IR 05000250/1996006

Insp Repts 50-250/96-06 & 50-251/96-06 on 960505-0615. Violation Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support

ML17353A772
Person / Time
Site:	Turkey Point
Issue date:	06/15/1996
From:	Croteau R, Binoy Desai, Johnson T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A770	List: IR 05000250/1996006 ML17353A769 ML17353A771
References
50-250-96-06, 50-250-96-6, 50-251-96-06, 50-251-96-6, NUDOCS 9607110176
Download: ML17353A772 (82)

Text

e U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos.:

License Nos.:

50-250 and 50-251 DPR-31 and DPR-41 Report Nos.:

Licensee:

Facility:

Location:

50-250/96-06 and 50-251/96-06 Florida Power and Light Company Turkey Point Units 3 and 4; 9250 West Flagler Street Hiami, FL 33102 Dates:

Inspectors:

Approved by:

Hay 5 through June 15, 1996 T.

P. Johnson, Senior Resident Inspector B. B. Desai, Resident Inspector R.

P. Croteau, NRR Project Hanager P. J. Fillion, DRS Inspector H. L. Whitener, DRS Inspector K. D. Landis, Chief Reactor Projects Branch

Division of Reactor Projects Pb07i10i7b 9b0703 PDR ADQCK 05000250

PDR

i

e EXECUTIVE SUMMARY TURKEY POINT UNITS 3 and

Nuclear Regulatory Commission Inspection Report 50-250,251/96-06 This integrated inspection to assure public health and safety included aspects of licensee operations, maintenance, engineering, and plant support.

The report covers a six week period (May 5 to June 15, 1996) of resident inspection.

In addition, the report includes regional announced inspections of maintenance and engineering.

~0erati ons Unit 4 turbine control manipulations were well performed, demonstrated good teamwork and procedure compliance, and had good oversight (section 01.1).

One minor unit transient and one equipment loss were caused by licensed operator inattention to detail and a lack of self checking.

Licensee response to these and other problems was aggressive (sections 01.2 and 07.2).

Two examples of logkeeping improvements were identified.

Overall, logkeeping appeared to be adequate (sections 01.3 and 06.2).

Operators responded well to a Unit 4 feedwater heater relief valve failure (section 01.4).

Spent fuel pool area housekeeping was mixed:

Unit 3 was poor and Unit 4 was good (section 02. 1).

A lack of control room annunciation for a loss of startup transformer feeder breakers is being pursued by the licensee (section 02.2).

The steam generator blowdown and sampling systems were adequately maintained (section 02.3).

"Common designation" labelling of control room instruments which were installed pursuant to Regulatory Guide 1.97, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Access the Plant and Environs Conditions During and Following an Accident, had deteriorated for various reasons resulting in a non-cited violation. (section 02.4).

Configuration control was adequate; however, one minor error was identified by the licensee.

A turbine heating steam bypass valve was found out-of-position by a proactive operator tour (section 06.1).

The condition report system functions well to identify, correct, and trend problems (section 06.2).

The licensee's Unit 4 outage critique was thorough and demonstrated effective self-assessment (section 07. 1).

C>

Management's response to operator performance issues was timely and aggressive (section 07.2).

~

Operator response to reactor trip breaker fuse failure was consistent with technical specifications and demonstrated conservatism (section Hl.2).

Maintenance

~

Observed maintenance and surveillance testing was very good (section Hl.1).

~

Electrical maintenance response to a reactor trip breaker fuse failure was very good, timely, and demonstrated good teamwork (section H1.2).

~

Unit 3 hydrogen monitor repairs were well coordinated with excellent teamwork and oversight (section H1.3).

~

.

Good work instructions, good personnel performance, and good briefings were observed for several maintenance tasks (sections H H1.7).

~

The work plan for the Unit 4 emergency boration valve was sound (section Hl.8).

~

Appropriate leak rate testing was performed on the containment air locks (section H2.1).

Instrument and control group staffing appeared adequate even though three supervisors have recently left.

Further, recent performance trends for this area have shown improvements (section H6.1).

~

The safety-related batteries were found to be in good condition during a detailed walkdown inspection (section H2.2).

~

The surveillance procedure for demonstrating that the diesel generators were operable had a deficiency which caused the emergency diesel generators not to be started from normal conditions was a violation (section E2. 1).

En ineerin System engineering support of plant operations was very good during Unit 4 turbine control evolutions (section Ol. 1).

Drawing errors were noted in the spent fuel pool area ventilation system (section 02. 1).

System engineering support for a Un'it 3 hydrogen monitor repair and a Unit 4 boration valve repair was very good and demonstrated ownership (section Ml.3).

Thermal uprate related modifications and safety evaluations were acceptable with noted good documentation (section El. 1).

Engineering and technical support for a common switchgear room water intrusion problem and for a Unit 4 containment sump level instrument failure was very good (sections E2. 1 and E2.2).

The licensee continued to be aggressive in addressing auxiliary feedwater pump issues (section ES. 1).

Plant Su ort Radiation reduction efforts for hot spots was proactive and demonstrated very good performance (section Rl. 1).

ALARA Review Board efforts were proactive (section R6. 1).

Emergency plan drills were appropriately conducted and critiqued (section P5.1).

Hurricane preparedness was proactive.

However, procedure changes relative to unit shutdown criteria could have involved NRC earlier (sections Pl.1 and P3.1).

Security officer performance was mixed.

Poor performance resulted in a Unit 3 load center momentary power loss (section 01.2)

and a

failure to implement, appropriate compensatory actions during a

loss of the security computer (section Sl. 1).. The later event was a non-cited violation.

Good performance was noted in identifying a Unit 4 steam leak (section 01.4).

Fire protection programs including ignition source and combustible control, and fire event followup were well controlled (sections F1.1 and F1.2).

Fire water and pump systems,'nd fire suppression and detection systems were appropriately aligned and demonstrated good equipment performance.

Maintenance and testing activities were being performed as required.

Minor labelling issues were addressed (sections F2. 1, 2.2, 2.3, and 2.4).

Thermolag response by the licensee continues to be an open licensing issue (section F2.5).

~

Fire protection procedures and documents, including operating, fire pre-plans, administrative, and off-normal, were appropriate (sections F3. 1, 3.2, and 3.3),

Fire watch and fire bridge training and qualification programs were well implemented.

The licensee appropriately addressed i'ssues related to where fire brigade members were allowed to go and issues related to a self-identified non-cited violation for a missed fire watch due to a supervisory personnel error (sections F4.1, 4.2, 5.1, and 5.2).

Fire protection organization and administration was good, including offsite liaison and support for modifications (sections F6. 1, 6.2, and 6.3).

guality assurance audits and reviews of fire protection and programs were thorough and well documented (section F7. 1).

I)

TABLE OF CONTENTS Summary of Plant Status I.

Operations

.

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~ 4

~

~

~

~

~

~ 1 II.

Maintenance

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~ t 10 III.

Engineering

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

IV.

Plant Support.........................

~

~

~

~

~ ~

~ o20 V.

Management Meetings.............................................34 Partial List of Persons Contacted...................................34 List of Items Opened, Closed and Discussed Items....................35 List of Inspection Procedures Used..................................36 List of Acronyms and Abbreviations..................................36

REPORT DETAILS Summary of Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near full power and had been on line since March 29, 1996.

The unit operated at or near full power during the period.

Unit 4 I.

At the beginning of this reporting period, Unit 4 was operating at or near full power and had been on line since April 10, 1996.

Minor load reductions to accommodate turbine control issues and feedwater heater work occurred during the period (sections 01. 1 and 01.4).

Otherwise, the unit operated at or near full power during the period.

erations

01.1 Conduct of Operations Unit 4 Main Turbine Control During the period, minor control valve position swings occurred on Unit 4.

These swings resulted in 5-10 HWe load changes.

The licensee initiated load reductions on May 8, 1996, to 80% power and on Hay 16, 1996, to 96% power.

Procedure TP 96-44, Investigation of Unit 4 Control Oil Swings, was performed.

The licensee monitored control oil pressure and control valve performance during these load reductions.

Turbine control was swapped between the governor and the load-limit devices.

Procedure 4-0P-89, Hain Turbine, sections 7.3 and 7.4, delineated the necessary steps to perform these swaps.

System engineering documented these issues on condition report No.96-631, on two problem status summary reports, and on various WOs.

Although no conclusive cause could be determined, the licensee believes that a small amount of oil contamination may have affected the control oil devices and/or valve servos.

Unit 4 completed a refueling outage in April 1996, and the system may have seen some residual debris (reference NRC Inspection Report 50-250,251/96-04).

Longer term actions included control devices and servo valve inspections scheduled for a future SNO.

The inspector reviewed the above documentation including UFSAR section 10.2, observed'ystem operation, monitored maintenance activities, and discussed the issue with operations and engineering personnel.

The inspector also observed the data collection on May 8, 1996, and the swap from the governor to the

f

load-limit device on Hay 16, 1996.

The TP used was detailed, provided risk assessment, and contingency plans.

The evolutions were well controlled with very good oversight.

Procedure 0-ADH-217, Conduct of Infrequently Performed Tests and Evolutions, was used to ensure proper control over the evolution.

The briefings were thorough, independent verification was stressed, and overall the evolutions were well controlled.

The inspector noted that procedure 4-OP-89 use and compliance was also very good.

Teamwork among operations, maintenance, and system engineering was also very good.

No problems were noted with the reviewed documentation nor with the UFSAR.

The inspector noted that either the governor control or the load-limit control was allowed by the UFSAR and the OP.

Unit and E ui ment Transients Due to Personnel Error The inspector reviewed three minor operational transients that recently occurred caused by personnel error, a lack of self checking, and inattention to detail.

These events included a loss of the 4B 480 VAC load center caused by an RCO opening the wrong breaker (condition report 96-603),

a momentary loss of the Unit.3 containment sampling system when an RCO operated the wrong control switch (condition report 96-574),

and a loss of the 3A 480 VAC'oad center when a security guard inadvertently bumped the feeder breaker (condition report 96-669).

These events occurred during April and Nay, 1996, In each case licensed operators appropriately responded to plant condition per the ARPs, OPs and ONOPs, entered the appropriate technical specification action statements, and, quickly restored the equipment affected.

Other corrective actions included personnel counselling and discipline, night order promulgation, a

letter to all operators, shift briefings and management meetings, and additional actions (see section 07.2).

The licensee concluded that each event was not reportable, however, the inspector was either notified or learned of the event during routine condition report review.

In the case of the RCO errors, the switches incorrectly manipulated were identical to and in close proximity of the switches intended to be operated.

The inspector concluded that each of these events could have been avoided if personnel had appropriately used self checking (STAR)

techniques.

No procedural nor technical specifications violations were identified.

Further, quick, proper, and efficient operator reaction and response to these events minimized the overall unit effects.

Canal A uatic Grass and Al ae Intrusion The inspector followed up the recent aquatic grass intrusion events that occurred in January and February 1996, (reference NRC Inspection Reports No. 50-250,251/96-01 and 02).

During the

01.4

current period, several very minor in'trusion events occurred, requiring the implementation of procedures 3 and 4-0NOP-11, Screen Wash System/Intake Malfunction.

The inspector noted appropriate and conservative licensee response.

In addition, the inspector reviewed two issues relative to the January 31, 1996, grass intrusion event.

On February 1,

1996, divers were sent into the 3Al well without removing'the 3A ICW pump from service.

The inspectors verified by document review (logs and clearance)

and by discussions, that licensee actions were consistent with procedures 3-0P-10, Circulating Water System, and 3-0P-19, ICW System.

Further, the inspector reviewed control room logs for the affected periods on January 31, 1996.

The log stated that the 3A2 screen DP was 14.5 psid (the 3A1 Circulating Water pump was already off).

Discussions with operators in the control room at the time revealed that the DP had pegged (e.g. greater than 15.0 psid) for short periods.

Procedure 3-0NOP-Oll, Screen Wash System/Intake

. Halfunction, required the affected circulating water pump to be secured if either DP was above 15.0 psid or if waterfall was greater that 2.5 feet.

The inspector concluded that procedure should have better guidance and that the control room logs could have been more detailed.

The licensee has since revised the ONOP to address this issue.

Discussions with management were held to discuss these specific issues, including conservative operating philosophy and logkeeping.

Unit 4 Feedwater Relief Valve Leak

02.1 Operators reduced Unit 4 load to 88X on June 4,

1996, to accommodate the repair of the 5A feedwater heater relief valve (RV-4-3414).

During a routine security tour at about 2:00 a.m.,

an officer reported the leak to the control room.

Operators responded per the GOP to reduce load, isolated the heater, and made a voluntary notification to the inspector.

Repairs were completed and the unit returned to full power on June 5,

1996.

This non-safety related relief valve failure was attributed to spring failure.

The inspector examined the failed RV, verified licensee actions, inspected the clearance, reviewed maintenance activities, and discussed the item with licensee personnel.

The inspector concluded that licensee actions were appropriate.

Security officers'ours were effective in identifying abnormal conditions.

Operational Status of Facilities and Equipment S ent Fuel Pit Ventilation S stem Based on recent problems at another.facility, the inspector reviewed the Unit 3 and

SFP ventilation and related radiation

monitoring systems.

Items reviewed included 'Technical Specifications 3/4.3.3; P8 ID 5613(4)-M-3034; and, UFSAR sec'tions 11.2, 9.8, 14D, and 14.2. 1.

Each unit's SFP has a single exhaust fan (20,000 cfm) and associated damper operated from the control room.

Air is exhausted through a

HEPA and particulate filter.

Unit 3 SFP exhaust goes to a separate vent stack and is monitored by a single ARH channel (RD-3-1419)

and SPING (RD-6418).

Unit 4 SFP exhaust goes to the main plant vent stack and is monitored by the stack PRH (R-14)

and SPING (RD-6304).

Outside air is drawn in through two dampers and particulate filters.

The inspector noted that both UFSAR Figure 9.8-4 and P8 ID 5614-M-3034 incorrectly depicted an ARM channel for Unit 4 SFP vent exhaust.

This was pointed out to licensed operators on peak shift Hay 14, 1996.

Action was initiated, including condition report No.96-690 to correct both documents.

UFSAR section 11.2.3 correctly identified that only Unit 3 has a

SFP vent exhaust ARH (page UFSAR 11.2-19).

Operator knowledge also reflected this correct information.

The inspector walked down both units'FP ventilation and radiation monitoring systems noting that ARH channels exist for the SFP canal (RD-1407 and 8), cask wash area (RD-1411 and 12),

SFP wall (RD-1421 and 22)

and new fuel area (RD-1423 and 24).

The SFP exchanger rooms have local supply fans and exhaust dampers.

RD-1421 through 24 are the

CFR 70.24 required criticality monitors.

Specific system walkdown comments included:

good housekeeping in the Unit 4 SFP area, poor housekeeping in the Unit 3 SFP area, The Unit 3 and 4 new fuel area radiation monitors identification numbers were swapped, and Operators and system engineers were knowledgeable.

The licensee addressed the related concerns.

Control Room Walkdowns The inspector periodically performed control room walkdowns during the inspection period to verify equipment availability, operator knowledge, and technical specification compliance.

On Hay 28, 1996, the inspector was informed that one off-site power line (one of eight)

was OOS for maintenance.

A switching order was performed and one switchyard breaker (SW90) failed to reclose.

This caused the Unit 4 startup transformer to be supplied by only one breaker.

The inspector questioned whether the operators had alarm annunciation for either a total loss of the startup transformer or loss of one feed.

The ANPS stated that only a single white light (normally on)

was provided for transformer

P avail abi 1 ity.

Based on discussions and the inspectors'oncerns, the ANPS initiated condition report No.96-743 to address this issue.

The licensee is pursuing this matter.

Steam Generator'lowdown and Sam lin S stems The inspector walked down the Unit 3 and 4 S/G blowdown and sampling systems.

Items reviewed included P&IDs 5613(4)-H-3032,.

74, 72; electrical drawings; UFSAR sections 6.6, 11.2, and 10.2; EOPs and ONOPs; and, PC/H 95-168 and related PMTs.

The system includes a sampling system through phase A,

MOV isolation valves.

This sampling system directs S/G water to several coolers and sample locations, and to a

PRH (R-19).

The system also includes a

blowdown system through phase A,

CV isolation valves and FCVs.

Flow is then directed to a blowdown tank where water can be discharged to either the condenser or the canal.

Further, the tank vent can be either aligned to the 4 A/B feedwater heaters or to atmosphere.

The licensee recently implemented PC/H 95-168 on Unit 3.

The PC/M removed the FCV time delay and the CV bypass valves.

PHTs included procedure TP-1223.

The PC/H addressed an operator workaround (No. 5) regarding S/G blowdown.

Unit 4 (PC/H 95-167)

is scheduled'ext.

The inspector observed portions of the work and testing, and inspected accessible portions of the systems.

The inspector also interviewed operators regarding system knowledge.

The inspector concluded that the system was adequately maintained, with good housekeeping, personnel were knowledgeable,and system lineup was appropriate.

Desi nation Labellin of Post-Accident Monitorin Instrumentation (37550)

Regulatory Guide 1.97, Rev 3, Table 1, Design and gualification Criteria for Instrumentation, Item 8, Equipment Identification, requires that Category 1 and 2, Type A, B and C instruments be specifically identified with a common designation on the control panels so that the operator can easily discern that they are

.intended for use under accident conditions.

During a plant walkdown, the inspector noted that the labels for auxiliary feedwater flow to the steam generator indication did not have the purple colored tape, and they were instruments within the scope of RG 1.97.

In response to this finding, the license initiated a Condition Report.

To resolve the Condition Report, the Operations Manager reviewed most, if not all, of the RG 1.97 instruments to determine whether the common designation was clearly visibleas required.

This review identified several

I I

discrepancies in addition to the one identified by the inspector.

All the identified discrepancies are, summarized as follows:

Auxiliary feedwater flow to the steam generator.

There were twelve instruments, and they were RG 1.97, Category 1, Type B.

Quality Safety Parameter Display System, Train B, for both un'its.

This was a Category 1, Type A variable.

Containment purge valves 2600 - 2603 position indication for both units.

These were Category 1, Type 8 variables.

Emergency containment cooler valves position indication.

There were eighteen valves, and they were RG 1.97, Category 1, Type B.

Each of these discrepancies were promptly corrected by placing of the purple tape, and this was verified by the inspector.

UFSAR section 7.4.5 indicates that the licensee is committed to Regulatory Guide 1.97, Rev 3.

The inspector determined that the licensee's method for complying with the

"common designation" requirement was to place a narrow strip of purple colored tape on the instrument identification label of the appropriate instruments.

The licensee stated that reasons for the lack of common designations on the above instruments included, but were not limited to, the following: fading due to ultraviolet light, failure to replace tape after a modification changed the label and fell off.

The safety significance of the discrepancies described above was minor, because, for the particular variables in question, there was only one instrument available for the operator.

Therefore, there was no potential that the operator would be uncertain as to which among several instruments was the "qualified" instrument.

In addition, licensee management stated that a surveillance instruction would be prepared and issued requiring periodic review of the RG 1.97 instruments to help ensure that similar discrepancies do not recur.

The inspector concluded that the lack of common designations (labelling) for certain control room instruments was contrary to Regulatory Guide 1.97 which became part of the design basis when it was incorporated into the UFSAR section 7.4.5.

This NRC identified violation is not being cited because criteria specified in Section VII.B.I of the NRC Enforcement Policy were satisfied.

The matter is identified, as NCV 50-250, 251/96-06-01, Lack of Common Designation for Certain RG 1.97 Instruments, and is close.1 Operations Organization and Administration Confi uration Control The inspectors reviewed the licensee's processes for configuration control, including the following:

procedure O-ADH-212, In-Plant Equipment Clearance Orders, OP system lineups and OP component manipulation, test configuration control, and Technical Specification equipment OOS log books.

0-ADH-212 provides the requirements for hanging and releasing clearances in order to protect personnel and equipment.

Procedure steps 5. 11.4 and 5. 13.2 require a step-by-step order for placing and removing tags.

Deviations are allowed as long as the ANPS/NPS approves the discrepancy/order and documents as such on the clearance form.

The inspector audited selected clearances during the period, monitored the placing and removal of tags, and discussed the ADH implementation with licensed and non-licensed operators.

No abnormalities were identified.

Further, the inspectors noted that the licensee has a work control center manned with a permanently assigned ANPS on dayshift.

During outages, the center was manned 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day.

The inspectors also audited the control files for the current system OP lineups.

These lineups are typically performed during refueling outage, when a system is being realigned, or if a system lineup was questioned.

The inspector noted that during the recent Unit 4 outage (Harch-April 1996),

system lineups were performed during the course of the five-week, outage.

A formerly licensed NWE on loan from training provided oversight for the system lineup activities.

Some systems were not performed as authorized by the Operations Hanager.

Further, some system lineups were started early in the outage.

The inspector noted that too early of a start could invalidate the lineup effectiveness.

This would especially be the case if the lineups were performed prior to system maintenance/testing activities.

Although possible, no examples were identified for the recent outage.

However, the licensee performed a system lineup check of the IA system prior to the start of the outage.

This was appropriate as the IA system was not taken OOS.

During the inspection period, configuration control issues were addressed by the licensee.

Unit 4 RCP seal injection filter inlet

valve 4-293B was found closed during a routine SNPO tour of the auxiliary building on May 22, 1996.

The valve was opened and condition report No.96-724 was initiated.

This was a standby filter and had no safety consequence.

A root cause analysis determined that this was not a configuration control problem.

However, a minor deficiency was identified relative to the OP.

The second example was Unit 3 turbine right side cylinder steam heating bypass valve (3-90-051)

found by another SNPO during a

clearance independent verification, also on Hay 22, 1996.. The valve was repositioned and condition report No.96-723 was initiated.

This non-safety related component also had no safety consequence.

The root cause was indeterminate.

The inspector concluded the licensee's configuration control program was adequate.

Recent positioning errors were addressed.

No safety consequences occurred.

Corrective action programs and non-licensed operator attention to detail in uncovering these issues were very good.

Further, the licensee is pursuing trends in this area.

Condition Re ort S ste The inspector reviewed the licensee's corrective action program, including problem identification, evaluation, tracking, and resolution.

Procedure O-ADH-518, Condition Reports, implements the licensee's site wide program.

The condition report form may be initiated by anyone who is aware of a problem, condition, or deviation, which requires evaluation/followup.

The form addresses operability, reportability, plant manager/PNSC review, non-conformance, investigation and corrective actions, documentation, disposition and closeout, and trending.

Fifteen hundred to 2000 condition reports per year are typical.

During the current period, the inspector verified that condition reports were 'initiated and reviewed as required.

The licensee generally writes condition reports at the worker and supervisor level.

The site management team meets daily to review current issues.

If a condition report is needed but has not been written, the management team will ensure that one is initiated.

The inspector verified this by attending these meetings routinely.

The inspector also reviewed the licensee's periodic trend reports.

Per section 5. 16 of O-ADH-518, periodic trends are reviewed and action taken to address any problems.

On Hay 31, 1996, the quarterly (Ja Har.

1996) report was issued (PTN-TECH-96-69).

Negative trends were noted in procedure adherence/errors.

The licensee is currently addressing this issue (see section 07.2).

The inspector reviewed the control room operator's log regarding an event that occurred on November 6, 1994, during the Unit 4 cycle 15 outage.

(Note:

The Unit 4 cycle 16 outage was recently completed in April 1996).

The log noted a

SFP level of about two

II

~

~

07.1 inches during SFP transfer canal draindown per 4-0P-201, Filling/Draining the SFP Transfer Canal.

Corrective actions were performed; however, the log did not address root cause, nor was a

condition report initiated.

However, the OP did state that draindown should not be interrupted as a level decrease could occur until differential pressure seats the gate.

Procedure 0-ADM-518, step 7 of enclosure 1, stated that a condition report should be initiated for events caused by personnel errors (e.g.,

valves out of position).

Further, the step indicated that a

condition report was not necessary for corrective actions that involved simply correcting the error and counseling the individual.

Although not a procedural requirement (e.g., "shall" not stated),

the inspector concluded that a condition report could have been beneficial in this instance if the condition's cause was unknown.

The inspector discussed this issue with license management.

The inspector conclude'd, not withstanding the above comment, that the licensee's condition report system functions well to identify, correct, and trend problems.

guality Assurance in Operations Unit 4 C cle 16 Outa e Criti ue Licensee outage management conducted a self-assessment activity for the recently completed Unit 4 Cycle 16 outage.

A critique meeting was held on April 30, 1996.

Results of that critique were documented in a memo (PTN-OUT-96-052) dated May 6, 1996.

The licensee addressed outage successes including the achievement of all goals and improvements over previous outages; schedule losses and gains; and, areas targeted for improvements for future outages.

The inspector reviewed the memo and discussed it with outage management personnel.

The inspector noted that the major Unit 4 Cycle 16 outage successes were a 35'ay outage (schedule

<40 days),

158.5 man-Rem (goal

<215 man-Rem),

no major incidents, and major work scope completed.

The inspector reviewed the listing of comments and improvement recommendations.

In conclusion, the inspector noted that the Unit 4 Cycle 16 outage critique demonstrated very good and critical licensee self-assessment.

07.2 Mana ement Actions To Address 0 eratin Issues Based on recent instances of operator performance errors (NRC Inspection Report 50-250,251/96-04 and sections 01.2 and 06.2 of this report),

the licensee management instituted the following actions:

Temporarily removed the two licensed operators from shift for retraining, Operations Manager interviewed all licensed operators, Operators reread their license with emphasis of procedural compliance, Routine operations were accomplished for a four-week period with the procedure in hand, Retrained all operators in the CVCS OP, Revised CVCS OP to include required signoffs, JPH accomplishment for all licensed operators (RCOs),

Four-week around-the-clock management-on-shift (HOS)

coverage, Plant Management reviewed operator issues, and gA surveillance and monitoring of operator activities performed.

The inspector verified these actions, and discussed them with site and plant management personnel.

The inspector will assess their effectiveness during violation (50-250,251/96-04-02)

closure.

II. Maintenance Hl Conduct of Haintenance Hl, 1 General Comments a ~

Ins ection Sco e

62703 and 61726 The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

Unit 3 IR compressor after cooler drain trap repair (section Hl.6)

Unit 4 turbine control (section 01. 1)

Unit 3 steam trap cleanout and inspection (.section H1.7)

Unit 4 transformer deluge troubleshooting (section F2.4)

Unit 3 S/G blowdown PC/M 95-168 (section 02.3)

i

ll Unit 4 EDG preaction deluge system troubleshooting (section F2,4)

Fire pump troubleshooting and preventive maintenance (section F2.2)

Unit 4 feedwater heater RV repair (section 01.4)

Unit 3 PAHH valve repair (section H1.3)

Unit 3 SFP roughing filter inspection (section Hl.5)

Unit 3 Refueling Water purification pump oil leak (section Hl.4)

Unit 4 HOV-4-350 Repair (section H1.7)

B and C AFW governor stem replacement (section E8. 1)

The inspectors witnessed/reviewed portions of the following test activities:

N EDG rapid start testing (section E2.3)

Diesel and electric driven fire pump testing and troubleshooting (section F2.2)

Unit 3 penetration

LLRT (section H1.3)

A AFW pump testing (section ES. 1)

Unit 3 RPS testing (section H1.2)

b.

Procedure TP 96-44, Investigation of Unit 4 Control Oil Swings (section 01.1)

Observations and Findin s

For those maintenance and test 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.

C.

Conclusions The inspector noted very good procedure compliance.

Supervisor involvement was noted, including good briefings at the pre-evolution meetings,and reviews prior to field work.

Personnel demonstrated good team work and cooperatio M1.2 M1.3

Unit 3 Reactor Protection Testin The inspector observed portions of the Unit 3 Train B RPS test conducted on'une 4,

1996.

Procedure 3-OSP-049. 1, Reactor Protection System Test, was commenced as required by Technical Specification 3.3.1.

During the test, the B RTB failed to close from the control room.

Operators entered a six-hour TSAS.

Maintenance and system engineering responded and a blown fuse was found and replaced.

Subsequent PMT and operability checks were satisfactory and the RTB was returned to service within two hours from the beginning of the test.

The inspector independently assessed licensee actions including TSAS compliance, maintenance activities, coordination and operations oversight.

The inspector noted, that electrical maintenance response was prompt and very good.

gA, plant management, engineering, and material control personnel also responded.

Overall, very good teamwork and evolution control were noted.

A condition report was written to address the fuse failure and spare parts equivalency issues.

The inspector concluded that licensee actions were appropriate.

Unit 3 PAHM Re air On May 29, 1996, during performance of procedure TP 96-052,

. Cycling of PAHM Valves, Unit 3 PAHM Valve 3-001A failed.

The valve stem separated from the disc.

These PAHM valves are 3/4 inch valves, operated remotely in the auxiliary building with the use of reach rods.

The valves must be opened after an accident to place the hydrogen monitors in service.

The PAHM system shares the containment sample system, the PASS, and the hydrogen recombiner containment,penetrations (Nos.

32, 16, and 53).

The failure of PAHM-3-001A placed Unit 3 in a 30-day TSAS per Technical Specification 3.6.5.a.

In order to effect repairs, containment penetration No.

32 had to be isolated.

This disabled the PASS, the containment sampling sys'em, and both PAHMs, Numerous TSASs would have to be entered, the most limiting was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The licensee planned the work including contingencies if the post maintenance LLRT failed for other related valves.

Planning included involvement from all disciplines, documentation on the POD, and oversight at management and shift turnover meetings.

The system engineer was designated as overall coordinator.

Recent enhancements to the equipment outage process were used.

The repair, including clearances and LLRT, took from 4:45 a.m. to 10: 10 p.m.

on June 4,

1996.

This was consistent with the plan.

The inspector reviewed the plan, the TP, related documentation, test results, and discussed the repair with the licensee.

The inspector noted excellent teamwork and oversight of the job.

Recent enhancements appeared to be effective for this job.

TSAS

and procedure compliance was good and appropriate.

Overall, the

'icensee demonstrated noteworthy performance, including system engineer involvement.

Unit 3 Refuelin Water Purification Pum WO 96010930 checked the Unit 3 refueling water purification pump for an oil leak.

The work was considered safety-related and was in the nature of troubleshooting.

Indications of an oil leak were observable at the base of the Refueling Water Purification pump but the leak was not directly observable.

The troubleshooting process was to clean around the area of the pump, have operations run the pump for a period of time and reinspect for signs of a leak.

If leaks were found, the type of leak was to be documented and a repair procedure specified or developed.

The inspector observed that the work instructions were present at the job, health physics surveyed the area before clean up began, cleanliness was maintained, and generic procedures referenced in work instructions included cleaning, housekeeping, coatings, industrial safety, and equipment labeling.

The inspector concluded that the work instructions were adequate for the task and personnel performance was good.

Unit 3 S ent Fuel Pit Exhaust Fan Rou hin Filter WO 96011140 implemented the monthly PH to inspect the spent fuel pit exhaust fan roughing filter and was classified as non-safety related.

The inspector observed that gaskets were in good condition, filters were in "like-new" condition, and the differential pressure across the filter of 1.2 psid was well within the limit of 2.0 psid.

On this basis, filters were not replaced at this time.

The inspector concluded that the work instructions were sufficient for the task and personnel performance was adequate.

Unit 3 Instrument Air Com ressor Aftercooler Drain Tra WO 96011135 implemented weekly PH 013021 which required general cleaning, inspection, and lubricant checks.

WO 96001824 was issued for repair of non-safety related compressor aftercooler drain valve.

During this maintenance, the inspector observed the general cleaning and inspection of the compressor aftercooler, addition of oil, adjustment of oil feed rate to air motor, and replacement of the drain valve actuator.

Equipment clearance was established.

Proper tools and correct parts were available.

Work instructions were reviewed prior to the valve repair.

Supervision was present during the maintenance task.

Post-maintenance testing consisted of verifying proper actuation of the valve and no leakag The inspector concluded that skill of the craft in conjunction with work instructions were adequate for the assigned task.

Personnel performance was good.

Steam Tra -Extraction Steam To 3A Feedwater Heater WO 96010437 required inspection and repair of a steam trap in the extraction steam line for feedwater heater 3A.

The inspector observed that work instructions were reviewed prior to the job, correct parts were obtained and verified by supervision, clearance was established, and proper tools were available and calibrated.

The repair kit was installed and the trap reassembled.

Bolts were properly torqued with a calibrated wrench and a feeler gauge was used to verify correct bonnet seating.

In cleaning the trap, the technician found a black powder like substance had plugged the screen.

This material was removed from trap and line.

The technician reported this condition to his supervisor and obtained a sample for analysis of the source.

The inspector reviewed vendor manual 0-GHH-102. 13, Yarway Steam Trap Inspection and Overhaul, and found that vendor recommendations were adequately incorporated in the work instructions.

The inspector concluded that the work instructions were sufficient for the assigned task and personnel performance was good.

Unit 4 Emer enc Boration Valve Re air During the period June 11-14, 1996, the licensee repaired an apparent seat leak on the Unit 4 emergency boration valve HOV-4-350.

Detailed planning included technical specifications entry; safety evaluation clearances; freeze seals; electrical, mechanical and IEC maintenance interfaces; post-maintenance testing (HOVATS);

engineering involvement; gA/gC involvement; NDE requirements; and, outage/planning involvement.

The inspector reviewed UFSAR Section 9.2, the work plan, TSA 4-96-46-11, interfaces, work documentation (W096013038, 33172, 13164),

and PMT/NDE requirements, The inspector verified that technical specifications were properly followed.

The inspector observed portions of the work in the field, verified clearances, and discussed repairs with maintenance and management personnel.

The inspector concluded that the licensee's work plan was sound, that the work implemented was appropriate, and restoration and testing was good.

Overall, the licensee demonstrated very good performance.

Maintenance and Material Condition of Facilities and Equipment Containment Air Lock Testin

The inspector reviewed the testing, records for the Units 3 and

containment personnel air lock LLRTs.

CFR 50 Appendix J'nd Technical Specification 4.6. 1.3 requires a

LLRT every six months.

Technical Specification 3.6. 1.3 requires leakage to be limited to 0.05 La at Pa (49.9 psig).

This leakage value is 3750 cc/min.

Since 1992, both airlocks have been tested at least every six months.

One failure occurred on Unit 3 while in Mode 6 on November 1,

1992.

LLRT results were 4250 cc/min.

Repairs were made to an airlock vent valve (W092032035)

and a subsequent LLRT on November 6, 1992 passed (260 cc/min).

The inspector reviewed records, results, and discussed this issue with licensee test personnel.

The inspector concluded that LLRT was appropriately being conducted on the Unit 3 and 4 personnel air locks.

Walkdown of Batteries (37550)

The inspector walked down the safety-related batteries.

The inspector observed that the safety-related batteries were in good condition.

Cell No.

2 in the 4A battery had a small amount of sediment of no real consequence.

At the 4A battery, one of the intercell connectors utilized a washer that was different than the other washers, indicating that it probably had not been furnished by the battery manufacturer.

The washer in question was thinner than the other washers.

The inspector did not observe any deformation at this connection.

High resistance at this connection would been evident when the intercell resistances were checked as part of the surveillance.

Therefore, the inspector concluded that the discrepancy was of minor significance.

The design drawings and bill-of-material did not specify a washer thickness, only a diameter.

The licensee initiated a Condition Report to track evaluation of the discrepancy.

The inspector also compared the battery rack to the design drawings, and concluded that the rack had been constructed according to the drawings.

Maintenance Organization and Administration

~Staffin During the period, the inspector was informed of a voluntary termination of an INC supervisor.

This was the third supervisor to leave this year.

The inspector reviewed current staffing, historical turnover, and IKC performance.

Current staffing levels are near the authorized levels and the vacant supervisory positions were filled.

The'inspector noted that historical turnover in the I&C department has been high (10-20% per year).

Relative to performance, the inspection reviewed recent trend NRC Inspection Reports Nos. 50-250,251/95-19 arid 22 addressed negative performance issues in the I&C area.

Recent performance has notably improved.

This was evidenced by resident and specialist observations of I&C activities.

III.

En ineerin El Conduct of Engineering El. 1 Power U

rade Pro 'ect (37550)

The inspector reviewed the safety evaluations for modifications that had been implemented to support the Unit Power Upgrade Project.

The modifications reviewed were:

Number Title

'5-087 Rod Control CROM Timing Changes.95-089 Modification of CCW Supports on ECC Return Line Stress Problem CCW-14 95-097 95-100 95-104 95-113 95-120 Replacement of Hain Steam Safety Relief Valve Discharge Piping RTDP Related RPS/ESFAS Set Point Changes CCW Keat Exchanger Pedestal Modifications Condenser Tube Staking Piping Isometric Temperature Changes due to Thermal Uprate Implementation The inspector found that the safety evaluations were acceptable and in accordance with 10 CFR 50.59.

Statements and conclusions in the evaluations were supported by sufficient facts and details.

E2 Engineering Support of Facilities and Equipment E2. 1 Switch ear Room Water Intrusion On Hay 28-30, 1996, heavy rains in the area resulted in water intrusion into a number of electrical switchgear rooms.

The worst intrusion was in the 3C/3D 480 VAC load center room.

The inspector was onsite for this, and inspections of the room were made.

Although the switchgear was not wetted, the potential existed.

The licensee has pursued recent leakage problems, primarily from a degraded turbine deck expansion joint and a leaking drain pipe,

Ã

E2.2 The turbine deck provides the roof for the load center rooms.

Condition reports Nos.95-646 and 96-745, PC/H preparation, various PWOs and problem status summary documented this issue.

Interim corrective actions included modifying the drain system to divert water away from the damaged joint and temporary repairs to the drain system.

Longer term actions are planned for the 1997 refueling outages.

The inspector reviewed the documentation; walked down the buildings, drains, and expansion joint; and, discussed this issue with engineering and operations personnel.

The inspector concluded that the licensee has adequately dealt with this leakage issue.

Recent rains have not caused a repeat problem in the 3C/3D load center room.

Unit 4 Containment Sum Level During routine control. room walkdowns, the inspector noted that one Unit 4 containment sump level device (LI-4-6308A) was not functioning.

The licensee was tracking the device as OOS equipment.

Technical Specification 3.3.3.3, Table 3.3-5 items

and 13, address the narrow and wide range sump level accident instruments.

LT-4-6308A is a narrow range device (indication only) and the TSAS allows continued operation as long as one channel is operable.

The licensee confirmed operability of LT-4-6308B during routine sump pump drains (e.g. level changes occurred).

Further, procedure TP-96-49, Functional Checkout of Containment Sump Level Transmitters LT-4-6308A & B, was performed.

The TP also confirmed that the B channel was functional and that the A channel had failed.

The licensee scheduled repairs for a SNO of sufficient duration.

E2.3 The inspector independently confirmed the licensee's conclusions, assessed TSAS compliance, and reviewed related documentation.

The inspector concluded that the licensee has adequately assessed this equipment failure.

Support by engineering and technical department personnel was very good.

The inspector also concluded that Unit 4 operation could continue consistent with the TSAS.

Diesel Generator Failures

'a ~ Ins ection Sco e

37550 I

The inspector reviewed the root cause determination and corrective actions for recent emergency diesel generator (EDG) failures.

EDG 4A failed during surveillance testing on December 15, 1995, due to voltage regulator problems.

EDG 3B failed during surveillance testing on December

and 29, 1995, due to fuel oil priming system problems.

Refer to NRC Inspection Report No. 50-

'50,251/95-22 for details of the failures.

.During this inspection, the inspector reviewed the following documents:

l'

Failure report submitted by the EDG ven'dor, HKW Power Systems, Inc.

Licensee's Condition Reports.

Purchase Order for new parts and services.

Post modification testing related to corrective action for the above failures.

EDG system description.

EDG vendor manual pages F13 -F16.

Piping and Instrumentation Diagram for the fuel oil subsystem.

Elementary Diagrams for the motor driven fuel oil priming pump and voltage regulator.

Procedures for implementing Technical Specification surveillance testing on the EDG and the Integrated Safeguards Test.

b.

Observations and Findin s

The root cause determination, repair and modification work, and procurement of parts and services were acceptable.

'I The inspector identified a problem with the EDG test procedures in relation to the fuel.oil subsystem for the EDGs.

The fuel oil subsystem for the EDGs includes a motor driven fuel oil priming pump, which is connected in parallel with a shaft engine driven fuel oil pump.

Procedures for the EDG operability tests included steps to prime the engine fuel system by depressing and holding the fuel prime push button until fuel manifold pressure was verified.

These steps were performed daily and also before starting the EDG.

The inspector questioned whether fuel oil priming prior to starting the EDG was consistent with the Technical Specification requirement to start the EDGs from normal conditions.

In response, the licensee evaluated the fuel oil subsystem, the requirements of the Technical Specification, and the test procedures in light of this question.

The evaluation included consultation with the EDG vendor.

On Hay 21, 1996, at 11:00 a.m.

the licensee determined that starting the motor driven fuel oil priming pump was not consistent with the requirement to start from normal conditions.

This determination was based on the following facts:

gualification testing for the EDGs was carried out with the

motor driven priming pump in operation.

Therefore, the priming pump must be considered as having a safety-related function.

That function would be to ensure a fuel supply to the cylinders for the period of time between the start signal and full operation of the shaft driven pump.

This time was a few seconds.

Since the priming pump was safety-related, the automatic control circuitry for the priming pump motor must be verified by Technical Specification surveillance testing..

The surveillance testing had not verified functionality of a portion of the start circuitry, because the priming pump had been manually operated immediately prior to applying the start signal and operation of the priming pump had not been confirmed during the testing.

The circuitry that had not been verified was one relay contact and its interconnecting wiring.

The licensee entered Technical Specification 4.0.3 which required that the four EDGs be demonstrated operable, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, by starting from normal conditions.

The surveillance procedure was

~

revised, and the EDGs were successfully tested within the required time.

The licensee stated that, based on engineering judgement and inspection of the fuel.piping, residual fuel in the fuel header would allow starting of an EDG even if the priming pump did not operate.

This statement assumed no leak in the fuel header.

The licensee stated that applying manual priming before initiating the start signal had been performed during each test since initial plant startup for Unit 3 (3A and 3B EDGs).

For Unit 4 (4A and 4B EDGs), this had been done since the EDGs were placed in service during the Dual Unit Outage (1991).

This applied to the 30-day slow starts, the 184-day fast starts, and the once per refueling'ntegrated safeguards test.

Conclusions Technical Specification 4.8. 1. 1.2.a.4 requires that

"Each diesel generator shall be demonstrated operable at least once per 184 days by verifying the diesel starts and accelerates to reach rated generator voltage and frequency.

These conditions shall be reached within 15 seconds after the start signal from normal conditions."

For Unit 4, this requirement had been implemented by Procedure 4-OSP-023. 1, Diesel Generator Operability Test.

Step 7.3.2.3.c.

specifies that the fuel system be primed by depressing the Fuel Prime push button.

This step occurs before initiating the start signal for the operability test, and was not consistent with starting from normal conditions as required by the Technical Specification.

The procedure for Unit 3 was similar.

In addition, Procedure 4-OSP-203. 1, Train A Engineered Safeguards

Integrated Test, referred to Procedure 4-OSP-023.

1 to setup for the safeguards test.

These circumstances constitute a violation of NRC requirements in the area of procedures, since Procedures 3 and 4-0SP-023.1 did not ensure that the Technical Specification 4.8. 1. 1.2.a.4 was satisfactorily accomplished.

The item will be tracked as VIO 50-250,251/96-06-02, Surveillance Testing for Diesel Generators Did Not Start from Normal Conditions.

On June 18, 1996, the licensee submitted LER 250/96-08, Inadequate Surveillance Testing for EDGs.

The inspector reviewed the LER and concluded that the response requirements for the violation were met.

Based on the LER submitted, no response to the violation is required.

The LER and VIO remain open pending NRC review of corrective actions.

E8 ES. 1 Miscellaneous Engineering Issues 0 en IFI 50-250 251 96-02-02 AFW Issues During the period, the licensee completed modifying the B and C

AFW governor stems with an upgraded inconnel material and low sulphur washers.

The A AFW stem is scheduled for upgrading in July 1996.

Further, the licensee is still pursuing a modification to the train 1 steam supply piping to eliminate condensate induced overspeed trips.

Also, the licensee intends to continue periodic.

governor stem drag testing.

The inspector observed portions of the maintenance and testing activities, and discussed the repairs with engineering personnel.

The inspector noted that the AFW availability (both units) remains above the maintenance rule goal of 98.5X.

The inspector concluded that the licensee has been aggressive in addressing these AFW issues.

Further, system engineers ownership remained excellent.

The IFI remains open pending A AFW work, and train 1 steam supply modifications.

III.

~P1 Rl R1.1 Radiological Protection and Chemistry (RPSC) Controls Radiation Hot S ot Reduction Efforts The licensee instituted a Hot Reduction Team during the period.

An ALARA Review Board Meeting on May 2, 1996, recommended the establishment of this team.

The team's goal was to establish consistent and uniform methods to reduce plant radiation hot spots.

The team was comprised of personnel from engineering technical, operations, and ALARA (HP),

The licensee developed procedures (TPs) to flush the identified hot spot areas.

Other

actions included further studies, evaluations, and meetings.

The inspector assessed the hot spot reduction efforts, including reviewing meeting minutes, attending selected meetings, reviewing the approved Tps, and assessing the effect on auxiliary building access (e.g., Unit 4 RHR areas).

Overall, the inspector concluded that the licensee was proactively addressing the Turkey Point auxiliary building radiation hot spot issues.

A number of these hot spots occurred during the recent Unit 4 outage (Harch-April 1996).

R6 RPSC Organization and Administration R6. 1 ALARA Review Board ARB Based on inspector review of ARB activities, including meeting minutes summary, the inspector noted that the ARB remained proactive, and involved in plant operations and exposure reduction activities.'l Conduct of EP Activities Pl. 1 Hurricane Pre grat'ons The inspectors reviewed and discussed with the licensee the program and procedures associated with hurricane preparedness.

Hurricane season spans the months of June through November with the most intense activity expected to occur between August and October.

There are procedures, PHs, and other preparatory processes that the licensee performs at the onset of each hurricane season.,

Additionally, there are procedures that the licensee would implement upon declaration of a hurricane watch or warning.

The licensee has the following procedures in place to ensure adequate preparation due to a hurricane:

Procedure O-ONOP-103.3, Severe Weather Preparations, provides instructions for the preparation of the site for severe weather conditions not resulting in implementation of the Emergency Plan.

This procedure would be entered upon the notification of a tropical Storm Warning or a Hurricane Watch which includes the Turkey Point site.

(A Hurricane Watch is declared if a hurricane is located between 24 to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> from and is approaching the United States coast.

A Hurricane Watch area includes approximately 100 miles on either side of the expected landfall location.)

Instructions and guidelines for preparing, controlling, and recovering the plant following activation of the Emergency Plan for a natural emergency are provided in procedure EPIP-20106, Natural Emergencies.

This comprehensive procedure addresses tornadoes and hurricanes, but is to be used for any severe weather disturbance which results in the

V

activation of the Emergency Plan.

It also contains specific guidance for coping with the possible flood conditions associated with more intense hurricanes.

This procedure would be entered in advance of a Hurricane Warning.

A Hurricane Warning is declared if a hurricane is located between 12 and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from and -is approaching the United States coast.

A Hurricane Warning area includes approximately 50 miles on either side of the expected landfall location.

Procedure 0-SHM-1202. 1, Flood Protection Stoplog and Penetration Seal inspection, is utilized by the licensee to verify operability and adequate inventory of flood protection equipment.

Security force instruction SFI-3002, Hurricane Preparedness, provides guidance for security activities in preparation for, during, and following hurricane threats or actual conditions.

The FPL Nuclear Power Plant Recovery Plan is an FPL corporate document which establishes a pre-planned organization and action plan to recover from a nuclear power plant emergency and minimize unfavorable impact on the FPL plants and the public.

The licensee's preliminary preparations for hurricane season have been completed.

The satellite up-link communication capability is on-site and ready fo} use, and the stoplog walkdown inspections have been performed.

The licensee has also procured and stored non-perishable food supplies and the storm supply inventory for preparatory actions required by procedures.

Prior to the onset of a hurricane, these items would be moved to the designated storage areas.

The inspector reviewed the licensee's procedures, storm stock inventory lists, and PWOs regarding the flood protection stoplog inspection and various floor drain inspections.

The inspector concluded that the licensee has been proactive in the area of hurricane preparedness.

The licensee's procedures provide thorough compensatory measures for equipment or facilities not designed for a hurricane (see section P3. 1).

P3 EP Procedures and Documentation P3. 1 Emer enc Plan Procedures During the period, on June 3, 1996, the inspector learned of the licensee's intention to modify procedure EPIP 20106, Natural Emergencies, step 8.2.8.5, regarding unit shutdown prior to the onset of hurricane force winds.

The current procedure step required the units to be placed in Node 4 (Hot Shutdown)

two hours before the onset of Hurricane force wind The proposed change was as follows:

Cate or 1 or 2 Hurricane Proceed to Mode 3 (Hot Standby)

per the requirements of SBO per NUMARC 87-00 (reference L-90-338, dated September 21, 1990).

Cate or

4 or 5 Hurricane Proceed to Mode 4 (Hot Shutdown)

and maintain RCS T,,

between 350-343'F to assure AFW operating steam pressure (785 psig).

The inspector reviewed the procedure change form and -10 CFR 50.59 screen (RTS No. 95-0996P).

PNSC approved the change on Hay 31, 1996, at meeting No.96-116.

The inspector reviewed the UFSAR and the Emergency Plan.

The change did not conflict with any requirement nor commitment.

The inspector also reviewed previously promulgated (Hurricane Andrew) documents, including NRC Inspection Report No. 50-250,251/92-20, and NRC/INPO/FEMA studies.

Based on these reviews, the inspector did not identify any deficiencies.

P5 Staff Training and gualification in EP P5. 1 Emer enc Drill The inspector reviewed the licensee's critique for an emergency drill held on Hay 1, 1996.

The'rill was in preparation for the annual exercise.

Due to the recent Everglades aircraft accident, the annual drill originally scheduled for May 15, 1996, was postponed.

The inspector concluded that the Hay 1, 1996, drill was appropriately performed and self-critiqued.

Further, good training was received.

Sl Conduct of Security and Safeguards Activities Sl. 1 Securit Event Followu The inspector reviewed events associated with failures of the security computer and improper operation of a vital area door.

One of the failures was apparently improperly responded to on May 9,

1996, as documented in condition report No.96-689.

A security officer was not posted at one of the required areas within the required time limit.

Security plan implementing procedures required this action.

This event was also documented in the security event log.

Licensee corrective actions included security computer repair,

II

disciplinary actions, procedure/checklist enhancements, training improvements and event documentation as stated above.

The inspector was informed of the event by licensee security management and the inspector had noted the event during routine condition report review.

Failure to follow security plan implementing procedures is a violation.

This licensee identified and corrected violation is being treated as a non-cited violation, consistent with section VII.B.1 of the NRC Enforcement Policy NCV 50-250,251/96-06-03, Failure to Properly Compensate For Security Computer Failure.

The NCV is closed.

Control of Fire Protection Activities (64704 and 71750)

Control of Combustibles and I nition Sources The inspector reviewed procedures 0-ADH-016. 1 Transient Combustible and Flammable Substances Program and O-ADH-016.5, Hot Work Program, and UFSAR section 9.6A (subsection 2. 1 and 7. 1.2).

These procedures delineate the process controls which ensure proper use of ignition sources and combustible/flammable material.

During the recent Unit 4 outage (Harch-April 1996, the inspector toured the facility to check for the licensee's implementation of these fire prevention programs.

In addition, during the current report period, the inspector toured the facility and verified proper controls of all ignition sources and combustible/flammable material.

No discrepancies were noted.

The inspector concluded that the licensee has appropriate controls.

Recent Fire Incidents The inspector reviewed the recent (two year) fire incidents that have occurred at Turkey Point.

The incidents are summarized as follows:

Date Harch 21, 1994 June 21, 1994 Incident Laundry room dryer fire small hydraulic oil HacGregor substation (offsite)

fire Cause dryer malfunction electrical fault August 12, 1994 Small rag fire in Unit 4 condensate pit poor hot work controls December 6,

1994 Vehicle fire (backhoe)

near new cafeteria site oil leak

July 1, 1995 3B HCC non-vital breaker smoldering (CR 95-540)

equipment failure September 27, 1995 Laundry'oom fire in dryer (CR 95-962)

dryer fan blade failure F2 F2.1 The inspector reviewed each event including fire brigade response, root cause, corrective actions, and any related documentation.

Previous NRC Inspection Reports also reviewed selected incidents.

In each instance, fire brigade response was timely and effective.

Condition and fire incident reports documentation was good.

All fires (except the offsite substation)

were minor and needed no offsite assistance.

Further, only one fire was caused by poor fire protection controls.

The inspector concluded that the licensee has appropriate immediate and followup response to fires.

Status of Fit e Protection Facilities and Equipment Fire Water Su l

S stems The Turkey Point Fire Water Supply System includes two independent tanks and pumps.

Raw water tank I (500,000 gal.) supplies an electric fire pump and raw water tank II (750,000 gal.) supplies a

diesel fire pump).

A backup water supply can be installed from the screen wash system.

The fire protection main includes an underground 10 inch fire water loop with sectionalizing valves and hydrants.

The system supplies both nuclear units

8 4 and both fossil units

& 2.

Water deluge, dry and wet pipe sprinkler, preaction, hose station, and stand-pipe systems are also provided.

The inspector reviewed fire protection design standard H-006, P&ID 5610-H-3016, UFSAR section 9.6A (subsection 3.0),

and NFPAs 20 and 24.

The inspector also walked down portions of the system and reviewed recent test and trend data.

The inspector noted that some of the fire protection labelling was faded, included valve tags, diesel fire pump control panel, and some locked tags were missing.

Further, a broken lock wire was identified on the diesel injector pump.

Also, some component labels were either missing or broken.

These minor deficiencies were pointed out to operations and fire protection personnel, who corrected them.

None of the deficiencies affected system operability.

The inspector noted the fire water system to be in good material condition.

Open work items (PWOs) were appropriately tracked and were scheduled to be fixed.

F2.2 Fire Pum Desi n

Testin and Haintenance The inspector reviewed Turkey Point fire pump testing and design

information.

A common electric driven fire pump (P39)

powered from the 3A vital 480 volt AC load center, takes suction on the RWT I (500,000 gal).

A common diesel driven fire pump (P101),

independent of unit power, with an installed 8-hour fuel tank and starting batteries, takes suction on the RWT II (750,000 gal).

In addition,'wo fire water jockey pumps (P234 A and B provide system pressure at standby.

Detailed pump information follows:

~pum

~Pessure Flow Auto Start Electric 140 psi 2,000 gpm 80 psig Diesel 140 psi 2,500 gpm 70 psig The diesel fire pump was tested weekly (0-0SP-016.23, Diesel Driven Fire Pump Operability Test)

and annually (O-OSP-016.2, Diesel Driven Fire Pump Annual Surveillance Test).

Periodic and preventive maintenance was performed per various PHEs, PHHs, SFPs, SHEs, and SHHs.

The electric fire pump was tested monthly (0-OSP-016.26, Electric Fire Pump Operability)

and annually (0-OSP-016. 1, Electric Fire Pump Annual Surveillance Test).

The inspector reviewed recent test and maintenance results, observed selected tests, and reviewed pump trending information for the past five years.

The inspector concluded that design parameters were met.

Further, observed testing was well performed, with very good procedure compliance by operations.

The inspector noted that maintenance, engineering, and gA personnel were present observing selected testing activities.

The inspector noted that UFSAR section 9.6A (subsection 3.0) specified the fire pumps discharge pressure and design flows.

However, testing-acceptance criteria assumed some degradation.

The inspector verified that this was appropriate.

Further, the licensee stated that they would revise the UFSAR.

The inspector concluded that the fire pumps were well maintained and appropriately tested.

E ui ment Performance and Testin The inspector reviewed recent completed surveillance tests for fire protection equipment.

Open PWOs were also reviewed by checking a listing and by noting the identifiable tag in the field.

As of Hay 8, 1996, 145 PWOs were open on the listing.

Each item was well identified and plans to correct deficiencies were in place.

Further, for those deficiencies that caused a fire impairment, daily tracking and accountability was maintained in the POD.

This ensured management attention, and minimized the number of open impairments.

A goal of no more than five was targeted.

The majority of the open PWOs were associated with thermolag repairs.

None of the open PWOs made any fire pumps, water supply, or suppression systems inoperable.

Further,

detection systems were fully functional.

A sampling of completed tests (OSPs, PHEs, PHIs, PHHs, SHEs, SFPs, SHHs, SHIs) indicated that appropriate routine testing, surveillance, and preventive maintenance were being preformed.

The inspector also reviewed recent equipment failures, trending information, and condition reports.

Historical failures (1993-1996) associated with fire protection equipment have been trending down.

The licensee tracks'each failure, amount of downtime, impairments, condition reports, and associated corrective actions.

The inspector noted that a large number of inadvertent deluge system actuations occurred in 1994.

These were adequately addressed and corrected.

The issues were appropriately resolved as indicated by 1995-1996 performance.

For additional information, see NRC Inspection Report Nos. 50-250,251/94-11 and 20.

F2.4 Fire P otectio Detection and Su ression S stems The inspector walked down portions of the following systems:

CSR and Invertor Room Halon Systems (see also NRC Inspection Report No. 50-250,251/95-19),

EDG and Charging Pump Room Pre-action Sprinkler Systems, Transformer, lube oil, and seal oil deluge systems, Turbine and auxiliary building deluge (water curtain)

systems, CCW deluge systems, EDG fuel oil wet pipe sprinkler systems, fire detectors (all types),

fire dampers, fire barriers (seals, doors, walls, etc),

and portable fire extinguishers.

The inspector reviewed UFSAR section 9.6A (subsections 3.3, 3.4, 3.5, 3. 11, 3. 12, 3. 13, 3. 14, 3. 15, 7.2),

and related operating, maintenance, and surveillance procedures.

Hinor issues were discussed with licensee personnel.

The inspector concluded that licensee programs were appropriate, equipment appeared functional, and licensee procedures were goo F2.5

28 Heavy rain in the area on May 29, 1996 caused a loss of the 4B EDG fire deluge (pre-action)

system.

Fire impairments and condition

"

report 96-747 were initiated.

The outside panel was resealed.

The inspector verified corrective actions.

Thermola U date On April 29, 1996 through May 2, 1996, members of the NRR fire protection and systems branches visited Turkey Point Nuclear Plant.

During the visit, an independent review of the outside thermolag fire barriers and their relationship to plant fire hazards was performed.

Based on this review, the initial NRR view indicated that the existing level of fire protection and the 30-minute raceway fire barriers located in certain outdoor plant areas may provide an adequate level of fire safety.

With respect to the turbine building and its known fire potential, the initial NRR view indicated that the level of fire protection provided and the fire rating (1-hour or 30-minute) of the raceway fire barriers in this building were not adequate and additional fire protection features were needed.

For example, the licensee could meet the current regulation by upgrading the existing raceway fire barriers to 1-hour and installing a complete area wide sprinkler system in the turbine building under the turbine operating deck, the turbine lagging and in the bearing dog-house; upgrade the existing fire barriers to 3-hour designs or re-route the required raceways out of the fire area of concern.

F3 During the exit meeting of May 2, 1996, NRR personnel discussed the findings with the licensee.

This issue will be the subject of future correspondence.

Fire Protection Procedures and Documentation F3.1 0 erations Interfaces and Procedures The inspector reviewed operations related procedures and interfaces with the fire protection organizations.

Procedures reviewed included the following:

O-ONOP-016.8, Response to a Fire/Smoke Detector System Alarm,

O-ONOP-016.10, Pre-Fire Plan Guidelines and Safe Shutdown Manual Actions, O-ONOP-105, Shutdown From Outside the Control Room, EPIP-20107, Fire/Explosion Emergencies, 0-OP-016. 1, Fire Protection Water System, O-ONOP-016.2, Response to Spurious Actuation of a

Fire/Isolation Damper, O-ONOP-016.7, Screen Wash Emergency Hakeup to the Fire Protection System, O-OP-016.2, Fire and Smoke Detection System, O-OP-016.5, Halon Suppression System, The inspector reviewed implementation of selected procedures during observed drills, actual fire alarm conditions, and fire protection system manipulations.

No deficiencies were identified.

The inspector concluded that the licensee has good operations related fire protection procedures.

In addition, strong procedure compliance was noted.

Fire Protection Documentation The inspector reviewed related fire protection documentation including P&ID 5610-H-3016 (all sheets);

electrical and logic drawings; fire barrier doors, dampers, and seal drawings; and, fire detection system drawings.

The inspector noted the fire protection personnel had good access to these drawings, were knowledgeable, and demonstrated appropriate use.

Further, the inspector did not identify any-.

drawing or documentation deficiencies.

Fire Pre-Plan Procedures The licensee has detailed fire pre-plan procedures for all areas.

Procedure 0-ONOP-016. 10, Pre-Fire Plan Guidelines and Safe Shutdown Hanual Actions, promulgate the plans as attachments.

These procedures were available in the.control room.

The inspector reviewed the ONOP and the attachments, walked down selected pre-plans in the field, and observed operator use of these procedures during drills and actual fire alarm conditions.

The inspector noted good pre-plan procedure use and compliance.

Hinor procedure enhancements were discussed with the licensee.

Fire Protection Staff Knowledge and Performance Fire Watch Performance The inspector reviewed the licensee's program for fire watches, including training, performance and program requirements.

SBI Nuclear provided contractor services for the program at Turkey Point.

Procedure O-ADH-016.4, Fire Watch Program delineated the overall requirements.

The inspector also reviewed the following documents:

Fire Watch training handouts and related material, Fire rove routes, including fire areas, Fire Watch Organization, Fire Watch Logs, FWI-OOI, Access Sleeve Inspection, FWI-002, Manhole Inspection, Fire Watch Tests, FPDI-001, Closed Circuit TV FPDI-003, Fire Panel C39A Failure, FPDI-005, Monthly Fire Protection Surveillance, FPDI-009. Auto Dialer Response.

Based on issues associated with thermolag (section F2.5)

and other periodic fire impairments, FPL had initiated a fire watch program and organization.,

Four 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts, each with a supervisor and three to four fire watches, provided the compensatory coverage.

This included two roving patrols and one continually manned area with CCTV monitors for 40 in-plant cameras.

All thermolag areas outside containment are being monitored by both periodic roving patrols and by continuous camera and CCTV coverage.

The inspector accompanied fire watch patrols on their roves, monitored the CCTV/camera facility, toured with supervisors and questioned fire watch personnel.

The inspector concluded that compensatory fire watches were performed per the requirements, and that fire watch personnel were knowledgeable, cognizant of program requirements, and demonstrated a very good sense of ownership.

The inspector reviewed an event that occurred on May 9, 1996.

The 3B EDG preaction sprinkler system alarmed due to a trouble condition.

The licensee declared the system inoperable, established a continuous fire watch per procedure O-ADM-016, Fire Protection Program, and initiated a fire impairment (No. 6879).

After further investigation, the licensee concluded that the sprinkler system remained functional and therefore the continuous fire watch was secured.

An hourly rove was therefore established.

However, later in the day, the sprinkler isolation valve was closed, rendering the system inoperable.

This condition lasted for about nine hours, and a continuous fire watch was not posted as required.

Licensee corrective actions included condition report No.96-678, disciplinary action for the personnel error, fire watch correspondence detailing the event, and establishment

ANPO ANPS ANSI ARB ARM ARP BOP CC CCW cfm CFR CR CRDM CSR CV CVCS DDFP DP DPR DRS DWST EA ECC ECCS EDG e.g.

EOP EP EPIP ESF(AS)

oF FCV FEMA Fl FPL FWI GMM GOP gpm HEPA HHSI HP IA ILC ICW i.e.

IFI INPO JPM JPN KV L

Associate Nuclear Plant Operator Assistant Nuclear Plant Supervisor American National Standards Institute Alara Review Board Area Radiation Monitor Annunciator Response Procedure Balance of Plant Cubic Centimeter Component Cooling Water Cubic feet per minute O

Code of Federal Regulations Condition Report Control Rod Drive Mechanism Cable Spreading Room Control Valve-Chemical Volume Control System Diesel Driven Fire Pump Differential Pressure Power Reactor License Division of Reactor Safety Demineralized Water Storage Tank.-

Emergency Containment Cooler Emergency Core Cooling System Emergency Diesel Generator For Example Emergency Operating Procedure Emergency Preparedness Emergency Plan Implementing Procedure Engineered Safeguards Feature (Actuation System)

Degrees Fahrenheit Flow Control Valve Federal Emergency Management Agency Florida Florida Power and Light Fire Watch Instruction General Maintenance - Mechanical General Operating Procedure Gallons Per Minute High Efficiency Particulate Air High Head Safety Injection Health Physics Instrument Air Instrumentation and Control Intake Cooling Water That Is Inspector Followup Item Institute for Nuclear Power Operations Job Performance Measurement Juno Project Nuclear (Nuclear Engineering)

Kilovolt Letter (licensing)

lh l

La LER LI-LLRT LPDR LT m

M HCC Min MKW Co.

MOS HOV MOVATS HWe NCV NDE NFPA NOV NPO NPS NUHARC NRC NRR NSSS NWE ODI ONOP 00S OP OSP OTSC OUT Pa PAHH PASS PC/H PDR P&ID PIV p.m.

PH PHE PHH PHT PNSC POD psid Pslg PTN PWO QA Containment Design Leakrate Licensee Event Report Level Indicator Local Leak Rate Test Local PDR Level Transmitter milli Mechanical (drawing)

Motor Control Center Minute EDG Vendor Management-On-Shift Motor-Operated Valve HOV Acceptance Testing System Megawatts Electric Non-Cited Violation Non-destructive Examination National Fire Protection Association Notice of Violation Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Utilities Management Group Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear Steam Supply System Nuclear Watch Engineer Operations Depar'tment Instructions Off-Normal Operating Procedure Out-of-Service Operating Procedure Operations Surveillance Procedure On-the-Spot Change Outage (Department)

Containment Design Pressure Post-Accident Hydrogen Monitor Post-Accident Sampling System Plant Change/Modification Public Document Room Piping and Instrumentation Drawing Post Indicating Valve Post Meridiem Preventive Maintenance Preventive Maintenance Electrical Preventive Maintenance - Hechanical Post-Maintenance Test Plant Nuclear Safety Committee Plan of the Day Pounds Per Square Inch Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Quality Assurance

QAO QC RCA RCO RCP RCS RD rem RG RHR RO RPS RTB RTDP RV RWT SBO S/B SGFP SFI SFP SFP S/G

'GFP

~ SHE SHI SHH SNO SNPO SP ING SRO STAR Tavg TECH TP TSA TSAS

.UFSAR URI V

VAC VIO WO

Quality Assurance Organization Quality Control Radiation Control Area Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Radiation'etector Roentgen Equivalent Han Regulatory-Guide Residual Heat Removal Reactor Operator Reactor Protective System Reactor Trip Breaker Reactor Thermal Design Process Relief Valve Raw Water Tank Station Black Out Standby SGFP Security Force Instruction Spent Fuel Pit Fire Protection Surveillance Steam Generator S/G Feedwater Pump Surveillance Maintenance - Electrical Surveillance Maintenance IKC Surveillance Maintenance Mechanical Short Notice Outage Senior Nuclear Plant Operator System Particulate Iodine Noble Gas (Monitor)

Senior Reactor Operator Stop-Think-Act-Review average coolant temperature Technical Department Temporary Procedure Temporary System Alteration TS Action Statement Updated Final Safety Analysis Report Unresolved Item Volt Volt AC Violation Work Order

F4.2 of JPMs for fire watch performance.

This licensee identified and corrected violation is being treated as a non-cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.

NCV 50-250,251/96-06-04, Failure to Properly Establish a

Continuous Fire Watch, and is closed.

Fire Bri ade Mannin The licensee maintains a five person fire brigade as required by Procedure O-ADM-016, Fire Protection Program, and UFSAR section 9.6A (subsections 2.4 and 7.0).

The fire brigade includes three members from operations (including the leader)

and two members from HP.

The NWE assured appropriate manning every shift by documenting assignments using a form provided by fire protection and filed in the control "red book".

F5 F5.1 The inspector verified proper manning periodically during the period, including backshifts and weekends.

The inspector concluded that the licensee effectively provided for and documented fire brigade manning.

The inspector did note that fire brigade manning was concurrent to normal shift complement, and in addition to the manning necessary to effect a two unit shutdown outside the control-room, (see NRC Inspection Reports No. 50-250,251/95-9 and 10).

Additionally, the inspector questioned whether fire brigade members or shutdown required positions could perform shift duties which would make them unavailable for a short period (e.g.,

containment entries, switchyard clearances, etc.).

Although no formal guidance exists, licensee practice allowed fire brigade members (other than the leader)

and shutdown-positions to perform these normal routine shift duties if no other personnel were available.

The licensee reviewed this practice, including possible procedural coverage.

An OOI will be written to address this issue.

In the interim, operations issued a night order and a training brief (No. 628).

Fire Protection Staff Training 'and gualification Fire Bri ade Trainin Pro rams The inspectors reviewed fire brigade training programs during NRC Inspection Report No. 50-250,251/96-01.

Further, fire drills were observed on April 24 and 26, 1996, and during NRC Inspection Reports No. 50-250,251/95-19, 14, 11, 9, 1.

All drills observed were appropriately scheduled, planned, performed, and critiqued.

Unsatisfactory drill performance was documented and corrected.

The inspector verified that quarterly, annual, backshift, and unannounced drills were being performed as required.

The inspector reviewed fire brigade member medical examination

F6 F6.1

requirements and related records.

An annual physical per

CFR 50, Appendix R requirements was performed.

The inspector reviewed the sample medical questionnaire and concluded it to be appropriate.

During fire drills and annual practice sessions, the inspector verified that medically fit personnel were available.

In one instance, a fire brigade member with a back problem was replaced by a medically fit member.

The NWE has this responsibility each shift.

The inspector concluded that the fire brigade training and qualification programs were appropriate in assuring well trained and medically.fit fire brigade members were available to fight fires.

UFSAR section 9.6A (subsection 7. 1)

and procedure 0-ADM-016.2 Fire Brigade Program, requirements and commitments were also reviewed.

The inspector also noted that 80X of the fire brigade staff had been certified as Florida State Volunteer fire fighters.

No unacceptable conditions were identified.

Fire Protection Organization and Administt ation Fire Protection Or anization The inspector reviewed the licensee's Fire Protection organization which included two supervisors, three analysts, a fire watch organization (see section F4. 1),

and a fire brigade shift organization (see section F4.2).

This organization reports to the Services Manager and was supported by the technical, engineering, training, operations, maintenance, and HP organizations.

The inspector reviewed procedure O-ADH-016, Fire Protection Program, and UFSAR section 9.6A (subsections 2.4 and 7.0.)

The inspector concluded that organizational requirements were met.

F6. 2 Offsite Fire Res onse F6.3 The inspector verified that FPL has agreements with offsite fire protection organizations.

This included agreements dated December 18, 1995, with the"Homestead Air Reserve Base; and dated July 10, 1995, with Metro-Dade County Fire Rescue Department.

Both agreements were verified to be current.

Further, drills involving these offsite organizations were being conducted annually.

The most recent drill was performed on November 8,,1995.

The inspector concluded that the licensee meets the UFSAR section 9.6A, subsection 3.9 regarding the maintenance of agreements, training, and drill requirements.

Recent Plant Modifications The inspector reviewed the fire protection interfaces with the PC/H process.

Recent PC/Hs reviewed.included the following:

I

Cold Chemistry Lab, PC/H 93-099, Instrument Air Upgrade, PC/Hs93-108 and 109, Control Room Ceiling Tiles Replacement, PC/H 94-122, New Site'afeteria, PC/H 94-119, CCW Deluge Panel Wiring Hods, PC/Hs94-081 and 099, B S/B SGFP (diesel),

PC/M 94-059 The inspector verified that fire protection criteria was appropriately addressed during PC/H design, installation, and testing phases.

No detrimental fire protection program effects were identified.

The licensee's program for modifications appeared to appropriately address fire protection issues.

F7 guality Assur ance in Fire Protection Activities F7. 1 ualit Assurance Audits Technical Specifications 6.5.2.8.e and f require periodic audits of the fire protection activities. including a 24 monthly programmatic audit, a

12 month equipment and implementation audit, and a 36 month independent review by an outside consultant.

The inspector verified that audits gAO-PTN-.95-017,95-007, and 94-007 implemented these requirements.

The audits reviewed all fire protection activities including detection and suppression, fire barriers (doors, walls, dampers, seals, etc.),

design and configuration control, fire watch and brigade programs, ignition source and combustible material control, 'training, procedures, event response, commitments, Thermolag issues, and

CFR 50 Appendix R and UFSAR compliance:

Positive and negative findings were addressed.

The audits concluded that the Turkey Point fire protection program.was satisfactorily implemented.

Findings were identified relative to penetration seals documentation.

Corrective actions were addressed and determined to be adequate.

The 1994 audit also identified problems with one fire brigade member's annual physical.

Corrective actions were appropriate, and no repeat-issues were noted during the subsequent two audits.

The inspector reviewed the audits and discussed results with gA and fire protection personnel.

The inspector noted the audits to be appropriately independent, thorough, and well documente V.

Mana ement Heetin s

X1 Exit Meetin Summar X2 The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on June 19, 1996.

The licensee acknowledged the findings present.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

Pre-Decisional Enforcement Conference Summar X3 On June 14, 1996, a pre-decisional enforcement conference was held in the Region II offices in Atlanta, Ga.

Members oF the FPL stafF and former members involved in the DOL case No. 92-ERA-10 were in attendance.

The NRC's resolution will be the subject of future correspondence.

Mana ement eeti Summa On June 10, 1996, a licensee self-assessment meeting was held in the Region II officers in Atlanta, Ga.

The'icensee discussed their performance over the past two years.

'Members of the licensee's site organization and NRC: RII and NRC:

NRR were present.

Partial List of Persons Contacted Licensee T.

R.

J.

p.

C.

W.

T.

J.

R.

S.

R.

J.

R.

J.

p.

G.

R.

M.

D.

V. Abbatiello, Site guality Manager J. Acosta, Company Nuclear Review Board Chairman C. Balaguero, Reactor Engineering Supervisor H. Banaszak, Electrical/I&C Engine Supervisor R. Bible, Site Engineering Manager H. Bohlke, Vice President, Engineering and Licensing J. Carter, Project Engineer M. Donis, BOP Engineer Supervisor J. Earl, gC Supervisor M. Franzone, Instrumentation and Co~trois Maintenance Supervisor J; Gianfrancesco.

Maintenance Planning Supervisor H. Goldberg, President, Nuclear Division G. Heisterman, Maintenance Manager R. Hartzog, Business Systems Hanager C. Higgins, Outage Manager E. Hollinger, Licensing Manager J.

Hovey, Site Vice-President P.

Huba, Procurement Supervisor E. Jernigan, Plant General Manager

H.

H. Johnson, Operations Manager H.

D. Jurmain, Electrical Maintenance Supervisor V. A. Kaminskas, Services Manager J.

E. Kirkpatrick, Fire Protection, EP, Safety Supervisor J.

E. Knorr, Regulatory Compliance Analyst G.

D. Kuhn, Procurement Engineering Supervisor R.

S. Kundalkar, Engineering Manager H. L. Lacal, Training Hanager J.

D. Lindsay, Health Physics Supervisor E. Lyons, NSSS Engineer. Supervisor F.

E. Harcussen, Security Supervisor R.

B. Marshall, Human Resources Manager D.

D. Hiller, Acting Projects Supervisor H.

N. Paduano, Manager, Licensing and Special Projects H. 0. Pearce, Projects Supervisor K.

W. Petersen, Site Superintendent T.

F. Plunkett, Assistant to the President K. L. Remington, System Performance Supervisor R.

E.

Rose, Nuclear Materials Manager C. V. Rossi, gA and Assessments Supervisor D. A. Sager, Vice President, Nuclear Assurance A. H. Singer, Operations Supervisor R.

N. Steinke, Chemistry Supervisor E. A. Thompson, Project Engineer D. J.

Tomaszewski, Component Specialist Supervisor B.

C. Waldrep, Mechanical Maintenance Supervisor G. A. Warriner, guality Surveillance Supervisor NRC R.

P. Croteau, NRR Project Manager B. B. Desai, Resident Inspector T.

P. Johnson, Senior Resident Inspector P. J. Fillion, DRS Inspector H. L. Whitener, DRS Inspector K. S.

West, NRR P.

Madden, NRR L. B. Marsh, NRR List of Opened, Closed, and Discussed Items 0 ened 50-250,251/96-06-02 LER 250,251/96-08 VIO, Surveillance Testing for Diesel Gener tors did'ot Start From Normal Conditions (section E2.3)

LER, Inadequate EDG Surveillance (section E2.3)

Closed 50-250,251/96-06-01 50-250,251/96-06-03 50-250,251/96-06-04

NCV, Lack of Common Designation for Certain RG 1.97 Instruments (section H62.2)

NCV, Failure to Properly Compensate for a Security Computer Failure (section Sl. 1)

NCV, Failure to Properly Establish a Continuous Fire Watch (section F4. 1)

Discussed 50-250,251/96-02-02 IFI, AFW Issues (section ES. 1)

List of Inspection Procedures Used IP 37550:

Engineering IP 37551:

Onsite Engineering IP 40500'ffectiveness of Licensee Controls in Identifying, Resolving, and Prevent Problems IP 61726:

Surveillance Observations IP 62703:

Haintenance Observations IP 64704:

Fire Protection Program IP 71707:

Plant Operation IP 71750:

Plant Support Activities IP 90712:

Inoffice Review of Written Reports IP 90713:

Review of Periodic Reports IP 92700:

Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92903:

Followup - Engineering List of Acronyms and Abbreviations AC ADH AFW ALARA a,m.

Alternating Current Administrative (Procedure)

Auxiliary Feedwater As Low As Reasonably Achievable Ante Heridiem

0