IR 05000250/1995022

Insp Repts 50-250/95-22 & 50-251/95-22 on 951119-1230.No Violations Noted.Major Areas Inspected:Plant Operations Including Operational Safety & Plant Event,Maint,Including Surveillance Observations & Fire Protection

ML17353A550
Person / Time
Site:	Turkey Point
Issue date:	01/26/1996
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A549	List: IR 05000250/1995022 ML17353A547
References
50-250-95-22, 50-251-95-22, NUDOCS 9602120125
Download: ML17353A550 (59)

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%AS iEOO UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 3032341%

Report Nos.:

50-250/95-22 and 50-251/95-22 Licensee:

Florida Power and Light Company 9250 West Flagler Street

'iami, FL 33102 Docket Nos.:

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspection Conducted:

November 19 through December 30, 1995 Inspectors:

T.

P. Johnson, S ni esident D t Signed Inspector B. B.

D sai, ident Inspector Approved by:

. D.

La is, Chief Reactor Pro'ects Branch

Division of Reactor Projects D te igned SUMMARY Scope:

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

plant operations including operational safety 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 and unresolved item.

URI 50-250,251/95-22-01

- Firmware Problems associated with Containment Radiation monitor R-11 (section 5.2.4).

9b02120i25 960126 PDR ADQCK 05000250

PDR A

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NCV 50-250,251/95-22-02

- Failure to Meet Technical Specification 6. 12. 1 To Have High Radiation Trash Posted (Section 6.2. 1).

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

Plant 0 erations Operator identification of and response to a Unit 3 steam flow transmitter failure caused by a steam leak in containment was prompt and overall excellent (section 3.2.1).

Operator training involving minimum control room staff response to simulated emergencies including procedure use was very good (section 3.2.2).

A Unit 4 power reduction to perform maintenance and testing was well planned and performed by both operations and outage management (section 3.2.3).

Plant management proactively responded to a series of recent personnel performance related issues (section 3.2.4).

The control room was immediately notified of an event involving an inadvertently bumped switch on an electrical switchgear, however, the applicable Technical Specification action statement was not immediately logged.

Further, the questioning attitude by a gA inspector associated with this issue was considered a

strength (section 3.2.5).

The licensee appropriately and proactively implemented cold weather off-normal operating procedures (section 3.2.6).

Operator response to emergency diesel generator failures, to an intake cooling water pump failure, and to a high head safety injection pump abnormality was appropriate (sections 4.2.7, 5.2. 1, and 5.2.2).

1995 performance indicators were reviewed and show excellent performance in most areas (section 3.2.7).

Maintenance Inspector observed station maintenance and surveillance testing activities were well performed (sections 4.2.1 and 4.2.2).

Electrical maintenance personnel appropriately responded to and demonstrated strong knowledge relative to a circulating water pump breaker that failed to operate remotely (section 4.2.3).

Plant management issued a temporary stop work order followed by increased supervisory attention affecting Instrumentation and Control work in order to address recent personnel issues and errors.

Short term effect of this aggressive effort appeared to be positive (section 4.2.4).

The decision to defer replacement of a sticking Unit 4 safeguards test switch until the next outage was reasonable as channel operability was not affected (section 4.2.5).

The licensee appropriately evaluated that the unexpected actuation of steam generator protection bistables during certain analog channel operational tests would not cause an inadvertent safety injection.

However, an earlier opportunity that existed to revise numerous procedures to preclude the actuation was missed and is considered a weakness (section 4.2.6).

Troubleshooting efforts associated with the 4A emergency diesel generator failure were prompt, well planned, and well executed.

The increased testing frequency following the initial. 3B emergency diesel generator failure identified a problem that potentially could have prolonged the 3B emergency diesel generator inoperability (section

4.2.7).

Though recent feedwater control related perturbations have not resulted in a challenge to the reactor protection system, plant management needs to :ontinue to focus attention a,id be aggressive in the identification and resolution of the root cause associated with these problems (section 4.2.8).

En ineerin Engineering and technical department response to and support for a Unit 3 steam flow transmitter issue was very good (section 3.2. 1).

Event response team followup for a Unit 3 intake cooling water pump failure and for a Unit 4 high head safety injection pump abnormality was thorough, including root cause determination and corrective actions (sections 5.2. 1 and 5.2.2).

The licensee appropriately identified and modified several emergency diesel generator circuit and relay related issues that did not manifest in the emergency diesel generators being inoperable.

The condition report process was effective in this resolution (section 5.2.3).

An unresolved item was identified pertaining to firmware that was installed through a modification on the containment radiation monitor (R-11).

The item is open pending root cause determination associated with the firmware problem that manifested at Turkey Point and caused the radiation instrument to be inoperable following the modification.

Safety significance was minimal as redundant instruments existed (section 5.2.4).

Though Technical Specification limits affecting power distribution limits, were not exceeded following indications of a problem, licensee efforts were aggressive to determine'he accuracy and adequacy of the factors that affect the limits (section 5.2.5).

Plant Su ort Health physics response to and control of containment entries associated with a Unit 3 steam leak were very good.

Exposure resulting from these entries was maintained as low as possible (sections 3.2.1 and 6.2.3).

Failure to adequately tag and post high radiation trash in the radwaste building is a licensee identified, non-cited violation (section 6.2.1).

Licensee actions pertaining to several fitness for duty issues were appropriate (section 6.2.2).

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

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

1.2 NRC Resident Inspectors 1.3 Other NRC Personnel Onsite........

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

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2.1 Unit 3 2.2 Unit 4..............

2.3 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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4.0 Hasntenance...........................

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4.2 Inspection Findings

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5..0 Engineering....................................................14 5.1 Inspection Scope....

5.2

- Inspection Findings

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Inspection Scope....

Inspection Findings

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.0 Exit Interviews

,............................................23 8.0 Acronyms and Abbreviations.....................................24

REPORT DETAILS 1.0 Persons Contacted Licensee Employees

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• C W.

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• E V. Abbatiello, Site guality Manager J. Acosta,.Company Nuclear Review Board Chairman C. Balaguero, Reactor Engineering Supervisor R. Bible, Site Engineering Manager H. Bohlke, Vice President, Engineering and Licensing M. Franzone, Acting Instrumentation and Controls Maintenance Supervisor E. Geiger, Vice President, Nuclear Assurance J. Gianfrancesco, Haintenance Planning Supervisor H. Goldberg, President, Nuclear Division G. Heisterman, Haintenance Manager R. Hartzog, Business Systems Manager C. Higgins, Outage Manager E. Hollinger, Training Manager J.

Hovey, Site Vice-President'.

Huba, Procurement Supervisor E. Jernigan, Plant General Manager H. Johnson, Operations Manager D. Jurmain, Electrical Maintenance Supervisor A. Kaminskas, Services Manager E. Knorr, Regulatory Compliance Analyst S. Kundalkar, Engineering Hanager D. Lindsay, Health Physics Supervisor E. Harcussen, Security Supervisor D. Hiller, Acting Projects Supervisor N. Paduano, Manager, Licensing and Special Projects F. Plunkett, Assistant to the President E.

Rose, Nuclear Materials Manager H. Singer, Operations Supervisor N. Steinke, Chemistry Supervisor A. Thompson, Project Engineer J.

Tomaszewski, Acting Technical Manager C. Waldrep, Mechanical Maintenance Supervisor J.

Weinkam, Licensing Hanager Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.

1.2 NRC Resident Inspectors

• B B

• T P

Desai, Resident Inspector Johnson, Senior Resident Inspector 1.3 Other NRC or Affiliated Personnel on Site H.

G.

K.'.

Ashar, Technical Reviewer, NRR Bandyopadhyay, Department of Energy, Contractor

S.

R. Caudill, Physical Scientist, NRR R.

P. Croteau, NRR Project Manager A. H. Galishev, Republic of Kazakstan, Visitor V. Kourghinian, Republic of Armenia, Visitor E.

Lea, Project Engineer, Region II H.

W. HcBrearty, Division or Reactor Safety, Region I W. H. Sartor, Emergency Preparedness Inspector, Region II H. Shlyamberg, Contractor L. C. Stratton, Physical Security Inspector, Region II

Attended exit interview (Refer to section 8.0 for'dditional 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 2.2 Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near full reactor power and had been on line since October 18, 1995.

The unit maintained full power operation during this period.

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

The'unit was reduced to 40% power on November 17, 1995 for testing and maintenance.

The unit returned to full power on November 19, 1995 and maintained full power operation during the period.

Personnel Changes, During the inspection period, the licensee announced the following personnel changes to become effective within the next two months:

Hr.

G.

E. Hollinger will b'ecome the Licensing Manager Hs.

H. L. Lacal will become the Training Manager Hr.

R. West (from ENTERGY) will become the Technical Manager 3.0 Plant Operations (40500, 71707 and 71714)

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.

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

and performance indicators.

Inspection Findings Unit 3 Steam Flow Transmitter Failure On November 19, 1995, at 12:04 a.m., Unit 3 operators received alarms indicating a failure of steam flow transmitter FT-3-474.

The alarms included steam flow greater than feed flow, high steam flow, steam generator high level, and level deviation on the 3A steam generator.

The 3A S/G feed regulating valve (FCV-3-478)

responded in automatic and opened.

The RCO took manual control of the FCV and returned S/G level to a normal level of 60%.

The highest level was 72% (the high-high level trip occurs at 80%).

Operators appropriately entered procedure 3-OHOP-049. 1, Deviation or Failure of a Safety Related or RPS Channel, and tripped the RPS and SI bistables as required by Technical Specifications 3.3.1 and 3.3.2.

Approximately 1/2 hour later, the control room noted indications of increasing containment temperature (several degrees)

and increasing input to the containment sump level (>1.0 gpm).

Operators appropriately entered procedure 3"-ONOP-41.3, Excessive Reactor Coolant System Leakage.

Operators confirmed that there was no in'dication of any primary'eakage, and they suspected a

secondary steam leak from FT-3-474.

At 3:36 a.m.,

personnel entered the Unit 3 containment and observed a steam leak from FT-3-474 3/8 inch tubing near a

swagelock fitting.

Isolation valves 3-10-100 and 101 were closed, stopping the steam leak.

The 3A S/G FCV was then returned to automatic, with control on the redundant steam flow channel FT-3-47 Subsequent containment entries repaired the failed 3/8 inch tubing and swagelock fitting, and returned the tubing's configuration to the as-design condition.

Inspections determined that the tubing supports (Girard clamps)

were either missing or not attached.

The remaining Unit 3 lines and the Unit 4 lines were also inspected and no additional deficiencies were noted.

. The licensee initiated condition report No. 95-1146 and an'RT to evaluate the root cause and to recommend corrective actions.

During one of the containment entries on November 22, 1995, an ILC supervisor valved out the wrong transmitter (FT-3-475 in lieu of FT-3-474).

Operators responded appropriately and no technical specification violations occurred as the SI and RPS trip bistables were already tripped.

The licensee initiated condition report No.

95-1163 to address this issue (see section 4.2.4 for licensee actions to address this item).

The ERT concluded (through metallurgical laboratory analysis) that the failure was cyclic fatigue initiated due to the missing/un-connected clamp supports.

The ERT also concluded that the clamp supports were correctly installed in 1987 based on gC holdpoint signoffs.

Further, ERT review of a photograph taken in January 1993 noted that the clamps were missing.

A search of work history could not identify who removed the clamps, or when or why the clamps were removed.

Licensee corrective actions'ncluded re-installing the missing clamps, performing a metallurgical analysis. confirming a fatigue failure mechanism, reviewing work history, reviewing instrument filling procedures, and verifying correct configuration for the remaining Unit 3 and all the Unit 4 steam flow detectors.

Although not required by NRC regulations, the inspector was notified at home of this event.

The inspector reviewed the condition report, control room logs, Technical Specification action statement entries, ARPs and ONOPs, the ERT and problem reports, and discussed the event with operators, engineering, and management personnel.

The inspector accompanied personnel on one of the containment entries on November 20, 1995.

The inspector observed the FT-3-474 clamp support deficiencies and also verified that the remaining five Unit 3 Fts were adequately supported.

The inspector noted that the FT-3-474 supports were in an area of low traffic and out of normal line of sight.

This would explain why the deficiency went undetected for over three years.

The inspector concluded that operator, maintenance, HP, and engineering response and teamwork were excellent.

Control room operator identification of and response to the leak and the S/G level transient were noteworthy.

The initial containment entry and subsequent entries were well controlled with noted excellent teamwork, and a safety-conscious attitude. 'egative findings included poor post-maintenance testing in that the FT-3-474 was

3.2.2 3.2.3 not vented resulting in another containment entry, and I&C valving out the wrong steam flow transmitter during one containment entry (see section 4.2.4).

Licensed Operator Training The inspector reviewed licensed operator training with an emphasis on minimum control room staffing response to a single or dual unit problem.

Technical Specification 6.2.2 minimum staffing is two SROs and three ROs.

Normal manning includes four SROs (one NPS, two ANPSs, and one NWE) and three or four ROs (RCOs).

The inspector determined that minimum control room staff response per unit could be as few as one SRO (NPS or ANPS)

and one RO.

This could occur if a dual 'unit problem occurred or for a short period of time i,f one or more licensed operators were out of the control room.'he inspector verified by discussions with training personnel and operators, by training record review, and by simulator training observation that one SRO and one RO could respond adequately to a unit problem.

On November 21, 1995, the inspector observed simulator training scenarios where the minimum operations staff (one SRO and one RO)

responded appropriately.

The scenarios included a steam generator steam flow transmitter failure and steam leak (similar to the actual event discussed in section 3.2.1)

and a design basis accident (e.g.,

LOOP/LOCA with single EDG failure).

In each of these observed scenarios, the minimum control room staffing response was very good, including ONOP and EOP implementation.

Unit 4 Power Reduction For Maintenance and Testing On November 17, 1995, the licensee initiated a power reduction on Unit 4 to 40% power.

The purpose was to conduct the quarterly turbine valve test and to perform secondary plant preventive and corrective maintenance.

The maintenance included SGFP work, breaker inspections, condenser water box cleaning, TPCW heat exchanger cleaning, circulating water pump work, heater drain pump work, and other-'miscellaneous items.

The'uhit was returned to full power on November 19, 1995 at 8:30 p.m.

The inspector reviewed the work scope, schedule, and discussed the activities with licensee personnel.

While attempting to start the 4B SGFP for its return to service at 3:30 p.m.

on November 19, 1995, operators noted that valve 4-20-771 (isolation valve for PS-4-2031)

was closed.

The PS provides a suction pressure start permissive signal for the 4B SGFP.

During the weekend power reduction, I&C personnel calibrated the PS and manipulated the valve per W095031752.

The valve was apparently difficult to operate and I&C personnel thought the valve had been reopened when in fact it remained closed.

Procedure O-GMI-102.1, Troubleshooting and Repair Guidelines, documented the valve

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manipulations, including independent checks.

A condition report (No. 95-1147)

was written to identify root cause and corrective actions.

The licensee concluded that inc.ttention to detail and not following self checking (STAR) contributed to the problem.

Corrective actions included a

HPES evaluation, training of 18C personnel in valve operations, and additional disciplinary actions.

Since this was a non-safety related component and function, no regulatory action will be taken.

However, I&C valve manipulation weaknesses including training deficiencies were noted.

Further, the licensee was aggressive in following up on this issue (see section 4.2.4).

Overall, the power reduction was well planned and implemented by operations and outage management personnel.

3.2.4 Management Response to Recent Plant Problems The inspector reviewed plant management response to recent personnel (operator and others) related problems and issues.

Some issues were documented in NRC Inspection Report 50-250,251/95-19.

Current examples included unposted high radiation trash (section 6.2. 1),

IEC valving errors (sections 3.2.1 and 3.2.3),

and three other operator related configuration errors:

a non-safety related tagging error by SNPOs on the cooling water to the nitrogen'gas-house compressors and the deaerator vacuum pump (reference CR 95-1148); three mispositioned valves on the Fire Protection System that were found to be closed and were required to be open (reference CR 95-1200)

and, a Unit 3 CCW pump suction line instrument valve (indication only).

These issues were all self-identified by the licensee, including by their gA organization.

Further, the fire protection valves being out-of-position did not result in the system being inoperable.

Licensee corrective actions included:

All-employee meetings conducted by the plant manager to discuss the events, importance of STAR (self-checking),

and adherence to station procedures.

Emphasis of management expectations.

Training for selected groups in the area of valve manipulations, independent verification, and procedure adherence.

Increasing field supervision presence, including additional verification of selected configuration control processes.

The inspectors reviewed the licensee's actions and concluded that they were appropriate and proact,iv ~

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3.2.5 3.2.6 Inadvertent Electrical Switch Bumping The inspectors reviewed control room logs for the report period and noted a log entry of an incident that occurred at approximately 12:50 p.m.

on December 5,

1995 during a plant tour being performed by the Plant General Hanager and the Operations Hanager.

The incident involved the Plant General Hanager accidently bumping the normal/isolate control switch on breaker 4AB09 for the 4B load center feeder from the 4B 4.16KV bus.

The control room was immediately informed of the incident.

Based on a

conversation with the control room, and the need to return the electrical bus to an operable state, the switch was returned to its normal position by the Plant General Hanager.

The switch was in the mid-isolate position for approximately two minutes.

For this two minute period, Units 3 and 4 were in 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> action statement per Technical Specification 3.8.3.1, Action'.

However, this was not promptly logged by the control room operators.

At a 1'ater time, (3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />)

a gA inspector questioned the applicability of the Technical Specification action statement.

Consequently, the control room operators made an appropriate "late entry" in the log at approximately 3:55 p.m.

The inspectors reviewed and discussed this event and concluded that the control room was immediately notified by the Operations Hanager of the switch being bumped.

However, the control room did not immediately log the Technical Specification action statement entry and this is considered a weakness.

The inspector also concluded that the identification by gA of the Technical Specification applicability was a strength.

No violations were identified.

Cold Weather Preparations During the inspection period, several instances of cold weather occurred at the Turkey Point Site.

The licensee entered procedure O-ONOP-103.2, Cold Weather Conditions, when auxiliary building temperature was less than 65'F.

This required installation of temporary heaters to protect the Unit 3 and Unit 4 boric acid blender stations and the common BAST room.

The inspector reviewed the ONOP, discussed its implementation with operations and management personnel, and independently verified actions.

The inspector concluded that the licensee appropriately and proactively implemented cold weather procedures.

3.2.7 1995 Performance Indicators

The inspectors reviewed the Turkey Point performance indicators and achievements for calendar year 1995.

These are documented in

periodic department, site, and a corporate reports.

A few of the more significant items were:

Highest unit availability ever (88.36% Unit 3, 97.42%

Unit 4).

Record unit runs (dual unit 147 days, single unit 294 days).

Shortest refueling outage ever (Unit 3-34 days)

and all outage goals met.

Lowest ever annual radiation exposure (215 Rem).

No automatic reactor trips.

Improvements in other indicators including personnel safety, contaminated floor space, and personnel contaminations.

Improvements in site facilities including a new secondary chemistry lab, a permanent cafeteria, and an operations work control center.

4.0 Haintenance (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 acc'ordance 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 Haintenance Activities Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

3A ICW pump repair (section 5.2. 1),

Unit 3 steam flow transmitter troubleshooting (section 3.2.1).

3A Hain Feedwater Pump suction pressure switch fitting repairs 4A EDG troubleshooting (section 4.2.7)

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FCV-4-113A troubleshooting and testing 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.

4.2.2 Surveillance Testing Activities Observed Unit 4 Boric Acid Hakeup Flow Troubleshooting (section 4.2.9)

The inspectors witnessed/reviewed porti'ons of the following test activities:

4B HHSI testing (section 5.2.2).

4A EDG testing (section 4.2.4)

S/G Level Protection testing RPS Logic testing ESF Periodic testing (section 4.2.5)

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

4.2.3 4160 Volt AC Breakers Issue The inspector reviewed and followed up on an issue with the 3B2 circulating water pump breaker that occurred on November 13, 1995.

Condition report No. 59-1134 documented a problem where a local white indicating light at the breaker was noted by an NPO during a

routine tour to be off.

The operators could not trip the pump from the control room switch.

The NWE proceeded to the Unit 3B 4KV bus room, and tripped the pump locally using the alternate shutdown switches.

Electrical maintenance (per WO No. 95031973 and procedure 0-GHE-102. 1, Troubleshooting and Repair) assisted operations and a blown fuse was replaced.

The electricians also noted that the fuse block was not fully installed, and this probably caused the fuse to blow.

New fuses were installed into the fuse block, and'the fuse block was subsequently installed into the 4KV breaker cubicle.

The 3B2 circulating water pump was restarted and the breaker operated satisfactorily.

The inspector. reviewed the CR, the relevant electrical prints, the WO, and the troubleshooting procedure.

The inspector walked down the 4KV bus breakers with electrical personnel and discussed this item with operations and maintenance management.

The inspector

questioned whether this non-safety related breaker would have successfully tripped on a load shed (e.g.,

LOOP or LOCA signal).

Electrical personnel indicated, by use of electrical schematics, that the safety function to trip this breaker was not affected.

The inspector noted that electrical maintenance knowledge and s'upport was strong.

Operators and maintenance personnel appropriately reacted to this failure of the circulating water pump to trip issue.

However, non-licensed operator training relative to correct fuse block installation may have been a causal factor.

The inspector intends to review this area during future inspections.

4.2.4 I&C Work Force Stop Work Order On November 27, 1995, the Plant General Manager issued a temporary stop work order affecting all I&C work except under emergency conditions.

Further, on November 28, 1995, the maintenance manager issued a letter promulgating additional supervisory oversight required for all I&C power block activities.

These measures were implemented as a result of recent errors attributed to I&C personnel including those discussed in sections 3.2. 1 and 3.2.3 of this inspection report.

The additional oversight included each I&C work crew being directly observed by either an I&C field supervisor, a field supervisor from another maintenance discipline, or a maintenance management representative designated by the I&C supervisor.

Responsibility of the oversight personnel included direct observation of critical aspects of each work activity including:

Verification of correct unit, train, component, Manipulation of any valves, bistables, etc.,

Independent verification, Correct work package/procedure at job site, work performed within the scope of work instruction, Verification of adequate clearance orders, Verbatim compliance with work instructions.

Pre-job briefing/tailboards, and Use of Stop, Think, Act, Review (STAR) process in conjunction with all aspects of work activities.

The stop work order was lifted on November 29, 1995, and the additional supervisory oversight requirement was lifted on December 15, 1995.

The inspectors concluded that the short term

effect of this measure appears to have been positive as no further ISC related errors have manifested.

The inspectors plan to monitor long term effects.

The inspectors also concluded that plant management was aggressive in addressing IKC related errors prior to one resulting in significant consequences.

4.2.5 Unit 4 Safeguards Test Switch Sticking On November 28, 1995 during performance of ESF surveillance procedure OP-4004.2, Safeguards Relay Rack Train A, B Periodic Test on Unit 4, Train A, as required by Technical Specification Table 4.3.2, test switch S35 was noted to have a sticking contact.

When the test switch was depressed, the high delta pressure relay PC-486-Xl de-energized as expected to allow testing of the 2-out-of-3 matrix associated with the 4B S/G.

However, when the pushbutton was released by the operator, relay PC-486-Xl failed to immediately energize as expected.

The relay energized following a few second delay.

The relay de-energizes to actuate and therefore, operability of the ESF train was not in question.

However, the licensee initiated condition report No. 95-1175 to evaluate possible corrective actions, including replacement of the switch.

A replacement switch was not immediately available, and current plans are to replace the switch'during the next refueling outage.

Further, a replacement at power would involve making one of the automatic ESF actuation channels inoperable which would result in a six-hour to Hot Standby action statement per Technical Specification Table 3.3-2, Item 1.b, Action 14.

The inspector reviewed licensee actions and concluded that since channel operability was not affected, licensee decision to defer the switch replacement until the next outage (Spring 1996)

was reasonable.

Further, the inspector plans to monitor future required performances of procedure OP-4004.2 that will cycle the sticking switch.

4.2.6 Unexpected Actuation of Unit 4 Steam Generator Protection Bistables The inspector reviewed a condition affecting ESF actuation circuity that occurred on November 28, 1995 during periodic performance of analog channel operational test per procedure 4-SHI-071.4, S/G Level Protection.

During restoration of the actual steam flow transmitter signal, using a toggle switch, unexpected actuation of the low steam pressure bistable occurred due to an apparent voltage dip in the electrical loop.

This condition only affected the S/G channel under test and appeared to occur as the current loops for steam flow and S/G pressure loops were tied together.

The S/G pressure loop was affected during testing of the flow loop because the two were electrically connected via a pressure compensation input to the steam flow square root extracto ~

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During testing, actual steam flow signal from the transmitter was interrupted by opening of a toggle switch to accommodate an analog channel test.

When the toggle switch was subsequently closed following the test, current flow occurred and voltages were reestablished, However, the loo'ps were also equipped with grounded capacitors which momentarily reduced voltage as the capacitors charged up.

This momentary voltage dip was sufficient to pick up the low steam pressure bistable.

The inspector verified that an inadvertent SI initiation was not possible during this voltage per'turbation as the test involves individual protection channels and the SI logic initiations requires 2-out-of-3 channels to actuate.

4.2.7 A similar problem had occurred on June 22, 1995, during the performance of procedure 3-PMI-72.4, Turbine First Stage Pressure Protection Instrument Set III Channel P-3-446.

Consequently, condition report No.95-517 was initiated and procedure 3-PMI-72.4 was changed such that the'steam pressure bistable would be placed in the tripped position, thus precluding actuation following a potential perturbation during restoration of the toggle switch.

However, the condition report failed to address numerous other PMIs and SMIs involving steam break protection that had similar vulnerability during testing.

Following the incident that occurred on November 28, 1995, the licensee revised the condition report to include updates to approximately 10 additional procedures.

The changes, similar to that made on PMI-72.4 were performed via an OTSC.

The licensee is also'ursuing a long term permanent solution to the problem.

The inspector reviewed and discussed this issue with'he licensee.'he inspector recognized that this was a reasonably complex issue and excluding a few select 18C personnel, not well understood.

However, the inspector concluded that an opportunity was missed following the June 22, 1995 incident to riodify and revise all applicable procedures.

The inspector considers this a weakness in the scope of the corrective action that ensued f". cm the condition report.

Emergency Diesel Generator 4A and 3B Failures On December 15, 1995, at approximately 7:30 a.m., during the performance of surveillance on 4A EDG per procedure 4-0SP-023.1, Emergency Diesel Generator Operability Test, the operato}

noted that the 4A EDG output current indication pegged high reading approximately 616 amps (nominal 390 amps.).

Further, the, 4A EDG voltage was reading 4190 volts.

This abnormal indication was noted during the end of the one hour full load run.

The operator

"emergency stopped" the 4A EDG from the control room.

The 4A EDG was declared inoperable and a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement was applicable on both units per Technical Specification 3.8. 1. I.b.2.b.

Further, the licensee complied with the

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requirements of the action statement including successfully testing the remaining required EDGs (3A and 48) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The licensee initiated troubleshooting and inspection, including through monitored running of the 4A EDG.

During this troubleshooting, the licensee identified several problems including EDG voltage immediately building up as opposed to at 450 rpm as designed.

Further, voltage spiking was also noted.

The licensee narrowed the problem to the voltage regulator which was replaced.

Following the replacement of the voltage regulator, the 4A EDG was returned,to service following post maintenance testing at approximately 5: 15 p.m.

on December 16, 1995.

Post maintenance testing included rapid start as well as full load reject test of the 4A EDG.

The licensee initiated a condition report (95-1238)

as a result of the failure.

This appears to be the third failure of a voltage regulator on the 4A or 48 EDGs which were installed in 1990-1991.

Current plans are to send the failed voltage regulator to NEI (vendor) for root. cause analysis.

On December 21, 1995, at approximately 7:45 p.m., during preparations for testing of the 38 EDG in accordance with procedure 3-OSP-023. 1, the 38 EDG fuel priming pump was noted to not develop required pressure.

The 38 EDG was declared inoperable and a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement was applicable on both units per Technical Specification 3.8.1. l.b.2.b.

Further, the licensee complied with the requirements of the action statement including successfully testing the remaining required EDGs (3A and 48 or 4A)

within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The priming pump was replaced and the EDG was later run successfully.

Initially, the licensee suspected that the gears associated with the priming pump were binding causing the pump to fail.

The 38 EDG failure was considered a valid failure and consequently the 38 EDG was scheduled to be tested on a weekly frequency.

On December 29, 1995, while performing the prestart check in accordance with procedure 3-0SP-.023. 1, Diesel Generator Operability Test, prior to starting the 38 EDG, the operator noted that the fuel prime indication initially read between five to ten psig on local instrument gage PI-3-36708 upon running the prime pump.

The indication then indicated zero psig.

The operator notified the control room as well as I&C and mechanical maintenance.

The ANPS verified that the alignment associated with the 38 Fuel prime pump was correct.

Further, the ANPS noted a

grinding sound as well as no discharge pressure when the priming pump shaft was rotating.

The 38 EDG was declared inoperable and a

72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement was applicable on both units per Technical Specification 3.8. l.I.b.2.b.

Further, the licensee complied with the requirements of the action statement including successfully testing the remaining required EDGs (3A and 48 or 4A)

within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> e Upon investigation the licensee identified two fittings in the fuel lines to be wetted with fuel.

Further, the pump sounded dry when running.

The suction line was removed and confirmed to be dry, indicating that the priming pump was air bound.

The licensee confirmed fitting leaks on two 1'ocations which were tightened and the priming pump and the 3B EDG were subsequently run successfully.

The inspector discussed the issue with the licensee, especially in light of the second failure of the priming pump.

The licensee is postulating that the most likely cause of the initial priming pump failure on December 21, 1995 was also due to air binding, not a

binding of the gears as initially suspected.

In addition to the Technical Specification required increased frequency of the 3B EDG, as corrective action following the December 29, 1995 failure, the licensee tested the priming pump every two hours for approximately two days.

Further, the licensee progressively reduced the frequency, as there were no further problems with the priming pump.

The licensee also plans to issue special reports to the NRC discussing the three valid EDG failures.

The required 4A EDG test frequency will not change as a result of this failure. The 3A, 4A, and 4B EDGs remain on a monthly test frequency while the 3B EDG will be tested on a weekly frequency.

The inspector concluded that the operator attentiveness that identified the abnormal current indication was noteworthy.

Further, licensee troubleshooting efforts particular with regards to the 4A EDG failure were prompt, well planned, and thorough.

The inspector also concluded that the increased testing frequency of the 3B EDG as a result of the failure on December 21, 1995, helped identify small leaks in the fuel line that would otherwise have gone unnoticed and potentially caused the 3B EDG to be inoperable for longer periods of time.

The inspectors plan to followup this issue to resolution through the condition report system as well as the special reports that the licensee plans to issue to the NRC.

4.2.8 Feedwater Control System Issues The inspectors reviewed and discussed with the licensee several issues associated with feedwater control system.

These included minor oscillations on the 3B S/G steam and feed flow channels that occurred on December 1,

1995.

Licensee performed an investigation and was not able to conclude the root cause.

On December 17, 1995, a level channel associated with 3C S/G spiked high.

The operators notified I&C as well as established a

dedicated watch.

IRC performed.troubleshooting and did not identify any cause associated with the spike.

Further, during subsequent AFW testing on December 19 and 20, 1995, involving additional challenge to the 3C S/G level control system, no

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problems were identified.

The inspector verified that licensee management was aware of the ongoing feedwater control problems that have occurred recently.

Further, th. licensee is specifically monitoring the 3B and 3C S/G level problems through open PWOs as well as condition report.

The inspector concluded that though the recent feedwater control related perturbations have not resulted in a direct challenge to RPS, plant management needs to continue to focus attention and be aggressive in the identification and resolution of the root cause(s)

associated with the problems.

The inspectors plan to continue to monitor licensee effectiveness in this area.

4.2.9 Boric Acid Makeup Flow Troubleshooting The inspector observed troubleshooting and testing activities associated with the Unit 4 boric acid makeup flow deviation alarm set point change.

This was performed under WR 95019343.

The WR indicated that "the boric acid to blender flow control valve actuator took too long to stabilize flow".

The licensee indicated that it took 90 seconds or greater for the flow to stabilize and for flow control valve FCV-4-1123A to perform as designed.

Design changes had been previously implemented indicating that the flow stabilization should occur within 50 seconds.

The licensee did an excellent job of troubleshooting and testing to assure that the system functioned as designed following the initiation of the WR.

Background documentation indicated that the licensee performed PCH 95-002 to change the time delay setpoint from 10 seconds to 50 seconds.

The increase time was intended to allow the boric acid flow rate and t)e primary water flow rate time to stabilize.

Documentation indicated that the auto closure prematurely terminates operation of the blender.

When this happens, the operator must take manual control of the boric acid makeup valves.

This situation diverts the operators attention from other tasks, and creates the potential of leaving the isolation valves open after the makeup operation is complete.

The inspector questioned the licensee about the testing performed to indicate that the change had in fact prevented premature termination of blender operation, and attempted to locate supporting documentation.

No supporting documentation was located.

The inspector and the licensee were only able to locate documentation which indicated that the relay was calibrated for a 50 second time delay.

5.0 Engineering (37551)

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

5.2 5.2.1 ensuring that the licensee's processes included the identification, resolution, and prevention of problems and'the evaluation of the self-assessment and control program.

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

Inspection Findings 3A Intake, Cooling Water Pump Failure On November 21, 1995, at 3:55 a.m.,

the 3A ICW pump was noted by the ANPO to have high vibration and noise, and increasing motor current (amps).

Operators stopped the pump and started a standby pump.

The 3D 4KV bus was realigned to the 3A bus, and Technical Specification Action Statement 3.7.3.A was entered (7 day action).

Operators initiated condition report No. 95-1174.

U Licensee management directed the technical department and site engineering to initiate an ERT to determine root cause of the ICW pump failure.

The ERT concluded that the pump had a bound shaft at the stuffing box.

The failed parts were sent to the metallurgical lab for analysis'he most probable cause was shaft corrosion of an idle pump.

Licensee corrective actions included replacing the 3A ICW with a spare pump.

IST activities were completed on November 24, 1995, and the 3A ICW pump was declared operable, and the action statement was exited.

Licensee corrective actions relative to the failure included replacing the graphite packing with chesterton 1727 multi-Lon and replacing the aluminum-bronze stuffing box bearing with a non-conductive material (Thordon style "SXL").

The inspector reviewed the condition report and ERT report and observed maintenance activities in the field.

The inspector concluded that the licensee appropriately responded to the failure.

The final root cause analysis and related corrective actions will be reviewed in a future inspection.

5.2.2 4B High Head Safety Injection Pump Abnormality On December 18, 1995, at 6:25 p.m., operators started the 4B HHSI pump to fill the cold leg accumulators and immediately noted low motor current (amps)

and low discharge pressure.

The pump was stopped and the licensee entered a 30-day action statement per Technical Specification 3.5.2.c.

Operations verified the valve lineup to be appropriate and ini.tiated venting of the piping.

No obvious abnormalities could be found other than some gas/air when the BIT was vented.

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5.2.3

A PWO and condition report No. 95-1256 were initiated and the technical department was contacted.

Operators performed an IST on the 4B HHSI pump per procedure O-OSP-062.2, Safety Injection System Inservice Test.

The IST results were satisfactory for all parameters, The remaining three HHSI pumps were also run, and no abnormalities were noted.

Based on these actions and test results, the 4B HHSI pump was returned to service at 1:20 a.m.

on December 19, 1995.

Licensee management directed an ERT to review this issue and to develop an action plan to address the 4B HHSI pump abnormality and indications that were observed on December 18, 1995.

The actions included the following:

operations periodic testing and venting (initiallydaily, then weekly) to assure the'ump remained functional, maintenance reviewed work history and pump starts, technical department prepared a TP to monitor for potential back leakage from the RCS and/or the cold leg accumulators, engineering reviewed the possibility (including related calculations) for back leakage, Based on these actions, the licensee concluded that an air or gas intrusion was the most plausible cause for the 4B HHSI pump abnormality.

The inspector reviewed logs, the interim condition report, the ERT report, IST results, and PWO history.

The inspector attended a

portion of the ERT meetings, and discussed this issue with licensee personnel.

The inspector observed the periodic pump starts testing, and venting evolutions.

The inspector noted that no further abnormalities were observed.

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

The inspector intends to continue to follow licensee actions for this issue includinp the final condition report disposition.

Emergency Diesel Generator Relay Issues The inspector reviewed and discussed with the licensee several issues affecting EDGs.

These included two conditions affecting the control circuitry of the 3A and 38 EDGs that were identified by the licensee as well a relay failure mechanism affecting Turkey Point EDGs that was identified at St. Lucie.

The first condition affecting the 3A and 3B EDG control circuitry involved a wiring error such during the IDLE run period following a normal stop, the main bearing oil pressure trip and alarm signals were disabled.

This would result in a loss of capability

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to alarm or to trip the engine if oil pressure were lost during the 20 minute IDLE run following a normal stop.

The licensee evaluated the condition and concluded that the main bearing low oil pressure trip was provided for equipment protection purposes and is bypassed during an emergency run.

During non-emergency EDG runs at normal or idle speed, a failure of the engine lube oil system should cause the EDG to be inoperable regardless of the low oil pressure trip, function.

The availability of the low oil pressure trip only assures that serious engine damage does not occur by shutting down the engine.

The engine trip would initiate a lockout making the EDG inoperable until the trip condition is corrected.

Therefore, the low oil pressure trip circuit is not required for the EOG to be operable.

Nevertheless, the licensee completed a modification of the circuity to correct this issue'or 3A and 3B EDGs on December 21, 1995.

The second condition involved a relay race which would result in an EOG lockout if an emergency start signal was received during the coastdown from 450 rpm to 40 rpm after a normal stop.

When a

normal stop is initiated, the normal stop timer (NST) is energized to establish a 20 minute cooldown run period at idle speed.

After the NST times out, normally closed contacts of the NST open to deenergize shutdown relays (SDX,SDRX) which in turn shuts off the fuel supply and causes the engine to decelerate from the 450 RHP idle speed to a stop condition.

Normally closed contacts from the NST also open the emergency shutdown relays (ESDR,ESDRX) circuit in order to prevent a lockout due to the drop-out of relay SDRX.

If an emergency start signal is received during the coastdown period form 450 to 40 RPH, the NST will drop out due to pick-up of the emergency run relay AER which causes voltage to be applied simultaneously to the SDR and SDRX, and ESDR and ESDRX relays.

This causes a direct race between the pickup of relays SDRX and ESDRX as they provide permissive to each others circuit.

Relay SORX is a square D type KP while ESDRX is an Asea Type RXHE relay.

Both relays have a nominal pickup time if 15 ms per vendor catalog specifications.

If the actual pickup time of SDRX is slightly less than that of ESDRX, the shutdown relays would not pickup and lockout would occur following an emergency start.

The licensee performed an operability evaluation as a result of this condition.

The relay race condition could occur during the short period of coastdown from 450 to 40 RPH following a normal stop.

This short time was estimated to be 10 seconds.

This post normal condition would be present as a minimum once a month when an EDG operation occurs to verify operability as required by Technical Specifications.

The licensee estimated that considering both 3A and 3B EDG operation, the maximum window of time that the spurious lockout could occur is approximately

seconds per month.

This constit'uted a probability of 2.9 E-2, for an EDG failing to perform its function and a subsequent increase in core damage frequency of approximately 3.8 E-9 per year.

Further, the relay race condition does not preclude the ability to

manually reset the lockout circuit and subsequently start and load the EDG impacted which is addressed in plant procedures.

Thus the licensee, in accordance with guidance provided in NRC GL 91-18, concluded the EDG operability to be unaffected.

However, the licensee has already'initiated efforts to implement a modification to rectify the condition.

With regard to the Square D, 8501 series, model KPD-13 relay failures that were experienced at FPL's St. Lucie Nuclear Plant, the licensee confirmed that Turkey Point utilizes the same relays for numerous functions involving EDGs.

The relays at St. Lucie experienced problems with the relay/socket interface, including failed solder joint where the socket is mounted on the circuit board as well as broken connections between the socket and the circuit board.

A condition report, No. 95-1120 was initiated to address the effects at Turkey Point.

Initial review has determined that the subject relays are'not skid mounted at Turkey Point nor are they are subject to the periodic inspection.

Thus the subject relays are not subject to vibration and/or repeated mechanical cycling during inspection as at St. Lucie.

Further, an inspection of a small sample did not reveal any damage.

The condition report is still open pending root cause analysis of the relays that were noted to have failed at St. Lucie.

The inspector plans to monitor any further development associated with this issue.

With regard to the issues discussed above, the inspector concluded that no EDG operability issues existed and that licensee resolution through the condition report process was effective.

The inspector also concluded that the identification of the EDG circuit problems was a strength.

5.2.4 Unit 3 Containment Particulate and Gas Honitor Problems On December 3,

1995, during the performance of a source check on Unit 3 containment particulate monitor, 3-R'-ll, in accordance with procedure 3-0SP-201.1, RCO Daily Logs, the microprocessor (RH-80)

that controls and manipulates da'ta provided by radiation monitors 3-R-11 and 3-R-12 failed.

Radiation monitors 3-R-11 and 3-R-12 monitor Unit 3 containment particul.ate and gas activity, respectively.

They provide signals that isolate containment ventilation, close containment air bleed valves, and initiate control room ventilation in a recirculation mode.

These monitors are part of ESF instrumentation and provide a means to detect leakage from the RCS.

These redundant monitors are safety related and are required by Technical Specification 3.4.6. 1 and 3.3.3.1, Table 3.3-4.

Additionally, there are other instruments that accomplish redundant function as R-11 and R-12.

A modification, PC/H 95-128, was implemented on November 30, 1995 to address an existing software error in the analog output scaling routine of the RH-80, (Revision 2), processor.

The software error

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associated with the analog output scaling routine had the potential for affecting operability and consequently, a shiftly check of R-11 and R-12 was performed to verify operability.

This problem with the analog scaling routine was never observed at Turkey Point.

A 10 CFR Part 21 report associated with the RM-80 (Revision 2), software had also been initiated by Sorrento in February 1994.

I PC/M 95-128 performed on Unit 3 essentially consisted of installation of modified firmware, i.e. Revision 3. (firmware is software/program that is preinstalled on a replaceable cir'cuit/chip).

Testing associated with the new firmware installed per PC/H 95-128 included verification by the vendor that the monitor would detect high radiation levels and provide appropriate actuation functions.

Further, as post-modification testing, procedure 3-OSP-067. I, Process Radiation Monitoring Operability Test, was performed to verify 3-R-11 and 3-R-12 operability.

Following the failure of 3-R-11 on Unit 3, the licensee contacted the vendor (Sorrento Electronics).

The vendor confirmed the firmware changeout implemented by the PC/M also caused the RM-80 processor to malfunction when a check source operation was performed at their facility.

Consequently, the vendor recommended that the firmware installed by PC/H 95-128 be removed and the old version be reinstalled.

The vendor plans to perform a root cause analysis associated with the problem involving Revision 3 of the

.firmware.

The licensee determined that 3-R-12 was not affected as a result of PC/H 95-128 based on different steps in the software used to perform the check source routines for R-11 and R-12.

To date, manual check source routines that were performed on 3-R-12 did not give obvious indications as was observed on 3-R-11 (e. g.,

the microprocessor slowing down and eventually stopping).

Nevertheless, as per vendor recommendation, the new firmware was removed and the old firmware was reinstalled on 3-R-12.

Fol',owing the. emergency load sequencer software problems that manifested in 1994, (NRC Inspection Report No. 50-250,251/94-23)

the licensee's corrective actions included audits of software development and revisions to procedures at Sorrento Electronics.

The purpose of the audit was to gain reasonable assurance that the containment gaseous'nd particulate radiation monitors currently installed did not contain software logic errors similar to the sequencers.

The audit noted that most software for the monitors was developed before the adoption of the formal validation and verification concept by the nuclear industry.

Further, the audit did not find documentation that indicated conformance to ANSI/IEEE Standard 7-4.3.2-1993, Application Criteria'for Programmable Digital Computer Systems In Safety Systems of Nuclear Power Generating Stations as the vendo'r had developed the software prior to the promulgation of the validation and verification standards issued in the ANSI/IEEE 7-4.3.2-1993.

However, the audit concluded that based on the experience gained from the large

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amount of installed radiation monitoring firmware supplied by Sorrento Electronics, a reasonable amount of confidence existed that the installed firmware did not contain errors similar to those that appeared in the sequence logi".

The inspector reviewed and discussed the issue with the licensee,-

including condition report CR No. 95-1214 and concluded that the applicable Technical Specification LCO were not exceeded and action statements were met.

Further, the inspector concluded that the safety significance associated with 3-R-11 inoperable from November 30, 1995 through December 3, 1995 was minimal as redundant instruments were operable.

Pending the results of the root cause analysis by Sorrento, this issue will remain open and will be tracked as Unresolved Item 50-250,251/95-22-01 Firmware Problems associated with Containment Radiation monitor R-ll.

5.2.5 Unit 4 Enthalpy Rise Hot Channel Factor On December 13, 1995 during the review of Unit 4 Enthalpy Rise Hot Channel Factor (F Delta-H) data associated with surveillance that was performed on December 7,

1995 as required by Technical Specification 4.2.3.3, the licensee noted an adverse trend such that there was a potential for exceeding the F Delta-H power distribution limit at a later time in core life.

The F Delta-H limit as allowed by Technical Specification 3.2.3 for current power level was less than or equal to 1.62.

The F Delta-H value based on December 7,

1995 data for the most limiting core location (K-13) was 1.6089 and the predicted value for this core location was 1.54.

Though the Technical Specification limit was not exceeded, the licensee conservatively initiated an investigation including condition report No. 95-1235 to ascertain the trend as well as to identify all possible contributors to this observed anomalou's trend.

The investigation included performance of several incore flux maps to recalculate the F Delta-H value, discussions with the fuel manufacturer, and a review of pertinent fuel data, including input data assumptions and core verification for correct installation of fuel assemblies during the past outage.

The investigation concluded that no errors with regard to input data assumptions, fuel manufacturing, or fuel assembly installation, burnable poison depletion model assumptions existed.

Further, the F-Delta-H values obtained from the subsequent incore flux maps were commensurate with predicted values, thus negating the anomalous results and the associated trend that the anomaly noted on December 7,

1995 may have been caused by, was initially observed.

The licensee is investigating the cause of the anomalous data that was obtained on December 7,

1995.

The inspector plans to follow this issue through the condition report proces I

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The inspector concluded that though Technical Specification limits were not exceeded, the licensee aggressively pursued a potential problem affecting Power Distribution Limits and verified the accuracy and adequacy of the factors that affect the limits.

6.0 Plant Support (71750)

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

Inspection Findings Unattended and Unposted High Radiation Trash During a routine survey on November 17, 1995, a licensee HP technician noted that some bagged valve internal parts were indicating high radiation levels, but the affected area was not posted.

The HP technicians'urvey indicated that contact readings were 1.8 Rem/hour and 175 Nrem/hour at 12 inches.

The bagged trash was Unit 3 valve 3-'455A (pressurizer spray)

internals.

Apparently, this item was moved from a Kelley Building inside the radwaste building to an interim storage area along with other trash the previous day.

The valve internals were shielded by the other low level trash such that the high radiation readings were only noted when the trash on top of valve internals was removed.

The HP technician immediately tagged the bag and posted the area as required.

In addition, management was informed and condition report No. 95-1141 was generated.

The licensee notified the inspector and conduc'ted an investigation.

The license concluded that work on November 16, 1995, relocated this high radiation trash.

However, the HP involved that day failed to adequately survey the movement and thus failed to adequately post the new storage area.

The worker involved in the trash movement received 4 mrem of exposure.

Further, no other personnel received dose from this unposted high radiation trash as it was shielded.

The licensee also concluded that the material was previously tagged with its appropriate radiation levels and contents.

However, the tag became dislodged.

Licensee corrective actions included the following:

Tagged the trash and posted the effected are ~

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Checked the RCA for other potential unmarked or unposted items.

None were found.

Held crew meetings with all HP personnel.

Included the event and CR in the HP requalification training.

Counselled and disciplined the HP technician who failed to conduct adequate surveys and postings.

Revised HP procedures to enhance the handling and posting of radioactive material.

The inspector reviewed the event.,

including the CR, the survey, HP procedures, dose records, and log entries.

The inspector toured the radwaste building with HP supervision and management, and discussed the issue with plant management.

Technical Specification 6. 12. 1 requires that high radiation areas (>100 Nrem/hour at 12 inches)

be barricaded and posted, and entrance to the area be controlled by an RWP.

The inspectors concluded that the failure to adequately post the area where the valve internals was stored on November 16-17, 1995, was a violation of Technical Specification 6. 12. 1.

This was caused by inadequate selF-checking by the HP technician which resulted in the failure to adequately survey and post the high radiation material.

The inspectors also noted that the issue was taken seriously by licensee management and corrective actions were prompt and aggressive.

Further, the identification of the condition by another HP technician was indication of a questioning attitude.

The inspector also concluded that the safety significance was minor because the trash was adequately shielded while in the temporary storage area and no personnel received any unwarranted exposure from this unmarked and unposted radioactive material.

The failure to meet the requirements of Technical Specification will not be subject to enforcement action because the licensee identified the issu'e and because licensee corrective actions were prompt and appropriate.

This meets the criteria specified in Section VII.B of the NRC Enforcement Policy.

This item is being tracked as NCV 50-250,251/95-22-02, Failure to Neet Technical Specification 6.12. 1 To have a High Radiation Trash Posted.

This item is closed.

6.2.2 Fitness For Duty Program and Random Drug Testing The, licensee notified the inspector of three FPL individuals affiliated with Turkey Point testing positive for marijuana during recent random drug testing.

The three individuals did not hold any supervisory positions and therefore these events were not reportable.

The inspector discussed the cases with the licensee and concluded that the licensee took appropriate measures

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following the identification, including review of recent activities performed by the individuals.

6.2.3 Unit 3 Containment Entries The licensee performed multiple Unit 3 containment entries at power in order to isolate and fix a steam flow transmitter leak

'see section 3.2. 1).

The inspector accompanied one entry and monitored the performance of several others during the period November 19-22, 1995.

Entries were performed in accordance with the ADM and exposure was kept ALARA.

Total exposure was 1. 103 Rem which included

.876 Rem neutron and

.236 Rem beta/gamma.

The inspector verified that the RWP (95-0323)

was appropriately written, reviewed, and adhered to.

Further, the inspector noted HP supervision involvement.

Overall, the entries were well controlled.

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

An exit meeting was conducted on January 4,

1996.

(Refer to section 1.0 for exit meeting attendees.)

The areas requiring management attention were reviewed.

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

Dissenting comments were 'not received from the licensee.

However, the inspectors had the following findings:

Item Number Status Descri tion and Reference 50-250,251/95-22-01 50-250,251/95-22-02 (Open)

URI, Firmware Problems associated with Containment Radiation Monitor R-ll (section 5.2.4).

(Closed)

NCV, Failure to Have High Radiation Trash Posted (section 6.2.1).

e 8.0 Acronyms and Abbreviations AC ADM AFW ALARA a.m.

amp ANPO ANPS ANSI ARP Alternating Current Administrative Auxiliary Feedwater As Low As Reasonably Achievable Ante Meridiem Ampere Associate Nuclear Plant Operator Assistant Nuclear Plant Supervisor American National Standards Institute Annunciator Response Procedure

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BAST CCW CR cpm EDG e.g.

EOP ERT ESF 4F FCV FPL FT GL GME GMI gpm HHSI HP HPES IKC ICW i.e.

IEEE IST KV LCO LER LOCA LOOP M

Mwe NCV NPO NPS NRC NRR NWE ONOP OP OSP OTSC P21 PC/M PI p.m.

PMI PMT PNSC PS psig PWO Boric Acid Storage Tank Component Cooling Water Condition Report Counts Per Minute Emergency Diesel Generator for Example Emergency Operating Procedure Event Response Team Engineered Safeguards Feature Degrees Fahrenheit Flow Control Valve Florida Power and Light Flow Transmitter Generic Letter (NRC)

General Maintenance

- Electrical General Maintenance

-

I&C

'allons Per Minute High Head Safety Injection Health Physics Human Performance Evaluation System Instrumentation and Control Intake Cooling Water That Is Institute of Electrical and Electronics Engineers Inservice Test Kilovolt Limiting Condition for Operation Licens<<

Event Report Loss-of-Coolant Accident Loss of Off-Site Power Milli Megawatts Electric Non-Cited Violation Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear Watch Engineer Off-Normal Operating Procedure Operating Procedure Operations Surveillance Procedure On-the-Spot Change

CFR Part

Plant Change/Modification Pressure Indicator Post Meridiem Preventive Maintenance

- ISC Post-Maintenance Test Plant Nuclear Safety Committee Pressure Switch Pounds Per Square Inch Gauge Plant Work Order

I

gA gC R

RAD RCA RCO RCS rem RO RPS RWP RWST S/G SGFP SI SMI SNPO, SRO STAR TP TPCW TSC URI WO WR

equality Assurance equality Control Radiation Monitor Radiation Adsorbed Dose Radiation Control Area Reactor Control Operator Reactor Coolant System Roentgen Equivalent Man Reactor Operator Reactor Protective System Radiation Work Permit Refueling Water Storage Tank Steam Generator-Steam Generator Feedwater Pump Safety Injection Surveillance Maintenance

- I8C Senior Nuclear Plant Operator Senior Reactor Operator STOP-THINK-ACT-RE VI EW Temporary Procedure Turbine Plant Cooling Water Technical Support Center Unresolved Item Work Order Work Request

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