IR 05000250/1995014

Insp Repts 50-250/95-14 & 50-251/95-14 on 950702-29.No Violations Noted.Major Areas Inspected:Plant Operations Including Operational Safety,Refueling Preparations & Plant Events;Maint Including Surveillance Observations

ML17353A320
Person / Time
Site:	Turkey Point
Issue date:	08/11/1995
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A318	List: IR 05000250/1995014 ML17353A317
References
50-250-95-14, 50-251-95-14, NUDOCS 9508220268
Download: ML17353A320 (27)

Text

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+p*p4 UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30323-0199 Report Nos.:

50-250/95-14 and 50-251/95-14 Licensee:

Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspection Conducted:

July 2 through 29, 1995

Inspectors:

T.

P.

J nson, Senior Resident Inspect B. B. Desai, Resident Inspector Approved by:

K. D. Landis, Chief Reactor Projects Section 2B Division of Reactor Projects Date Signed Da e igned SUMMARY Scope:

This resident inspection was performed to assure public health and safety,-

and it involved direct inspection at the site in the following areas:

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

Backshift inspections were performed in accordance 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 did not identify any regulatory compliance t

issues.

However, the following unresolved item was identified:

Unresolved Item 50-250/95-14-01, Pressurizer Pressure Transmitters Calibration (section 5.2.4).

9508220268 V508ii PDR ADOCK 05000250

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

Plant 0 erations During the period, the licensee demonstrated effective self-assessment programs (section 4.2. 1).

Good management oversight associated with the self-contained breathing apparatus program was noted (section 4.2.2).

Good teamwork and controls were noted during Unit 3 new fuel receipt inspections and handling (section 4.2.3).

Maintenance Inspector-observed station maintenance and surveillance testing activities were well performed (sections 5.2. 1 and 5.2.2).

Miscommunications between operations and chemistry resulted in a late Unit 3 containment air sample (section 5.2.3).

A licensee identified problem with the calibration of the Unit 3 pressurizer pressure protection instruments is unresolved (section 5.2.4).

A relay wiring issue with the C auxiliary feedwater system was appropriately identified, evaluated, and corrected.

Operability was unaffected (section 5.2.5).

En ineerin Relative to the Unit 3 pressurizer pressure calibration issue, the licensee demonstrated an effective operating experience feedback program (section 5.2.4).

Strong teamwork was noted during the testing and turnover phases of the B standby steam generator feedwater pump modification (section 6.2. 1).

A license event report associated with the emergency load sequencers and the 480 volt load centers was timely and well written, and is therefore closed (section 6.2.2).

Plant Su ort The fire protection program continued to demonstrate strong and effective performance (section 7.2. 1).

A security event was appropriately logged (section 7.2.2).

The licensee's fire brigade response to observed smoke in the 3B motor control center was timely and appropriate.

Further, the licensee's investigation into a breaker failure and smoke detector issues was thorough (section 7.2.3).

TABLE OF CONTENTS

.0 Persons Contacted..............................................

1 l. 1 Licensee Employees................

1.2 NRC Resident Inspectors...........

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6..0 Eng>neering....................................................

6.1 Inspection Scope.....

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..10

..10 8.0 Exit Interviews................................................

9.0 Acronyms and Abbreviations.....................................

1.0 Persons Contacted REPORT DETAILS Licensee Employees T. V.

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Abbatiello, Site guality Manager Acosta, Company Nuclear Review Board Chairman Balaguero, Technical Department Supervisor Banaszak, Electrical/ISC Section Supervisor Bohlke, Vice President, Engineering and Licensing Bowskill, Reactor Engineering Supervisor Earl, guality Control Supervisor Geiger, Vice President, Nuclear Assurance Goldberg, President, Nuclear Division Heisterman, Maintenance Manager Higgins, Outage Manager Hollinger, Training Manager Hovey, Assistant to the Site Vice-President Huba, Procurement Supervisor Jernigan, Plant General Manager Johnson, Operations Manager Jurmain, Electrical Maintenance Supervisor Kaminskas, Services Manager King, Acting Fire Protection/Safety Supervisor Knorr, Regulatory Compliance Analyst Koschmeder, Acting Instrumentation and Controls Maintenance rvisor Kundalkar, Engineering Manager Lindsay, Health Physics Supervisor Harcussen, Security Supervisor

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Hiller, Acting Projects Supervisor Paduano, Manager, Licensing and Special Projects Plunkett, Site Vice President Rose, Nuclear Materials Manager Singer, Operations Supervisor Steinke, Chemistry Supervisor Tomaszewski, Acting Technical Manager Waldrep, Mechanical Maintenance Supervisor Weinkam, Licensing Manager Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.

1.2 NRC Resident Inspectors

• B.

B. Desai, Resident Inspector

• T.

P. Johnson, Senior Resident Inspector

Attended exit interview (Refer to section 8.0 for additional information.)

Note:

An alphabetical tabulation of acronyms used in this report is listed in section 9.0 of this report.

2.0 Other NRC Inspections Performed During This Period Re ort No.

Dates Area Ins ected 50-250,251/95-13 July 19-21, 1995 Chemi stry Van/Confirmatory Measurements 3.0 Plant Status 3.1 Unit 3 3.2 At the beginning of this reporting period, Unit 3 was operating at full reactor power and had been on line since April 9, 1995.

The unit operated at full power during the report period.

Unit 4 3.3 At the beginning of this reporting period, Unit 4 was operating at full reactor power and had been on line since March 12, 1995.

The unit operated at full power during the report period.

Common On July 21, 1995, the plant set a record for dual unit run of greater than 102 days.

4.0 Plant Operations (40500, 60705, and 71707)

4.1 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, refueling preparations, and evaluation of the licensee's management control.

The inspectors also performed a review of the licensee's self-assessment capability by including PNSC and CNRB activities, QA/QC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicator.2 4.2.1 Inspection Findings Self-Assessment Activities 4.2.2 4.2.3 During the period, the inspectors reviewed licensee self-assessment activities.

This included the following:

several PNSC meetings; the July 26, 1995, PTN status meeting; the July 18, 1995, CNRB meeting; gA/gC independent activities; and line management initiated reviews.

The inspectors noted the on-site presence of FPL corporate management at the CNRB and the PTN Status Meetings The inspectors also noted that line management and independent reviews and assessments were self-critical and demonstrated conservative operation of the nuclear units.

CNRB members demonstrated a good questioning attitude and a strong safety perspective.

The reviews and self-assessments recognized current plant issues and the current trend of performance.

In summary, the inspectors concluded that FPL has effective programs relative to self-assessment which ensured nuclear safety.

Self-Contained Breathing Apparatus Programs The inspectors reviewed licensee procedures and practices associated with SCBA programs.

The licensee's SCBA program procedure O-ADN-041, PTN Respiratory Protection Plan, states that the need for SCBA use at Turkey Point is to limit inhalation of harmful atmospheres including airborne radiological contaminants; non-radiological hazards during planned activities such as spray painting, abrasive blasting, solvent/cleaning, welding, etc.;

and oxygen deficient environments.

SCBAs are also utilized by the fire team while carrying out fire brigade functions.

The licensee does not have provisions for SCBA use (including in the control room) following an unplanned toxic gas release in the vicinity of the plant.

The basis for this is that no potential toxic chemical releases have been identified for the site.

The inspectors discussed the issue with the licensee and verified the bases in UFSAR section 9.9. 1.3, Control Room Emergency Operation Design.

The inspector also recently reviewed the SCBA program as documented in NRC Inspection Report 50-250,251/95-11.

The inspector concluded that the licensee has a good SCBA program with strong management oversight.

Unit 3 New Fuel Receipt During the period, the licensee received shipments of new fuel for the upcoming Unit 3 refueling outage.

The shipping containers were unloaded, moved, and opened.

The new fuel was unloaded, inspected, and moved to the new fuel storage racks.

The licensee used procedures 0-OSP-040. 11, Receipt of New Fuel and 0-OP-040. 1, Handling New Fuel Shipping Containers and New Fuel Assemblie The inspector reviewed the procedures, observed the new fuel receipt activities, and discussed these activities with licensee personnel.

The inspector noted good teamwork among operations, reactor engineering, and maintenance personnel, and good support by HP, Security, and gC personnel.

Activities were well controlled and performed in accordance with procedures.

5.0 Maintenance (61726 and 62703)

5.1 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.

5.2 Inspection Findings 5.2. 1 Maintenance Activities Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

Unit 3 new fuel receipt (section 4.2.2),

and C AFW pump and turbine maintenance (section 5.2.5).

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.

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

procedure 3-SMI-41. 10, Pressurizer Pressure Protection Loops Monthly Analog test (section 5.2.4),

procedure TP-1167, Diesel Driven Standby Steam Generator Feedwater Pump Start-up Test (section 6.2. 1),

and procedure 4-0SP-200.3, Secondary Plant Periodic Test.

The inspectors determined that the above testing activities were well performed and met the requirements of the technical specification.2.3 Reactor Coolant System Leakage Surveillance On July 5, 1995, at about 2: 15 p.m., the Unit 3 containment atmosphere process radiation monitors (RO-3-11 and 12) were removed from service due to a noisy sample pump.

Technical Specification 3.4.6. 1 was appropriately entered which required the following:

7-day action statement, containment sump level monitoring system operability verification, containment 24-hour grab sample and analysis, 8-hour RCS water inventory balance, and closure of the containment purge, exhaust, and air bleed valves.

The licensee initiated actions to perform these above requirements as well as to repair the sample pump.

At about noon on July 6, 1995, the chemistry department and operations began actions for the 24-hour containment grab sample.

However, due to a

miscommunication, a clearance was hung which isolated the alternate sample path.

This action delayed the sample and analysis by 34 minutes.

The licensee subsequently entered a

6-hour LCO, which was exited when the sample was analyzed.

No radioactivity was detected in the sample.

The licensee initiated a condition report (No.95-546)

and performed the following number of corrective actions.

The inspector reviewed this issue including the condition report, the LCO, operator logs, and discussed the issue with chemistry, operations, and management personnel.

The inspector reviewed the current NRC guidance relative to surveillance interval grace of +

25/. per Technical Specification 4.0.2.

This included standard technical specifications, NUREG 1433, and a draft technical guidance document.

The inspector also discussed the issue with NRR.

The licensee concluded, and the resident inspectors agreed, that the licensee met technical specification 3.4.6. 1 LCO action statement when they entered and subsequently exited the 6-hour action to hot standby.

The inspector concluded that the licensee appropriately documented, reported, and corrected this miscommunication issue between chemistry and operations concerning the sample.

Further, the inspector concluded that no violations of technical specifications occurred.

However, the licensee should review their current Technical Specification 4.0.2 requirements and interpretations to ensure they are appropriately understood and addresse.2.4 Pressurizer Pressure Transmitter Calibration Based on a recent problem at another PWR, the licensee's technical department and system engineering performed an operating experience feedback review per FOP-042 as documented on condition report No.95-528.

The problem was associated with calibration errors with the pressurizer pressure protection transmitters.

The licensee determined that the same problem did not exist at Turkey Point.

However, a different calibration issue for the Unit 3 pressurizer pressure protection channels (PT-455, 456, and 457)

was identified.

Routine refueling calibrations of these pressurizer pressure channels performed in April 1994 were done with a Heise gauge which was later found to have about a 15-20 psig error (low).

The licensee immediately documented this calibration issue in another condition report (No.95-550)

and performed an operability and reportability assessment.

A review of the Unit 3 control room pressurizer pressure protection channels noted them to be 10 to 20 psig higher than both the Unit 3 control channels and the corresponding Unit 4 pressure channels.

(One graduation of the control room pressure instrument is 20 psig).

Further, the licensee reviewed the calibrations performed in April 1994 (procedures 3-PHI-041.69,

.70, and.71, Pressurizer Pressure Protection Calibration) noting that the as-found values were all low, requiring an adjustment.

This could be indicative of a Heise gauge calibration problem.

The Heise gauge was successfully calibrated by the H&TE shop on January 25, 1994.

However, due to an apparent damaged gauge, noted after the April 1994 pressurizer pressure calibrations, the N&TE shop put a hold on further use and on June 16, 1994, found the gauge to be out-of-calibration by about 15 to 20 psig.

Based on the damage to the Heise gauge occurring after the April 1994 calibrations, the licensee concluded the Unit 3 pressurizer pressure channels had been satisfactorily calibrated.

This N&TE assessment was completed in June 1994.

Engineering performed an evaluation and supporting calculations (PTN-3FJI-95-005) to review this issue.

The licensee concluded that the reactor protection and SI functions performed by pressurizer pressure (e.g.,

low/high pressurizer pressure reactor trip, low pressure SI, and OTET reactor trip) remained operable.

The licensee concluded that the low pressure reactor trip was the most limiting item due to Technical Specification Table 2.2-1 five column format for allowable errors and the trip setpoints.

The nominal reactor trip setpoint for low pressurizer pressure is 1835 psig with an allowable value of 1817 psig and an allowable tolerance of 4.5% of span (1000 psig) or an error of 45 psig.

Thus, the safety analysis trip setpoint of 1790 psig would be assured.

This allowable tolerance is comprised of rack errors,

sensor errors, and other errors, all based on Westinghouse methodology and Technical Specification equation 2.2-1.

The licensee reviewed of the current cycle monthly surveillances which check the trip setpoints (per procedure 3-SMI-41. 10, Pressurizer Pressure Protection Loops Monthly Analog Test)

noting that all of the results were within the test acceptance criteria of t 10mv or 2.5 psig.

Thus the instrument rack error was no more that 2.5 psig.

Thus, given the current higher than expected sensor error and the as measured rack error, the licensee concluded that Technical Specification 2.2. 1 and equation 2.2-1 were met.

The licensee performed reviews by design and system engineering, maintenance, operations, and an independent HPES review.

Corrective actions included the following:

M&TE program enhancements, I&C calibration process enhancements when as-found data is out-of-specification, HPES independent review including root cause analysis, changed the monthly surveillance test acceptance criteria to ensure trip setpoints do not deviate by more than 2 12 mv (or 3.0 psig),

calibration of the

PTs scheduled during the September 1995 refueling, including determination of the as-found setpoints, training of the I&C and METE personnel of the lessons learned, and PNSC review and approval of the condition report.

The inspectors were notified of this issue by system engineering personnel.

The inspectors reviewed the condition reports, oper ability determinations, associated surveillance procedures, M&TE documentation, and related calibration sheets.

The inspectors did not identify any issues with the licensee's operability assessment.

The inspectors also discussed this item with licensee personnel.

Pending the determination of the as-found calibration data scheduled for September 1995 and completion of the above corrective actions, this item is unresolved (URI 50-250/95-14-01, Pressurizer Pressure Transmitters Calibration).

Further, the inspector noted the licensee's Operating Experience Feedback program to be effectively functioning by the identification of this issu e 5.2.5 Auxiliary Feedwater Wiring Error During routine C AFW pump and turbine maintenance on July 17, 1995, licensee personnel, upon opening cabinet C240, noted that the 7CR relay was installed incorrectly.

This relay is used to bypass the thermal overloads for the trip and throttle valve (MOV-6459C), during an AFW initiation sequence.

The thermal overload relays ensure that the motor is protected against operating conditions that exceed design limits.

With the 7CR relay pins in the incorrect socket locations, the relay coil was isolated from any power source.

This configuration effectively disabled the thermal overload bypass function.

Licensee calculation PTN-BF-JE-92-028 resized (oversized)

the thermal overload relays for all the AFW trip and throttle HOV circuits.

Maintenance inspection confirmed that the correct thermal overloads were installed.

The licensee concluded that the upsized thermal overload relays met the intent of NRC Regulatory Guide 1. 106, Thermal Overload Protection For Electric Motors and Motor-Operated-Valves, and of their MOV Program.

The bypass relays were therefore not required for AFW pump operability.

Further, the licensee concluded that the relay misalignment did not create any short circuit conditions in the AFW control circuit.

Therefor e, the licensee concluded that operability of C AFW pump was unaffected by this event.

In accordance with existing design documents, the 7CR was properly installed prior to returning the C AFW back to service.

Also, possible misalignment of the 7CR relay on the A or B AFW pumps would not have posed an operability concern for the same reasons described above.

The inspector reviewed this issue including the condition report (No.95-561), electrical drawings, design bases, and related documentation.

The inspector concluded that the licensee appropriately identified, reviewed, evaluated, and corrected this item.

Further, corrective actions addressing the incorrectly installed 7CR relay were aggressive.

No violations or operability issues were identified.

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

6.1 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/Hs including the applicable safety evaluation, in-field walkdowns, as-built drawings,

.associated procedure changes and training, modification testing, and changes to maintenance program i

6.2 6.2.1 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 NUREG-1600, General Statement of Policy and Procedures for NRC Enforcement Actions, were applied.

Inspection Findings Standby Steam Generator Feedwater Pump Hodifications During the period, the licensee completed PC/H 94-059 which replaced the motor driver with a diesel engine driver for the B

S/B SGFP.

This PC/H allows the licensee to eliminate the five blackstart diesels (non-safety-related)

which provide backup power to the 3C and 4C 4KV non-vital buses.

Buses 3C and 4C provided the power to the A and B S/B SGFP motors, respectively.

The A S/B SGFP power supply remains unchanged.

The NRC had previously approved this modification per Technical Specification amendments 164 (Unit 3)

and 158 (Unit 4) in a letter and safety evaluation dated Hay 20, 1994.

The licensee had requested this amendment in a letter dated September 3,

1993 (L-93-200).

The Technical Specification 3/4.7. 1.6 and related bases were modified.

The licensee completed testing and the PNSC reviewed and approved test results on July ll, 1995.

The PC/H paperwork closure was completed on July 13, 1995.

The licensee reported the completion of this PC/H in a letter (L-95-208) dated July 18, 1995.

The inspectors observed portions of PC/H during this inspection and also during NRC Inspection Report 50-250,251/95-10 (section 6.2.2).

During the current period, the licensee experienced some delays due to diesel-pump alignment problems'.

The licensee worked with the vendor and replaced the diesel engine support channel.

Alignment attempts were successful and testing was performed per procedure TP-1167, Diesel Driven Standby Steam Generator Feedw'ater Pump Start-up Test.

The inspectors observed portions of the testing including the uncoupled and coupled diesel tests, and the pump IST. Testing was completed successfully.

The inspectors also reviewed the completed PC/H package and turnover documentation.

During the post-modification testing, the inspectors noted strong teamwork among system and design engineering, maintenance, operations, and vendor personnel.

The inspectors concluded that the licensee appropriately planned, performed, and tested the B

S/B SGFP PC/.2.2 6. 2.3 Licensee Event Report Review The inspector reviewed LER 50-250,251/94-05-02, Design Defect in Safeguards Bus Sequencer Test Logic Places Both Units Outside Design Basis, that was issued on July 17, 1995.

This LER was a

revision to a previously issued LER.

This revision incorporated 480 volt load center feeder breaker automatic closure vulnerability that was identified by the licensee during the verification and 'validation of modifications associated with the corrective actions for the original sequencer defect.

This condition was reported to the NRC on June 19, 1995 in accordance with 10 CFR 50.72(b)(2)(iii).

The inspectors also reviewed and discussed the condition in NRC Inspection Report 50-250,251/95-11.

The licensee concluded that the affected load centers remained operable and that core cooling and ECCS requirements of 10 CFR 50.46 as well as UFSAR commitments were met contingent on manual operator actions.

The licensee has plans to modify the emergency load sequencers during the upcoming Unit 3 and Unit 4 refueling outages.

This modification will correct the identified defects, including the 480 load center breaker auto closure vulnerability.

The inspector plans to follow licensee corrective actions, including planned modifications.

Further, this issue is being tracked through VIO 50-250,251/94-23-03, which remains open.

The inspector concluded that the LER was well written with sufficient details.

LER 50-250,251/94-05-02 is considered closed.

Monthly Operating Report The inspectors reviewed the June 1995 monthly operating report and determined it to be complete and accurate.

7.0 Plant Support (71750 and 64704)

7.1 7.2 7.2.1 Inspection Scope The inspectors verified the licensee's appropriate implementation of the physical security plan; radiological controls; the fire protection 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.

Inspection Findings Fire Brigade Program The inspectors reviewed the licensee's fire brigade program as described in procedure O-ADM-016.2, Fire Brigade Program as well

as discussed its implementation with the licensee.

The following program attributes were noted:

The fire brigade is composed of a minimum of five individuals:

three operators (including possible representation from the NWE and the non-licensed SNPO, NPO and ANPO); and two HP technicians.

The fire brigade manning is similar during backshifts and weekends; The fire brigade-would normally be activated following confirmation of smoke and/or flames; The fire alarm in the control room is audible and visible including during other annunciations such as during a

reactor trip or LOOP; The fire brigade is trained to combat electrical switchgear fires with water fog after de-energizing equipment.

Special nozzles suited for electrical fires are available in the vicinity of the switchgear areas; The fire brigade was tested

and 19 times during backshift in 1994 and 1993, respectively; The criteria for classifying an emergency per procedure EPIP 20101, Duties of the Emergency Coordinator are as follows:

NOUE for an uncontrolled fire within the power block lasting longer 10 minutes; Alert for an uncontrolled fire potentially affecting safety systems and offsite support required; Site Area Emergency for a fire which prevents a

safety system from performing its design function; and General Emergency for a major fire which has caused massive damage to plant systems resulting in any of the other General Emergency initiating conditions; and, Offsite assistance is requested at the discretion of the fire brigade leader and the NPS.

The inspector concluded that the licensee continued to maintain a

strong and effective fire protection program.

7.2.2 Security Loggable Event On July 21, 1995, the licensee discovered that an individual was granted temporary unescorted access on September 19, 1994, without the individual's fingerprint cards being appropriately processed.

The individual was a temporary FPL employee and was on-site between the periods of September 23, 1994, through November 6, 1994, in support of the Unit 4 refueling outage.

Upon discovery, the licensee verified through the local police department that the individual did not have any criminal histor.2.3 Further, the licensee verified that all other access processing requirements were completed.

The licensee determined this to be a

loggable security event.

Upgrades to the access authorization process are planned by the licensee to prevent recurrence.

The inspector discussed the issue with the licensee as well as the NRC regional security specialist.

A security inspection is planned in the near future.

The security specialist plans to review this event.

The inspector concluded that the licensee appropriately determined this to be a loggable event.

38 Motor Control Center Room Smoke On Saturday July 1, 1995, at 9:20 a.m.,

the NPO noted smoke in the

HCC room.

The NPO called the control room and the fire team was activated.

Operators entered procedures EPIP-20101, Duties of the Emergency Coordinator and 0-ONOP-016. 10, Pre-Fire Plan Guidelines and Safe Shutdown Manual Actions.

The NPO on the scene was also the fire team leader.

The NPO and the ANPS (who also went to the scene)

determined the problem to be in a non-vital breaker (30690) for the sewage pump, and subsequently opened the breaker.

This action stopped the smoke generation and no actual fire occurred.

The fire brigade responded appropriately and remained on location in standby.

The licensee initiated a condition report (No.95-540),

a fire incident report, and made notifications per procedure O-ADM-115, Notifications of Plan Events.

This event did not meet any formal NRC notification requirements; however, the resident inspector was called at home.

Licensee personnel noted that the four installed smoke detectors did not alarm during this event.

A review concluded the smoke level in the 38 HCC room was below instrument sensitivity.

This was confirmed by discussions with the personnel on the scene and with the vendor.

The vendor recommended verifying detector sensitivity per procedure O-PHE-091, Outside Containment Smoke Detector Sensitivity Check and Calibration.

The licensee's investigation noted that a security guard and a

periodic fire watch had been in room less than 10 minutes before the NPO entered the room.

These two individuals did not note any smoke; however, they did note a musty smell and alerted the NPO to check the room.

The licensee's electrical department initiated troubleshooting of the 30690 breaker.

They determined that the 480/120 VAC control transformer and starter coil had shorted, and were the cause of the smoke.

Repairs were completed and the breaker was returned to service.

The inspectors walked down the 38 HCC room area, inspected the faulty breaker, reviewed the related documentation and interviewed the fire team leader.

The inspectors also discussed this event

8.0 with plant management and the fire protection supervisor.

The inspectors concluded that the fire brigade responded promptly and appropriately.

Further, the licensee's investigation into the smoke, the breaker failure, and the fire detection issues was thorough and demonstrated effective corrective programs.

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 July 27, 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 the inspectors during this inspection.

Dissenting comments were not received from the licensee.

The inspectors did not identify any regulatory compliance issues.

However, the inspectors had the following finding(s):

Item Number Status Descri tion and Reference 50-250,251/95-14-01 URI, Pressurizer Pressure Transmitter Calibration (section 5.2.4).

Additionally, the following previous items were discussed:

Item Number 50-250,251/94-23-03 50-250,251/94-05-02 Status Descri tion and Reference (Open)

VIO, Inoperable Emergency Load Sequencers (section 6.2.2)

(Closed)

LER - Design Defect in Safeguards Bus Sequencer Test Logic Places Both Units outside the Design Basis (section 6.2.2).

9.0 Acronyms and Abbreviations AC ADM AFW ANPO CFR CNRB ECCS EPIP FPL FL FOP HP HPES IKC IST Alternating Current Administrative Auxiliary Feedwater Assistant Nuclear Plant Operator Code of Federal Regulations Company Nuclear Review Board Emergency Core Cooling Systems Emergency Plan Implementing Procedure Florida Power and Light Florida Feedback Operating Programs Health Physics Human Performance Evaluation System Instrumentation and Control Inservice Test

KV L

LCO LER LOOP M&TE MCC HOV mv NOUE NPO NPS NRC NRR ONOP OP OSP OTBT PC/H PME PHI PNSC Pslg PT PTN PWR QA QC RCS RD S/B SGFP SCBA SI SMI SNPO TP UFSAR URI VAC VIO Kilovolt Letter (licensing)

Limiting Condition for Operation Licensee Event Report Loss of Off-Site Power Measuring and Test Equipment Motor Control Center Hotor-Operated Valve Milli Volts Notice of Unusual Event Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Regulatory Commission Nuclear Reactor Regulation Off-Normal Operating Procedure Operating Procedure Operations Surveillance Procedure Over-Temperature-Differential Temperature Plant Change/Modification Preventive Maintenance

- Electrical Preventive Maintenance

-

I&C Plant Nuclear Safety Committee Pounds Per Square Inch Gauge Pressure Transmitter Project Turkey Nuclear Pressurized Water Reactor Quality Assurance Quality Control Reactor Coolant System Radiation Detector Standby Steam Generator Feedwater Pump Self Contained Breathing Apparatus Safety Injection Surveillance Maintenance

-

I&C Senior Nuclear Plant Operator Temporary Procedure Updated Final Safety Analysis Report Unresolved Item Volts Alternating Current Violation