

The licensee sealed the anchor stantion plates in the CSR.

The ERT, PNSC, and plant management completed the post trip.

review,'orrective actions included the following':

I8C inspected the 2BD power cabinet; verified fuse

-- integrity; removed, cleaned, and dried the wetted cards, I8C tested the 2BD power cabinet per procedure TP-1209, functional Checkout of the Unit 3 Rod Control System, Mechanical maintenance, implemented a

PM to check drip pan drains periodically, Engineering is reviewing the cooler drip pan and drain design, Operator rounds were modified to ensure cooler drains and drip pans are checked, The 2BD rod cabinet cables entry was caulked,

3.2.2 The hilti-bolt anchorage base plates in the CSR were sealed with caulking, The CSR door was closed and the Halon system was repaired (section 6.2. 1).

The unit was restarted at 10:55 p.m.,

on October 17, 1995, and the unit was placed on-line on October 18, 1995.

During the startup a

rod control urgent failure alarm occurred on the 1BD power.

cabinet.

The licensee reset the rod control system and no further alarms occurred (section 3.2.2).

The inspector gpsponded to the site and observed licensee post-trip actions iR~the control room.

The inspector verified that Unit 3 was stable in Node 3.

Operators and control room personnel and plant management personnel were interviewed.

The inspector reviewed the ARPs, ONOPs, and EOPs that were implemented and verified appropriate licensee actions.

The inspector also examined the RCC room and CSR, confirming the water source and flow path to the rod control cabinet.

'he inspector attended ERT meetings; reviewed the LER, CR; and post-trip review; and, discussed root cause, corrective actions, and restart with the ERT leader and the plant manager.

Selected corrective actions were verified.

The inspector concluded that operators appropriately:HeSponded to the dropped rods and trip.

Further, ERT, PNSC, and management follow up appeared to be thorough.

Temporary System Alterations Unit 3 TSA 3-95-28-27 installed an Astro-Med multi-pen recorder on 1BD the RCC Power Cabinet.

During Unit 3 restart following the manual reactor trip (section 3.2. 1),

a rod control urgent failure alarm was received for the 1BD power cabinet.

The 1BD power cabinet contains power circuits for group 1 rods in shutdown Bank B, Control Bank B, and Control Bank D.

An initial investigation performed under the trouble shooting procedure following the receipt of the alarm did not reveal any abnormalities.

The TSA

~ y The inspector reviewed two TSAs that w'ere'er'formed during this report period.

Unit 4 TSA 4-95-081-06 supplied temporary power to the heater drain tank level switch LS-4-1558 for controlling the 4B heater drain pump.

On October 20, 1995, the 4B heater drain pump tripped causing a minor unit transient and a-loss of approximately 100 HWe.

A non-safety related cable associated

.with the level switch was found to be damaged.

The TSA routed a

temporary cable from the level switch to the 4B heater drain pump 4160 kv breaker located in the switchgear room.

The expected duration for the TSA is approximately three months.

PC/H 95-151 is being planned to effect permanent repairs.

The licensee was not able to determine the cause of the damage to the cabl was implemented to monitor approximately 13 signal points within the IBD power cabinet in the event another urgent alarm failure should occur.

The inspector reviewed, discussed, and performed a walkdown of the two TSAs.

The inspector concluded that the TSAs were appropriately approved and implemented and the number of effective TSAs remained low.

3.2.

Configuration Control Problems The inspector reviewed two problems related to configuration control that occg~ed.= duriag:-this report period.

The first involved the Unit 3 SJAE exhaust valve 3-30-019 that was discovered by the licensee to be closed when it should have been open.

Further, the condenser system vent valves 3-30-179-and'-"3-'".30-152 were open when they should have been closed.

.At approximately 4:20 p.m.

on October 25, 1995, a non-licensed operator performed procedure 3-0P-73.1, Steam Jet Air Ejector Operation which required valve 3-30-019 to be closed to accommodate measurement of condenser air in -leakage.

Upon completion of the 10 minute condenser air in-leakage measurement, valve 3-30-019 was required by procedure to be reopened and condenser system vent valves 3-30-179 and 3-30-152 were required to be closed, The valve manipulations required by procedure 3-OP-73. 1 did not have any sign-offs as this procedure was frequently performe'd:.

At approximately 9: 10 p.m

, during performance.of a "snoop" test to identify condenser leakage paths by exposing potential;-in-leakage paths to helium and detecting the helium at the SJAE vent to the atmosphere, chemistry personnel noted that there was no fl.ow through the SJAE'exhaust vent.

Upon investigation, it was noted by chemistry technicians that valve 3-30-019 was closed, thereby isolating the normal SJAE vent and the SJAE. SPING monitor.

Valve 3-30-019 was reopened and the SJAE SPING monitor was immediately returned to service.

A condition 'report (No. 95-1070)

was initiated.

With valve 3-30-019 closed, the SJAE "System Particulate Iodine and Noble Gas" (SPING) monitor required by Technical Specification 3.3.3.3, Table 3.3-5, Item 19.c was inoperable for approximately five hours.

However, the action statement associated with Technical Specification 3.3.3.3 allows the SPING to be inoperable for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> prior to any alternative sampling requirements.

Therefore, no Technical Specification action statements were violated as a result of the SPING being out-of-service.

Further, with vent valves 3-30-179 and 3-30-152 left open, condenser vacuum remained adequate and Technical Specification radiation monitor R-15 remained unaffected.

The licensee interviewed and obtained written statements from the operator as well as the chemistry personnel involved in the snoop

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test.

The inspector interyiewed the operator who maintained that

he.-had performed the appropriate valve alignments as required.

The inspector postulated that it is likely that the operator forgot to reopen valve 3-30-019 and then to re-close valves 3-30-'52 and 3-30-179 following completion of condenser in-leakage measurement as no sign-off was required which would have positively reminded the operator of the appropriate valve alignments,

'As immediate corrective action, the licensee initiated a night order requiring operators, for a two month period, to initial&each-step during performance of frequently performed procedures that do not have sign-offs.

Further, the licensee plans to revise procedures 3 and 4-OP-073. 1 to add sign-off steps and independent verification.

During the review o@the, circumstances surrounding this incident, the inspector noted that the control room operators had not been appropriately logging the technical specification action statement when the SJAE SPING was being taken out of service approximately every eight hours to perform condenser in-leakage measurements.

The inspector brought this to the attention of the operations supervisor who immediately initiated a night order addressing this requirement.

Additionally, the inspector reviewed the requirements of procedure O-ADM-031, Independent Verification, which required independent verification be applied to plant systems including process radiation monitoring system.

Procedures 3 and 4-OP-073.

1 which affected the SPING monitor valve alignment did not have independent verification.

The licensee revised procedures 3 and 4-OP-'073.

1 to now include independent verification.

Further, the inspectors requested the licensee to review similar procedures that may not have independent..;.:

verifications performed.

The inspector also reviewed the circumstances surrounding valves 3-20-415 and 4-20-415 that were found in the closed position by gA during a

CST system walkdown on October 25, 1995.

Manually operated valves 3-20-415 and 4-20-415 are on. the makeup line to the Unit 3 and 4 CSTs, respect'ively.

The valves are required by procedures 3 and 4-0P-18.1, Condensate Storage Tanks, to be open.

Procedures 3 and 4-OP-18.

1 are utilized to align the CST as well as to provide demineralized water to the CST from the water treatment system.

Further, procedures 3 and 4-OP-018.

1 was last performed on August 10, 1995, and'valves 3-20-415 and 4-20-415 were independently verified to be open.

A condition report (95-1073)

was also initiated as a result of this discovery.

Operability of the CSTs capability to supply water to AFW pumps or the manual capability to makeup to the CST were not affected.

Valves 3-20-415 and 4-20-415 are located downstream of the associated CST's automatic makeup control valves CV-3-1540 and CV-4-1540.

Due to historic problems with leakage past CV-3-1540 and CV-4-1540, makeup to the CST was being performed using the bypass lines through valves 3-20-414/3-20-410 and 4-20-414/4-10-410 in

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accordance with procedures, 3 and 4-OP-18. 1 when needed.

Further, problems with leakage past CV-3-1540 and CV-4-1540 and other problems attributed to elevation difference and line resistance affecting makeup capability from the water treatment system to tanks such as CSTs, PWST, DWST, and Lab tank.was considered as an operator workaround.

This operator workaround also caused operators to manipulate makeup valves associated with tanks that were at lower elevation in order to fill tanks at higher elevations.

This manipulation included periodically closing valves 3 and 4-20-415 to isolate leakage to the CST and allow makeup Co. another tank located at a higher elevations.

The control valves associated..wi,th.,both the automatic makeup paths were repaired in 1993'",-thereby eliminating the need to use the bypass line for CST makeup.

However, procedures 3 and 4-OP-018. 1,

" 'Condensate Storage Tank were not revised and.makeup to CST was still performed using bypass lines as opposed to CV-3-1540 and CV-4-1540.

The licensee is postulating that valves 3 and 4-20-415 may have

,been closed without any administrative control during an evolution involving makeup to either the PWST, DWST, or the Lab tank.

The licensee plans to perform a root cause analysis associated with this problem.

The licensee revised procedures 3 and 4-0P-20-018.1 to require the use of the normal control valves for makeup to the CSTs.

Additional corrective actions as a result of the two conditions discussed above included discussion by the plant manager during weekly operator luncheons of the importance self checking as well as a letter to all operations staff from the operations supervisor discussing these as well as several other'recent--issues".a'ffecting operations.

Further, the licensee has initiated. action's to improve system capability to provide makeup to several tanks.

The inspector reviewed and discussed both the incidents, including planned as well as completed corrective actions and safety significance.

The inspector also reviewed past licensee performance, including NCV 50-250,251/95-09-01, Failure to Have Valves Aligned as Required by Their Associated Procedures, Multiple Examples, as it relates to configuration control.

The inspector ascertained that the circumstances surrounding NCV 50-250,251/95-09-01 and the consequent corrective actions were not similar to the two conditions identified in this report.

Further, licensee corrective actions and self-assessment capability that led to the identification of one of the problems was noted to be a

strength.

The inspector determined that the failure to have the SJAE valves 3-30-19, 3-30-152, and 3-30-179; and CST valves 3-20-415 and 4-20-415 in the position required by the associated operating procedure will be classified as NCV 50-250,251/95-19-02, Failure to Adequately Configure Several Valves in Their Required Positions.

This configuration control violation meets the criteria in the NRC Enforcement Policy section VII.B.I.

The non-

3.2.4 3.2.5 3.2.6 cited violation is closed.

The inspector concluded that licensee corrective actions and self-assessment relative to configuration control were aggressive.

Minor weaknesses pertaining to control room logging and a revision to an operating procedure were noted.

System Walkdowns The inspector'alked down portions of the Uni't 3 and Uni't 4 PASS, PAHH, and PACV systems.

The inspector accompanied the system engineer during the 'walkdown.

The inspector concluded that -the system was aligned as required by current plant condition's.

Further, the inspector concluded that the system engineer was very knowledgeable and exhibited a sense of ownership of his system.

Refueling Outage Critique The inspectors reviewed the'nit 3, 1995 refueling outage critique report that was issued on November 7, 1995.

The outage critique was conducted on October 24, 1995, and included outage accomplishments and improvement actions to be taken during, future'utages.

The inspector noted that among the areas needed for improvement included better inclusion of the POD supervisor into the Risk Assessment Team to better coordinate operating unit and outage activities.

This issue of the outage affect on the operating unit was highlighted by the inspector during previous inspections including NRC Inspection Report 50-250,251/95-16.

The inspector concluded that the licensee was responsive to inspector concerns pertainfng to this matter.

Further, the licensee's self-assessment capability appeared 'to be thorough and effective..

Staff Reductions 3.2.7

. On November 1,. 1995, the licensee reduced staffing affecting Turkey Point.

Approximately 40 personnel were released.

The layoffs affected practically all disciplines-excluding licensed operators.

Further,'here were several supervisors that were also affected.

The staff reductions were at Turkey Point as well as other FPL installations.

The inspectors plan to monitor the effect of the staff reduction of approximately five percent on plant performance.

FPL Corporate and Site Management Changes On November 13, 1995, FPL announced that Hr. Thomas F. Plunkett will become President of Florida Power

& Light Company's Nuclear Division effective March 1, 1996, upon the retirement o'f Hr.

Jerome H. Goldberg.

The announcement was made by Hr. James L.

Broadhead, Chairman and Chief Executive Officer of FPL Group.

Inc.

Mr. Broadhead also announced that Mr. Robert J.

Hovey, has been named to succeed Hr. Plunkett as Site Vice President for Turkey

Point, effective immediately.

Hr. Hovey was.previously the assistant to Hr. Plunkett at Tur'key Point.

4.0 Maintenance (61701, 61726, 62703, 72700 and 92902)

4. 1 Inspection Scope The inspectors verified that station maintenance and surveillance testing activities associated with safety-related systems and components were conducted in accordance with approved procedures, regulatory, guides,,industry codes and standards, and the technical specifications.,

They accomplished this by observing maintenance and surveillance testing activities, performing detailed technical procedure reviews, and reviewing completed maintenance and surveillance documents.

The inspectors also reviewed a previous open item to assure that corrective actions were adequately.implemented and resulted in conformance with regulatory requirements.

4.2 Inspection Findings 4.2. 1 Maintenance Activities Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

ICW pump replacement (section 4.2.3),

3C S/G level control system troubleshooting '.(section 4.2.4),

~

Unit 3 Replacement of Pr'op Latch Spring on 480 volt AC Load Center Breaker (section 4.2.5),

Unit 4 Reactor Trip Breaker Timing Test (section 4.2.6),

Unit 4 8 Reactor Coolant Pump Low Oil Level Alarm (Section 4.2.7),

Inspection and Preventive Maintenance of the Unit 3 Intake Area Gantry Crane (section 4.2.8),

3CH Instrument Air Compressor Maintenance(section 4.2.9),

and Ultimate Heat Sink Maintenance (section 4.2. 10).

For those maintenance activities observed, the inspectors determined that the activities were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.

Specific comments on those activities are addressed in the following section.2.2

Surveillance Testing Activities Observed The inspectors witnessed/reviewed portions of the following test activities:

Reactor Protection System Logic Test (section'4.2.6),

and Unit 4'SFP Blackness Testing.

-'~The'inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the technical specifications.

4.2.3 3B ICW Pump Replacement The inspector monitored licensee activities associated with 3B ICW pump replacement.

The ICW Pumps are periodically changed out for inspection and preventive maintenance.

During change out of the 3B ICW pump motor, electrical maintenance inadvertently dropped one of the termination bolts into the:vertical conduit during the de-termination of motor leads.

'The bolt was stainless steel coated and I/2 inch diameter and I inch in length.

The 1'icensee attempted to retrieve the bolt but was unsuccessful.

Consequently, the licensee initiated a condition report as this constituted a non-.conformance due to foreign material being present in a safety related component.. Further, an evaluation was performed addressing the effects of:.-'the'bolt being left in the conduit.

The evaluation concluded that the stranded bolt in the embedded conduit would not have any adverse affect on the ability

'f the cable to perform its function.

Further,.:the.l.icensee plans to periodically megger the shiel,ds for the cabl:e to confirm the bolt has not 'affected the cable.

Additional corrective actions included counselling the electricians on the importance of foreign material exclusion and plans to add foreign material steps to motor work related procedures.

The inspector reviewed the condition report as well as licensee efforts to retrieve the bolt.

The inspector concluded that the licensee attempts to retrieve the bo'1t were aggressive.

Further the inspector concluded that the corrective actions that resulted from this event should reasonably sensitize plant personnel to the importance of foreign material excl.usion during similar work activities.

4.2.4 Unit 3C Steam Generator Level Control Problem At approximately 2:40 a.m.

on November 7, 1995, the 3C S/G level deviation annunciator alarmed.

The 3C S/G level as well as feedwater flow were noted by the control room operator to be decreasing.

The operator immediately placed the 3C feedwater regulating valve FCV-3-498 in manual and increased feedwater flow to the 3C S/G to raise level to within program level.

The

operator did not note any S/G level, steam flow, or feedwater flow channel failures.

Feedwater flow channel FI-3-497 was selected and feedwater regulating valve FCV-3-498 was placed in automatic.

Immediately the FCV started to go close.

The operator placed the FCV back to manual and swapped the controlling S/G level channel.

Once again, when the FCV -3-498 was placed in automatic and the 3C S/C level started to decrease.

The operator placed FCV-3-498 back to manual arid restored 3C S/G level to normal.

A dedicated watch of the 3C S/G level control system was established and 18C was.

also informed of the condition.

At 8:00 a.m., Unit 3 load was reduced to 80% power to accommodate trouble shooting associated with the 3C S/G level control system.

The licensee performed troubleshooting and data gathering to 'plan

"-'appropriate repairs.

During this trouble shooting, the licensee noted abnormal behavior of Hagan controller.LC-498 associated with the 3C level control module.

The licensee concluded that the reset switch assembly associated with the LC-498 module had a

chassis ground on the one of the resistors, The resistors'ead was noted to be pressed against the metal nut that holds the switch together.

The licensee replaced LC-498 Hagan module and successfully returned the unit to full power without any problems.

The inspector. discussed the issue 'with the licensee as well as observed portions of the troubleshooting, including in the I&C shop.

The inspector 'confirmed that the Hagan module refurbishment activity that the licensee had recently performed due to prior problems with S/G level control did not contribute and could not have prevented the problem as'he refurbishment activity was not related to the reset switch assembly.

The licensee ini'tiated a

condition report and is developing a scope for future inspections that will incorporate testing and verification of the reset switch.

The inspector concluded that the operator response to the transient was appropriate and timely.

The inspectors also concluded that IKC'troubleshooting activities that identified that ground were noteworthy.

4.2.5 Replacement of Prop Latch Spring on 480 Volt AC Load Center Breaker A malfunction of breaker 30107, associated with Unit 3 pres'surizer heater backup group A, was discovered by the licensee on July 31, 1995.

An investigation conducted by the licensee revealed that the breaker's prop latch spring had broken.

The

'ailed spring was forwarded to the FPL Metallurgical Laboratory for analysis.

The licensee determined that initiating mechanism of the prop latch spring was high cycle fatigue and given the test results and the design information provided, the root cause could not be determine The breaker manufacturer's (ITT/ABB) representative informed the licensee of, the following:

the prop spring is not required for breaker operation as long as the latch mechanism has not collapsed (it is articulated and the spring keeps the mechanism extended against formed arm stops);

and there have been no reported failures of this spring reported to the factory.

Based on the 'above the licensee performed the following actions:

Replaced prop latch springs on 480.,Volt AC load center breakers with high operation duty.

'These=were determined to be the pressurizer, backup heater breakers and the charging pump feeder breaker's,"'for a total of eight breakers for the Turkey Point site.

Checked other plants via the Nuclear Network, with respect to their experience with prop latch spring failures.

Revised the scope of work done whenever load center breakers are sent off for refurbishment to include replacement of all springs.

On November 14, 1995 the. licensee replaced the spring, cleaned, lubricated and adjusted the 4B Charging Pump feeder breaker.

The inspector observed the cleaning, lubrication and adjustment phase of the operation.

The inspector, by record review, verified that the breaker was removed, serviced, installed and tested by properly qualified personnel, using correct parts and calibrated tools.

The activities observed by the inspector were accomplished'n accordance with appropriate, concise -and-well. written procedures.

4.2.6 Unit 4 Reactor Protection System Logic Test Testing of the Reactor Protection system is required by Technical Specification Table 4.3-1, Items 19, 20, and 21.

This is implemented by surveillance procedure 4-OSP-049. 1, Reactor Protection System Logic Test, dated August 17, 1995.

This surveillance is supported by the maintenance department, performing PM 049055, Reactor Trip Breaker Monthly Timing Test.

The inspectors attended the Electrical Maintenance and Operations pre-job briefings, observed the work activities from the removal of the 4A Reactor Trip Breaker. from service, to its return to.

service.

Observations included Reactor Trip Breaker timing test and the Reactor Protection System logic test, and system restoration.

The inspectors, by record review, verified that the breaker was tested by properly qualified personnel, using calibrated tools.

The inspectors noted that this RPS test conducted in three locations by two organizations was well planned and implemented.

The inter-departmental communications were excellen "

4.2.7 4B Reactor Coolant Pump Low Oil Level Alarm The licensee received a low oil level alarm from the 4B Reactor Coolant Pump on November 10, 1995 (see section 6.2.4).

The decision was made to monitor the RCP oil level by remote visual examination of the lower oil reservoir gage glass on a daily periodicity.

This required containment entries at power.

Licensee inspections indicated marginally low but safe oil level with no perceptible level change.

The inspectors attended the pre-job briefing for the first and third daily containment entry and accompanied the licensee's entry team.

The entry was well planned, coordinated and implemented.

The activities went smoothly causing the entry team to spend a

minimum amount in the containment at power.

The inspectors noted that housekeeping in the areas of the Unit 4 containment observed was good.

The inspectors consider the licensee's actions related to the 4B RCP low oil level alarm were appropriate.

4.2.8 Inspection and Preventive Haintenance of the Unit 3 Intake Area Gantry'rane The inspector observed a portion of the inspection and preventive maintenance of the Unit 3 intake area gantry crane.

The inspector noted that procedure compliance was good but the inspector did note the below listed material condition discrepancies.

Host of those discrepancies should have been identified by the mechanical maintenance personnel.

The gasket on the crane drive spur gear speed reducer inspection cover gasket

'was damaged and eviden'ce.of moisture was noted on the gasket mating surface indicative of a moisture intrusion into the housing.

There were no marks on the. bridge drive spur gear speed reducer oil site glass indicating proper oil fill level.

Two cover mounting bolts were missing:

A weather tight electrical panel door was loose indicating that the weather tight seal was compromised.

The inspector discussed these issues with maintenance personnel.

4.2.9 Instrument Air Compressor Haintenance The 3CH Instrument Air compressor tripped on low pressure outlet high pressure.

As the compres'sor was still under warranty, repairs were conducted by vendor representatives with FPL mechanical maintenance and system engineering personnel providing assistance as requeste The inspector observed a portion of the activities associated with the installation of the second stage compressor.

The inspector noted the following items:

At the beginning of the shift, several openings into the compressor were not covered as required by procedure'I2-PTN-3, Fluid System Cleanliness Control, dated December 6,

1994, paragraph 5.4.4.4.

Procedure gI2-PTN-3, paragraph 5.4.4.4 states

"For Periods in which work is not actively being conducted, openings shall be protected by the use of a suitable cover..."

The vendor's representative was using a vendor supplied torque wrench which was not calibrated to install a drive gear on the second stage compressor.

Uhdocumented FP&L policy requires vendor METE to be processed through the FP&L M&TE program prior to use.

The Instrument Air system is not safety-related and therefore the safety signi.ficance of these issues was.small.

However, the above issues indicated a weakness in the area of vendor oversight.

Both of the above circumstances should have been identified by the licensee's mechanical maintenance or system engineering personnel".'.2.

Ultimate Heat Sink Maintenance P

The ultimate heat sink consists of approximately 38 series-parallel canals, with a total linear length of 168 miles and a

total water surface area of 4330 acres which forms the plants closed loop cooling systems for ICW and Circulating Water.

The ultimate heat sink further includes the CCW and RHR"systems.

The ult'imate heat sink maintenance program focused'n:

berm land maintenance; berm edge trimming; and, canal, underwater weed removal.

Additionally, the program included leveling the berm that had received dredge spoil material, and topping and removing floating weeds to prevent their entry into the plant intakes.

Berm land maintenance was performed with a Caterpillar wide track bulldozer tractor which pulls a large rolling drum chopper which'ultivates the grass and chops out weeds.

Berm edge trimming was performed with amphibioug backhoes to keep the canal edges straight and deep in order to keep full-width uniform water flow down each canal and to shape and compact the banks to make them stable against erosion.

Underwater weed removal was accomplished by a specially designed

"weed-eating" machine mounted on s self propelled barge.

As the barge moves down the canal the 10-foot wide jet-suction-head scours the bottom of the canal and sucks up the weeds and algae, which then are ground up and returned to the canal bottom to deca The inspector observed the operation of the underwater

"weed-eating" barge and the amphibi-ous backhoe.

In addition the inspector observed the annual maintenance overhaul activities on the other amphibious backhoe.

The licensee's maintenance program has the ultimate heat sink in the best physical condition in its 22-year lifetime, and created 20 to 30 acres of new cooling water surface each year.

4.2. 11 Licensee Actions on Previous Inspection Findings (Closed)

IFI 50-250,251/94-24-01:

Proceduralize Bobbin Probe Wear Measurement and gualification of Computer Data Screening Analysis.

This item concerns the fact that the licensee's Eddy Current procedures did not address bobbin probe~wear measurement and qualification of Computer Data Screen'4g&nalysis.-'he licensee's procedure NDE 1.3, Eddy Current Examinations of Non-Ferromagnetic Tubing Using Multi-Frequency Techniques HIZ-18/MIZ-30, Revision 6, was revised to address bobbin probe wear measurement and qualification.

The IFI is considered closed.

5.0 Engineering (37551, 90712, 90713, 92700, and 92903)

5. 1 Inspection Scope The inspectors verified that licensee engineering problems and incidents were properly reviewed and assessed for root cause determination and corrective actions.

They accomplish this by ensuring that the licensee's processes included the identification, resolution, and prevention of problems and the evaluation of the self-assessment and control program.

The inspectors reviewed selected PC/Ms including the applicable safety evaluation, in-field walkdowns, as-built drawings, associated procedure changes and training, modification testing, and changes to maintenance programs.

The inspectors also reviewed the reports discussed below.

The inspectors verified that reporting requirements had been met, root cause analysis was performed, corrective actions appeared appropriate, and generic applicability had been considered.

When applicable, the criteria of 10 CFR Part 2, Appendix C, were applied.

5.2 5.2.1 Inspection Findings'nstrument Air System Modifications The inspectors performed a walkdown of the new IA compressors and related modifications that which was recently turned over to operations.

Two electrical motor driven (3CH and 4CH)

and two diesel driven (3CD and 4CD)

IA compressors were installed per PC/Hs93-108 and 93-109.

The licensee currently places one motor

5.2.2

driven IA compressor in the lead mode maintaining IA system pressure between 104,.:--'. 110 psig.

The other -electric driven IA compressor is placed in lag mode with an automatic start capability at 99 psig in accordance with procedures 3/4-0P-013, Instrument Air System.

Further, one diesel driven compressor is placed in lag with an automatic start capability at 96 psig.

The second diesel driven compressor is placed in standby with automatic start capability at 90 psig.

The portable IA compressors will remain available until the end of the year and will be maintained in standby.

The inspector concluded that the engineer involved in the walkdown was knowledgeable of the PC/Ms.

Further, the inspectoK&have not noted any significant operational problems associated with the modification.

A recent failure of the 3CM IA compressor is being pursued (see section 4.2.9).

The inspectors intend to continue to follow these PC/Ms.

Spent Fuel Pool Cooling System The inspector reviewed plant design, procedures, the UFSAR, and Technical Specifications affecting Spent Fuel Pool Cooling.

The SFP cooling system at Turkey Point is seismically qualified; however, single active failure criteria is not a design bases.

The SFP cooling system is comprised of one pump, one heat exchanger, filter, demineralizer, piping, and associated valves and instrumentations.

Additionally, there is a provision for two spare pumps that are permanently installed to function in place of the original pump.

The licensee received a license amendment in November 1984 to allow SFP storage capacity,-to increase from 621 to 1404 assemblies for both units.

Currently," there.are 701.-and 648 fuel 'assemblies stored in the Unit 3 and Unit 4 SFP,

.

respectively.

The 1'icensee performed decay heat calculations for the SFP as a result of the increase in spent fuel storage capability and concluded that it did not affect existing design basis and that the increase in heat load was 'acceptable.

The inspector noted that the description in the UFSAR pertaining to SFP decay heat loads and the ensuing temperatures did not reflect current plant practice of conducting complete core off-loads during refueling outages.

The UFSAR states that partially spent fuel is rearranged in the core and only 1/3 of the core is off-loaded during refueling outages.

This was true until early 1980s at which time the plant went to full core off-load.

A full core is comprised of 157 fuel assemblies.

The inspector discussed this issue with the licensee with particular emphasis on the affect on the decay heat analysis.

The inspector was informed that the decay heat analysis performed during the November 1984 high density SFP storage rack installation was bounding, including the SFP temperature profile following the full core coo-load.

The inspector verified this by comparing the SFP temperature profile following a full core off-load during the Unit 3 refueling outag.0 5.2.3 Plant 6.1

'I The inspector was also informed that the licensee had learned about similar issues at other plants and had plans to revise the information in the UFSAR.

The licensee initiated a condition report following the d'iscussion with the inspector.

The inspector concluded that the licensee was responsive to inspector questions.

The inspector intends to review the revised UFSAR that is expected to reflect current plant practice relative to the SFP and cooling systems.

Licensee Written Reports

'4*

The inspectors reviewed the September and October 1995 monthly operating report and determined it to be complete and accurate.

f (Closed) Unit 3 LER 95-007-00, Manual Reactor Trip Following Drop of Four Control Rods.

The event and LER were reviewed as discussed in sections 3.2:I,.and 6.2. 1 of this report.

The LER was accurate, timely, and well written; and, is closed.

Support (71750 and 82701)

Inspection Scope The inspectors verified the licensee's appropriate implementation of the physical security plan; radiological controls; the fire protecti'on program; the fitness-for-duty program; the chemistry programs; emergency preparedness; plant housekeeping/cleanliness conditions; and the radiological effluent, waste treatment, and environmental monitoring programs.

6.2 6.2.1 I'nspection Findings Cable Spreading Room Halon System Actuation At 4:29 p.m, on October 16, 1995, during the performance of procedure O-SME-091.9, Fire and Smoke Detector System Semi-Annual Test, an inadvertent Halon, system actuation occurred for the CSR.

The licensee evacuated the CSR, responded to the alarms, made a

PA announcement, assembled the fire brigade, and two operators entered the CSR in SCBAs.

Control room operators entered procedures O-ONOP-016.8,. Response to a Fire/Smoke Detection System Alarm, and 0-ONOP-016. 10, Pre-Fire Plan Guidelines and Safe Shutdown Manual Actions.

Operators confirmed that no fire had occurred in the CSR, and secured fire response activities.

Inspection of the CSR revealed no apparent damage caused by the Halon discharge.

The CSR doors were opened, and the room was ventilated.

Security and fire watch personnel were posted as required.

The Halon system was inspected, and the licensee noted that one of two bottles of the main bank had not discharged.

Based on discussions with the Halon vendor, the licensee

maintained the CSR doors opened and posted, to assure personnel protection if the non-discharged bottle were to discharge.

This condition ultimately let to a Unit 3 manual reactor trip (see section 3.2. 1).

. Further licensee and vendor inspections noted an incorrectly installed (reversed)

check valve (10-821) for the bottle number

of the main bank.

The remaining check valves were properly installed (three for the CSR and four for the invertor rooms).

The CSR Halon system is a

200% redundant system, with two bottles for the main bank and two bottles for the reserve bank.

A local

.selector switch outside the CSR door aligns either bank's two bottles.

The licensee concluded that the check valve had been improperly

.installed since o'riginal installation in 1986.

A review of the vendor's pre-operational test procedure (P.O.

B59-00919)

noted that the orientation of the check valves was an inspection criteria; however, the vendor marked the step as

"Not Applicable"..

Further, an air flow verification (puff test)

was performed; however, verification of the check valve performance was not included.

The licensee corrected check valve 10-821 orientation, and verified the disc's freedom of movement.

Each check valve has an

"arrow" stamped on the valve body to indicate the correct orientation.

Check valve 10-822 operated correctly as evidenced by the Halon discharge.

The remaining check valves were verified to be. correctly installed by checking the "arrow" orientation.

The licensee performed an engineering evaluation.(JPN-PTN-SENP-95-034) to address the safety significance of the CSR Halon system being improperly installed.

The licensee's licensing basis per UFSAR Chapter 9.6A; sections 2.3.2, 2.4.E4, 2.5, 3.3.e, and 4.HH discuss the CSR Halon automatic suppression.

These UFSAR sections conform to the requirements of 10 CFR 50 Appendix R, section III.G.2.

The licensee concluded that one bottle of the main Halon bank would not achieve the NFPA 12A requirements of a 5.0 percent Halon 1301 solution.

However, the reserve bank could be manually activated outside the CSR by the on-the-scene fire brigade.

Further, licensee ONOP procedures would direct the fire brigade to the scene to fight a CSR fire.

Also, procedure O-ONOP-105, Control Room Evacuation, directs control room operators to abandon the control room for a fire in the CSR, or the control room, or the North-South breezeway in the auxiliary building.

Thus, a fire in the CSR would damage common equipment but would not prevent achieving hot or cold shutdown at the local alternate shutdown panel Licensee corrective actions included the following:

Corrected check valve orientation, Inspected other check valves for proper orientation, Performed an evaluation, PSA and LER, Refilled the Halon system.and returned it to service, Troubleshot the suppression Halon actuation, no problems were found, Revised the procedures to de-energize and remove the Halon system from service during testing.

Based on a low increase in risk (e.g.,

5.61 E-06 per year),

and on availability of the reserve Halon system, and on the availability of the alternate shutdown system for a CSR fire, the licensee concluded that the check valve's incorrect installation represented minimal impact on plant safety.

Based on the licensee's review of the check valve incorrect installation event and their identification of causes and corrective actions, the inspector considered the event to be a

failure to appropriately install and test the Halon modification in 1986.

Further, the failure resulted in UFSAR and. 10 CFR 50 Appendix R non-compliances.

The inspector considered this issue to be a licensee identified, non-cited violation:

NCV 50-250,251/95-19-2, Failure to Adequately Install and Test a Halon Hodification.

'[he violation meets the criteria in the revised NRC Enforcement Policy section VII.B.1.

6.2.2 Emergency Plan Changes A Nascar motorsports complex was constructed within the EPZ, approximately 5:5 miles west of the Turkey Point site.

The complex (Homestead Notorsports Complex or HHC) was initially conceived in the early 1990's, and construction planning'egan in 1992.

Construction delays and environmental issues delayed the completion until 1995 to support an initial race for November 3-5, 1995.

The inspectors noted construction activities in late 1994 and early 1995.

Preliminary discussions were held with site EP and NRC regional personnel approximately six months ago, and more detailed discussions in early October 1995.

At that time, licensee EP personnel stated that the emergency plan changes were drafted, and that the state, county, and local plans were also complete, Traffic control and EPZ evacuation plans were in place to handle the estimated 60,000-70,000 people who would attend

these races, and any other future events.

An additional three hours could be expected to complete an EPZ evacuation.

The licensee's site and corporate EP personnel stated that FEHA was aware of the plan changes through informal discussions including one in March 1995 during the annual EP exercise; and, through discussions among the State of Florida, Dade County and FEMA.

6.2.3 On October 16, 1995, the inspector updated regional personnel.

NRC regional contact with FEHA on October.

19, 1995, determined that FEHA Region IV was not aware of thi's-major EP plan change.

Additional discussions among the NRC, the State of Florida, Dade County, FEHA and HMC race officials were held.

On November 2, 1995, FEMA was satisfied with the planning for emergency notifications, traffic control and possible eyacuations.

All interested parties attended the race during the peri'od November 3-5)

1995.

The inspector observed traffic control during the period, reviewed the EP plan changes.,

discussed actions and plans with licensee EP personnel and NRC regional personnel.

Although not required, the inspector concluded that licensee personnel could have been more proactive in formally notifying FEHA relative to the EP plan changes.

NRC regional specialists intend to revisit this issue, including a review of EP plan changes in a future inspection; Fire Protection Drill's The inspector observed two fire drills that were conducted during this report period.

The drill observed on November 8, 1995, was.a

"Mutual Aid" drill which required notification for offsite assistance.

During this drill, the fire brigade appropriatelyequested offsite assistance.

The Homestead Air Reserve Station appropriately responded to the site, including entry into the

.

protected area.

The inspector also'iscussed with the licensee circumstances surrounding a drill that was conducted on November 6, 1995, where one of the minimum five required fire brigade members did not respond.

The HP technician who was on the fire brigade had.

apparently left the site for personal reasons without appropriately notifying his supervisor and the NWE.

Consequently, the minimum Fire Brigade Shift Staffing of five members as required by the Fire Brigade Program procedure O-ADH-016.2, Fire Brigade Program was not met for a short duration (1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />).

Procedure O-ADM-016.2 allows the fire brigade composition to be less than the minimum required for a period of time not to exceed two hours in order to accommodate unexpected absence of fire brigade members provided immediate action is taken to restor the fire brigade to within the minimum requirements.

The HP technician was not available to respond for approximately hours.

However, due to the fire drill that was conducted, the HP technicians absence was recognized within approximately 30 minutes and an alternate fire brigade member was immediately designated.

The licensee considered the drill to be unsatisfactory and successfully re-performed the drill on a different date.

A condition report was also originated and plans are to issue a

training brief to each brigade member about the importance of notifying the appropriate personnel to ensure minimum fire brigade staffing is, always maintained.

The inspector discussed the event as well as the two drills with the licensee.

The inspector concluded that the licensee was responsive to inspector concerns and questions.

The inspector also concluded that the fire protection program remained effective.

6.2.4 Unit 4 Containment Entries On November 10, 1995, at 5:36 a.m., control room operators responded to a

4C RCP low oil reservoir alarm.

Appropriate ARP and ONOP entries were made, and the 4C RCP parameters were normal.

Operators began periodic monitoring as required.

On November 13, 1995, Unit 4 containment entries were made to check the RCP oil

'ollection system and to attempt to view the oil level sight glass.

Subsequent entries were made on November 14, 15, and 17, 1995.

The inspector attended the HP conducted pre-job briefings as required by procedure O-ADM-009, Containment Entries When Containment Integrity Is Established.

Operations, Maintenance, HP, and Engineering personnel attended.

Items addressed included neutron and gamma dose, RWP requirements, heat stress concerns, security involvement, personnel airlock use, containment integrity and evacuation requirements, and HP shift supervisor oversight.

The inspector observed the entry "and exit activities, and entered the Unit 4 containment on November 15, 1995.

The licensee did. not find any oil in the collection tank, and observed the sight glass oil level with a horoscope.

Level trends are currently being monitored (see section 4.2.7).

The inspector concluded that licensee controls for the Unit 4 containment entry were conservative and in accordance with the procedure.

Good team work was noted among all 'organizations involved.

Unit 4 containment cleanliness and housekeeping was good.

6.2.5 Unit 3 Cycle 15 Refueling Outage Radiation Exposure The licensee's ALARA Review Board met on October 25, 1995, to review the Unit 3 Cycle 15 (Fall 1995) refueling outage radiation exposure.

The exposure was 178.335 person-Rem which was 51.662

below the goal.

Jobs which achieved the greatest exposure savings were the flux mapper thimble cleaning, ISI activities, HP coverage, and maintenance refueling activities.

The inspector reviewed the exposure results and the ALARA Review Board meeting summary, and discussed ALARA with station personnel.

The inspector concluded that the licensee performed very well during the outage.

6'.6 Emergency Plan Augmentation Drill On November 14, 1995, the licensee conducted an EP augmentation drill.

The inspectors observed~the OSC and TSC, and concluded that the drill was effective 'and well run.

7.0 Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with both the site vice president and plant general manager and selected members of their staff.

An exit meeting was conducted on November 17, 1995.

(Refer to section 1.0 for exit meeting attendees.)

The areas requiring management attention were reviewed.

The licensee did not identify as proprietary any of the materials provided to or reviewed by %he inspectors during this inspection.

Dissenting comments were not received from the licensee.

However, the inspectors had the following findings:

Item Number Status Descri tion and Reference NCV 50-250)251/95-19-01 NCV 50-250, 251/95-19-02 (Closed) Failure to Adequately Configure Several Valves in Their Required Positions.

(Section 3.2.'3)

(Closed) Failure to Adequately Install and Test a Halon Modification.

(Section 6.2')

Additionally, the following previous item was discussed:

Item Number Status Descri tion and Reference LER 50-250/95-007-00 IFI 50-250,251/94-24-01 8.0 Acronyms and Abbreviations (Closed)

Manual Reactor Trip Following Drop of Four Control Rods (section 5.2.3).

(Closed)

Proceduralized Bobbin Wear Measurement and I)ualification of Computer Data Screening Analysis (section 4.2. 11).

AC ADM Alternating Current Administrative

AFW ALARA a.m.

ANPS

'RP CCW CD CM CR CRDM CRN CSR DWST EDG e.g.

EOP EP EPZ ERT ESF 0 F

~

FCV FEMA FL FPL FI GDC HMC HP IA I&C ICW 1.e.

ISI JPN LC LER M&TE MWe NCV NFPA NRC NWE ONOP OP OSC OSP PACV PAHM PANS PASS

Auxiliary Feedwater As Low As Reasonably Achievable Ante Meridiem Assistant Nuclear Plant Supervisor Annunciator Response Procedure Component Cooling Water IA Dies'el Compressor IA Electric Compressor Condition report Control Rod Drive Mechanism Change Request Notice Cable Spreading Room Demineralized Water Storage Tank Emergency Diesel Generator For Example Emergency Operating Procedure Emergency Preparedness Emergency Planning Zone Event Response Team Engineered Safeguards Feature Degrees Fahrenheit Flow Control Valve Federal Emergency Management Agency Florida Florida Power and Light Flow Indicator General Homestead Motorsports Complex Health Physics Instrument Air Instrumentation and Control Intake Cooling Water That Is Inservice Inspection Juno Project Nuclear (Nuclear Engineering)

Level Controller Licensee Event Report Measuring and Test Equipment Megawatts Electric Non-Cited Violation National Fire Protection Association Nuclear Regulatory Commission Nuclear Watch Engineer Off-Normal Operating Procedure Operating Procedure Operational Support Center Operations Surveillance Procedure Post-Accident Containment Ventilation Post-Accident Hydrogen Monitor Post-Accident Monitoring System Post-Accident Sampling System

PC/H PDR p.m.

PH PNSC PSA Pslg PTN PWST QA QC QI RCA RCC RCP RCS RHR RPS RWP SCBA SFP S/G SJAE SME SPING TP TSA TSC UFSAR V

Plant Change/Modification Public Document Room Post Meridiem Preventative Maintenance Plant Nuclear Safety Committee Probabilistic Safety Assessment Pounds 'Per Square Inch Gauge Project Turkey Nuclear

.Primary Water Storage Tank Qua i,t'y. Assurance Quality Control Quality Instruction Radiation Control Area Rod Control Cluster Re%a to% Coolant Pump Reactor Coolant System Residual Heat Removal Reactor Protective System Radiation Work Permit

'Self Contained Breathing Apparatus Spent Fuel Pit Steam Generator Steam Jet Air Ejector Surveillance Maintenance

- Electrical System Particulate Iodine Noble Gas Temporary, Procedure Temporary System Alteration Technical'Support Center Updated Final Safety Analysis Report Volt