IR 05000250/1996001

Insp Repts 50-250/96-01 & 50-251/96-01 on 951230-960210.No Violations Noted.Major Areas Inspected:Plant Operations, Plant Events,Maint,Engineering,Plant Support & Radiological Controls & Fire Protection

ML17353A613
Person / Time
Site:	Turkey Point
Issue date:	03/08/1996
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A612	List: IR 05000250/1996001 ML17353A611
References
50-250-96-01, 50-250-96-1, 50-251-96-01, 50-251-96-1, NUDOCS 9603260284
Download: ML17353A613 (44)

Text

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."e 4y*y4 UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTASTREET, N.W., SUITE 2900 ATlANTA,GEORGIA 303234199 Report Nos.:

50-250/96-01 and 50-251/96-01 Licensee:

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

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

B. B. Desai, Resident Inspector B.

R.

rowley RS Inspector (sections 4.2.3 to 4.2.7)

a 8'A D t Signed Approved by:

t K. D. Landis, Chief Reactor Branch

Division of Reactor Projects Inspection Conducted:

D ember 30, 1995 through February 10, 1996 Inspectors:

sl @fee, y~T P. Johnson, Senior Resident Date Signed Inspector SUMMARY Scope:

Inspections were conducted by the resident and regional inspectors to assure public health and safety.

It involved direct inspection at the site in the following areas:

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

Backshift inspections were performed in accordance with Nuclear Regulatory Commission inspection guidance.

Results:

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

The inspectors identified the following non-cited violation:

NCV 50-250,251/96-01-01, Failure to Follow Contaminated Control Procedures (section 4.2.3).

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

Plant 0 erations The licensee appropriately pursued and resolved an issue pertaining to the stroke timing of a containment isolation valve (section 3.2.1).

Response and efforts pertaining to the 3A Reactor Coolant Pump low seal leakoff flow were aggressive, including discussions with Westinghouse and initiation of recommendations.

The inspectors noted a discrepancy associated with the annunciator setpoint for seal leakoff flow for which appropriate actions were initiated (section 3.2.2).

The licensee was proactive in updating their probabilistic safety assessment and aggressive in promulgating information to plant personnel.

Overall plant safety has increased (section 3.2.3).

The quality assurance organization and the off-site and on-site safety committees were functioning well, and were appropriately focused towards nuclear safety (sections 3.2.4, 3.2.5 and 3.2. 10).

The licensee has a very good program which identified, tracked, and corrected equipment issues which affect control room monitoring and response capability (section 3.2.6).

Performance associated with the control of safety equipment during on-line maintenance activities was mixed:

excellent performance was noted for a startup transformer outage and weaknesses were observed when redundant safety equipment was taken out-of-service (section 3.2.7 and 3.2.9).

The licensee has been proactive in addressing reactivity control measures (section 3.2.8).

Another grass and algae influx occurred at Turkey Point resulting in short term low intake cooling water flows.

The licensee reacted to this problem promptly and corrective actions previously in place were effective in minimizing the overall impact (section 3.2. 11).

The Updated Final Safety Analysis Report was determined to be adequate for those chapters reviewed (section 7.0).

Maintenance The inspector observed that station maintenance and surveillance testing activities were completed in a satisfactory manner with an exception as discussed in section 4.2.3 (sections 4.2.1 and 4.2.2).

A failure to adequately follow contaminated material control procedures during a pump grease. evolution was a non-cited violation (section 4.2.3).

Diesel driven fire pump maintenance was appropriately conducted (section 4.2.4).

Two instances of Instrumentation and Control procedure weaknesses were identified (sections 4.2.5 and 4.2.6).

Poor planning was observed during blender flow control Instrumentation and Control maintenance (section 4.2.7).

En ineerin Special reports associated with recent Emergency Diesel Generator failures were timely and appropriately addressed the issues.

Further, activities and follow-up associated with a diesel fuel oil transfer valve problems were aggressive (section 5.2. 1).

A previous violation

associated with component cooling water design issues was closed (section 5.2.2).

A previous unresolved item pertaining to the containment radiation monitor was resolved and closed (section 5.2.3).

Safety-related pump failures were appropriately addressed, and the licensee demonstrated a safety conscious sensitivity (section 5.2.4).

Followup and root cause analysis associated with a emergency containment cooler outlet valve failure was aggressive and component engineer involvement was noteworthy (section 5.2.5).

The licensee appropriately identified and corrected a steam generator blowdown flow anomaly (section 5.2.6).

The licensee appropriately responded to a turbine overspeed trip associated with auxiliary feedwater (section 5.2.7).

Followup and coordination associated with a hydrogen recombiner issue was prompt and appropriate (section 5.2.8).

Plant Su ort The ALARA Review Board was noted to function well and was proactive in their efforts to minimize site dose (section 6.2.1).

Fire brigade training was determined to be very good (section 6.2.2).

U date Final Safet Anal sis Re ort UFSAR Review The inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected (section 7.0).

The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameter \\ ~

TABLE OF CONTENTS 1.0 Persons Contacted..............................................

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

1.2 NRC Personnel

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

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2.1 2.2 2.3 U t nit 3 o

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Personnel Changes..................

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3.0 Plant Operations....................................

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3.1 Inspection Scope...................

3.2 Inspection Findings................

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4.1 Inspection Scope.............

4.2 Inspection Findings..........

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...12 5.0 Engineering....................................................17 5. 1 Inspection Scope.............

5.2 Inspection Findings..........

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...17 6.0 Plant Support..................................................23 6.1 Inspection Scope.............

6.2 Inspection Findings..........

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...23 7.0 Update Final Safety Analysis Report.............................24 8.0 Exit Interviews................................................25 9.0 Acronyms and Abbreviations..;..................................25

REPORT DETAILS 1.0 Persons Contacted Li

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censee Employees V. Abbatiello, Site guality Manager J. Acosta, Company Nuclear Review Board Chairman C. Balaguero, Reactor Engineering Supervisor M. Banaszak, Electrical/IEC 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 Controls Maintenance Supervisor J. Gianfrancesco.

Maintenance Planning Supervisor G. Heisterman, Maintenance Manager R. Hartzog, Business Systems Manager C. Higgins, Outage Manager E. Hollinger, Licensing Manager J.

Hovey, Site Vice-President P.

Huba, Procurement Supervisor E. Jernigan, Plant General Manager H. Johnson, Operations Manager D. Jurmain, Electrical Maintenance Supervisor A. Kaminskas, Services Manager E. Kirkpatrick, Fire Protection, EP, Safety Supervisor E. Knorr, Regulatory Compliance Analyst D. Kuhn, Procurement Engineering Supervisor L. Lacal, Training Manager D. Lindsay, Health Physics Supervisor T. Luke, Engineering Manager Lyons, NSSS Engineer Supervisor E. Marcussen, Security Supervisor B. Marshall, Human Resources Manager D. Miller, Acting Projects Supervisor Mowrey, Compliance Specialist N. Paduano, Manager, Licensing and Special Projects 0. Pearce, Projects Supervisor W. Petersen, Site Superintendent F. Plunkett, President, Nuclear Division L. Remington, System Performance Supervisor E.

Rose, Nuclear Materials Manager V. Rossi, gA and Assessments Supervisor A. Sager, Vice President, Nuclear Assurance M. Singer, Operations Supervisor N. Steinke, Chemistry Supervisor A. Thompson, Project Engineer J.

Tomaszewski, Component Specialist Supervisor C. Waldrep, Mechanical Maintenance Supervisor A. Warriner, guality Surveillance Supervisor

Other licensee employees contacted included construction crafts-men, engineers, technicians, operators, mechanics, and electri-cians.

1.2 NRC Personnel R.

P.

B.

R.

B. B.

T.

P.

K. D.

Croteau, NRR Project Manager Crowley, DRS Inspector Desai, Resident Inspector Johnson, Senior Resident Inspector Landis, Branch Chief, Region II

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

Note:

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

2.0 Plant Status 2.1 Unit 3 2.2 At the beginning of this reporting period, Unit 3 was operating at full reactor power and had been on line since October 18, 1995.

On January 31, 1996, the unit was reduced to 60% and then to 40%

due to aquatic grass problems in the intake and canal.

The licensee also performed routine testing and preventive maintenance during this time frame and returned the unit to full power on February 3, 1996.

On February 9, 1996, the unit was reduced to 60% to perform secondary plant corrective maintenance.

An automatic reactor trip occurred which will be reviewed in the next inspection.

Unit 4 2.3 At the beginning of this reporting period, Unit 4 was operating at full reactor power and had been on line since March 12, 1995.

The'nit remained at or near full power during this period.

Personnel Changes Mr. J. T. Luke was appointed as the Turkey Point Engineering Manager effective January 31, 1996.

He relieved Mr. R. S.

Kundalkar who resigned from FPL.

3.0 Plant Operations (40500, 71707, and 93702)

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

The

3.2 3.2.1 inspectors accomplished this by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and technical specification compliance, review of facility records, and evaluation of the licensee's management control.

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

The significance of these events was evaluated along with the performance of the appropriate safety systems and the actions taken by the licensee.

The inspectors verified that required notifications were made to the NRC and that licensee followup including event chronology, root cause determination, and corrective actions were appropriate.

The inspectors also performed a review of the licensee's self assessment capability by including PNSC and CNRB activities, gA/gC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicators.

Inspection Findings Unit 3 Containment Isolation Valve Stroke Time Test Failure The inspector reviewed licensee actions pertaining a containment isolation valve that failed the quarterly inservice test.

Pressurizer liquid space sample valve (CV-3-953) stroked at 12.05, 11.79, 11.77, and 11.79 seconds, respectively during the performance of 'procedure 3-0SP-206.2, quarterly Inservice Valve Testing.

The maximum allowed time was 11.53 seconds.

The licensee initiated a condition report and appropriately isolated the redundant containment isolation valve (CV-3-956B) in accordance with Technical Specification 3.6.4.b.

An investigation revealed that the limit switch associated with the valve was misaligned.

The limit switch was adjusted and the valve was returned back to service following a satisfactory retest.

The inspector concluded that the licensee appropriately pursued and resolved this issue.

3.2.2 Unit 3 3A Reactor Coolant Pump Seal Leakoff Flow The inspector reviewed and discussed licensee actions associated with low number 1 seal leakoff flow that the 3A RCP has experienced since April 1994.

The number 1 seal for the 3A was replaced in April 1994 as part of normal maintenance.

Since then, the number 1 seal leakoff flows for the 3A RCP have ranged from approximately 0.4 gpm to approximately 0.9 gpm on the wide range recorder and off-scale high to approximately 0.9 gpm on the narrow range recorder.

The recorders'cales are 0 to 6.0'gpm and 0 to 1.0 gpm, respectively.

The narrow range indication more accurately reflects actual RCP seal leakoff flow.

The number

seal leakoff flows for the 3B and 3C RCPs are approximately ~

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gpm each on the wide range and off-scale high on the narrow range.

The number 1 seal for the Turkey Point RCPs were supplied by Westinghouse and are a film riding type with minimum recommended leakoff flow of 0.8 gpm.

Further, the licensee has observed a

correlation between cooler ambient air temperatures and a

decreasing trend in seal leak off flow.

Cooler ambient air temperature lowers CCW temperature which affects the VCT and charging flow temperatures which in turn affects seal leakoff flow.

The 1'icensee contacted Westinghouse seal design engineers and discussed the low seal leakoff problem.

Following the discussion with Westinghouse, the licensee issued a list of operating recommendations as well as verified instrument specific parameters as well as valve alignments to rule out possible contributors to the low seal leakoff flow.

Further, Westinghouse also suggested to the licensee that it is highly probable that the seal package on the 3A RCP has a characteristically low seal leakoff flow rate that could be tolerated through the remainder of this operating cycle which ends in Parch 1997.

The inspector reviewed the recommendations, the completed and planned verification activities, procedure 3-0P-041.1, Reactor Coolant Pump Off-Normal, Westinghouse Technical Bulletin ESBU-TB-03-Ol-Rl associated with RCP shutdown due to seal leakage outside operating parameters, and Control Room Annunciator Response Procedure 3-ARP-097.CR for low RCP seal leak-off.

During the review of the annunciator response procedure 3-ARP-097.CR, the inspector noted that the setpoint for the control room annunciator for low seal leakoff flow was 0.7 gpm.

The inspector requested the licensee to determine if the 0.7 setpoint was appropriate in view of Westinghouse recommended minimum leakoff flow of 0.8 gpm.

The licensee reviewed the applicable procedures and concluded that a change to the setpoint was appropriate.

Subsequently, the licensee initiated a

REA to change the setpoint.

Further, the inspectors noted differences in the OP and ONOP values for seal leakoff flows, and related actions.

The licensee initiated corrective actions to address these differences.

The inspectors concluded that licensee response to inspector questions were prompt including differences in the ARP, OP, and ONOP procedures.

Further, the inspector concluded that licensee efforts pertaining to issue were aggressive, including discussions with Westinghouse and initiation of recommendations.

The inspectors plan to continue to monitor this issue.

3.2.3 Turkey Point Probablistic Risk/Safety Assessment Update The licensee completed an update to their site specific PSA in 1995.

This included a review of site specific equipment and component history from 1990 through 1994, a review of all PC/Hs, and an update of the PSA model.

The new calculated safety factor

3.2.4 was better in that CDF decreased from 6.63 E-5 per year to 6.30 E-5 per year (an increase of 5% in plant safety).

Other changes included a rearrangement of the top ten important systems and new important operator actions.

For example, the AFW system has increased in importance (from 8th to 3rd).

The CCW system and the CVCS system remained 1st and 2nd in overall importance, respectively.

The licensee promulgated this new information by classroom training, by disseminating training brief No.

599 and information bulletin No. 96-02, by issuing laminated cards used by site personnel, and by posting information around the site on bulletin boards.

Additional licensee actions included a planned update to the risk table for equipment OOS in procedure O-ADM-210, On Line Maintenance; sending a letter (L-96-021) to the NRC summarizing these changes; and, pursuing an "on-line" risk monitor as an operator tool.

The inspector reviewed the above mentioned documentation, verified licensee actions, and discussed these changes with PSA engineering and operations personnel.

The inspector concluded that the licensee was proactive in updating the PSA, and aggressive in promulgating information to site personnel and in the conduct of PSA related training.

Company Nuclear Review Board The inspector attended a portion of CNRB meeting No. 427 held at Turkey Point on January 16, 1996.

The inspector verified that the meeting was conducted in accordance with Technical Specification 6.5.2, NP-803 (Nuclear Policy - CNRB),

and CNRB implementing procedures.

Generally, the CNRB meets monthly, rotating the location of the meeting among the three FPL sites (e.g.,

Turkey Point, St. Lucie and Juno Beach).

Normally representatives from all three locations are present at each meeting.

At this recent meeting, CNRB members noted that there was no representation from the St. Lucie Site, even though St. Lucie issues were discussed.

The CNRB initiated an action item to address this issue.

The inspector noted that the Turkey Point Plant Manager's report was very informative and it sparked a good exchange of questions and a healthy discussion.

The inspector also noted that the CNRB addressed self-assessment issues and held a discussion of early warning indicators in order to identify degrading performance.

The inspector intends to review this area in the future.

The inspector also discussed these specific issues with the CNRB chairman on several occasions.

Notwithstanding the above issues and comments, the inspector concluded that the CNRB remained focused towards nuclear safety,

3.2.5 3.2.6 effectively carried out their charter, and that members displayed a very good questioning attitude.

Plant Nuclear Safety Committee The inspectors attended several PNSC meetings during the period.

Technical Specification and procedure requirements were verified, including meeting frequency, quorum, and review responsibilities.

The inspectors noted a good questioning attitude by most members.

At one meeting, the PNSC rejected a proposed revision to the ODCN (Rev.

6) because chemistry personnel could not demonstrate that the NRC TER comments (reference 9/29/95 NRC letter)

had been adequately incorporated.

Overall, the inspectors concluded that the PNSC was functioning well.

Control Room Deficiencies The inspector reviewed the licensee's process for documenting, tracking, evaluating, and repairing control room deficiencies.

This included issues associated with control room indications and controls, with plant equipment, with alarms and annunciators, and with operator workarounds (long term and short term).

Operators documented these deficiencies per an ODI as well as a maintenance PWO.

The use of a computerized list and a "brown dot" on the control boards assisted the operators in denoting deficiencies.

Operator workarounds and equipment OOS were generally denoted by a tag (caution, information, or clearance type).

Technical Specification required equipment that was OOS was logged separately per procedure O-ADM-213, Technical Specification Required Equipment Out-of-Service Logbook.

Further, the maintenance ILC group used a "green tag" tracking.system (Green signified that an open PWO existed).

The inspector audited the Unit 3 open deficient equipment issues and concluded that the status was well known by both operations and maintenance personnel.

Further, plant management was aggressive in ensuring that open items were tracked and closed in a timely fashion.

These items were covered daily in the POD meeting and listed in the documentation package.

The operator workaround list was also well documented, known by operators, and aggressively pursued by management.

The inspector did identify several minor administrative errors in the various lists, which the licensee corrected.

The inspector interviewed a number of operators regarding the possible negative synergistic effects of these deficiencies, and concluded that the existing plant status was appropriate.

No technical specification issues or violations were identifie Overall, the inspector concluded that the licensee has a sound program to identify, track, and close equipment issues which effect control room monitoring and response capability.

3.2.7 Unit 4 Startup Transformer Outage On January 30, 1996, at 4:30 a.m., the licensee removed the Unit 4 startup transformer from service for a planned 35 hour4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> preventive maintenance outage on the transformer and associated breakers, switches, and relays.

Technical Specification 3.8.1.1 action a

was entered placing Unit 3 in a 30 day action and Unit 4 in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action.

Work was completed, including PMTs, and the transformer was returned to service at 5:00 p.m.

on January 31, 1996.

The total outage was 36.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

Prior to transformer removal from service, the licensee made a

notification to the NRC as required.

Further, all four EDGs were satisfactorily tested as a precautionary measure.

The schedule was pre-planned and published in the plan of the day for several weeks prior to removing the transformer from service.

In addition, a

PSA evaluation (JPN-NR-96-17)

was performed consistent with procedure O-ADM-210, On-Line Maintenance Work Coordination.

The PSA analysis noted that the increase in CDF was 0. 13% for the 35 hour4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> scheduled outage.

The primary cutsets involved a loss of power and plant transient with failures of the 4A and the 4B EDGs.

The inspector reviewed the work scope, the PSA letter, the technical specifications action statement and surveillance requirements, and loss of power related OPs and ONOPs.

The inspector reviewed the availability of the following power supplies for the 4160 VAC vital buses (4A and 4B):

Unit 4 auxiliary transformer (available with Unit 4 on line),

Unit 4 startup transformer (unavailable),

Station blackout tie (available via the D buses with the unit off line),

The 4C bus ties (available with the unit off line),

The opposite (Unit 3) startup transformer feed to the 4A bus only (available with unit off line),

and Backfeed via the Unit 4 auxiliary and main transformers (available with the unit off line).

During the transformer outage, the inspector toured the facility to ensure that no unauthorized work was ongoing which could affect Unit 4 or site electrical power.

None was found.. The inspector also walked down the Unit 4 EDGs and concluded that they were

3.2.8 operable.

The inspector observed portions of the maintenance activities, including PHTs and job pre-briefs.

The inspector noted that the sensitivity to this outage was addressed during management and shift turnover meetings.

Operators demonstrated sensitivity and a heightened awareness by stopping some outage related scaffolding work on the Unit 4 turbine deck.

The inspector also reviewed respective UFSAR chapters (8.0 through 8.5) relating to the electrical power distribution (see section 7.0).

Overall, the inspector concluded that the Unit 4 startup transformer'outage was well planned and executed, with a noted high sense of importance for this risk-related equipment.

Reactivity Hanagement Based on recent plant events and industry initiatives, the inspector reviewed the licensee's reactivity management process and related oversight for routine chemical shims and control rod movements.

The inspector noted that the licensee has conducted recent training during licensed operator requalification cycles addressing recent industry events and management's expectations.

Based on reactivity dilution event at Turkey Point in 1993, a

number of corrective actions were taken (reference.

NRC Inspection Reports 50-250,251/93-23 and 94-10).

Additionally, the licensee recently addressed the issues of reactivity management, control room oversight, and formality in a night order, through meetings and briefings, and in procedure changes and training sessions.

All reactivity changes must be performed in accordance with a procedure and witnessed by a SRO (usually the ANPS or NPS)

and the RCO must remain at the control boards during the duration of all reactivity changes.

The inspector verified these actions and also reviewed the following reactivity related procedures:

OP-1604.9, Reactor Full Length Control Rod (CRDH) System Test, O-ADH-555, Reactivity Hanagement, O-ADH-200, Conduct of Operations, 3/4-0P-047, CVCS - Charging and Letdown, 3/4-0P-046, CVCS - Boron Concentration Control, 3/4-GOP-301, Hot Standby to Power Operation

e

The inspector confirmed that the licensee's reactivity management control and oversight expectations were either currently addressed

'r being addressed in these procedures.

In conclusion, the inspector noted positive control of reactivity changes during control room observations.

The licensee was proactive in re-addressing these recent industry issues.

3.2.9 Unit 3 On-Line Maintenance Controls On January 26, 1996, during a routine afternoon control room tour, the inspector noted the following Unit 3 safety equipment OOS:

~Eni ment Reason Technical S ecification Action 3B EDG repair fuel priming 3.8. lelb,d (72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />)

leak 3A ICW pump repair travelling screen 3.7.3.a (7 day)

3A ICW header mechanically clean 3.7.3.c (72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />)

strainer The inspector reviewed all applicable technical specifications and confirmed that this condition was allowed.

From a safety perspective, Unit 3 had one operable EDG, and one operable ICW loop with one pump (3C) aligned to the EDG protected vital bus (3A).

However, the inspector questioned the safety impact given thi's condition.

The licensee's PSA group performed an analysis and concluded that increased risk was very small (3e4 E-7 or a Oe5% increase in CDF).

However, taking multiple safety equipment OOS did.not meet management's expectations.

Normally, the outage group, through the plan of day, schedules on-line maintenance.

Equipment is removed only if a net safety gain can be realized with pre-calculated risk, e.g.,

the quantified increase in CDF is known.

In this case, unscheduled maintenance based on plant conditions combined with a misunderstanding in communications led to this condition.

Although, allowed by technical specifications, the inspector considered this instance to be a weakness in the licensee's on-line maintenance program.

Licensee corrective actions included condition report No.96-091, and operations issuance of a letter to all operators re-affirming management's expectations.

These actions were noted to be appropriate and included discussions with shift management, night order communication, training, and procedure enhancement.2.10 guality Assurance Activities The inspectors reviewed the licensee's recent gA activities including the quality trend report for the fourth quarter of 1995.

The inspectors also met with gA supervisory and management personnel.

gA identified negative performance trends regarding personnel performance, procedure compliance, and on-line maintenance program implementation.

gA issued findings in their periodic reports and discussed these issues with plant and site management.

The inspectors recent observation and findings have also noted these issues as documented in this and previous Inspection Reports.

The inspectors concluded that gA is functioning well and providing an input to the overall nuclear safety.

3.2. 11 Aquatic Grass and Algae Fouling of the Intake Structure On January 31, 1996, both Units 3 and 4 experienced problems with aquatic grass and algae clogging the intake screens that filter the salt water supply to the condenser circulating water pumps as well as the safety related ICW supply.

The ultimate heat sink at Turkey Point consists of a closed canal system.

The water from the ultimate heat sink is filtered through a passive "grizzly screen" and traveling screen before it reaches the suction of the circulating water and the ICW pumps.

Unit 3 load was reduced to approximately 60% as 2 of the 4 condenser circulating water pumps had to be secured.

Further, this enabled the licensee to ensure adequate flow to the Unit 3 ICW pumps which share intake wells with the circulating pumps.

The licensee initiated condition report No.96-103, and formed an ERT to develop an action plan to address this issue.

The licensee stationed maintenance personnel at the intake structure to physically remove surface grass from the canal water stream.

Further, surveys of the canal system were performed to determine the magnitude of impending grass intrusions.

The licensee notified the NRC pursuant to 10 CFR 50.72 due to a Technical Specification 3.0.3 entry when the Unit 3 intake cooling water flow to component cooling water heat exchangers dropped to 7500 gpm (9500 gpm required).

This occurred at 8:57 p.m.,

on January 31, 1996.

No heatup to the component cooling water was observed.

Further, the licensee sampled the algae/grass for potential radioactivity as effluents are discharged to the canal.

Results remained consistent with previous samples.

The ERT concluded that operator response was in accordance with the newly developed procedure 3-0NOP-11, Screen Wash System/Intake Malfunction.

The ERT also concluded that corrective actions that were put in place in March 1995 (reference NRC Inspection Reports 50-250,251/95-06 and 08, and LER 95-3) were somewhat effective in minimizing the effect of the current grass influx.

However, additional enhancements were identified.

The ERT report was

reviewed and approved at a

PNSC meeting on February 2, 1996.

The licensee concluded that the proximate cause was a low canal water level (caused by the dry season),

combined with high winds which caused some of the grass to be swept off the canal embankments and into the water by wave action.

Subsequent strong directional winds (either northerly or southerly)

moved the grass into the intake area where it affected the intake screens.

The licensee further believes root cause to be the inability of the screen wash system to effectively remove all of the attached grass.

The nature of the grass (ditch grass, widgeon grass or, Rupia Naritima) and algae is a fine fibrous material which forms a dense and sticky mass which attaches itself to the screens and str ainers.

The normal screen wash and strainer backwashing methods become less effective in removal.

Corrective actions included enhancing the related OPs and ONOPs to include early warning criteria (e. g.,

number of strainer cleanings in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period).

This would then result in actions to remove the screen covers and have maintenance personnel available to rake the grass loose so that the screen wash would effectively remove it.

Longer term actions included plans to review of minimum ICW flow to determine LER reportability, to coat the screen wash deflector plates for corrosion enhancements, to assess the screen mesh size and possible coatings material, and to assess the possible addition of another spray header to better remove the grass material.

The resident inspectors monitored licensee activities in the control room, at the intake, and at the basket strainers.

The inspectors attended portions of the ERT meetings, attended the February 2,

1996 PNSC, reviewed the ERT and condition reports, verified corrective actions, and assessed root cause and corrective actions.

The inspectors concluded that actions and procedures that were in place as a result of the 1995 grass influx lessened the impact of this current influx.

However, additional corrective action were appropriate.

The inspectors reviewed operator and maintenance personnel re-sponse to the affected scenes (e.g.,

intake area and ICW/CCW area).

Two operators and a

SRO went to each area to monitor conditions, and to operate equipment as necessary.

At the ICW/CCW basket strainers, operators performed backwash operations, monitored the clearance boundary for maintenance strainer cleanings, and monitored local flow indicators.

Additionally, shift and operations management called in extra personnel to deal with the grass.

The inspectors noted that there was no remote readout or alarm annunciation for an ICW low flow condition.

Each CCW heat exchanger has a local ICW outlet flow measuring device (FT).

These FTs are checked every four hours during routine SNPO tours, and, prior to, during, and after strainer cleanings and backwashings.

The inspectors questioned whether or not a remote (control room) readout and/or annunciation was required.

(The

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,3J

current design does not call for this.)

Currently the licensee has no intention of providing remote readout or annunciation.

This is based on UFSAR chapter 9.6, (see section 7.0), the DBD (reference 5610-019-DB-001),

and the Service Water System Operational Performance Inspection Self-Assessment (L-95-202 dated July 14, 1995).

The inspectors reviewed the available control room indications and related ONOPs (e.g.,

loss of CCW, loss of ICW, loss of TPCW, and screen wash malfunction).

Although no ICW flow alarm or indication existed, operators could infer ICW cooling degradation by control room indications and alarms relative to TPCW and CCW cooled components, and screen malfunctions.

Further, the inspectors observed a simulator scenario which included degraded ICW flows without direct annunciation.

A high surge tank level and related component temperature alarms were received in 9 and

minutes, respectively to alert the operators of a ICW flow problem.

4.0 Maintenance (61726 and 62703)

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

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

4.2 Inspection Findings 4.2.1 Maintenance Activities Witnessed e

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

WO 95033188, Preventive Maintenance (PH) of Unit 4 Primary Water Makeup Pumps, Deaerator Water Transfer Pump and Deaerator Vacuum pump (section 4.2.3).

WO 95034467, 18 Month PH on Emergency Diesel Driven Fire Pump (section 4.2.4).

WO 95003977, Installation of Damping Module Electronics in Unit 4 Flow Transmitter FT-4-605 for RHR Discharge to Cold Legs (section 4.2.5).

WO 95032473, Calibration of IST Loop F-605 After Installation of Damping Hodule Electronics in Flow Transmitter FT-4-605 (section 4.2.5).

WO 95032401, Repair Packing Leak on Unit 3 Charging Pump 3B.

procedure 4-PHI-023-1 Calibration of Various Unit 4 Emergency Diesel Generator Instruments (section 4.2.6).

MO 95010754, Replace Base-to-Yoke Cap Screws on, Flow Control Valve Unit 4 FCV-114A (section 4.2.7).

Unit 4 startup transformer outage (section 3.2.7).

3B EDG fuel oil priming pump troubleshooting/maintenance (sections 5.2.1 and 3.2.9).

Travelling screen and ICM strainer cleanings (section 3.2.11)

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

However, an issue with the use of potentially contaminated tools was identified (section 4.2.3)

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

procedure 3-SHI-041. 16, Surveillance of T,, and Delta T Protection Channels procedure 3-SHI-041.11, Surveillance of Pressurizer Level Protection Loops procedure 3-0SP-089, Hain Turbine Valves Operability Test Unit 4 startup transformer testing (section 3.2.7)

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

4.2.3 Primary Mater Pumps Haintenance WO 95033188 covered the routine PH for the non-safety-related Primary Water Hakeup pumps, including general inspection of the pumps while running and greasing of bearings.

The inspector noted

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that the grease gun used was obtained by the mechanical maintenance journeyman from the Hot (contaminated)

Tool Room and was color coded "purple".

The pumps were clean (not contaminated).

When questioned by the inspector, the journeyman stated that the tools in the Hot Tool Room had fixed contamination only.

The PH was performed on the peak shift.

The Tool Rooms were not manned on this shift and plant policy is for the Maintenance Supervisor to control issue of tools when the tool room is not manned.

In this case, the journeyman obtained a key to the tool room and issued his own tools.

The tools were logged in and out in accordance with procedure requirements.

Further review and discussions with licensee management revealed the following:

Although tools in the Hot Tool Room are smeared for and cleaned of loose contamination upon return to the tool room, they possibly have fixed contamination, and therefore, are controlled to ensure use only in contaminated areas.

Paragraph 5.7.1 of procedure O-ADM-605, Control of Radioactive Tools, Equipment, and Components, requires that

"Tools and equipment with fixed or smearable contamination shall not be used in non-contaminated areas".

In August 1995, a mechanical maintenance journeyman was contaminated while using a torque wrench from the Hot Tool Room.

Because of this problem, the Maintenance Manager issued Hot Tool Room policies to add additional controls over tools in the Hot Tool Room.

The licensee immediately issued Condition Report No.96-034 to investigate this problem and document corrective actions.

The equipment and area where the grease gun was used was surveyed and found to be clean.

Other licensee corrective actions included disciplining the individual, retraining maintenance personnel, issuing letters and, reposting the tool room area.

The inspectors concluded that the failure to follow procedure 0-ADH-605 is a violation of Technical Specification section 6.8.1.

The violation is considered to be an isolated instance, and has low nuclear safety and low radiological safety significance as no spread of contamination occurred.

Further, licensee management treated this issue seriously, with an aggressive and prompt followup.

This failure constitutes a violation of minor significance and is being treated as a NCV, consistent with section VI of the NRC Enforcement Policy.

This item is designated as NCV 50-250,251/96-01-01, Failure To Follow Contaminated Material Control Procedures.

This item is close.2.4 4.2.5 Diesel Driven Fire Pump Maintenance WO 95034467 covered the 18 Month PH on the Diesel Driven Fire Pump.

The PH was performed in accordance with procedure 0-PNH-016.1, Diesel Fire Pump Engine 18 Month Maintenance Inspection.

The procedure covered changing oil and filters, 1'ubrication, installation of a new water pump, checking/rep1acing belts and hoses, and checking the overspeed trip, etc.

The inspectors witnessed portions of these activities, including the PHT after completion of the maintenance, and concluded that the work was appropriately conducted.

Unit 4 RHR Flow Transmitter Maintenance WOs 95003977 and 95032473 covered installation of damping module electronics in Unit 4 Flow Transmitter FT-4-605 for RHR-4-605 for RHR Discharge to Cold Legs and calibration of IST Loop F-605 after installation of damping module electronics in Flow Transmitter FT-4-605.

The installation of the damping electronics was accomplished in accordance with Procedure O-CHI-102.2, Rosemount Differential Pressure Transmitter Repair and Calibration.

The flow calibration was performed in accordance with procedure 4-PHI-50.'1.

The inspectors witnessed portions of the electronics changout and the start of the flow calibration.

The calibration required removal of the Flow Controller from the Control Room for bench calibration.

Step 6.13.2 of the procedure required installation of a jumper prior to removal of the controller.

The procedure did not clearly define the points for the jumper installation.

The correct jumper installation was verified by the ILC Maintenance Supervisor prior to installation.

After removal of the Controller, step 6.13.3 required verification of operation by simulating input voltages in Data Sheet and measuring output current (mA), and charting input vs. output.

The IKC technician determined that the details in this step was inadequate for performing this step.

The procedure was discontinued and an extensive revision written to detail performance of this step, prior to continuing the calibration.

The inspector concluded that the IKC personnel acted appropriately.

However, this was one example of an IKC procedure weakness.

4.2.6 Unit 4 EDG Instrument Calibrations Procedure 4-PHI-023-1 covered calibration of various Unit 4 EDG instruments.

The inspector witnessed portions of the calibrations for section 6.5, Diesel Oil Storage Tank Wide Range Level Indicator (EDG 4A), section 6.14, Engine Cooling Water Temperature Indicators (EDG 4B),

and section 6.21, Miscellaneous Temperature

Indicators (EDG 4A).

During performance of these calibrations, the 18C technicians identified the following areas where procedure revision was needed to allow compliance with procedure requirements:

For the diesel oil storage tank Level Indicator Calibration, the data sheet specified acceptable level ranges in 250 gallon increments.

The indicator scale for the instrument from which the level was to be taken was graduated in fairly narrow 1000 gallon increments.

Thus, the indicator scale would have to be read to the nearest 1/4 increment.

For the narrow increments on the scale, it is not feasible to reasonably read the instrument accurately to less than 1/2 of an increment.

For the Engine Cooling Water Temperature Indicator, section 6. 14 specified the use of a RTD test set, which supplies a

variable resistance load expressed in ohms, to the indicator circuit.

The data sheet specified ohm inputs with 2 significant decimal places, e.g.,

113.26 ohms.

The RTD test set provided readings to only 1 significant decimal place.

In both cases, the I8C technicians discontinued the calibrations until the procedure could be clarified.

The inspector concluded that the IKC personnel acted appropriately.

However, these are two more examples of I&C procedure weaknesses.

4.2.7 Unit 4 Blender Maintenance WO 95010754 covered replacement of base-to-yoke cap screws on Unit 4 blender flow control valve (FCY-114A).

The valve is air operated and controls the flow for primary water to the blender.

The cap screws were being replaced as part of a replacement program because of a previous failure on another valve as required by Condition Report 95-173.

In addition to replacement of the base-to-yoke cap screws, the WO also specified replacing the

bonnet-to-yoke cap screws.

During pre-job planning, the I8C technician determined that this design valve did not have 4 bonnet-to-yoke cap screws.

There were two packing bolts and nuts.

Based on the discrepancy in the description and type of fasteners, Engineering was contacted to determine exactly which fasteners were to be replaced.

After several hours of research, the decision was that the base-to-yoke cap screws and the 2 packing assembly bolts and nuts were to be replaced.

The WO was revised to clearly specify which fasteners were to be replaced.

After review of the revised WO, Operations determined that the work should not be performed on-line and should wait until the upcoming outage.

Another Condition Report (96-027)

was issued to determine the cause and corrective actions for this problem.

Indications were

that the job had not been adequately planned.

The inspector also noted evidence of poor maintenance pre-job preparations.

The valve had been taken out of service and the clearance tag hung on the previous shift.

Well into the shift in which the work was to be performed, maintenance was still gathering necessary tools and determining what materials were needed.

5.0 Engineering (37551, 90713, and 92903)

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

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

The inspectors also reviewed the report discussed below.

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

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

In addition, the inspectors reviewed one previous noncompliance and one open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

5,2 5.2.1 Inspection Findings Emergency Diesel Generator Failure Reports The inspector reviewed two special reports that were submitted by the licensee associated with the 3B EDG failures that occurred on December

and 29, 1995 and the 4A EDG failure that occurred on December 15, 1995.

The inspectors had reviewed and documented the failures in NRC Inspection Report 50-250,251/95-22, The licensee sent the 4A voltage regulator to the vendor NEI Peebles for further analysis.

The analysis revealed some dirt/contamination within the potentiometer associated with the voltage regulator.

The potentiometer was supplied to the vendor by Cleveland Electric Company.

The vendor and the licensee believe that this was the most likely cause of the voltage regulator failure.

The vendor is considering a

CFR part 21 notification associated with the voltage regulator failure.

Current licensee plans are to replace the 4A and 4B EDGs voltage regulator potentiometers with a newer design.

The replacement is planned during the upcoming March 1996 Unit 4 refueling outag.2.2 With regard to the 3B EDG failures attributable to the fuel priming pump, the licensee continued testing the priming pump on a

regular basis.

A hydrostatic test was performed on the fuel priming line and two leakage paths were identified and repaired.

The licensee then performed a vacuum test and a bubble test to determine system inleakage and repaired additional leaks.

All of these leaks were extremely small.

Subsequent testing of the priming system noted appropriate response and performance.

The inspectors also reviewed and discussed licensee actions pertaining to the failure of the makeup valve to the 3B EDG tank CV-3-2046B that occurred on January 18, 1996 during a monthly surveillance test.

The licensee initiated Condition Report numbe}

96-56, and formed an ERT to investigate the potential causes for the failure of the control valve to open on demand.

The ERT preliminary conclusion was that the failure of the valve was caused by debris in the close tolerance fit between the valve plug assembly and bushings and mechanical binding at the valve seat.

The licensee cleaned and reassembled the valve with a new seat and plug assembly.

Further, the licensee successfully stroked redundant train valve CV-3-2046A and plans to inspect the internals in the near future.

The origin of the debris was not determined.

The licensee plans to consider this a component function failure of a support system.

However, the failure was not considered as maintenance preventable as there are no applicable maintenance requirements for this component.

Further, the failure of control valve CV-3-2046B did not result in the 3B EDG being inoperable as there is procedural guidance in procedure O-ONOP-013, Loss of Instrument Air, to operate the valve using a

nitrogen bottle handloader.

The inspectors concluded that the special reports were timely and appropriately addressed the EDG failures.

Further, the inspectors concluded that licensee activities and follow-up associated with valve CV-3-2046B were aggressive.

Component Cooling Water Flow (Closed)

VIO 50-250,251/95-16-02, Failure To Take Appropriate Corrective Action To Resolve Potential Unit 3 CCW Heat Exchanger Flow Related Vulnerability.

The inspector reviewed licensee response dated December 7,

1995, including description of corrective actions, to NRC Violation 50-250,251/95-16-02 issued on November 8, 1995.

The inspector concluded that licensee corrective actions were appropriate.

A description of the corrective actions was included in NRC inspection report 50-250,251/95-16.

This violation is close.2.3 Containment Radiation Monitor (Closed)

URI 50-250,251/95-22-01, Firmware Problems associated with Containment Radiation monitor R-11.

An issue associated failure of Containment Radiation Monitor R-11 was discussed in NRC inspection report 50-250,251/95-22.

The issue was open pending root cause determination by Sorrento Electronics (vendor).

The vendor completed the analysis and concluded that the problem was introduced in the firmware due to a typographical error associated with a data storage command.

The licensee requested the vendo} to perform additional validation and verification testing, including

"negative tests" which would consist of simulating various off-normal conditions/inputs and ensuring predictable response.

FPL has plans to participate in the negative tests that the vendor plans to perform.

Further, FPL plans to perform additional tests on the R-11 and R-12 skids that are used for training purposes.

Based on this review of additional information provided by the licensee the inspector had concluded that the unresolved item is considered closed.

5.2.4 Safety Related Pump Failures The inspectors reviewed licensee efforts and followup activities for two safety-related pump failures (reference NRC Inspection Report 50-250,251/95-22):

3A ICW pump (November 21, 1995)

4B HHSI pump (December 18, 1995)

The licensee's review (ERT and Condition Report 95-1174 supplement No. 1) for the 3A ICW pump inservice failure determined that root cause was corrosion buildup causing a loss of lube water to the stuffing box.

This subsequently caused the shaft to overheat and melted the aluminum bronze bearing and locked the 'pump shaft.

Contributing factors included short duration runs for the 3A ICW pump and a small misalignment issue.

Corrective actions included replacement of lower pump head shaft with a new less corrosion susceptible material (Hitronics 50)

and replacement of the stuffing box bearing with non-conductive material (Thordon style SXL).

Additional actions were taken to address the misalignment and short run time issues.

The licensee intends to upgrade the six ICW pumps with these material changes by the end of 1996.

The licensee's review (ERT and Condition Report 95-1256) of the 4B HHSI pump air binding event continued during this inspection period.

The licensee continued accelerated testing and did not observe any problems.

A search of work history did not identify any maintenance initiated possible causes.

A TP was written and performed to check for backleakage from either the RCS or the cold leg accumulators.

No backleakage was measured.

The licensee then

obtained special equipment to ultrasonically test for backleakage through the pump discharge check valve (4-879D).

Although not quantifiable, the licensee did note a higher backleakage through this valve than the other HHSI pump discharge check valves.

The licensee believes that this small leak (not quantifiable, but probably around 0.01 gpm)

may have over time introduced air or gas into the pump, thus causing it to become bound.

Weekly system venting continues and, a check valve overhaul is planned for the near future.

5.2.5 The inspector reviewed these issues by discussing them with the respective system and component engineers, by reviewing relating documentation including the condition reports, by observing testing and maintenance in the field, and by discussing these issues with licensee management.

The inspector also noted that these failures, root cause and corrective actions were discussed with senior corporate management at the PTN Status Meeting on January 31, 1996.

The inspector concluded that licensee attention to these failures has been prompt, aggressive, and appeared thorough.

Emergency Containment Cooler Outlet Valve Failure On January 11, 1996, the 4A ECC outlet valve,(CV-4-2907) failed to fully open during the loss of air test portion of surveillance procedure 4-OSP-055. 1, Emergency Containment Cooler Operability Test.

The valve stroked properly when the solenoid valve was energized by manual start.

With valve CV-4-2907 failing to fully open during the air fail test, Unit 4 was placed in a

72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification action statement.

The licensee initiated Condition Report 96-36 to further investigate and resolve the issue.

The licensee determined that the failure of valve CV-4-2907 was attributed to the pilot operated lock-up valve that transmits air to CV-4-2907 not fully shifting, Failure of the pilot operated lock-up valve was attributed to increased friction between the spool pieces and

"0" rings within the pilot operated lock-up valve.

As immediate corrective action, the licensee replaced the pilot operated lock-up valve and satisfactorily retested the 4A ECC prior to returning it back to service within the Technical Specification action statement time, The licensee also verified operability of all ECC outlet valves by performing the air fail test portion of procedures 3 and 4 OSP-055. 1.

Further, the licensee performed a root cause analysis and concluded that the failure of the pilot operated relief valve to shift was due to increased friction from age related hardening of the "0" rings.

The "0" rings are made of 8una-N material.

As additional corrective action, the licensee plans to replace the 8una-N "0" ring with viton elastomer units which have a greater service life.

The licensee also plans to periodically (every

month) replace all ECC pilot operated lock-up valve The licensee also concluded that CV-4-2907 is a key component within the scope of the maintenance rule and identified it as a

significant risk.

Failure of CV-4-2907 was classified as a

functional failure,but not maintenance preventable; the vendor had not recommended or required any maintenance.

The inspector reviewed the condition report and UFSAR chapter 6.3.1, Emergency Containment Cooling and Filtering System, and discussed the issue with the licensee (see section 7.0).

The inspector concluded that licensee, including the component engineer, aggressively pursued resolution and root cause determination associated with this failure.

5.2.6 Steam Generator Blowdown Flow Based on an observed mismatch between the water treatment output and the plant water usage, operation, maintenance, and engineering personnel began looking for the cause of the discrepancy.

After several days of troubleshooting and analysis, the licensee concluded that actual S/G blowdown rates on both units were higher than indicated at lower flows (e.g.,

less than 40,000 ibm/hour per S/G).

The error was as much as 50%.

The licensee initiated Condition Report No.96-081 to review past and current operability, reportability, the impact of the secondary calorimetric, UFSAR issues, and ODCH/release report effects.

The licensee concluded the following:

The effect on the secondary calorimetric was minimal, The UFSAR analyses were bounded, The R-19 (S/G blowdown radiation monitor) assumptions were conservative and the trip setpoints were unaffected, The ODCN release reports were unaffected, and No operability and no reportability issues were identified.

The licensee's immediate corrective actions, (as stated in the condition report) included using a conservative value of 40,000 ibm/hour flow rate at low blowdown rates for power calculations and release information.

The use of a modified flow transmitter is under review.

The inspector reviewed the condition report and UFSAR chapter 14.1 and 14.2 (see section 7.0).

The inspector concluded that the licensee appropriately identified and dispositioned this issue.

The timeliness of the condition report disposition, including PNSC, was very goo.2.7 Auxiliary Feedwater Trip on Overspeed On February 4, 1996, during performance of surveillance procedure 3-0SP-075.1, Auxiliary Feedwater Train 1 Operability Verification the C AFW pump tripped on electrical overspeed during the pump shutdown The licensee initiated condition report No.96-113 and performed an operability assessment prior to declaring the pump operable.

The operability assessment concluded that the most probable cause of the overspeed trip was the introduction of water into the steam supply which caused the turbine to slow down.

With the turbine slowing, the governor over-compensated by further opening the governor valve which eventually led to turbine overspeed.

This occurred following clearing of the water slug that initially slowed the turbine.

The design associated with the steam supply to the C AFW pump is such that there is potential for condensate to accumulate in a dead-leg portion of the pipe.

This occurred during cold weather conditions. Currently there is no steam trap in that portion of the pipe.

Further, the potential for turbine overspeed during startup due to condensation buildup is precluded due to several factors including ramp rate bushings which function to lower the speed control setpoint during startup to prevent overspeed by allowing gradual turbine acceleration.

The operability assessment concluded that the safety-related function of the C AFW pump was not compromised by the entrained condensate.

The licensee has plans to install a steam trap on the dead-leg portion of pipe that is known to accumulate condensate.

The licensee stated that an REA has been written associated with this issue.

The inspector concluded that the licensee appropriately dispositioned the overspeed issue.

The inspector plans to further follow up on the status of the REA.

5.2.8 Hydrogen Recombiner Issues The inspectors reviewed Condition Report 96-107 which identified a

potential operability concern with the operation of the Post Accident Hydrogen Recombiner based on an evaluated condensation concern at the Oconee Nuclear Station.

Turkey Point utilizes the same Hydrogen Recombiner as Oconee.

Turkey Point implemented provisions to externally connect hydrogen recombiners as an alternate means for controlling post accident hydrogen concentrations in accordance with changes to 10 CFR 50.44.

These modifications were completed in 1984 by implementing PC/N 82-'70 and 177.

In 1991, a contractual agreement was reached with Oconee for the use of their recombiner, should the need arise.

At this time, an on-site test was performed using the Oconee hydrogen recombiner

I

5.2.9 The licensee performed an interim disposition that concluded that the hydrogen recombiner is not relied upon in the UFSAR chapter 9.12, for accident prevention or mitigation (see section 7.0).

The recombiner functions to supplement the PACV system, which is the primary means to control post-accident containment hydrogen by venting of the containment atmosphere.

The PACV system is required by Technical Specification 3.6.6.

Unlike Oconee, the hydrogen recombiners are not required by technical specifications to be operable.

Notwithstanding, the licensee plans to follow up with Oconee to determine if the condensation concern associated with the line leading to the hydrogen recombiner was applicable to and possible at Turkey Point.

The licensee plans to pursue this matter to final resolution through the condition report process.

The inspector discussed this issue with the licensee and with the Oconee resident inspectors to better understand the problem that was experienced at Oconee.

Based on this conversation and review of data and design at Turkey Point, the inspector did not have any further questions.

The inspectors concluded that the licensee appropriately followed the issue, and that their operating experience program was functioning well.

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

6.0 Plant Support (71750 and 64704)

6.1 6.2 6.2.1 Inspection Scope The inspectors verified the licensee's appropriate'mplementation of the physical security plan; radiological controls; the fire protection program; the fitness-for-duty program; the chemistry programs; emergency preparedness; plant housekeeping/cleanliness conditions; and the radiological effluent, waste treatment, and environmental monitoring programs.

Inspection Findings ALARA Review Board The inspector attended the January 30, 1996, ARB Meeting.

The inspector noted good attendance by all site disciplines, including, plant management.

An agenda was effectively utilized.

Dose goals for 1996 and for the Unit 4 cycle 16 outage were discussed.

These goals were 265 Rem and 215 Rem, respectively.

A good practice was noted in that the licensee discussed other utility good ALARA practices, with the intention of incorporating these improvements into their own ALARA initiatives.

Overall, the

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ARB appeared to be functioning well, and was proactive in their efforts to minimize site dose.

6.2.2 Fire Brigade Training The inspector reviewed the licensee's periodic fire brigade training.

This included practical training at the Dade County

'Miami Dade Community College) Fire Academy.

The annual practical training included classroom and practical fire fighting in the field.

Scenarios included electrical fires, gas cylinder fires, flammable liquids, transformer fires, search and rescue, fire hose advancement, ventilation techniques, SCBA use, and confined interior firefighting.

The inspector attended the February 8, 1996, session for fire brigade members.

The inspector also reviewed

CFR Appendix R, UFSAR chapter 9.6A (section 7.0,) the ADH 016 series procedures, and the related lesson plans.

The inspector concluded that the training scenarios were challenging and the students and instructors performed professionally and very well.

Overall, the licensee's fire brigade training program appeared realistic and sound.

7.0 Updated Final Safety Analysis Report A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR descriptions.

While performing the inspections discussed in this report, (during the period February 1-10, 1996), the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected.

The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters.

The inspectors noted that modifications performed since the last UFSAR update (July 1995) were not addressed; however, the licensee has scheduled them for inclusion in the next update (late 1996).

The following UFSAR sections were reviewed:

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Ins ection Re ort Section 8.0-8.5 Electrical Power 3.2.7

9.6 6.3.1 14.1, 14.2 Intake Cooling Water 3.2.11 Emergency Containment Cooler 5.2.5 Steam Generator Blowdown 5..0 9.6A 9.12 Exit Interview Fire Protection Training Hydrogen Recombiner 6.2.2 5.2.8 The inspection scope and findings were summarized during management interviews held throughout the reporting period with both the site vice president and plant general manager and selected members of their staff.

An exit meeting was conducted on February 12, 1995.

(Refer to section 1.0 for exit meeting attendees.)

The areas requiring management attention were reviewed.

The inspector described the areas inspected, and discussed in detail the inspection results.

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

Dissenting comments were not received from the licensee.

The inspectors had the following finding:

Item Number Status Descri tion and Reference 50-250)251/96-01-01 (Closed)

NCV, Failure to Follow Contaminated Haterial Control Procedures (section 4.2.3)

Additionally, the following previous items were discussed:

Item Number Status Descri tion and Reference 50-250,251/95-16-02 (Closed)

VIO, Failure to Take Appropriate Cor-rective Actions to Resolve Potential Unit 3 CCW Heat Exchangers Flow Related Vulnerability (sec-tion 5.2.2).

50-250,251/95-22-01 (Closed)

URI, Firmware Problems Associated with Containment Radiation Honitors R-ll (section 5.2.3)

9.0 Acronyms and Abbreviations AC ADH AFW ALARA a.m.

ANPS ARB ARP CCW CDF CFR CHI CNRB CR Alternating Current Administrative (Procedure)

Auxiliary Feedwater As Low As Reasonably Achievable Ante Heridiem Assistant Nuclear Plant Supervisor ALARA Review Board Annunciator Response Procedure Component Cooling Water Core Damage Frequency Code of Federal Regulations Corrective Haintenance

- I&C Company Nuclear Review Board Condition Report

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CRDM CV CVCS DB/DBD DPR DRS ECC EDG e.g.

ERT FCV FPL FI FT GOP gpm HHSI I&C ICW IST JPN ibm L

LER NCV NP NPS NRC NRR ODCM ODI ONOP OOS OP OSC OSP PACV PC/M p.m.

PH PMI (M)

PHT PNSC POD PSA PTN PWO gA gC R

RCO RCP

Control Rod Drive Mechanism Control Valve Chemical Volume Control System Design Basis (Document)

Power Reactor License Division of Reactor Safety Emergency Containment Cooler Emergency Diesel Generator for example Event Response Team Flow Control Valve Florida Power and Light Flow Indicator Flow Transmitter General Operating Procedure Gallons Per Minute High Head Safety Injection Instrumentation and Control Intake Cooling Water Inservice Test Juno Project Nuclear (Nuclear Engineering)

pound mass Letter Licensee Event Report Non-Cited Violation Nuclear Policy Nuclear Plant Supervisor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Offsite Dose Calculation Hanual Operations Department Instruction Off-Normal Operating Procedure Out-of-Service Operating Procedure Operational Support Center Operating Surveillance Procedure Post Accident Containment Ventilation Plant Change/Modification Post Meridiem Preventive Haintenance Preventive Maintenance

- I8C (Mechanical)

Post-Maintenance Test Plant Nuclear Safety Committee Plan of the Day Probabilistic Safety Assessment Project Turkey Nuclear Plant Work Order guality Assurance guality Control Radiation (Monitor)

Reactor Control Operator Reactor Coolant Pump

RCS REA Rem RHR RTD SCBA SNI SNPO SRO T

TER TP TPCW UFSAR VAC VCT WO WR Reactor Coolant System Request for Engineering Assistance Radiation Equivalent Man Residual Heat Removal Resistance Temperature Detector Self-Contained Breathing Apparatus Surveillance Maintenance I&C Senior Nuclear Plant Operator Senior Reactor Operator Temperature Technical Evaluation Report Temporary Procedure Turbine Plant Cooling Water Updated Final Safety Analysis Report Volt AC Volume Control Tank Work Order Work Request

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