IR 05000250/1994005

Insp Repts 50-250/94-05 & 50-251/94-05 on 940227-0326. Noncited Violation Noted.Major Areas Inspected:Plant Events,Operational Safety,Maint Observations,Surveillance Observations & Followup on Previous Items

ML17352A540
Person / Time
Site:	Turkey Point
Issue date:	04/12/1994
From:	Binoy Desai, Johnson T, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352A539	List: IR 05000250/1994005 ML17352A538
References
50-250-94-05, 50-250-94-5, 50-251-94-05, 50-251-94-5, NUDOCS 9404200162
Download: ML17352A540 (40)

Text

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/94-05 and 50-251/94-05

'icensee:

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

50-250 and 50-251

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License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspect'ion Conducted:

February 27 through March Inspectors:

T.

P. Jolinson, Senio Resident Inspector B.

B. Desai, Residen Inspector

. L. Trocine, Resident I spector Accompanied by:

R.

P. Schin, Project Engineer, Division of Re r Projects 26>

1994 Date Signed Dat Signed S-qz C

Dath Signed Reactor Projects Section 2B, Approved by:

K. D. Landis, Chief Reactor Projects Section 2B Division of Reactor Projects Date S gn d

SUNHARY Scope:

This resident inspection to assure public health and safety involved direct inspection at the site in the areas of operational safety, plant events, maintenance observations, surveillance observations, followup on previous items, review of written reports, and Unit 3 refueling preparations.

Backshift inspections were performed in accordance with NRC Region II guidance.

Results:

Within the scope of this inspection, the inspe'ctors determined that the licensee continued to demonstrate satisfactory performance to ensure safe osppozso ihz 940412

plant operations.

The following non-cited violation, inspector followup item, and unresolved item were identified:

Non-Cited Violation 50-250,251/94-05-01, Non-Licensed Operator Exceeded Overtime Limit (section 4.2. 1).

Inspector Followup Item 50-250,251/94-05-02, Administrative Procedures Upgrade (section 4.2.3)..

Unresolved Item 50-250,251/94-05-03, Power Operated Relief Valve Seat Leakage Root Cause and Corrective Action (section 6.2.4).

During this inspection period, the inspectors had comments in the following Systematic Assessment of Licensee Performance functional areas:

~0erations An instance where a non-licensed operator exceeded, the overtime limit is classified as a licensee-identified non-cited violation (section 4.2. 1).

Some minor errors were identified in the administrative procedure regarding Nuclear Regulatory Commission notifications; this issue (including the completion of administrative procedure upgrades)

is an inspector follow item (section 4.2.3).

The licensee has an appropriate program in place to update the final safety analysis report (section 4.2.5).

The licensee appropri ately removed Unit 4 from service due to a

small reactor coolant system leak.

Subsequent shutdown, cooldown, and restart activities by operations were professionally conducted (section 5.2. 1).

The licensee appropriately responded to a Unit 4 rod position indication problem (section 5.2.2).

Licensee event, special, and periodic reports submitted to the Nuclear Regulatory Commission were well written and appropriate (section 8.2).

The licensee's plans and preparations for the upcoming Unit 3 refueling outage were in place.

Management involvement and oversight and risk assessment planning appear strong; however, the risk assessment administrative procedure checklists do not address spent fuel pool cooling equipment availability (section 9.0)

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Maintenance Inspector-observed maintenance and surveillance activities were properly performed (sections 6.2. 1 and 7.2.1).

The licensee's maintenance training programs were appropriate with a professional training staff and with strong classroom and laboratory equipment facilities.

However, the training program did not preclude the use of uncertified journeymen to perform safety-related maintenance.

Current practice and management philosophy 'require certification prior to any unsupervised work.

The quality assurance organization is appropriately involved in the review of maintenance activiti'es (section 6.2.2).

Although the licensee repaired a Unit 4 power operated relief valve, the other valve began leaking upon restart.

Therefore, this issue is unresolved pending licensee determination of root cause and corrective actions (section 6.2.4).

Good work coordination was noted during the licensee's repair

of a leak on the Unit 4 spare control -rod drive mechanism canopy se'al (section 6.2.5).

Although the decision to remove Unit 4 from service in order to repair indications of a very small seal table leak was conservative, a weakness was noted in the work control process and associated intra-departmental communications.

This resulted in the fill and vent of the reactor coolant system prior to completing the repairs and in the subsequent movement of a thimble tube.

The licensee's response to this problem was aggressive including line management and independent root cause investigations and effective corrective action implementation (section 6.2.6).

En ineerin Materials management, program implementation and engineering support for the spare parts and warehouse recovery process was very'ood (section 6.2.3),

Engineering support for the plant change/modifications for the Unit 4 spare control rod drive canopy seal repair and the seal table repair was strong (sections 6.2.5 and 6.2.6).

Plant Su ort Radiation Controls Emer enc Pre aredness Securit Chemistr Fire Protection Fitness For Out and Housekee in Controls The licensee responded to a potential condition relative to fire retardant material in an appropriate and timely manner (section 4.2.2).

Radiological controls during the Unit 4 forced outage were very good.

This included containment control, radiation work permits, and job coverage (section 4.2.4).

An Unusual Event declaration was made in a timely and appropriate manner (section 5.2. 1).

Licensee response to a

small laundry. room fire including fire brigade and health physics was prompt and appropriate (section 5.2.3).

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 On Site,..............,.............

2.0 Other NRC Inspections or Activities Performed During This Period

3.0 Plant Status

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3.1 Unit 3

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3.2 Unit 4

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4.0 Operational Safety Verification

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4. 1 Inspection Scope...............

4.2 Inspection Findings

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5.0 Plant Events

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5. 1 'nspection Scope.....

5.2 Inspection Findings 6.0 Maintenance Program, Support, and Observations 6. 1 Inspection Scope....

6.2 Inspection Findings 7.0 Surveillance Observations

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7. 1 Inspection Scope........

7.2 Inspection Findings.....

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8.0 Onsite Followup and In-Office 8.1 Inspection Scope

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8.2 Inspection Findings Review of Mritten Reports

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9.0 Unit 3 Refueling Preparations.....

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9. 1 Inspection Scope.......

9.2 Inspection Findings....

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10.0 Exit Interviews..

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11.0 Acronyms and Abbreviations....................................

REPORT DETAILS 1.0 Persons Contacted 1. 1 Licensee Employees T. V. Abbatiello, Site guality Manager R. J. Acosta, Company Nuclear Review Board Chairman W.

H. Bohlke, Vice President, Engineering and Licensing H. J. Bowskill, Reactor Engineering Supervisor S.

H. Franzone, Instrumentation and Controls Maintenance Supervisor J.

E. Geiger, Vice President, Nuclear Assurance R. J. Gianfrancesco, Haintenance Support Services Supervisor J.

H. Goldberg, President, Nuclear Division R.

G. Heisterman, Mechanical Maintenance Supervisor'.

C. Higgins, Outage Manager G.

E. Hollinger, Training Manager D.

E. Jernigan, Operations Manager H.

H. Johnson, Operations Supervisor V. A. Kaminskas, Services Manager J.

E. Kirkpatrick, Fire Protection/Safety Supervisor J.

E. Knorr, Regulatory Compliance Analyst R.

S. Kundalkar, Engineering Manager J.

D. Lindsay, Health Physics Supervisor J. Harchese, Site Construction Manager F.

E, Harcussen, Security Supervisor H.

N. Paduano, Manager, Licensing and Special Projects L.

W. Pearce, Plant General Manager M. 0.

Pearce, Electrical Maintenance Supervisor T.

F. Plunkett, Site Vice President D.

R. Powell, Technical Manager R.

E.

Rose, Nuclear Materials Manager R.

N. Steinke, Chemistry Supervisor H.

B. Wayland, Maintenance Manager E. J.

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

1.2 NRC Resident Inspectors B.

B. Desai, Resident Inspector T.

P. Johnson, Senior Resident Inspector L. Trocine, Resident Inspector 1.3 Other NRC Personnel on Site M. V. Sinkule, Chief, Reactor Projects Branch

• Attended exit interview on March 29, 1994

Note:

An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this report.

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Other NRC Activities or Inspections Performed During This Period Re ort No.

Dates Area Ins ected 50-250,251/94-04 N/A 3.0 Plant Status February,28-Harch 4, 1994 Harch 15, 1994 Effluents and Chemistry Self-Assessment and Outage Heetings in Atlanta,,GA 3.1 Unit 3 3,2 At the beginning of this reporting period, Unit 3 was operating at or near full power and had been on line since February 23, 1993.

The unit continued to operate at power during this period.

Unit 4 At the beginning of this reporting period, Unit 4 was operating't or near full power and had been on line since August 17, 1993.

The unit was shutdown on Harch 10, 1994, due to a through wall leak in a seal table guide tube.

Repairs were completed (Refer to section 6.2.6 for additional information.),

and the unit returned to full power on Harch 18, 1994.

4.0 Operational Safety Verification (40500'nd 71707)

4.1 Inspection Scope The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers, and monitored instrumentation.

The inspectors verified proper valve/switch alignment of selected safety systems, verified that maintenance work orders had been submitted as required, and verified that followup and prioritization of work was accomplished.

The inspectors reviewed tagout records, verified compliance with TS LCOs, and verified the return to service of affected components.

By observation and direct interviews, verification was made that the physical security plan was being implemented.

.The implementation of radiological controls, fire protection, fitness for duty, chemistry, emergency preparedness, and plant housekeeping/cleanliness conditions were also observed.

Tours of the intake structure and diesel, auxiliary, control, and turbine buildings were conducted to observe plant equipment

conditions including potential fire hazards, fluid leaks, and excessive vibrations.

4.2 4.2.1 Inspection Findings Non-Licensed Operator Exceeded Overtime Limits On March 1, 1994, the licensee discovered that a non-licensed operator had inadvertently worked 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> in a 48-hour period.

Turkey Point TS 6.2.2.g.2 prohibits an individual from working more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period without prior authorization by the department manager or higher levels of

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management.

The non-licensed operator was originally scheduled to work on the day shift.

After working for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> on the day shift on February 22, 1994, the NPS requested the operations scheduler to arrange two additional field non-licensed operators for the peak shift.

The non-licensed operator,was contacted by the backup operations scheduler to work peak shift on February 22, 1994.

The backup operations scheduler forgot to document the overtime worked during peak shift in the overtime book, and the regular operations scheduler was on leave.

On February 23, 1994, the non-licensed operator worked his normally scheduled 8-hour day shift and was later requested by the NWE to work overtime during the midnight shift February 23-24, 1994, The NWE filled out the overtime guideline form to verify that overtime limits would not be exceeded.

However, this is derived from the overtime logbook which was in error.

The'on-licensed operator accepted and worked the overtime.

This resulted in the non-licensed operator working a total of 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> in a 48-hour period.

Two incidents involving operations personnel exceeding overtime-requirements without management approval had occurred in December 1993.

An NCV (50-250,251/93-29-02),

Exceeding Overtime Limits Specified in TSs, was issued as a result 'of the incidents.

Licensee corrective action included development of the overtime guideline checklist form.

As a result of the recent incident, the licensee took several additional corrective actions to prevent recurrence.

These included shifting the responsibility of maintaining the overtime book from the scheduling technician to the NWE.

The overtime guideline form was also revised to strengthen individual accountability by requiring the individual working overtime, the NWE, ahd the NPS to sign the overtime guideline form prior to the overtime being worked.

In addition, the involved personnel were disciplined, and gA was assigned to independently review the event as well as the overall overtime control progra.2.2 The inspectors discussed this event with plant management including why the corrective actions from the December 1993 events had not prevented overtime from being exceeded.

In addition, the-inspector reviewed the licensee's overtime control process.

The-inspectors concluded that the licensee was responsive with respect to overtime issues.

The inspector believes that the recent overtime violation was caused by personnel errors, especially on the part of the backup scheduling technician.

It was not an indication of a programmatic problem nor was it caused by inadequate corrective actions.

Based on the low safety significance of the event, the.fact that the incident was identified by the licensee, and the additional corrective actions taken by the licensee discussed above, this failure to meet the requirements of TS 6.2.2.g.2 will be identified as NCV 50-250,251/94-05-01, Non-Licensed Operator Exceeding Overtime Limit.

The criteria specified in Section VII.B of the Enforcement Policy were satisfied.

This item is closed.

Fire Protection Flamemastic Material During a routine plant tour, the inspector noted that certain cables and cable trays in the Unit 3 and 4 electrical penetration rooms exhibited a degraded condition relative to the coating material (Flamemastic).

, Flamemastic is a fire retardant coating material which has been in use since construction of Turkey Point.

The inspector immediately informed the licensee of this condition.

Licensee representatives from operations, engineering, and the fire protection group inspected the electrical penetration rooms and affected areas.

The licensee confirmed that roving fire watches were already in the areas and then proceeded to initiate a

condition report (No. 94-97).

Engineering responded to the condition report in an evaluation (JPN-PTN-SENP-94-011)

dated Harch 2, 1994.

The evaluation concluded that FPL did not take credit for this Flamemastic fire retardant material in these areas to meet the safe shutdown requirements of 10 CFR Part 50, Appendix R.

However, for certain areas, which do not include the electrical penetration rooms, Flamemastic was documented as a preventive measure (reference UFSAR 9.6A) because

CFR Part 50, Appendix R, exemptions apply.

This includes the changing pump rooms, containment, auxiliary feedwater area, and two outside areas in the turbine building.

The inspector reviewed the condition report response, the UFSAR, and the engineering evaluation.

The inspector concluded that the licensee responded to this issue appropriately and in a timely manner.

The inspector spot checked the areas where Flamemastic is taken credit for as a preventive measure, and no deficiencies were note.2.3 Administrative Procedures Following the Unit 4 event regarding a rod position indication problem (Refer to section 5.2.2 for additional information.), the inspector reviewed administrative procedure AP-0103. 12, Notification of Events to the NRC.

Operator interpretation of a note in Appendix A of the procedure resulted in a conservative

CFR 50.72 call, which the licensee later retracted.

The inspector noted several minor errors in the procedure, primarily incorrect or missing references to some

CFR reporting requirements.

The inspector discussed this issue with licensee personnel who indicated they would correct AP-0103. 12 in,a future revision.

The inspector also questioned the status of AP procedure upgrades into the new ADH format.

Host administrative procedures have been revised and changed to the new ADH format; however, some (like AP-0103. 12) remain in the older format.

Licensee personnel indicated that they are currently scheduled to complete AP revisions by the end of 1994.

This item will be tracked as IFI 50-250,251/94-05-02, Administrative Procedure Upgrades.

4.2.4 Unit 4 Forced Outage During the Unit 4 forced outage from Harch 10-18, 1994, the

'nspectors monitored the following various licensee activities and performed various inspections during all shifts:

containment entries to monitor work in progress and radiological conditions; plant tour s to review maintenance work; control. room tours to review operation's control of work turnover and plant conditions; unit shutdown, cooldown, mode changes, heatup, RCS fill and vent, and inventory control; decay heat removal while in cold shutdown; shift director control of the outage and turnover meetings; outage schedule and tracking of activities; and reactor and plant startup.

The inspector concluded that the outage, with the exception of the issues identified with the seal table repair (Refer to section 6.2.5 for additional information.);

was appropriately controlled and that shift director oversight was good.

HP controls were

noted to be strong including control of containment access, RWP implementation, and job control and oversight.

4.2.5 UFSAR Revisions The inspector previously identified a concern with accuracy and adequacy of some UFSAR information.

This was documented in section 12.2. 1 of NRC Inspection Report No. 50-250,251/94-01.

The licensee has addressed this issue.

Licensee actions= to improve control of the UFSAR included the following:

completion of a design basis document program, re-assigned responsibility for the UFSAR revision process including development of document update and search programs, modifications/additions to the UFSAR completed following the 1991 dual unit outage, operational review of UFSAR to,be done, and development of an abandoned equipment program and plans to begin implementation including UFSAR updates.'ased on these actions, the inspector concluded that the licensee now has an improved program in place to assure that the UFSAR will reflect current design and as-built information.

4.2.6 General Results As a result of routine plant tours and various operational observations, the inspectors determined that the general plant and system material conditions were satisfactorily maintained, the plant security program was effective, and the overall performance of plant operations was good.-

5.0 Plant Events (93702)

5.1 Inspection Scope The following plant events were reviewed to determine facility status and the need for further followup action.

Plant parameters were evaluated during transient response.

The significance of the event 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.

Evaluations were performed relative to the need for additional NRC response to the event.

Additionally, the following issues were examined, as appropriate:

details regarding the cause

5.2 5.2.1 of the event; event chronology; safety system performance; licensee compliance with approved procedures; radiological consequences, if any; and proposed.,corrective actions.

Inspection Findings Unit 4 Shutdown Due to RCS Pressure Boundary Leakage At 6:00 a.m.

on March 10, 1994, FPL deolared an Unusual Event at Turkey Point, and commenced a Unit 4 shutdown as required by TS 3.4..6.2.a due to RCS pressure boundary leakage through an incore instrument guide tube located at the seal table.

The leak was not quantifiable; however, a 1/4-inch long by 1/8-inch diameter buildup of boric acid was observed during a, quarterly visual leak inspection'of the incore guide tubes and the seal table.

The leak was on a 0.86-inch OD, 1/8-inch thick, stainless steel portion of the N-5 guide tube just above the seal table and just below a

welded fitting adapter.

lg The licensee notified the NRC and the state of Florida of this event.

The inspector was in the control room during the notifications.

Additionally, the inspectors monitored a large portion of the activities.

Unit 4 reached cold shutdown at approximately 3:25 a.m.

on March 11, 1994.

Following repairs to the guide tube (Refer to section 6.2.6 foradditional information.)

and the canopy seal (Refer to section 6.2,5 'for additional information.), the licensee commenced unit heatup on March 14,, 1994.

Criticality was achieved on March 17, 1994, and the unit reached 100% power on March 19, 1994.

l The inspectors concluded that the licensee appropriately made a

notification to the NRC pursuant to

CFR 50.72(a)(i)

in a timely manner.

The shutdown, cooldown, and subsequent startup were also professionally conducted.

5. 2.2 Unit 4 RPI Problem On March 18, 1994, at approximately 3:05 p.m., during a power escalation following the shutdown discussed in section 5.2. 1 of this report, one of the bank D control rods indicated greater than 12 steps misaligned.

The RPI was reading 206 steps withdrawn while the step counter was indicating 190 steps withdrawn.

An action statement was entered pursuant to TS 3. 1.3.2.c.

There had not been any rod movement in the previous hour.

Per the action statement, a flux map was performed by reactor engineering at approximately 4:00 p.m. to confirm actual rod position.

At approximately 4: 15 p.m.,

3 other rods in bank D were noted to have drifted to more than 12 steps above the group step counter.

With more than 1 full length rod potentially misaligned from the group step counter demand position by more than 12 steps, TS 3.0.3 was in effect which required that actions be initiated within

hour to bring the plant to hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

By this time, from the data obtained from the flux map, reactor engineering had concluded that all rods in bank 0 were at the position indicated on the step counter and that the RPI on the four rods had drifted due to the temperature sensitivity of the primary and secondary windings associated with the RPI system.

This is not an uncommon occurrence for most Westinghouse plants.

By approximately 4:22 p.m.,

I&C made allowed calibration adjustments such that all the bank D rods indicated actual rod position.

TS 3.0.3 was exited at 4:25 p.m.'s all rods were now appropriately indicating within 12 steps of the step counter.

A licensee perception existed that an entry into TS 3.0.3 by itself required a 1-hour notification pursuant to

CFR 50.72(b)(i)(A). 's a result, the,licensee conservatively made a

one-hour notification to the NRC.

This was later retracted as unit shutdown had not been initiated, and the report was not necessary.

The inspector responded to the control room, reviewed licensee activities associated with the event, and found them to be

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appropriate.

'Additionally, the inspectors discussed the notification aspects of entry into TS 3.0.3.

The licensee indicated that it will provide clarification in the notification procedures to indicate that entry into TS 3.0.3 is by itself not reportable per

CFR 50.72.

" 5.2.3. 'Auxiliary Building Laundry Room Fire At approximately 1:55 p.m.

on Harch 21, 1994, a fire started in a clothes dryer in the auxiliary building laundry room, and approximately 20% of one PC burned.

An HP employee working in the laundry room at the time smelled the smoke and opened'the dryer door.

The individual noticed that the dryer drum was not rotating and that the top PC was on fire.

The individual immediately turned the dryer off, obtained an extinguisher, and extinguished the fire.

The smoke in the laundry room actuated the smoke detectors, and the fire brigade responded within two minutes.

A clearance was issued on the dryer, and HP is having the vendor come to the site to inspect the dryer.

Based on the licensee's initial investigation, the preliminary cause of the fire was a mechanical failure of the dryer.

Apparently, the dryer drum had stopped rotating, and the heating coils -did not turn off.

When this occurred, the radiant heat eventually ignited the top PC.

The vendor's inspection of the dryer will complete the investigation and determination of the final cause.

When the fire was announced over the plant page, the NRC inspectors responded to both the auxiliary building laundry room

and the control room.

The inspectors also reviewed the licensee's preliminary fire incident report and condition report No.94-184.

Plant personnel appropriately responded and promptly extinguished the fire.

6.0 Maintenance Program, Support, and Observations (38702, 62700, 62703, and 93001)

6. 1 Inspection Scope Station maintenance activities of safety-related systems and components

'were observed and reviewed to ascertain they, were conducted in accordance with the TSs, approved procedures, and commitments to regulatory guides and industry codes and standards.

The following items were considered during this review, as appropriate:

LCOs were met while components or systems were

-= removed from service; approvals were obtained prior to initiating work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and repair records accurately reflected the maintenance performed; functional testing and/or calibrations were performed prior to returning components or systems to service; gC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; gC hold points were established and observed where required; fire prevention controls were implemented; outside contractor force activities were controlled in accordance with the approved gA program; and housekeeping was actively pursued.

6.2 Inspection Findings 6.2. 1 Maintenance Witnessed

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

repair of the Unit 4 PORVs and block valves, PWO Nos.

94000658 and 940005901 (Refer to section 6.2.4 for additional information.);

repair of the Unit 4 G-9 CRDM canopy seal, PC/M No. 94-28, and procedure TP-1044, Installation Procedure For Canopy Seal Clamp Assembly (Refer to section 6.2.5 for additional information.);

and repair of the Unit 4 N-5 seal table thimble, PC/M No.94-027.

(Refer to section 6.2.6 for additional information.)

6.2.2 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.

Maintenance Training and gualification The inspector reviewed the licensee's program for training and qualifying maintenance craft personnel.

The program is described in procedure O-ADM-714, Conduct of Maintenance Training, and in specific electrical, mechanical, and ILC program documents.

This training program includes formal initial training in the classroom and in various laboratories, on the job training, formal vendor classes, and continuing training.

Personnel achieve the qualification level o'f journeyman.

fach individual also receives specific training and performance evaluations using a job performance measurement system.

Specific job tasks for each of the disciplines are defined, and JPHs are then developed.

JPH evaluators assess task performance and, if appropriate, qualify individuals for that specific task.

This information is then assembled in a qualification matrix document for each discipline.

Only individuals who have documented training and qualification criteria satisfied (e.g.,

JPH completed successfully)

are all'owed

=- to work those specific job tasks.

Some tasks are considered

"skill of the trade" and, therefore, are not included within the matrix.

The inspector reviewed the training program procedures and documents, reviewed a sample of JPH files and individual training records, and reviewed each of maintenance discipline's qualification matrix.

In addition, the inspector interviewed training and maintenance department personnel'who are responsible for program implementation.

A tour of the training building including classrooms, laboratories, and files was performed.

The inspector concluded that the program appears sound and appropriate retrievable documentation exists.

The licensee has a very professional staff and complete classroom working laboratories.

The inspector also performed a review of maintenance activity implementation by reviewing historical work orders and completed procedures.

The inspector also reviewed current work in progress and previous NRC inspections that had examined this area.

The inspector checked to ensure that workers who performed the work as evidenced by work order/procedure signoff or by direct, in the field, observation were qualified as indicated by the qualification matrices.

NRC Inspection Report Nos. 50-250,251/93-20 and 94-02 also reviewed maintenance program implementation and did not identify any training or qualification program deficiencies.

No training or qualification effectiveness problems were noted during field observation The inspector noted that some tasks that were not specifically an

.item on the qualification matrix were performed by apprentices who were in a journeyman training program.

This work was done in 1992 and included activities such as battery surveillances, motor lubrications, switchgear thermography, and other breaker work in conjunction with operations personnel.

The -inspector reviewed these specific work orders and noted that the work was appropriately documented.

Further, the inspector did not identify any equipment performance issues.associated with these work activities.

The licensee's program did not preclude the use of trained and supervised apprentices (prior to formal journeyman qualification) to perform some safety-related work.

However, current practice and management philosophy require qualification completion prior to working on safety equipment.

The inspector discussed these items with maintenance and plant management personnel.

The inspector noted that most of the craft personnel are now journeyman qualified.

The inspector also reviewed gA inspections of maintenance programs and training/qualification issues.

The gA organization performed periodic surveillances of maintenance activities in the field.

This included a check of the qualification and training of individuals performing the work.

The inspector verified this by checking Surveillance Checklist PCS-I and a number of completed quality reports.

No adverse findings were identified relative to personnel qualification or training.

6.2.3 Recovery of Storm Damaged Materials and Warehouse Operations On August 24, 1992, Hurricane Andrew caused severe damage to both the central receiving facility and the issues warehouse.

The contents of both warehouses were exposed to rain, salt water, impact from debris, displacement from storage racks, submersion, and possible contact with unknown chemicals.

As a result, the licensee issued NCR No. N-92-0173 on September 5,

1992, in order to facilitate the evaluation of the continued use of spare parts and materials from both warehouses and to provide guidelines for the inspection and disposition of the subject materials.

The initial phases of the licensee's materials recovery process were inspected during October 1992 and were documented in NRC Inspection Report No. 50-250,251/92-26 dated November 10, 1992.

The licensee is currently in Phase II of the warehouse material recovery project which includes the various steps required to identify, evaluate, recover or replace, and restock affected items.

The licensee designed this process to maintain material traceability and to satisfy all nuclear and non-nuclear requirements imposed on the subject materials.

This process includes an item prescreen, material recovery group prescreen, recovery process, replacement process, obsolete item reviews, and gC final revie The item prescreen establishes the priorities required for continued operation based on time sensitivity and line item cost.

The items are physically located and storm effects are assessed.

In parallel to this, the task report is reviewed and updated concerning safety class and known IEEE, ASNE, ANSI, ISA, and NRC requirements to facilitate the recovery or replacement process.

The items are then tagged and restocked or staged for the material recovery group prescreen.

The material recovery group prescreen includes the determination of item obsolescence and recoverability and the performance of the economic decision concerning recovery versus replacement.

The first step of the recovery process is the determination to recover the items onsite or offsite.

Items to be recovered onsite are transferred to the materials recovery group facility (overflow building) where the appropriate recovery method is assigned.

The licensee utilizes a tracking system for all items that enter the recovery process in order to maintain unique item traceability and to generate a recovery report which documents,all processes, techniques, and tests performed on items that are important to safety.

Assignment of the appropriate recovery (cleaning)

method is determined by a test engineer and qualified technician.

The use of solvents during the cleaning process requires approval and written engineering justification by a material recovery group engineer on a line item by line item basis, and this justification is included in the item's recovery process report.

The item is cleaned using one of six cleaning methods and then dried.

If necessary, a protective coating is applied following the cleaning process.

The use of a protective coating also requires approval and written engineering justification by a material recovery group engineer on a line item by line item basis, and this justification is also included in the item's recovery process report.

Component testing is then performed by material recovery group technicians and engineers, and this testing is observed by gC inspectors as required.

At the completion of the recovery process, the recovery report provides documented evidence of all recovery, and test processes applied to the subject component.

This report establishes whether or not 'the subject items have been successfully restored to a condition which has made them acceptable for their originally intended end use.

The replacement process begins following the economic decision that the item replacement is the most cost effective process for maintaining the required usable inventory of the subject item.

The decision to replace immediately or to identify for reorder at a later time is determined upon the expected need of the subject item.

Obsolete items are of special concern to the licensee because they are both irreplaceable and necessary for plant operation.

Due to this special circumstance, an attempt is made for the recovery of obsolete items regardless of the items'os During the gC final step, the material is received either as new from the supplying vendor or as recovered material for the material recovery group.

The items are subject to the required inspection, testing, and documentation procedures and are then

,transferred to the warehouse facility for restocking.

The scope of this project includes approximately 54,000 HKS numbers.

(Each H&S number may include numerous items; i.e.

breakers or 1,000 bolts.)

The licensee has completed the prescreening process for approximately 40% of these items and approximately 28% of the items have been recovered to date.

This project is currently scheduled for completion by the end of 1995.

The inspectors toured the overflow building, the central receiving facility, the bubble tent, the outside storage area for items awaiting disposal, and'he issues warehouse (which included staging areas for a potential Unit 4 short notice work outage, the upcoming Unit 3 refueling outage, and specific PC/Ms) with the licensee's Nuclear Materials Manager.

The inspectors also reviewed NCR No. N-92-0173; the licensee's material recovery group project desktop procedure; the licensee's storm recovery procedure; Nuclear Assurance guality Control Technique Sheet 7. 11, Revision 2, Material Recovery of Storm Damaged Materials; procedure 01-2-PTN-3, Fluid System Cleanliness Control; a March 29, 1993, letter sent from the licensee to all bidders documenting the qualifications required for the mechanical, ISC, and electrical technicians and engineers needed for Phase II of the material recovery project; and some of the resumes submitted by the bidders.

In addition, the inspectors spot checked material traceability and reviewed the licensee's material recovery work practices.

The inspectors concluded that the licensee spare parts recovery program, processes, and procedures were very good.

Further, violations or deviations were not identified.

6.2.4 Unit 4 PORV Repairs During the Unit 4 forced outage, the licensee elected to repair a

leaking PORV (FCV-4-455C)

and to repack its corresponding block valve (HOV-4-535).

The leak was an internal seat leak.

The licensee performed the work per PWO Nos.

94000658 and 94005901, and procedures 0-PMM-041. 1, Reactor Coolant System PORV Overhaul, and 0-GMM-102. 1, Valve Repacking.

Maintenance personnel changed out the valve internals; however, no obvious failure or degradation was documented on the PWO.

Subsequent review by engineering identified'

.degraded flexatallic gasket which probably caused the seat leakage.

The inspector reviewed the work packages, PWOs, procedure, RWP, and other related documentation.

Post-maintenance testing included valve testing, leak checks at rated pressure, HOVATs, and remote position verification.

This testing was determined to be satisfactory, and the inspector concluded that mechanical and

electrical maintenance personnel appropriately performed these activities.

Upon returning the unit to service, operators noted that the redundant PORV (FCV-4-456)

was leaking as indicated by elevated tail pipe temperatures and increasing PRT temperature and pressure.

Based on this, the,licensee isolated the corresponding block valve (MOV-4-535).

Prior to the shutdown, PORV FCV-4-456 had not been leaking; however, it had been identified as a

potential leaking component on August 16, 1993, per deficiency tag No. T-93-181.

The inspector expressed concern that although the unit restarted with two operable PORVs and block valves, PORV FCV-4-456 began leaking again, Further, no obvious root cause for the PORV seat leaks was identified on the PWO.

The inspector discussed this issue with license management, and they indicated that they were reviewing this issue including plans for the Unit 3 PORVs during the upcoming refueling outage.

During subsequent discussions, the inspector was informed that all of the Unit 3 PORVs and block valves are currently scheduled for maintenance during the refueling outage.

The inspector noted that although one PORV was leaking and its block valve was closed, TSs were met; and the PORV could be used if required to relieve RCS pressure.

The inspector considered this issue unresolved pending the licensee's final determination of root cause for leaking PORVs and implementation of corrective actions.

This item will be tracked as URI 50-250,251/94-05-03, PORV Seat Leakage Root Cause and Corrective Action.

6.2.5 Uni.t 4 CROM Canopy Seal Leak and Repairs During the Unit 4 forced outage, the licensee noted indications of a through wall leak in the canopy seal weld area of the G-9 spare CRDM housing.

The licensee routinely inspects the RPV head area, including the CRDM and instrument penetrations for possible leaks during shutdown periods.

CROM (spare)

penetration G-9 had indications of boron deposits and a visual defect in the canopy seal weld area.

Based on these indications, the licensee

initiated actions to repair the defect and generated condition report No.94-157.

The licensee contacted a vendor and initiated plans to repair the defect with the use of a mechanical seal clamp assembly.

This type of repair had been performed at other PWRs and had been previously evaluated by the NRC as an acceptable repair method.

The canopy seal is not considered to be a pressure retaining device.

The reactor vessel pressure boundary is considered to be the mechanical fitting between the head penetration and the spare CROM housing.

The licensee classified this as a permanent repai The licensee developed PC/M No.94-028 and procedure TP-1044, Installation Procedure For Canopy Seal Clamp Assembly.

The licensee then proceeded to install, the clamp.

The work proceeded as planned during the period March 13-15, 1994, except for a minor spill of hydraulic fluid from the installation tool.

The licensee initiated actions to clean the small amount of oil and, as a

precaution, removed the clamp assembly to ensure there was no ill effect.

The inspectors reviewed the repair activities including the following:

reviewed condition report No.94-157; observed a video of the G-9 spare CRDH canopy seal inspection; I

reviewed PC/M No.94-028; reviewed the installation in the containment per procedure TP-1044'iscussed the repair with maintenance, engineering,

'anagement, and contractor personnel; and reviewed HP coverage of the work included the RWP.

The inspectors concluded that the licensee appropriately repaired

.

the canopy seal leak.

The inspectors did not identify any deficiencies relative to the procedural controls nor installation activities.

Further, the inspectors noted that the work coordination among all involved groups was very good.

6.2.6 Unit 4 Incore Instrument Guide Tube Leak and Repairs On Harch 9, 1994, an RCS pressure boundary leakage through an incore instrument guide tube at the seal table on Unit 4 was identified during a quarterly visual leak inspection.

The leak was not quantifiable, however, a 1/4-inch long by 1/8-inch diameter buildup of boric acid was observed.

The leak was on a

0.86-inch OD, 1/8-inch thick, ASTH A-213 304, stainless steel portion of N-5 guide tube just above the seal table and just below a welded fitting adapter.

Initial inspection of the leak area identified an approximate 1/4-inch linear indication within the heat-affected zone of the guide tube fitting socket weld.

A preliminary liquid penetrant examination confirmed the existence of the linear indication.

Based on the appearance of the leak and previous experience, the licensee postulated that the through-wall leak defect was due to transgranular stress corrosion cracking.

A final metallurgical analysis will be completed after removal of the defective tub The unit was brought to cold shutdown, the reactor was depressurized, and pressurizer level was maintained at approximately 80% to accommodate repairs on the guide tube.

A PC/H (No.94-027)

was performed to repair the leak.

The PC/H involved repairs that resulted in a configuration equivalent to the existing design.

All materials, welds, and fittings were identical.

The bottom of the seal table is the same elevation as the reactor vessel flange.. Draindown of the RCS to below the flange level was avoided by establishing a freeze seal plug on the affected guide tube.'he contingency for the freeze plug failure included the availability of a second freeze seal and a high pressure fitting sized 5/16 inches by 3/4 inches that was kept at the job site.

This high pressure fitting would be installed on the thimble tube in the event of the freeze seal failure.

On Harch 13, 1994, the guide tube was circumferentially cut to ensure removal of all possible indications.

.The fitting was subsequentially rewelded to the guide tube stub.

The only design change was a slight (approximately two to three inches)

reduction in the length of the guide tube extending above the top of the seal table surface.

The thimble tube was also shortened by an equivalent amount; therefore, this had no impact on the capability of the flux mapping system.

Following completion of the guide tube cutout and rewelding, the low pressure seal was installed, and the freeze seal was subsequently released.

The low pressure seal was capable of withstanding pressure for current plant conditions which included a vented RCS with pressurizer level at approximately 80%.

The licensee then commenced reassembly of the high pressure seal.

However, construction personnel performing the repairs installed a 'wrong fitting.

There were two sets of high pressure fittings at the work location.

One was the replacement fitting and the other a contingency fitting which had a ferrule which was sized 1/8 inch smaller.

The fitting with the.smaller ferrule was the contingency for freeze seal failure.

The fitting with the smaller ferrule was mistakenly installed as it was not clearly labeled as to which was the contingency fitting and which was the replacement fitting.

The wrong fitting had to be removed, and the correct fitting was reinstalled.

Construction initially estimated that the correct fitting would be installed in approximately five to six hours.

However,-the process took approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

The delays associated with this rework as well as the exact nature of the rework were not properly communicated to the short notice outage scheduling group, plant management, or the control room.

Consequently, the general impression among plant staff was that the repair job was essentially complete and that cleanup associated with the repair was all that was left.

This was discussed in the 2:30 p,m outage meeting on Harch 13, 199 Based on the discussion in the outage meeting and the assumption that the repairs had been completed except for some cleanup, the Unit 4 ANPS gave instructions to initiate RCS fill and vent activities in preparation for RCP runs.

Consequently, RCS fill and vent activities including charging pump operation, RCS heatup and pressurization, and 10 minute RCP starts were performed between 4:00 p.m.

and 7:45 p.m.

The RCS was pressurized to approximately 325 psig without the high pressure fitting installed.

The increase in RCS pressure caused the thimble tube to move out approximately 10 to 12 feet.

The thimble tube was re-inserted, and the high pressure fitting was tightened and the installation signed off as complete at approximately 8:40 p.m.

The consequences of the thimble tube moving out were minor.

Minimal RCS water leaked out as the low pressure seal was still in place.

Additionally, the radiation levels of the portion of the exposed tube at the seal table area were low.

Appropriate radiological controls were in place to prevent inadvertent access into the reactor sump area which had the potential for having higher radiat,ion levels.

This event highlighted a weakness in the work control process that allowed RCS pressurization and heatup without the high pressure fitting installed.

Under normal circumstances, work on any system is performed under a clearance and associated tagouts.

The completion of the work and the control room awareness of the completion is controlled through the clearance signoffs.

In this case, since the guide tube was not an isolable component (i.e.

no provision to tag out a valve or a breaker),

a clearance did not exist for the job.

The job was controlled by the PWO alone without positive feedback to the control room.

This caused the control room operators to initiate an evolution based only on verbally communicated status of the job.

Since communications associated with the status of the guide tube repairs were poor, the RCS was pressurized without the high pressure fitting installed.

Additionally, the lack of proper labeling distinguishing the contingency fitting from the replacement fitting,also contributed to the problem.

This lack of proper labeling could have slowed the contingency efforts had the freeze seal fa'iled.

As a result of this event, gA as well as the technical department initiated independent investigations.

As immediate corrective actions, the licensee implemented a change to the fill and vent procedure to require a management signoff from all disciplines prior to initiating RCS fill and vent.

Additionally, the licensee will modify the existing clearance process to issue information clearances on systems that cannot be physically isolated and tagged out-of-service with a clearanc Post-maintenance testing included a visual inspection by ISI of the N-5 guide tube, the remaining guide tubes, and the seal table.

The ISI was performed during unit startup with the RCS pressure at 2280 psig.

No pressure boundary through wall leaks were observed.

In addition, the licensee increased the visual surveillance frequency of the seal table area on both units from quarterly to once every six weeks until the completion of the metallurgical evaluation of the N-5 guide tube is completed.

The inspector concluded that the quarterly visual inspection of the seal table and guide tubes that identified the leak and the conservative decision to shut down the unit was considered to be a

strength.

However, a weakness was noted in the work control process as well as in the control of the contingency fitting.

The investigations performed by the licensee associated with the problems were also determined to be prompt and thorough.

The corrective actions, both completed and planned, appear effective in preventing future similar incidents.

Engineering involvement associated with the development of the PC/H was strong.

The inspectors will closely monitor similar future licensee activities to gauge the effectiveness of the corrective actions as a result of this event.

r 7. 0 Surveillance Observations (61726)

7.1 7.2 7.2.1 Inspection Scope The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TSs; testing was performed in accordance with adequate procedures; test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate.

For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.

Inspection Findings Tests Observed The inspectors witnessed/reviewed portions of the following test

activities:

procedure 3-OSP-23. 1, 3A EDG Operability Test; procedure 4-OSP-41. 17, RCS Pressure Boundary Leak Test; and procedure 4-0SP-051.3, Containment Air Lock Pressure Tes The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the TSs.

7.2.2 Spent Fuel Pool Boroflex Surveillance The inspector reviewed the results of the neutron absorption tests (also known as blackness tests)

that were performed in selected cells of the Unit 3 spent fuel storage racks (Refer to section 7.2.2 of NRC Inspection Report No. 50-250,251/93-22).

The blackness tests were performed to confirm the presence and integrity of the Boroflex neutron absorber material that is used in the spent fuel pool for criticality control.

Boroflex assures a shutdown margin of 5% with no boron in the spent fuel pool.

The spent fuel pool is normally maintained at greater than 1950 ppm boron.

Some plants have experienced Boroflex degradation including gaps and shrinkage in the aqueous and gamma radiation environment of the spent fuel pool.

The blackness test on the Unit 3 spent fuel pool was performed in December 1993.

A total of 80 full length panels were examined during the test.

Of these, 30 panels were determined to not have any shrinkage.

An average of approximately one gap per panel was noted with an average shrinkage size of approximately 0.65%.

. Additionally, the test showed. that the gaps appeared to be randomly distributed at all elevations.,

Turkey Point has performed a criticality analysis showing that shutdown margin is maintained even if two-inch gaps exist in every panel at exactly the same location.

This analysis does not take credit for the boron concentration in the spent fuel pool.

Additionally, EPRI has demonstrated that a random distribution of small gaps has small impact on the criticality analysis.

The licensee currently plans to perform blackness testing every five years.

In addition, Turkey Point performs an in-service coupon surveillance to determine Boroflex presence and degradation.

However, the licensee plans to eliminate the coupon surveillance program as the blackness test provides more useful information pertaining to boroflex gradation.

While no criticality issues exist now, the inspectors will continue to monitor the results of future blackness tests.

8.0 Onsite Followup and In-Office Review of Written Reports (90712, 90713, 92700, and 92701)

8.1 Inspection Scope The reports discussed below were reviewed.

The inspectors verified that reporting requirements'had been met, root cause analysis was performed, corrective actions appeared appropriate,

20'.2 8.2.1 8.2.2 8.2.3 8.2.4 and generic applicability had been considered.

Additionally, the inspectors. verified the licensee had reviewed each event, corrective actions were implemented, responsibility for-corrective actions not fully completed was clearly assigned, safety questions had been evaluated and resolved, and violations of regulations or TS conditions had been identified.

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

Inspection Findings Honthly Operating Report The inspectors reviewed the February 1994 Honthly Operating Report and determined it to be complete and accurate.

Annual Radiation Exposure Report The inspectors reviewed the Turkey Point annual radiation exposure report for 1993 dated February 28, 1994, Total site whole body exposure was reported as 275 person-rem.

The inspector had no questions.

3B EDG Failure Special Report The inspectors reviewed the Special Report dated Harch 18, 1994, associated with the failure of the 3B EDG that occurred on November 18, 1992.

The failure involved the EDG output breaker which did not close while manually attempting to load the running EDG to the 4-KV bus.

The licensee attributed the failure to a bent charge-discharge indicator which restricted movement of the closing trip latch mechanism.

The indicator was straightened and the breaker was satisfactorily tested.

The licensee had failed to report this failure as required by TS 4.8. 1. 1.3.

This issue was identified by a region based inspector and is discussed as NCV 50-250,251/94-02-01 in NRC Inspection Report No.

50-250,251/94-02 dated Harch 18, 1994.

The inspector reviewed this special report and concluded it to be accurate.

(Closed)

LER 50-251/92-005, Fire Watch Not Haintained in Accordance with Technical Specifications At the time of this-event, the plant was in the process of recovering from the damage caused by Hurricane Andrew which occurred August 24, 1992.

Unit 4 was in Hode 5, and the licensee was in the process of switching the Unit 4 safeguards busses from offsite to onsite power with both EDGs running.

(Off-site power was available.)

In addition, the fire suppression spray/sprinkler system in the Unit 4 EDG building was inoperable due to hurricane damage.

With the loss of the fire suppression spray and/or sprinkler system, action statement a of TS 3.7.8.2 required that a

continuous fire w'atch be in place with backup fire suppression

equipment.

However, from approximately 11:30 p.m.

on September 2,

1992, until about 12: 13 p.m.

on September 3,

1992, the assigned fire watch left,the designated fire watch location on several occasions and performed the watch as if it were a short duration roving fire watch.

The licensee concluded that the root cause of this event was attributed to personnel error.

The individual involved in this incident was newly trained and was not normally assigned to this duty.

The fire watch was told during training that a relief would be provided approximately each hour.

However, the watch was not relieved in this case for approximately six hours.

As a r'esult, during the time frame noted above, the watch was moving in and out of the Unit 4 EDG building seeking relief.

During this event, the fire watch was in place intermittently for a period of about 60 minutes.

Fire extinguishers were in place as required for the use of fire response personnel; and a fire brigade was in place at all times prior. to, during, and after the hurricane.

Diesel driven pumps wer e also available around the site for use as a dedicated source of fire suppression using salt water sources.

Therefore, the licensee concluded that the health and safety of plant personnel and the general public were not compromised.

As a result of this event, the fire watch involved was relieved of watch-standing duties in the Unit 4 EDG building and was re-instructed on the correct method of performing fire watches:

The licensee also disciplined the on-shift fire watch supervisor responsible for the fire watches at the time of this event.

A meeting was held with all fire watch supervision to emphasize the need to relieve personnel on a timely basis and to provide specific instructions to each fire watch stander as to the correct method'f performing the assigned fire watches.

In addition, on October 15, 1992, the licensee issued standing orders to all watch standers providing specific written instructions on what to do in case of a fire and what to do in case of the need for watch relief.

These standing orders were required to be carried by the fire watch standers..

The licensee also documented this event in a condition. report.

The inspector reviewed portions of the condition report and verified that the fire watch assignment sheet contained specific instructions for watch relief.

The licensee's corrective actions were appropriate and effective.

The inspector concluded that this event had minimal safety significance, and therefore, this item is close.2.5 (Closed)

LER 50-250/94-001, Failure of Emergency Containment Cooler Component Cooling Water Discharge Solenoid Valve This 'voluntary LER was submitted by the licensee due to sever'al failures of solenoid valves associated with the CCW to ECC system.

The solenoid valves were ASCO model NPL83442B2E direct-acting 4-way valves with factory-applied Nyogel-775A lubricant.

The issue associated with these ECC solenoid valves is currently being tracked under IFI 50-250,251/93-26-01, ECC Valve Failures.

The inspector reviewed the LER and concluded it to be accurate and completed.

Based on this, the LER is closed.

8.2.6 (Closed)

LER 50-251/94-001, Hissed Surveillance on Steam Generator Protection Channel The licensee discovered on February 23, 1994, that Unit 4 TS required Analog Channel Operational Test had not been performed within the required surveillance interval.

The surveillances were in progress at the time of. discovery and were later successfully completed on February 23, 1994.

The root cause was determined to be a procedural surveillance scheduling error.

This issue including corrective actions was identified in a previous NRC Inspection Report as NCV 50-250,251/94-03-04, Missed TS Required Steam Generator Protection Surveillance.

The inspector reviewed the LER and determined it to be appropriate.

Therefore, this LER is closed.

9.0 Unit 3 Refueling Preparations (30702 and 60705)

9. 1 Inspection Scope Unit 3 is scheduled for a 46-day refueling outage during the period April 4 to Hay 21, 1994.

The inspectors reviewed the licensee's preparation for refueling and outage activities.

This included the following:

fuel movement procedures and fuel receipt; outage schedule, critical path, and goals; PC/H scope; major maintenance and testing activities; plant conditions and mode changes; core offload/reload activities; RPV draindown;

outage risk assessment; control of contractors and temporary employees; shift director schedules and functions; plant manager briefings; and licensee commitments and TSs.

9.2 Inspection Findings The inspectors reviewed in detail.administrative procedure

.0-ADM-051, Outage Risk Assessment and Control.

This procedure provides recommended equipment to be maintained operable or available during shutdown conditions for decay heat removal, inventory control, power availability, reactivity control, containment integrity control, instrumentation, and fire protection.

In addition, the inspectors discussed this process with licensee plant, outage, and engineering management personnel.

The licensee establishes a Risk Assessment Team and leader whose function is to review schedule, key shutdown 'functions, and key equipment availability.

The inspector concluded that the licensee is appropriately prepared for the Unit 3 refueling outage.

The risk assessment process appears effective.

However, the inspector noted that although the spent fuel pool cooling system is addressed in the procedure, the procedure checklists (enclosures)

only apply to reactor decay heat 'removal.

These enclosures are the documents which the licensee uses to assure minimum required equipment availability.

The inspector discussed this specific item with licensee personnel.

The inspectors also noted that the plant manager met with all site personnel to discuss the outage scope, goals, and safety focus.

The inspectors concluded that this activity was very positive and demonstrated strong management oversight and commitment to safety.

A good practice noted was the use of a handout outage book given to each employee.

This book includes important outage facts and other pertinent information.

A meeting to discuss the outage was held in Region II on March 15, 1994.

The licensee's slides and meeting summary will be issued by another NRC document.

10.0 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 March 29, 1994.

The areas

requiring management attention were reviewed.

The licensee did not identify as proprietary any of the materials provided to or reviewed by

. the inspectors during this inspection.

,Dissenting comments were not received from the licensee.

The following new items were discussed:

Item Number Status Descri tion and Reference 50-250,251/94-05-01 50-250,251/94-05-02 (Closed)

.NCV - Non-Licensed Operator Exceeded Overtime Limit (section 4.2.1).

(Open)

IFI - Administrative Procedures Upgrade (section 4.2.3).

(Open)

URI -

PORV Seat Leakage Root Cause and Corrective'ction (section 6.2.4).

Additionally, the following previous items were discussed:

Item Number 50-251/92-005 50-250/94-001 50-251/94-001 Status Descri tion.

and Reference (Closed)

LER - Fire Watch Not Maintained in Accordance with Technical Specifications (section 8.2.4).

(Closed)

LER - Failure of Emergency Containment Cooler Component Cooling Water Discharge Solenoid Valve (section 8.2.5).

(Closed)

LER - Missed Surveillance on Steam Generator Protection Channel (section 8.2.6).

11.0 Acronyms and Abbreviations ADH ANPS ANSI AP ASCO ASHE ASTH CCW CFR CRDH ECC EDG EPRI FCV FPL GA GMM HP ILC Administrative Assistant Nuclear Plant Supervisor American National Standards Institute Administrative Procedure Automatic Switch Company American Society of Mechanical Engineers American Society of Testing Haterials Component Cooling Water Code of Federal Regulations Control Rod Drive Mechanism Emergency Containment Cooler Emergency Diesel Generator Electrical Power Research Institute Flow Control Valve Florida Power and Light Georgia General Maintenance

- Hechanical Health Physics Instrumentation and Control

e

IEEE IFI ISA ISI JPN JPH KV LCO LER H&S HOV HOVATS N/A NCR NCV NPS NRC NWE OD OSP PC PC/H PMH PORV ppm PRT Pslg PTN PWO PWR QA QC QCS QI RCP RCS rem RPI RPV RWP SENP T

TP TS UFSAR URI Institute of Electrical and Electronics Engineers Inspector Followup Item Instrument Society of America Inservice Inspection Juno Project Nuclear Job Performance Measurement Kilovolt Limiting Condition for Operation Licensee Event Report Materials and Supplies Motor Operated Valve HOV Acceptance Testing System Not Applicable Non-Conformance Report Non-Cited Violation Nuclear Plant Supervisor Nuclear Regulatory Commission Nuclear Watch Engineer Outside Diameter Operations Surveillance Procedure Protective Clothing

. Plant Change/Modification Preventive Maintenance

- Hechanical Power Operated Relief Valve

.Parts Per Million Pressurizer Relief Tank Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Pressurized Water Reactor Quality Assurance Quality Control Quality Control Surveillance Quality Instruction Reactor Coolant Pump Reactor Coolant System Roentgen Equivalent Man Rod Position Indication Reactor Pressure Vessel Radiation Work Permit Safety Evaluation Nuclear

- Plant Tag Temporary Procedure Technical Specification Updated Final Safety Analysis Report Unresolved Item