IR 05000250/1994020

Insp Repts 50-250/94-20 & 50-251/94-20 on 941001-29.No Violations Noted.Major Areas Inspected:Plant Operations Including Operational Safety Plant Events,Maint Including Surveillance Observations & Fire Protection

ML17352A915
Person / Time
Site:	Turkey Point
Issue date:	11/10/1994
From:	Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352A913	List: IR 05000250/1994020 ML17352A911
References
50-250-94-20, 50-251-94-20, NUDOCS 9411290013
Download: ML17352A915 (56)

Text

~S REogg UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/94-20 and 50-251/94-20 Licensee:

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

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspection Conducted:

October 1 through 29, 1994 Inspectors:

T.

P.

Jo nson, Senio Resident Inspector Date Si ned B.

B. Desai, Resid t Inspector Date Si ned t

L. Trocine, Resid t Inspector Accompanied by:

J.

F-King, em, Office of Approved by:

K. D. Landi

, Chief Reactor Projects Section

Division of Reactor Projects Da e Signed Nuclear Reactor Regulation A'g Dat Signed SUMMARY Scope:

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

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

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

9'4ii2900i3 94iiiO PDR ADQCK 05000250

PDR

'

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

The inspectors did not identify any regulatory compliance issues.

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

Plant 0 erations The Unit 4 shutdown and cooldown activities were well performed and safely conducted (section 4.2. 1).

The licensee's decision to complete Unit 4 core offload prior to entering reduced inventory and midloop operations was conservative and proactive in reducing risk.

Licensee actions to drain the reactor coolant system to 1.5 feet below the reactor vessel head flange were also effectively conducted with good procedural compliance and with strong oversight (section 4.2.2).

Unit 4 core alterations were noteworthy; and communication, teamwork, quality assurance involvement, training, and procedural compliance were strong (section 4.2.3).

Strong management as well as line and quality assurance oversight was provided during the Unit 4 refueling outage.

Risk assessment activities demonstrated positive nuclear safety (section 4.2.4).

Licensee management's response to an operations-initiated, non-conservative, but allowed condition for auxiliary feedwater demonstrated a strong sense of reactor safety (section 4.2.5).

Poor worker controls in the area of the heater drain tank level devices caused a trip of a heater drain pump and a transient for Unit 3.

Operator response to this transient was strong (section 4.2.6).

A meeting with local public officials was beneficial in introducing key licensee and Nuclear Regulatory Commission personnel to them as well as furnishing a forum for providing a status of the facility, getting feedback from county representatives, and providing answers to various questions (section 4.2.7).

The inspectors attended a Company Nuclear Review Board meeting and concluded that this offsite safety committee was effective (section 4.2.8).

Maintenance Inspector observed station maintenance and surveillance testing activities were completed in a professional and competent manner (sections 5.2. 1 and 5.2.2).

Unit 4 reactor vessel disassembly activities were performed in a well controlled manner with strong interdepartmental teamwork (section 5.2.3).

The licensee was very responsive to noted minor deficiencies in the containment coatings program (section 5.2.4).

Motor-operated valve related activities were satisfactorily performed with good coordination support from the system engineer (section 5.2.5).

The 4A and 4B emergency diesel generator 18-month preventive maintenance activities were satisfactorily completed with good support by the engineering, maintenance, and quality assurance groups (section 5.2.6).

The Unit 4 reactor cavity seal installation was

satisfactory as evidenced by leakrate data, and therefore, an inspector followup item was closed.

However, the inspectors noted minor deficiencies in related operating and maintenance procedures (section 5.2.7).

Unit 4 local leak rate testing activities were well planned, coordinated, and executed with strong involvement on the part of the inservice testing coordinator (section 5.2.8).

The licensee was proactive in pursuing a

CFR Part 21 issue relative to the auxiliary feedwater system; and troubleshooting activities following an overspeed mechanical trip were adequately performed (section 5.2.9).

En ineerin An issue with a potential for a core recriticality following an accident was acted upon in a timely manner, and the approach to resolve it conformed to the recommendations made by Westinghouse (section 6.2.1).

Plant changes and modifications performed during the Unit 4 refueling outage were appropriately performed.

Strong teamwork was noted during the design, review, implementation, testing, turnover, and documentation activities for the performance of these modifications (sections 6.2.2 through 6.2. 12).

The monthly operating report was satisfactory (section 6.2. 13).

Two licensee events reports were reviewed, determined to be appropri ate, and closed (sections 6.2. 14 and 6.2. 15).

Plant Su ort Chemistry and corporate engineering support personnel were effectively involved in steam generator outage-related activities.

A strong secondary chemistry program has resulted in no pluggable steam generator tubes for the current Unit 4 refueling outage (section 7.2. 1).

Unit 4 containment cleanliness and housekeeping were generally acceptable.

The air conditioned environment improved worker attitude and proficiency (section 7.2.2).

The licensee established a proactive approach to inadvertent fire protection deluge actuations (section 7.2.3).

The licensee appropriately responded to two externally caused personnel contamination events and a plant event which resulted in a skin dose.

Overall, the number of personnel contamination events has decreased since the last refueling outage (section 7.2.4).

The licensee took appropriate actions for a crane within the security fence isolation zone (section 7.2.5).

TABLE OF CONTENTS 1.0 Persons Contacted

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1.1 1.2 1.3 1.4 Licensee Employees.............

NRC Resident Inspectors........

Other NRC Personnel On Site....

Other Non-NRC Personnel On Site

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2.0 Other NRC Inspections Performed During This Period.............

3.0 Plant Status..................

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3.1 Unit 3 3.2 Unit 4....

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.0 Plant Operations...............................................

4.1 Inspection Scope.....

4.2 Inspection Findings..

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5..0 maintenance....................................................

5.1 Inspection Scope.....

5.2 Inspection Findings..

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6.2 Inspection Findings..

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7..0 Plant Support........................................;........

7. 1 Inspection Scope 7.2 Inspection Findings..

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8..0 Exit Interviews...............................................

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

1.0 Persons Contacted REPORT DETAILS 1.1 Licensee Employees T. V. Abbatiello, Site guality Manager R. J. Acosta, Company Nuclear Review Board Chairman C.

R. Bible, Acting Site Engineering Manager W. H. Bohlke, Vice President, Engineering and Licensing M. J. Bowskill, Reactor Engineering Supervisor S.

H. Franzone, Instrumentation and Controls Maintenance Supervisor J.

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

H. Goldberg, President, Nuclear Division R. Golden, Corporate Communications R.

G. Heisterman, Mechanical Hai'ntenance Supervisor P.

C. Higgins, Outage Manager G.

E. Hollinger, Training Manager D.

E. Jernigan, Operations Manager H. H. Johnson, Operations Supervisor H. D. Jurmain, Site Construction 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 F.

E. Harcussen, Security Supervisor H.

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

W. Pearce, Plant General Manager H. 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 craftsmen, 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 B. A. Boger, Acting Director, Division of Reactor Projects, Region II K. H. Clark, Public Affairs, Region II

+ R.

P. Croteau, Project Manager, Project Directorate II-2, Office of Nuclear Reactor Regulation

+ S.

D. Ebneter, Regional Administrator, Region II

• J.

F. King, Intern, Office of Nuclear Reactor Regulation

R.

P. Schin, Project Engineer, Region II

+ D. H. Verrell'i, Chief, Reactor Projects Branch 2, Division of Reactor Projects, Region II 1.4 Other Non-NRC Personnel On Site

+ P. Godfrey, Representative, Metro-Date Office of Emergency Management

+ L. Servais, Radiological Emergency Preparedness Coordinator/Planner, Monroe County Office of Emergency Management.

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Attended meeting with local officials on October 6, 1994 (Refer to section 4.2.7 for additional information.)

• Attended exit interview on October 31, 1994 (Refer to section 8.0 for additional information.)

Note:

An alphabetical tabulation of acronyms used in this report is t

listed in section 9.0 of this report.

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

Dates Area Ins ected 50-250,251/94-19 50-250,251/94-21 3.0 Plant Status 3.1 Unit 3 October 3-7, 1994 October 17-21, 1994 Health Physics Inspection Inservice Inspection, Steam Generator Tube Inspection, and Erosion/Corrosion Inspection At the beginning of this reporting period, Unit 3 was operating at or near full reactor power and had been on line since May 27, 1994.

The unit continued to operate at power throughout this inspection period.

3.2 Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near full reactor power and had been on line since September 24, 1994.

The Unit was shut down on October 3, 1994, to begin the Cycle 15 refueling outage.

The outage continued through this

inspection period, and the unit was in Mode 5 at the end of the period.

4.0 Plant Operations (40500, 60710, 71707, and 93702)

4.1 4.2 4.2.1 Inspection Scope The inspectors verified that the licensee operated the facilities safely and in conformance with regulatory requirements.

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

The inspectors also 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.

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

Inspection Findings Unit 4 Shutdown and Cooldown The licensee commenced power reduction for the Unit 4 refueling outage at 12:01 a.m.,

on October 2, 1994.

At 12:01 a.m.

on October 3, 1994, the generator output breakers were opened, and operators shut down the reactor, entering Node 3 at 12:45 a.m.

Subsequent testing and cooldown activities were performed, and the unit entered Node 4 at 5:30 p.m.

on October 3, 1994, and Mode 5 at 1:30 a.m.

on October 4, 1994.

Node 6 was entered at 1:00 p.m.

on October 6, 1994, when the licensee commenced reactor vessel head stud detensioning.

Node 5 was re-entered at 6:00 p.m.

on October 29, 1994.

The inspectors observed portions of the shutdown, cooldown, and related testing activities.

The inspectors verified that these evolutions were performed in accordance with approved procedures, that appropriate oversight was present, and that technical specification requirements were followed.

Overall, observed activities were well performed and safely conducted.

The inspectors did not identify any violation i i

4.2.2 Unit 4 Reactor Coolant System Draindown In order to support Unit 4 defueling activities, the licensee was required to drain the RCS to a level 1.5 feet below the RPV flange.

This did not meet the conditions as defined by reduced inventory or midloop operation (less than 3.0 feet below the RPV flange).

However, the inspectors reviewed the following documents:

Generic Letter No. 88-17, Loss of Decay Heat Removal, and the licensee's responses to this generic letter; operating procedures 4-0P-041.7, Draining the Reactor Coolant System; 4-0P-041.9, Reduced Inventory Operations; and 4-0P-201, Filling/Draining the Refueling Cavity and the SFP Transfer Canal; abnormal operating procedure 4-0NOP-050, Loss of RHR; surveillance procedures 4-0SP-051.14, Reduced Inventory Containment Penetration Alignment Verification; and 4-OSP-201.1, RCO Daily Logs; various plant drawings; training lesson plans and system description No. 007, Reactor Coolant System; control room log books; and refueling outage schedules.

Prior to the draindown evolution, the licensee conducted special briefings as required by procedure O-ADN-217, Conduct of Infrequently Performed Tests or Evolutions.

The licensee performed the RCS draindown on October 5, 1994.

Level was maintained at approximately 50% on LI-6421 and LI-6423 and at

feet 7 inches on LI-6422.

This corresponded to about 1.5 feet below the RPV flange.

The inspectors verified that redundant RCS level indication was available and was being monitored by control room operators.

Level devices LI-6421 and LI-6423 provided remote readout in the control room, and a tygon level tube (level device LI-6422)

provided local indication in the containment.

The inspectors verified that these devices were available, being used, and recorded accordingly and that they indicated within their allowable tolerances.

The inspectors did note that the tygon tubes used for LI-6422 were not conspicuously marked nor completely protected.

This issue was brought to the licensee's attention and corrective measures were take.2.3 During the last Unit 3 refueling outage, the inspectors noted that once a steady RCS level was obtained, no further readings were obtained from level device LI-6422 (containment tygon tube).

Although this was in accordance with licensee procedures at the time, the licensee modified the requirements such that a once per 8-hour shift reading of level device LI-6422 was taken and documented.

The inspectors verified that this requirement was incorporated into the current Unit 4 procedures.

The inspectors concluded that the licensee was proactive in reducing risk and demonstrated conservatism in its decision to complete core offload prior to entering reduced inventory and midloop operations for RCP and steam generator work.

Further, licensee actions to drain the RCS to 1.5 feet below the flange were effectively conducted with good procedural compliance and with strong oversight.

Unit 4 Core Offload and Reload The Unit 4 reactor core was completely offloaded into the SFP during the period October 10-13,'994.

The licensee implemented procedure 4-0P-040.2, Refueling Core Shuffle and TP-llll, Unit 4 Cycle 14 Core Offload.

Procedures 4-OP-038. 1, Preparations For Refueling Activities, and 4-0P-038.9, Refueling Activities Check Off List, were used to ensure that prerequisites, precautions, limitations, and guidance were appropriate for core alteration activities.

During the period October 21-25, 1994, the licensee reloaded the reactor core for Cycle 15.

This was done per procedure TP-1113, Unit 4 Cycle 15 Core Reload.

During the reload, the licensee experienced a few assemblies which were moderately bowed.

This required extra time and a number of fuel assembly move deviations.

The inspectors verified that these deviations were performed per procedure 4-0P-040.2, Attachment 2.

Hinor equipment problems occurred during both the offload and the reload.

These were associated with the manipulator crane, the SFP bridge, and the transfer cart.

The licensee initiated immediate repairs to the affected equipment, developed an action plan, and assembled a team together to address longer-term actions.

The inspectors reviewed the above mentioned procedures, refueling, technical specifications, operating procedures for each refueling station, condition reports associated with equipment problems, and operating and reactor engineering logs.

The inspectors witnessed portions of the Unit 4 refueling activities from the following locations:

RCO station in the control room; reactor engineer station in the control room;

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RCO, SRO, and vendor stations on the manipulator bridge; containment upender and transfer cart station; SFP upender and transfer cart station, and RCO station on the SFP bridge.

The inspectors noted that communications were formal, teamwork was effective, and procedure usage and compliance was strong.

Overall, core offload activities were professionally performed even with several equipment breakdowns.

The inspectors noted that gA was involved in monitoring these refueling activities.

Their findings and observations were appropriately documented.

The inspectors also noted a good practice that assured personnel were trained and qualified in using refueling equipment.

Prior to using refueling equipment, an individual was required to read the procedures and system descriptions and either have operated the equipment within the last two refueling outages or be given a

checkout on the equipment by a qualified individual.

The status of this qualification was maintained in a log book in the control room.

4.2.4 Unit 4 Refueling Outage Oversight The inspectors reviewed the licensee controls and oversight in effect during the Unit 4 outage.

This included the implementation of administrative procedure O-ADM-051, Outage Risk Assessment and Control.

This ADH required a risk assessment team to review the refueling schedule, switchyard work, higher risk evolutions, and key safe-shutdown functions and to maintain a risk information notebook.

The team was comprised of engineering, outage, operations, and maintenance personnel.

Ninimum required equipment was addressed in the ADN enclosures.

The inspectors verified that important equipment was maintained operable or available as necessary.

During one risk team meeting, the team concluded that plans to remove the 4D and 4C bus at the same time was not appropriate even though it would have been allowed by the technical specifications.

This was due to a potential simultaneous loss of the 4D station blackout feed bus tie and the blackstart diesel feed to the 4C bus.

The inspectors noted this to be a positive demonstration of nuclear safety and risk management.

The inspectors noted that the licensee assigned shift directors to cover the outage around the clock.

Senior plant personnel and department managers were assigned this shift direction function.

These shift directors provided oversight and maintained status of the refueling outage activities.

They also conducted the periodic outage meetings.

The inspectors noted that these shift directors were involved in the field and directly involved in containment activitie.2.5 The inspectors noted that gA personnel were involved in outage activities including core offload and reload (Refer to section 4.2.3 for additional information.), core verification, containment tours, EDG maintenance (Refer to section 5.2.6 for additional information.)

and PC/H implementation.

gA findings were discussed with the appropriate personnel and were documented in gA audit and surveillance reports.

Control room oversight was strengthened during the outages.

The operating shifts were modified from a six shift to a four shift rotation.

This provided extra NPSs and ANPSs on each shift to provide SRO coverage for refueling and other outage-related activities.

Further, operations'anagement provided additional oversight for key refueling activities, e.g.,

draindown, core alterations, etc.

Unit 3 Auxiliary Feedwater Technical Specification Issues The B AFW pump turbine failed during testing on October 17, 1994 (Refer to section 5.2.9 for additional information.),

due to an overspeed trip mechanical device malfunction.

The licensee entered a 30-day action statement as required by Technical Specification 3.7. 1.2, action statement 3.

Subsequently, on October 19, 1994, the operating shift removed the Unit 3 train

AFW FCVs from service to repair an air leak associated 'with a Unit 4 modification.

This placed Unit 3 in a 72-hour action statement per Technical Specification 3.7.1.2, action statements 3 and l.

Train

AFW remained operable with AFW pump C for Unit 3.

This condition lasted from 4:00 a.m. to 6:00 a.m.

on October 19, 1994.

The Turkey Point AFW system required the A pump to be aligned to train 1 and the B and C pumps to be aligned to train 2.

Although technical specifications allowed this AFW system condition, operations and plant management did not concur with the operating shift's actions.

The appropriate personnel were counselled, and the remaining shifts were made aware of this issue and management's expectations.

The corporate PSA group was also contacted to review quantitatively the effect for Unit 3 with simultaneous inoperability of AFW train 1 and AFW pump B.

(The A pump was noted to be available from its safety grade nitrogen backup supply to the FCVs).

PSA personnel concluded that the risk increase was 1.8 E-8, which was much less than the 1.0 E-6 significance criteria.

Thus, this action did not affect overall Unit 3 risk.

The inspectors noted this AFW system condition during the morning control room tour on October 18, 1994.

Subsequent discussions with management noted that the plant and operations manager had already taken actions.

The inspectors concluded that although no technical specifications were violated, this decision by the operating shift to remove train

AFW for Unit 3 from service was non-conservative.

Further, the inspectors noted that management's

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4.2.6 actions were proactive and demonstrated a strong sense of reactor safety once they were aware of the situation.

The inspectors did not identify any violations or deviations.

Unit 3 Heater Drain Pump Trip At 11:50 a.m.

on October 20, 1994, the control room received a 3A steam generator feedwater pump low suction pressure alarm.

The RCO noted that the 3B HDP had tripped on low HDT level.

The 3A HDP remained in service.

The RCO followed the actions of the ARPs and started the standby condensate pump.

Steam generator feedwater pump suction pressure subsequently returned to normal, and the alarm cleared.

The licensee determined that contractor lagging personnel in the vicinity of the HDT level switches most likely bumped the 3-LS-1558 device causing the 3B HDP to trip on a false low HDT level.

The licensee restarted the 3B HDP and stopped the standby condensate pump thus returning systems to normal.

In addition, a

condition report (No. 94-1054)

was written.

An inspector was in the control room shortly after the HDP trip.

The inspectors reviewed licensee actions including ARP and OP implementation, control room logs, and the condition report.

The inspectors also examined the area where the HDT level switches were located.

Both FPL and contractor management personnel were noted to be in the area reviewing the event.

Recently installed lagging was noted to be adjacent to the 3-LS-1558 device.

The inspectors also noted PWOs (Nos.

94007705 and 94011218)

on both the 3-LS-1557 and 3-LS-1558 devices stating that they failed to trip the HDPs on actual low levels.

This apparently occurred on Nay 20 and July 28, 1994, respectively.

The inspectors verified that these PWOs were in the forced outage work list.

The inspectors also reviewed previous condition reports and noted two instances where HDPs tripped due to level switch problems and/or inadvertent bumping.

These occurred in Hay and July 1994.

The licensee's event reviews and corrective actions were appropriately documented.

Licensee corrective actions for this most recent instance involved counselling the workers, modifying the work controls, considering new signs and barriers for the area, and writing a letter to the contractor involved.

The inspectors verified these actions and discussed them with the licensee.

The inspectors concluded that the contractor workers were not careful in the lagging activities, and this resulted in the HDP trip and unnecessary transient for Unit 3.

Control room operators'esponse was timely and appropriate.

Communications, command and control, and procedural compliance was noteworth ~

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4,.2.7 Meeting With Local Officials A meeting with local officials was conducted following the SALP presentation (Refer to NRC SALP Report No. 50-250,251/94-99 for additional information.)

on October 6, 1994.

Meeting attendees are indicated in section 1.0 of this report.

This meeting was beneficial in introducing key licensee, local, and NRC personnel as well as furnishing a forum for providing a status of the facility, getting feedback from county representatives, and providing answers to various questions.

4.2.8 Company Nuclear Review Board Meeting No.

409 CNRB meeting (No. 409)

was held at Turkey Point on October 18, 1994.

The inspectors attended the meeting and verified that the technical specification requirements were satisfied.

The following topics were discussed:

plant manager's report, several proposed licensee amendments, CNRB early warning indicators, gA program/audit status, NRC Inspection Report status, LERs, and plant tours.

The inspectors noted that CNRB members displayed a very good questioning attitude and a pro-active approach to nuclear safety.

The CNRB members also required individuals presenting issues to be thorough and to address the safety significance of the issues.

The inspectors concluded that the CNRB process was effective.

5.0 Maintenance (62703, 61726, and 92902)

5. 1 Inspection Scope The inspectors verified that station maintenance and surveillance testing activities associated with safety-related systems and components were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and the technical specifications.

They accomplished this by observing maintenance and surveillance testing activities, performing detailed technical procedure reviews, and reviewing completed maintenance and surveillance document The inspectors also reviewed a previous open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

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

procedure O-GME-005.1, 4.16KV Equipment Grounding and Testing; procedure O-GMM-041.2, Steam Generator Primary Manway Cover Removal and Installation; procedure O-GMM-043.13, Reactor Vessel Head Installation; procedure O-GHM-072.3, Steam Generator Safety Valve Repair Procedure; procedure OP-16900. 15, Coupling of Fuel Length Control Rods; procedure O-PHE-005.3, 4160V "General Electric" Breaker Inspection and Cleaning; 4A 4160-volt reactor grounding and meggering to allow work on 4160-volt breakers per procedure O-PME-005.6, 4160V A and B Bus Inspection and Cleaning; procedure O-PHH-041.1, Reactor Coolant System Power Operated Relief Valves Overhaul; double testing of overcurrent relays on 4160-volt breakers; 4B HHSI pump overhaul; Unit 4 reactor vessel disassembly (Refer to section 5.2.3 for additional information.);

procedure 0-GHH-043. 19, Reactor Vessel Stud Detensioning Two and One Half Pass Method (Refer to section 5.2.3 for additional information.);

procedure O-GHE-102.4, HOVATS of Safety-Related Limitorque Motor-Operated Valve Actuators (Refer to section 5.2.5 for additional information.);

procedure O-GHE-102.8, Motor-Operated Valve Operator-Inspection and Overhaul (SHB 0 through 34) (Refer to section 5.2.5 for additional information.);

procedure 4-'PMM-022.3, Emergency Diesel Generator 18-Month Preventative, for the 4A and 4B EDGs (Refer to section 5.2.6 for additional information.);

Unit 4 reactor cavity seal installation per procedure 0-GMM-043.6, Reactor Vessel Cavity Seal Ring Installation (Refer to section 5.2.7 for additional information.);

and procedure 0-PMM-075. 13, Auxiliary Feedwater Pump Mechanical Overspeed Trip System Inspection and Overhaul.

(Refer to section 5.2.9 for additional information.)

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

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

procedure 4-0SP-50.7, RHR MOV's/System Pressure Interlock Test; procedure 4-0SP-50.8, RHR MOV's 750, 751, 862, and 863 Interlock Test; and procedure 4-0SP-051.5, Local Leak Rate Tests.

(Refer to section 5.2.8 for additional information.)

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

5.2.3 Unit 4 Reactor Pressure Vessel Disassembly The licensee implemented procedures 4-OP-038. 1, Preparations for Refueling Activities, and 4-0P-038.9, Refueling Activities Checkoff List, for the prerequisites, precautions, limitations, and instructional guidance to perform the necessary checks and surveillances prior to RPV interference removal, head stud detensioning, reactor disassembly, refueling, and the start of any core alterations.

The licensee began detensioning the Unit 4 RPV head studs, and Unit 4 entered Mode 6 at 1:00 p.m.

on October 6, 1994.

The RPV head was lifted and placed on its stand per procedure O-GMM-043.8, Reactor Vessel Head Lifting.

Following the filling of the refueling cavity, the licensee uncoupled the control rods and performed drag testing per procedure OP-16900.1, Uncoupling Full Length Control Rods.

The upper internals was also lifted and placed on its stand per procedure O-GMM-043.9, Reactor Vessel, Removal of Upper Internal ~

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5.2.4

The inspectors reviewed the licensee's operating and maintenance procedures and monitored portions of the licensee's activities.

The licensee's RPV disassembly efforts were performed in a well controlled manner, and strong interdepartmental teamwork was noted.

The air conditioned containment was noted to have a

positive effect on personnel performing these activities.

Containment Coatings During Unit 4 containment tours, the inspectors noted that a few areas of the containment wall exhibited flaking paint.

This outer painting surface covered the zinc inner surface which protects the steel liner.

The inspectors noted that the zinc coating layer was free of corrosion, thus the containment steel liner was unaffected.

The inspectors discussed this issue with licensee engineering and maintenance personnel.

The inspectors reviewed specification No.

CN-2. 18, Materials, Applications and Maintenance of Service Level I Protective Coatings Inside Reactor Containment Building for Turkey Point Units 3 and 4.

Appendix B, paragraph B.2. l.b, of the specification allowed removal. of the top coat as long as the primer (zinc coating)

was intact and no liner corrosion was evident.

Further, engineering was required to evaluate the effect of exposed zinc areas if total area exceeded 5,000 square feet.

The inspectors verified that licensee met this criteria.

The licensee also stated that a final containment walkdown had not yet been performed.

The inspectors questioned the licensee's documentation for this walkdown.

The licensee stated that a video tape was made; however, no formal document existed which recorded the licensee's findings and assessments.

The licensee 'stated that they would correct this item.

The inspectors also observed coatings-related activities on containment piping (primarily CCW)

and other wall and floor surfaces.

In one instance, CCW piping was being treated for external corrosion (e.g.,

chipping and painting).

The CCM piping integrity was unaffected.

However, the paint chips were not being contained and could have affected the ECCS sump screen which was nearby.

The inspectors pointed this out to the containment coordinator and maintenance personnel.

These licensee representatives initiated immediate corrective actions to contain the paint chips.

In conclusion, the inspectors determined that the licensee had an adequate program to ensure that containment coatings meet acceptable standards.

Further, the licensee was very responsive to the inspectors'bservations.

The inspectors did not identify any violations or deviation ~

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5.2.5 Motor-Operated Valve Related Activities The inspectors reviewed the scope of HOV-related activities performed during the current Unit 4 refueling outage.

In addition, the inspectors observed a sampling of the licensee's HOV activities including differential pressure testing, HOVATS testing, and actuator refurbishment.

For the activities observed, the inspectors noted that appropriate procedures and precautions were being followed.

For the differential pressure test observed, the inspectors concluded that the activity was particularly well coordinated with strong involvement by the HOV coordinator as well as the system engineer.

Further, the licensee considered this activity to be covered by procedure 0-ADH-217, Conduct of Infrequently Performed Tests and Evolutions.

This demonstrated positive control of MOV testing activities.

5.2.6 Emergency Diesel Generator 18-Month Preventative Maintenance The inspectors reviewed and observed activities associated with the 4A and 4B EDG 18-month preventative maintenance as required by technical specifications.

The licensee's inspection of the EDGs was conducted in accordance with procedure 4-PHH-022.3, Emergency Diesel Generator 18-Month Preventative.

The inspection was performed by contractor personnel with assistance from onsite engineering and maintenance groups with support by offsite.

The EDG inspections did not reveal any notable discrepancies requiring further investigation.

Following the completion of the inspection, the 4A and 4B EDGs were tested and returned to service within the allotted time frame.

The inspectors also reviewed the gA surveillance activity (No. 96-0901) that was performed to review activities associated with the 4A EDG inspection.

gA personnel concluded that maintenance activities were appropriate.

The inspectors concluded that the 4A and 4B EDG 18-month preventative maintenance activities were satisfactorily completed, and abnormalities with regard to any 4A and 4B EDG subsystems were not surfaced during the inspection.

In addition, appropriate procedures and precautions were followed and activities were executed in a meticulous manner.

5.2.7 Reactor Cavity Seal Installation and Previous Item Closure:

IFI 50-250,251/94-07-02, Reactor Cavity Seal Leakage As part of the refueling sequence, the licensee installed the reactor cavity seal per procedure O-GHH-043.6, Reactor Cavity Seal Ring Installation.

The seal prevented refueling cavity, SFP, and transfer canal leakage through the floor opening.

The seal has been redesigned several times and currently had redundant safety-related rubber seals and a backup (non-safety-related)

inflatable boot seal.

These seals were fitted into a stainless steel ring

and were held in place by 24 compression arms that were bolted to the cavity floor.

These arms rested on the seal ring at designated compression blocks, and were torqued to 150 foot-pounds.

The licensee installed the seal on October 8, 1994.

However, the air line fitting to the inflatable seal was inadvertently bumped, and maintenance personnel were required to remove and re-install the seal ring assembly.

This was completed the following day.

The inspectors examined the seal ring assembly and installation location prior to maintenance installation.

The inspectors also observed the completed initial installation locally from the cavity floor.

The second installation was observed from the refueling bridge.

For the initial installation, the inspectors noted that the "T" compression arm was not fully engaged to the compression block as the arm overhung by about 1/2 inch.

The inspectors questioned licensee maintenance engineers regarding this issue.

The licensee had a

1991 evaluation (NCR No. N91-0803 and EWO No.91026973)

which previously concluded that this condition was acceptable.

Attachment 4 to procedure O-GNN-043.6 described acceptable contact for compression arms and blocks.

However, it did not depict conditions in between "full" and

"partial" contact.

The licensee stated that it would revise the procedure.

As part of the installation process, the licensee measured seal to floor gap on both sides thus ensuring adequate seal compression to perform its intended safety function.

During cavity floodup, operations personnel checked the seal integrity by performing leak rate checks.

This was done per procedure 4-0P-201, Filling/Draining the Refueling Cavity and the SFP Transfer Canal.

The licensee's leak check noted zero leakage initially with about 1.0 gpm leaking into the containment sump, which was a baseline number.

However, during floodup the leak rate increased to 1.5 gpm above the baseline number.

The licensee monitored the cavity liner leak chase system and noted a 1.0 gpm leak rate.

This was similarly noted during the previous Unit 3 outage.

(Refer to NRC Inspection Report No. 50-250,251/94-07 for additional information.)

Procedure 4-OP-201 did not account for this leak into the cavity liner leak chase system; however, the licensee intends to revise the procedure.

The licensee also intends to locate and repair these liner leaks.

Thus, the seal ring leakage was about 0.5 gpm, which was consistent with previous leak rates.

Subsequently, during cavity reload activities on October 21-25, 1994, the leak rate was again normal (about 0.3 gpm).

Based on inspector observations of the seal installation, on procedure review, and on leak-rate results, IFI 50-250,251/94-07-02 is considered closed.

In summary, the inspectors concluded that Unit 4 reactor cavity seal installation was appropriate.

However, the inspectors noted minor deficiencies in related operating and maintenance

5.2.8 procedures.

The inspectors noted that procedural compliance was good and that engineering and supervision involvement was strong.

Unit 4 Local Leak Rate Testing The inspectors reviewed the LLRT surveillance procedure 4-OSP-051.5, Local Leak Rate Tests, and the performance of several LLRTs on Unit 4 during the Cycle 15 outage.

For the LLRTs observed, the inspectors noted that technicians were knowledgeable about the process, procedures and precautions were followed, instruments were calibrated, and results were well documented.

In addition, the inspectors noted that the IST coordinator was well appraised of the ongoing LLRT status and that the results of LLRTs including as-found failures were given due attention.

In addition, the inspectors noted that appropriate controls were in place on LLRT activities during fuel movement activities during which containment integrity is required.

As of the end of the inspection period, all the required LLRTs have not been completed.

Therefore, the as-left leakage (sum of the type B and type C leakages)

was not available.

The maximum allowable leakage value for Turkey Point was 45,000 cc/min.

The previous as found leakage for Unit 4 was 17,010 cc/min.

Following completion of the LLRTs, the inspectors intend to review the results to determine compliance.

For those LLRT activities monitored, the inspectors concluded that LLRT activities were well planned, coordinated, and executed.

Additionally, the inspectors noted strong involvement by the IST coordinator.

5.2.9 Auxiliary Feedwater Issues The inspectors reviewed the licensee's actions pertaining to the notification made by Dresser-Rand Company pursuant to the requirements of 10 CFR Part 21.

The notification involved the

"Terry Turbine" trip and throttle valve and valve coupling.

This device, when not properly locked to the stem, could unthread and render the AFW turbine inoperable.

Turkey Point utilizes the

"Terry Turbine" for the three AFW pumps that are shared between the two units.

The inspectors noted that the licensee had already initiated a

condition report (No.94-966)

prompted by the operation experience feedback program to address the issue.

This condition report documented the immediate and planned corrective actions as a

result of the

CFR Part 21 notification.

The immediate actions involved a visual inspection of the three AFW trip and throttle valves.

The licensee contacted the vendor to seek further guidance to'isually determine stem engagement.

Based on the information provided by the vendor, the licensee concluded that the stems were properly engage In addition, the licensee generated three work requests to disassemble the coupling for inspection at the next opportunity.

The inspectors learned that the disassembly inspection was being delayed due to unavailability of the set screws.

The set screws are currently threaded through the coupling to engage to the stem and are staked in place to prevent them from backing out.

Following disassembly, the old set screw cannot be reused.

The inspectors discussed the disassembly inspection delay issue with the plant general manager.

The reason for the delay in acquiring the set screws was not known at the end of the inspection period.

On October 17, 1994, during performance of 3-0SP-75.2, Auxiliary Feedwater Train 2 Operability Verification, the B AFW trip and throttle valve unexpectedly tripped.

This valve was designed to trip electrically at a turbine overspeed condition of approximately 6,200 rpm and mechanically at a turbine overspeed condition of approximately 6,500 rpm.

During the test being conducted on October 17, 1994, the turbine had not experienced an overspeed condition.

The licensee's investigation determined that the two set screws associated with the trip tappet assembly were loose.

(These are different set screws from the ones discussed above.)

This caused the trip tappet to prematurely actuate.

The trip tappet assembly was rebuilt, and the B AFW pump was satisfactorily tested and returned to service.

The cause of the two set screws coming loose is not known.

A condition report was initiated to review prior maintenance history to determine if the set screws had been properly assembled as required by procedure for trip and throttle valve overhaul.

The A and C AFW pumps were also inspected, and no problems were identified.

The inspectors plan to follow the resolution and closeout of the condition report associated with this event during future inspections.

For the activities observed, the inspectors noted that the licensee was proactive in addressing the

CFR Part 21 issue associated with the trip and throttle valve coupling.

6.0 Engineering (37551, 37700, 90712, 90713, and 92700)

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

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

The inspectors reviewed selected PC/Hs including the applicable safety evaluation, in-field walkdowns, as-built drawings,

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6.2 6.2.1 associated procedure changes and training, modification testing, and changes to maintenance programs.

The inspectors also reviewed the reports discussed below.

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

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

In addition, the inspectors reviewed previous open items (LERs) to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

Inspection Findings Potential for Core Recriticality During Hot Leg Safety Injection Switchover The inspectors reviewed and discussed licensee's resolution to a

Westinghouse Nuclear Safety Advisory Letter No.94-016 involving potential recriticality following a large cold leg break LOCA.

The concern was that during hot leg SI switchover, the core would be flushed with diluted containment sump solution.

This had the potential to cause the core to return to criticality.

The sump solution would be diluted since boron could accumulate in the core during the cold leg recirculation phase due to core boiling.

The accumulation of boron in the core prevents the boron from being displaced to the sump which leads to a diluted sump solution.

I The licensee determined that the issue was applicable to Turkey Point Units 3 and 4.

Licensee's approach to resolving the issue was predicated on taking credit for bypass flow between the core barrel and the vessel as recommended by Westinghouse in the advisory letter.

This vessel gap allows fluid to bypass the core and flow from the upper downcomer directly into the hot legs during normal operation.

Following a large break LOCA, this flow reverses and provides a path for the incoming safety injection fluid to return to the sump by flowing from the upper plenum into the downcomer and broken cold leg.

In addition to the gap flow, normal flow around the RCS loops would exist for an extended period of time after the accident.

This loop flow would remove boron from the core and eventually return it to the sump.

The combination of the gap and loop flow during cold leg recirculation is sufficient to prevent the boron concentration in the Turkey Point cores from approaching the maximum allowable concentration of 23.5 weight percent or approximately 41,000 ppm before initiation of hot leg recirculation.

Thus sufficient flow would exist to circulate boron in the reactor back to the sump thereby preventing the sump from reaching a low boron concentration which could cause recriticality at the hot leg SI switchover tim I

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6.2.2 The inspectors reviewed and discussed the licensee's evaluation associated with the issue.

The inspectors determined that the licensee acted in a timely manner to the issue raised by Westinghouse, and the licensee's approach to resolving the issue conformed adequately to the recommendations made by Westinghouse.

Unit 4 Seismic Anchorage of MCCs (PC/M No.91-179)

Generic Letter No. 87-02, Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors-Unresolved Safety Issue A-46, established the NRC's position with regard to the seismic adequacy of the mechanical and electrical components required to achieve and maintain safe shutdown in operating nuclear power plants of Turkey Point's vintage.

Based on this information, the licensee utilized a seismic review team to conduct an engineering walkdown of the safety-related MCCs and developed calculations to show that the equipment would remain operable in the event of a safe shutdown earthquake.

These calculations utilized specific existing conditions to qualify the MCCs.

Although the use of these existing conditions was acceptable to justify continued operation, it was not considered to be the current industry design practice used for the seismic anchorage of permanent plant equipment.

This condition necessitated that additional positive anchorages be installed in order to ensure conformance with current industry design practices as follows:

Modification of the 4A MCC involved welding to existing embeds along the outside face of the cabinets and some chipping and repairing of concrete.

Modification of the 4B MCC involved attaching an angle to the wall, bolting the free end to the top of the cabinet, and welding to existing embeds along the outside face of the cabinet.

Modification of the 4C MCC involved attaching an angle to the wall, bolting the free end to the top of the cabinet, and retorquing existing expansion anchors inside the cabinet at its base.

The PC/M which incorporated these modifications was completed on June 9,

1994.

These modifications provided additional positive anchorages which enhanced the existing anchorages for the MCCs.

The licensee also generated an engineering calculation to demonstrate the adequacy of the modified equipment to resist all applicable loads (including seismic loads) relying solely on the new anchorages without having to take into account the specific existing conditions which previously justified continued operatio.2.3 The inspectors reviewed the licensee's minor engineering package for PC/M 91-179; process sheet Nos.93-112, 93-113, and 93-114; WO Nos.

93016150, 93016157, and 93016158; FPL weld control program hanger/support/structural weld traveler Nos. 300560-001E through 004E; and various reports for proprietary grout/mortar mixing and replacement, grout tests, visual welding inspection, expansion anchors inspection, raceway hangers and supports inspection, and gC general inspections.

The inspectors also reviewed drawings Nos. 5614-C-1790/91-179, Sheet 1, Motor Control Center 4A USI-46 Modifications Panel Seismic Anchorage Details; 5614-C-1790/91-179, Sheet 2, Motor Control Center 48 USI-46 Modifications Panel Seismic Anchorage Details; 5614-C-1790/91-179, Sheet 3, Motor Control Center 4C USI-46 Modifications Panel Seismic Anchorage Details; 5610-C-109/91-179, Powerhouse Ground.Floor Slab Turbine Generator Area Unit 4; 5610-C-285/91-179, Auxiliary Building Area

EL 18'-0";

and 5610-C-302/91-179, Control Building Ground Floor Slab Plan and Details; as well as CRN Nos.

C-6787, C-6798, C-6826, C-6832, C-6884.

and C-6923.

The inspectors concluded that the referenced modifications did enhance the existing seismic anchorage for the 4A, 4B, and 4C MCCs, and the modifications appeared to be performed in accordance with the PC/M.

Unit 3 Annunciator Dark Board Modifications (PC/M No.93-048)

As part of the control room human factor reviews and upgrades as required by NUREG Nos.

0700 and 0737, the licensee implemented PC/M No.93-048 on Unit 4 this refueling outage.

This PC/M completed the annunciator dark board concept which requires alarms to be off (not-illuminated) unless an abnormal condition exists.

Thirteen Unit 4 alarms were in this condition (e.g. illuminated normally while at power).

The licensee effected wiring and logic changes which resulted in alarms being off normally.

The alarm windows effected included RCP seal water bypass, source range high/loss'f voltage, gland steam exhauster stopped, breathing air trouble, RHR seal exchanger high/low flow, and desuperheater temperature/pressure.

The inspectors reviewed 'PC/M package No.93-048 including engineering design and safety evaluations, wiring and logic drawings, process sheets, post-modification testing procedures, work orders, and other related documentation.

The inspectors also reviewed selected field work, discussed the PC/M with design and construction engineering personnel, and observed post-modification testing.

The inspectors also verified that the operators were trained and that the ARPs were revised.

The inspectors concluded that this PC/M was well planned and coordinated, and it was also effectively implemented and tested.

This PC/M was completed for Unit 3 during the spring 1994 refueling outag ~

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6.2.4 6.2.5 Replacement of Valves PAHH-4-001A and B and PAHH-4-002A and B

(PC/H No.93-077)

PC/M No.93-077 was implemented during the Unit 4 Cycle

refueling outage.

The modification replaced the existing PAHH globe valves with equivalent gate valve structures.

The modification replaced the valve internals, bonnet, and stem while retaining the existing valve body and reach rod.

The modification was performed because the PAHM globe valves had broken numerous stems in the past several years.

A root cause analysis concluded that transmission of the reach rod torque to the valve stem was the cause of all reported stem failures.

The inspectors reviewed the PC/M package including engineering design, safety evaluation, post-modification acceptance, and selected drawings.

The inspectors concluded that this PC/M was well planned and coordinated and that it was also effectively implemented and tested.

Inspection, Repair, and Modification of the Unit 4 Intake Structure (PC/M No.94-003)

C As discussed in section 11.2.4 of NRC Inspection Report No. 50-250,251/94-07, the licensee's 1985 and 1986 inspections of the Unit 3 and 4 intake structure revealed corrosion and degradation of the circulating water pump thrust beams, horizontal struts, and deck support beams for the ICW pumps.

As a result, the licensee implemented a long-term inspection, repair, and modification program for the intake structure.

During the current Unit 4 outage, intake structure bays 4A1 and 4A2 were inspected, repaired, and modified per PC/M No. 94-03 and PWO Nos.

94017890 and 94024274.

6.2.6 The inspectors examined the field work in progress, reviewed the completed PC/M documentation, and discussed the work with licensee personnel.

The inspectors noted that the Unit 4 bays have been completed.

The inspectors did not identify any violations and concluded that the work was appropriately performed per the PC/M and associated procedures.

The closure documentation was complete and thorough.

Unit 3 Reactor Protection System Plant Reliability Improvement (PC/M No.94-014)

PC/M No.94-014 was implemented during the Unit 4 Cycle

refueling outage.

This modification involved the installation of redundant auxiliary relays for the SI signal and RCP breaker open reactor trip signals such that a 2-out-of-2 trip logic was obtained for each of the two redundant channels.

Prior to the modification, there was only one relay per channel for these signals which was normally energized at power and deenergized to trip.

The new relays'oils and contacts were wired in a

6.2.7 redundant manner to the existing SI and RCP breaker auxiliary relays to obtain a 2-out-of-2 trip logic per channel.

The PC/H was performed to preclude the possibility of a single relay failure initiating a reactor trip.

Likewise, no single relay failure would preclude a reactor trip.

This PCH did not violate the overall RPS design criteria.

The inspectors reviewed the PC/H package including engineering design, safety evaluations, post-modification acceptance testing, and selected drawings.

The inspectors concluded that this PC/H was well planned and coordinated, and it was also effectively implemented and tested.

A similar modification was implemented for Unit 3 during its last refueling outage.

Unit 4 Flux Napping System Enhancement (PC/H No.94-019)

PC/H No.94-019 was implemented during the Unit 4 Cycle

refueling outage.

This modification involved mechanical and electrical enhancements to the existing incore flux mapping drive units.

The mechanical modification involved the provision of a constant flow of instrument air to the drive enclosure to help reduce humidity.

Additionally, water resistant roofs were installed on the drive enclosures, and side access covers were replaced with a removable panel for ease of maintenance.

The mechanical modifications were performed to reduce corrosion-related failures of the flux mapping system.

The electrical modification included replacement of relays to prevent the five path motor from rotating upon energizing or de-energizing the system, replacement of the manual reset motor starter overload relays with automatic reset overload relays, installation of surge suppression on the power supply to prevent damage to control electronics due to voltage spikes, and installation of phone jacks and electrical outlets in convenient locations.

The electrical modifications were performed to enhance the reliability of the flux mapping system and to minimize containment entries and/or stay times during troubleshooting and maintenance.

6.2.8 The inspectors reviewed the PC/M package including engineering design, safety evaluations, post-modification acceptance testing, and selected drawings.

The inspectors concluded that this PC/H was well planned and coordinated and that it was also effectively implemented and tested.

Unit 4 Pressurizer Welded Hanway Diaphragm (PC/H No.94-057)

The licensee modified the Unit 4 pressurizer manway diaphragm from a gasket and insert design to a welded design.

The previous design was subject to leakage noted on both units in the pas The welded diaphragm eliminated the Unit 4 degradable gasketed joint.

The manway is a structural part of the RCS pressure boundary.

The diaphragm was made of Inconel-690 material, and the weld material was Inconel-600.

6.2.9 The inspectors reviewed the PC/M documentation including the safety evaluation and the vendor design specifications.

The inspectors also observed portions of the installation including nondestructive examination checks.

NRC Inspection Report No. 50-250,251/94-21 also reviewed this PC/M and subsequent installation.

The inspectors concluded that the PC/M documentation and related procedures were complete and that installation appeared appropriate.

Unit 4 Containment Isolation Barrier Testing Enhancement (PC/M No.94-058)

The licensee implemented this Unit 4 modification (PC/M No.94-058) to enhance the LLRT capability for containment penetrations.

The modification included changing existing valve designs, adding additional valve isolation capability, or adding valve bonnet paths to provide the capability to pressurize and test normally inaccessible valve bonnet/packing areas.

A similar modification was performed during the last Unit 3 refueling outage.

The inspectors reviewed the PC/M package including the design bases and analyses and the safety evaluation.

The inspectors noted that appropriate reviews and approvals were performed by responsible organizations.

The inspectors walked down portions of the PC/M in the field and discussed this item with licensee engineers.

The inspectors also reviewed revised drawings and procedures.

The post-modification tests including LLRTs associated with the penetrations affected by the modifications were also reviewed.

(Refer to section 5.2.8 of this report for additional information.)

The inspectors concluded that this PC/M was appropriately implemented, and violations were not identified.

6.2.10 Turkey Point Unit 4 Cycle 15 Reload (PC/M No.94-084)

The licensee initiated PC/M No.94-084 for the Unit 4 Cycle

reload.

This PC/M provided for the reload core design and included the replacement of 52 irradiated assemblies with 52 fresh optimized fuel assemblies.

The new assemblies are of the debris resistant design which included several fuel design enhancements.

These are similar to the Unit 4 Cycle 14 reload design.

The inspectors reviewed the documentation package for the PC/M including the design bases and analyses, the safety evaluation, core loading plan, and other pertinent data.

The inspectors noted that appropriate reviews and approvals were performed by engineering personnel, by reactor engineers, by gC, and by the PNSC.

The inspectors concluded that PC/M was well documented and

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23 6.2.11 adequately implemented by refueling procedures.

(Refer to section 4.2.3 for appropriate related implementing procedures.)

Unit 4 Containment Temporary Air Conditioning (PC/N No.94-085).

In order to improve the containment atmosphere (temperature and humidity) for worker comfort and efficiency, the licensee installed a temporary air conditioning system.

Two 200-ton portable air conditioning units were installed on the auxiliary building roof.

A chilled water system was connected into the non-safety-related portion of the CCW system to supply the four normal containment coolers.

This was accomplished per PC/M No.94-085 and procedure TP-1082, Temporary Containment Cooling.

The licensee's engineering and safety evaluations addressed possible effects on the operating unit (Unit 3);

on the assurance of safety-related CCM supply to the RHR heat exchangers on Unit 4; training of operators; plant drawings including piping, electrical power, and controls; possible flood effects; possible seismic concerns and heavy load handling; and other related issues.

The inspectors reviewed procedure TP-1082, PC/M No.94-085, appropriate drawings, and training brief No. 505.

The inspectors also walked down the system and discussed its operation with system engineering.

The system was placed in service on October 5,

1994, with very successful results.

Containment temperature and humidity were greatly reduced.

The inspectors concluded that PC/H and TP implementation were appropriate and that the licensee's efforts in addressing containment work conditions were noteworthy.

6.2.12 4C Bus Nodification (PC/8 No.94-114)

As part of the licensee's corrective actions for a Unit 4 reactor trip (Refer to section 6.2.14 for additional information.)

modifications were performed on the 4C bus.

In that event, the jarring of a breaker cubicle (4AC01)

on the 4C bus. actuated a

lockout relay.

That resulted in a loss of the 4C bus and an eventual automatic reactor trip.

This modification relocated the 4C (non-vital) bus protective relays from the outside of the breaker cubicles 4ACOl and 4AC16 to either the inside of cubicles 4AC02 and 4AC14 or the outside of a locked spare cubicle (4AC07).

The inspectors reviewed the PC/H package and related documentation including the

CFR 50.59 and engineering evaluations implementation instructions, PHT guidance, and associated drawings.

The inspectors also attended the PNSC meeting which reviewed and approved this PC/H, and witnessed portions of the PC/H implementation in the field.

The inspectors noted that the PC/N package was complete, and installation appeared appropriate.

Compliance issues were not identifie ~

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6.2.13 Monthly Operating Report The inspectors reviewed the September 1994 monthly operating report and determined it to be complete and accurate.

6.2. 14 (Closed)

LER 50-251/94-004, Automatic Reactor Trip Due to Loss of Power to Rod Control Cabinet 1AC The inspectors previously reviewed this event, and it was documented in NRC Inspection Report No. 50-250,251/94-18.

The automatic trip on Unit 4 was caused by an overtemperature delta-temperature signal which occurred when 12 control rods powered from cabinet lAC lost power.

A degraded auctioneered power supply (PS-3) failed when loaded due to a loss of the other power supply (PS-4)

due to loss of the 4C non-vital bus.

The licensee determined that the PS-3 device failed due to a faulty component, and the loss of the 4C bus was caused by maintenance activities which actuated a bus lockout relay due to inadequate breaker cubicle door and wall clearance.

As discussed in the above mentioned report, short-term corrective actions were taken and longer-term corrective actions were planned.

The licensee relocated the 4C bus relays per PC/M 94-114.

(Refer to section 6.2. 12 of this report for additional information.)

The inspectors concluded that this LER appropriately described the event and its causes and that adequate corrective actions were taken.

Based on this, the LER is considered closed.

6.2. 15 (Closed)

LER 50-251/94-005, Manual Trip While Shutdown The inspectors previously reviewed this event, and it was also documented in NRC Inspection Report No. 50-250,251/94-18.

The manual reactor trip occurred while Unit 4 was in Mode 3 during startup, and it was initiated by operators when a partial loss of rod position indication occurred.

An operator touched a shorted light bulb which tripped the power supply to the rod deviation cabinet.

This caused an abnormal rod position indication, and operators initiated a manual reactor trip.

The licensee replaced the light bulb and socket.

Other similar ones were checked, and additional abnormalities were not noted.

The inspectors concluded that this LER appropriately described the event and its causes and that adequate corrective actions Here taken.

Based on this, the LER is considered closed.

7.0 Plant Support (71750)

7.1 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

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25 programs; emergency preparedness; plant housekeeping/cleanliness conditions; and the radiological effluent, waste treatment, and environmental monitoring programs.

7.2 Inspection Findings 7.2. 1 Unit 4 Steam Generator Inspection and Cleaning Activities During the current Unit 4 refueling outage, the licensee performed eddy current tests, inspections, and secondary side sludge lancing associated with all three steam generators.

This included involvement among FPL corporate, site groups, and contractor organizations.

Steam generator inspections and-associated activities were performed in accordance with approved program plans.

The chemistry department retained overall responsibility for this steam generator work.

The licensee performed inspections of 100% of the tubes in all three steam generators during this refueling outage, and no steam generator tubes required plugging.

At the end of this outage, the following status existed on the Unit 4 steam generators:

4A 4B 4C Number of Tubes Tubes Plugged to Date 3214 3214 3214 Pounds of Sludge Removed 144 235 195 The inspectors observed a sampling of the above mentioned activities including field work, data retrieval, and assessment.

Inspection procedures were also reviewed, and personnel involved in the steam generator activities were interviewed.

Further, NRC Inspection Report No. 50-250,251/94-21 also documented inspections in this area.

The inspectors concluded that the licensee's engineering and chemistry personnel were effectively involved in all phases of these activities.

Strong secondary chemistry programs and controls have resulted in no pluggable steam generator tubes.

Negative findings were not identified.

7.2.2 Unit 4 Containment Tours During the inspection period, periodic tours of the Unit 4 containment were performed on the following days:

October 4, 6-12, 19, 22, 24, 25, and 27, 1994.

The inspectors observed refueling activities, reactor vessel disassembly/reassembly, work in progress, and other maintenance/surveillance activities.

The inspectors also checked for proper radiological controls, personnel safety, and cleanliness/housekeeping item.2.3 7.2.4 The inspectors concluded that the overall containment conditions were adequate.

The air conditioning has made the containment work environment very good.

Inspectors noted poor housekeeping in some areas.

These specifics were discussed with licensee management personnel who indicated that they had also noted these conditions and had initiated corrective actions.

The inspectors verified these corrective actions.

The inspectors also noted that health physics personnel were generally controlling the radiological aspects of work in progress in the containment.

However, in one instance a leak inside the biological shield was not being aggressively pursued by health physics personnel.

When the inspectors brought this to the attention of management, corrective actions were very thorough.

The leak was non-radioactive steam generator water that caused a blocked drain line to overflow.

The inspectors did not identify any compliance issues.

Fire Protection Deluge System As discussed previously in NRC Inspection Report No. 50-250,251/94-11, a high number of inadvertent fire protection system deluge actuations occurred in the first half of 1994.

Fire protection personnel embarked on a detailed action plan to assess root cause(s)

and to determine corrective actions.

The licensee identified several root causes including equipment failures due to setpoint drift, design problems, and personnel errors.

Corrective actions included enhanced preventive maintenance procedures and activities, design modifications per PC/N No.94-081, and retraining of personnel.

The inspectors reviewed the associated condition reports, the PC/H, and root cause and corrective action summaries and also discussed these issues with fire protection personnel.

The inspectors noted that the number of inadvertent deluge actuations has decreased in the last several months.

The inspectors concluded that the licensee established a proactive approach to these inadvertent fire protection system deluges, and corrective actions appeared effective.

Personnel Contamination Events During the period, three personnel arrived onsite with low levels of radioactive contamination.

On October 3, 1994, during entrance whole body counting, the licensee detected skin and clothing contamination of between 1000-5000 dpm per 100 square centimeters on two German national contractor personnel.

The licensee appropriately responded and made an ENS call.

On October 5, 1994, an FPL employee was also detected with 200 cpm of activity, and the source was traced to an offsite medical facility.

Again, the licensee appropriately responded and made another ENS call.

The inspectors monitored licensee actions for both of these events.

The inspectors reviewed the survey and count results, the

notification documentation, the condition reports, isotopic results, and discussed these with licensee management and health physics personnel.

(For additional information, refer to NRC Inspection Report No. 50-250,251/94-19.)

The inspectors concluded that licensee actions were consistent with health physics and

CFR 50.72 notification procedures.

Further, the licensee was noted to be thorough and open with its communications to the NRC, the state, and the county.

On October ll, 1994, a contamination event occurred on site which resulted in an estimated skin dose of approximately 1.043 rem to an individual.

The contamination involved a Co-60 hot particle on the right forearm of an individual working in the Unit 4 SFP area.

The individual was involved in activities that required collecting and bagging potentially contaminated material.

The NRC annual limit to the skin or to an extremity is 50 rem.

The dose received by the individual was well below the NRC limit as defined in

CFR 20.1201.

The licensee concluded that the individual was not properly dressed for the activity that he was involved in.

The individual was a temporary contractor employee and was subsequently disciplined.

The licensee initiated a condition report and documented the skin dose assessment.

The resident inspectors contacted a regional specialist health physics inspector and appraised him of the details.

The specialist also discussed the event with the licensee.

The inspectors reviewed the licensee's documentation and concluded that the licensee's response was appropriate.

Additionally, the inspectors noted that the number of contamination events during the current Unit 4 refueling outage were lower than the number of contamination events during the Unit 3 refueling outage that was conducted earlier this year.

7.2.5 Turkey Point Fossil Unit Effects on Security During the period, the inspectors noted that a crane to support the Turkey Point fossil units was within the isolation zone outside of the protected area fence.

The inspectors verified that appropriate compensatory measures were taken and that the licensee had assessed the safety effect of crane falling.

Further, the inspectors noted that the measures were preplanned for possible adverse weather conditions.

8.0 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 October 31, 1994.

(Refer to section 1.0 for exit meeting attendees.)

The areas requiring management

attention were reviewed.

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

Dissenting comments were not received from the licensee.

The inspectors did not identify any regulatory compliance issues.

However, the following previous items were discussed:

Item Number Status Descri tion and Reference 50-250,251/94-07-02 50-251/94-004 50-251/94-005 (Closed) IFI - Reactor Cavity Seal Leakage (section 5.2.7)

(Closed)

LER - Automatic Reactor Trip Due to Loss of Power to Rod Control Cabinet 1AC (section 6.2. 14)

(Closed)

LER - Manual Trip While Shutdown (section 6.2. 15)

9.0 Acronyms and Abbreviations ADM AFW ANPS ARP CC CCW CFR CN CNRB Co cpm CRN dpm ECCS EDG EL ENS EWO FCV FPL GME GMM gpm HDP HDT HHSI ICW IFI IST KV Feet Inches Administrative Auxiliary Feedwater Assistant Nuclear Plant Supervisor Annunciator Response Procedure Cubic Centimeters Component Cooling Water Code of Federal Regulations Specification Number Company Nuclear Review Board Cobalt Counts Per Minute Change Request Notice Disintegrations Per Minute Emergency Core Cooling System Emergency Diesel Generator Elevation Emergency Notification System Engineering Work Order Flow Control Valve Florida Power and Light General Maintenance

- Electrical General Maintenance

- Mechanical Gallons Per Minute Heater Drain Pump Heater Drain Tank High Head Safety Injection Intake Cooling Water Inspector Followup Item Inservice Test Kilovolt

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A LER LI LLRT LOCA LS HCC min HOV HOVATS NCR NPS NRC ONOP OP OSP PAHH PC/H PHE PMM PMT PNSC ppm PS PSA PWO QA QC RCO RCP RCS rem RHR rpm RPV SALP SFP SI SRO TP USI V

WO

Licensee Event Report Level Indicator Local Leak Rate Test Loss-of-Coolant Accident Level Switch Hotor Control Center Minute Motor-Operated Valve HOV Acceptance Testing System Non-Conformance Report Nuclear Plant Supervisor Nuclear Regulatory Commission Off Normal Operating Procedure Operating Procedure Operations Surveillance Procedure Post-Accident Hydrogen Monitor Plant Change/Modification Preventive Maintenance

- Electrical Preventive Maintenance

- Mechanical Post-Maintenance Test Plant Nuclear Safety Committee Parts Per Million Power Supply Probabilistic Safety Assessment Plant Work Order guality Assurance guality Control Reactor Control Operator Reactor Coolant Pump Reactor Coolant System Roentgen Equivalent Han Residual Heat Removal Revolutions Per Minute Reactor Pressure Vessel Systematic Assessment of Licensee Performance Spent Fuel Pit Safety Injection Senior Reactor Operator Temporary Procedure Unresolved Safety Issue Volt Work Order

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