IR 05000250/1994007

IRs 50-250/94-07 & 50-251/94-07 on 940327-0430.No Violations Noted.Major Areas Inspected:Operational Safety, Plant Events,Maint Observations,Surveillance Observations, Followup on Previous Items & Review of Written Repts

ML17352A610
Person / Time
Site:	Turkey Point
Issue date:	05/12/1994
From:	Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352A609	List: IR 05000250/1994007 ML17352A608
References
50-250-94-07, 50-250-94-7, 50-251-94-07, 50-251-94-7, NUDOCS 9406020178
Download: ML17352A610 (54)

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/94-07 and 50-251/94-07 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:

March 27 through April 30, 1994 Inspectors:

T.

P.

Johns n, Senior esident Inspector Dat S'gned B.

B. Desai, Resident nspector Dat Si ned L. Trocine, Resident spector Date Signed Accompanied by:

R.

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

P.

chin Pro 'ect En ineer Reactor Pro 'ects Section

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Di isio of Reactor Projects Approved by.:

andis, Chief React r Projects Section 2B Division of Reactor Projects Dat Si ned SUMMARY Scope:

This resident inspection was performed to assure public health and safety, and it 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 a

CFR Part 21 issue, Unit 3 refueling outage activities, and design changes and modifications.

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

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Results:

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

The following non-cited violation and inspector followup items were identified:

Non-Cited Violation 50-250,251/94-07-01, Unescorted Visitor Within the Protected Area (section 5.2. 1).

Inspector Followup Item 50-250,251/94-07-02, Cavity Seal Leakage During Refueling (section 6.2.2).

Inspector Followup Item 50-250,251/94-07-03, Licensee Corrective Actions for Inservice Testing Program (section 7.2.2).

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

~0erati ons The Unit 3 end of cycle coastdown was effectively implemented (section 4.2. 1),

The Unit 3 shutdown and cooldown for refueling was well performed and safely conducted (section 4.2.2).

Although the scaffold program was adequately implemented, unnecessary scaffolds over redundant safety systems were noted (section 4.2.3).

Licensee overtime has decreased over the past few years (section 4.2.4).

The licensee adequately addressed both standby steam generator feedwater pumps being out-of-service (section 4.2.5).

The licensee appropriately responded to issues associated with the Unit 4 residual heat removal sump cover being misaligned (section 4.2.6)

and with dust in a Unit 3 control room panel (section 4.2.7).

The licensee plans to pursue the issue of uncalibrated local valve position indicators (section 4.2.8).

The licensee was effective in assuring that the Unit 3 refueling outage did not adversely affect Unit 4 power operations (section 4.2.9).

The Company Nuclear Review Board displayed a good questioning attitude and a proactive approach to nuclear safety (section 4.2.10).

The licensee properly and promptly responded to a loss of Unit 3 spent fuel pool cooling caused by a component cooling water system temporary alignment (section 5.2.4).

The licensee aggressively pursued an overflow of a waste holdup tank (section 5.2.5).

Licensee Event Reports were appropriately written for several events (sections 9.2.2, 9.2.3, 9.2.4, and 9.2.5).

Licensee draindown activities for the Unit 3 reactor coolant system were effectively conducted with strong oversight.

The licensee's decision not to go to midloop with fuel in the reactor was conservative (section 10.2. 1).

Unit 3 core offload and reload activities were well performed (section 10.2.4).

Haintenance Inspector observed maintenance and surveillance activities were performed in a satisfactory manner (sections 6.2. 1 and 7.2. 1).

A higher

than expected Unit 3 cavity seal leak was an inspector followup item (section 6.2.2).

Inspector observed Unit 3 main steam safety valve setpoint tests were well organized and supported.

However, inservice testing failures were not being tracked with a condition report.

This issue was considered as an inzpector followup item (section 7.2.2).

The open item concerning the safety injection pump motor rotor bar cracking was updated; however, it continues to be open pending licensee completion of the 3A and 3B safety injection pump motor upgrades (section 8.2. 1).

Inspector observed Unit 3 reactor vessel disassembly/re-assembly activities were well performed with strong teamwork (section 10.2.3).

En ineerin The licensee aggressively and appropriately addressed a

CFR Part

issue regarding the reactor protection system (section 9.2.6).

Erosion/corrosion, steam generator tube inspections, and inservice inspection activities were well performed with noted integrated teamwork (section 10.2.5).

The inspectors did not note any deficiencies in the evaluation for or installation of a temporary spool piece on Unit 3 penetration 65A (section 11.2. 1).

The Unit 3 core reload modification package was appropriately reviewed and approved and was also well documented (section 11.2.2).

The Unit 3 control room annunciator dark board modification was effectively implemented (section 11.2.3).

The package for the inspection, repair, and modification of the Unit 3 intake structure was comprehensive, and work performed in accordance with this package was conducted in a thorough and professional manner (section 11.2.4).

Appropriate reviews and approvals of the Unit 3 containment isolation barrier enhancements were performed by responsible org5nizations (section 11.2.5).

Plant Su ort Radiation Controls Emer enc Pre aredness Securit Chemistr Fire Protection Fitness For Dut and Housekee in Controls An unescorted visitor within the protected area was a non-cited violation (section 5.2. 1).

The licensee's handling of a personnel contamination event was prompt and thorough (section 5.2.2).

The inspector noted that the safety height requirement for personnel fall protection was not specified in licensee procedures (section 5.2.3).

Health physics coverage noted during containment tours was effective, and less than adequate containment housekeeping was appropriately addressed by the licensee (section 10.2.2).

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

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1.1 1.2 1.3 Licensee Employees NRC Resident Inspectors Other 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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4.0 Operational Safety Verification........

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

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

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5.0 lant Events...................................................

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

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0 6.0 Haintenance Observations......................................

6.1 Inspection Scope.................

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

12 7.0 Surveillance Observations.....................................

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

7.2 Inspection Findings..............

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8.0 Followup on Previous Items and Noncompliances.................

8. 1 Inspection Scope.................

8.2 Inspection Findings..............

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9.0 Onsite Followup and In-Office Review of

CFR Part 21 Reviews.................

Written Reports and

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9.1 Inspection Scope.................

9.2 Inspection Findings..............

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17 10.0 Unit 3 Refueling Outage Activities............................

10. 1 Inspection Scope.................

10.2 Inspection Findings..............

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Table of Contents

11.0 Design, Design Changes, and Hodifications...

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11.1 Inspection Scope...............

11.2 Inspection Findings............

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1 2.0 Exit Interv>ews...............................................

13.0 Acronyms and Abbreviations.........................

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REPORT DETAILS 1.0 Persons Contacted Licensee Employees

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Abbatiello, Site Quality Manager Acosta, Company Nuclear Review Board Chairman Bohlke, Vice President, Engineering and Licensing Bowskill, Reactor Engineering Supervisor Franzone, Instrumentation and Controls Haintenanc Supervisor Geiger, Vice President, Nuclear Assurance Gianfrancesco, Maintenance Support Services Super Goldberg, President, Nuclear Division Heisterman, Mechanical Maintenance Supervisor Higgins, Outage Manager Hollinger, Training Manager Jernigan, Operations Manager Johnson, Operations Supervisor Kaminskas, Services Manager Kirkpatrick, Fire Protection/Safety Supervisor Knorr, Regulatory Compliance Analyst Kundalkar, Engineering Manager Lindsay, Health Physics Supervisor rchese, Site Construction Manager Marcussen, Security Supervisor Mowrey, Licensing Assistant Paduano, Manager, Licensing and Special Projects Pearce, Plant General Manager Pearce, Electrical Maintenance Supervisor Plunkett, Site Vice President Powell, Technical Manager Rose, Nuclear Materials Manager Steinke, Chemistry Supervisor Tomaszewski, Technical Department Component Speci Supervisor Wayland, Maintenance Manager Weinkam, Licensing Manager vlsol alist Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.

1.2 1.3 NRC Resident Inspectors

• B. B. Desai, Resident Inspector

• T. P. Johnson, Senior Resident Inspector

• L. Trocine, Resident Inspector Other NRC Personnel on Site R.

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

R.

G. Harsh, Investigator, Office of Investigations, Region III Field Office R.

P. Schin, Project Engineer, Reactor Projects Section 2B, Region II

Attended exit interview on May 5, 1994 Note:

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

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

Dates Area Ins ected

. 50-250,251/94-06 March 28-April 1, 1994 Engineering Inspection 50-250,251/94-08 Apri1 18-22, 1994 Inservi ce Inspection 50-250,251/94-09 April 11-15, 1994 Health Physics Inspection 3.0 Plant Status 3.1 Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near 100% power and had been on line since February 23, 1994.

The following evolutions occur red on this unit during this period:

The licensee commenced a Unit 3 coastdown on March 29, 1994, in preparation for a planned refueling outage.

(Refer to section 4.2. 1 for additional information.)

The licensee commenced a load reduction on April 3, 1994, and removed Unit 3 from service at 12:18 a.m.

on April 4, 1994 in order to begin a refueling outage.

(Refer to section 4.2.2 for additional information.)

3.2 Unit 4 Unit 4 has been operating at or near 100% power throughout this reporting period and has been on line since March 18, 1994.

4.0 Operational Safety Verification (30702, 40500, and 71707)

4. 1 Inspection Scope The inspectors verified that FPL operated the facilities safely and in conformance with regulatory requirements.

The inspectors evaluated the licensee's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and technical specification compliance, and review of facility

4.2 4.2.1 4.2.2 4.2.3 records.

By observation and direct interviews, verification was also made that the physical security plan, radiological controls, fire protection, fitness for duty, chemistry, emergency preparedness, and plant housekeeping/cleanliness conditions were appropriately implemented.

Inspection Findings Unit 3 Cycle 13 Coastdown As Unit 3 neared the end of the fuel cycle, the licensee implemented coastdown procedures per procedure TP-1039, Unit 3 Cycle 13 Coastdown.

This allowed continued operation of Unit 3 with decreased reactor coolant temperature and power when critical boron concentration reached 10 ppm.

The licensee implemented procedure TP-1039 on March 28, 1994.

This allowed reactor coolant temperature to decrease 4'F to compensate for fuel burnup without any boron concentration.

Then, reactor power was decreased to account for continued burnup.

The inspector reviewed the TP, Training Brief No. 452, the safety evaluation, and the licensee implementation.

The inspector noted that good shift briefings were held and that implementation was effectively conducted.

Unit 3 Shutdown/Cooldown The licensee commenced power reduction for the Unit 3 refueling outage on April 3, 1994.

At 12:18 a.m.

on April 4, 1994, the generator output breakers were opened.

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 5:25 p.m.

on April 4, 1994, and Node 5 at 4:05 a.m.

on April 5, 1994.

Node 6 was entered at 3:45 a.m.

on April 8, 1994, when the licensee commenced reactor head stud detensioning.

The inspectors observed portions of the shutdown, cooldown, and 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 adhered to.

Overall, observed activities were well performed and safely conducted.

Scaffold Program During a tour of the auxiliary building on the afternoon of April 4,

1994, the inspectors observed that a scaffold was in place over the 3A containment spray pump and another scaffold was over the 3B containment spray pump.

At the time, Unit 3 was in Mode 3 where technical specifications required two trains of containment spray to be operable.

Unit 3 went into Node 5 (where no containment spray is required to be operable)

the next day.

Tags on the

scaffolds indicated that one had been installed and inspected on March 29, 1994, and the other on April 4, 1994.

All parts of each of the scaffolds were securely fastened in place, and the scaffolds did not prevent operator access to safety-related equipment.

The scaffolgs were in place for planned outage work, on containment spray pump discharge valves.

On the afternoon of April 4, 1994, no work had begun on these valves, and plant conditions were not yet established for the commencement of that work.

The inspectors reviewed procedure O-ADM-012, Scaffold Control, which stated,

"Scaffolds shall be carefully planned and coordinated with the NWE/designee to ensure that scaffolds are not erected simultaneously over redundant pumps/components in a system in order to provide operability of at least one train of equipment under any foreseeable circumstance.

When scaffold erection over redundant pumps/components cannot be avoided, duration of the scaffold shall be kept to an absolute minimum and the NWE/designee shall be contacted before erecting."

The inspectors reviewed the scaffold control book in the control room and found it to be well organized.

Scaffold request forms for each of the scaffolds in question were in the book.

The forms clearly indicated that each of these scaffolds was to be erected over safety-related equipment and contained the required approval signatures including inspection by operators to ensure that there were no interferences with operation of safety-related equipment.

The NWE who had approved the installation of the second of the two scaffolds stated that he was aware at the time that it was to be installed over a second containment spray pump and that a scaffold was already in place over the other containment spray pump.

He was also aware of the words in the scaffold control procedure.

Further, he knew of at least two other instances where scaffolds were recently installed over both trains of a safety system in preparation for the Unit 3 outage.

The inspectors discussed this subject with the operations supervisor and plant general manager.

They had not intended that all of these scaffolds be built over both trains of safety-related equipment in preparation for the outage and stated that they would change the scaffold control procedure to require operations supervisor approval before installing scaffolds over both trains of safety-related equipment.

The inspectors concluded that operators were controlling and inspecting the installation of individual scaffolds.

The inspectors also concluded that, in this instance, there was no clear necessity for installing scaffolds over safety-related equipment while the equipment was required to be operable.

The installation of the scaffolds over both trains of containment spray was not conservative.

The inspectors plan to followup on the licensee's revision.to the scaffold control procedur.2.4 Overtime Issues 4.2.5 The inspectors reviewed licensee policy and procedures governing the use of overtime at Turkey Point.

Technical Specification 6.2.2 sets limits on the amount of hours that an individual is permitted to work over a period of specific times.

FPL Nuclear Division, nuclear policy NP-306, promulgates the policy governing overtime usage at Turkey Point.

Each department has an overtime documentation form that controls overtime approval and use.

The completion of the overtime documentation form by the individual and a review of the form by the supervisor prior to the individual working the overtime ensures compliance with Technical Specifications 6.2.2.

The inspectors determined that nuclear policy NP-306 clearly defined the expectations concerning overtime usage as required by technical specifications and that the process to control overtime usage through the use of the overtime documentation form should prevent unauthorized use of overtime above technical specification limits.

In addition, overtime data for the past two years was reviewed.

It was noted that in 1992, the electrical maintenance group had the highest use of overtime (approximately 18.8%);

and in 1993, the health physics group had the highest use of overtime (approximately 19%).

The site average was 13.9% for 1992 and 11%

for 1993.

Additionally, the overtime during outage periods was 30% in 1992 and 28.5% in 1993.

A downward trend in the use of overtime was noted.

Additionally, in the last two years, there were no cases involving approved overtime above the technical specification limit.

However, there were four cases in the last two years of individuals inadvertently exceeding overtime limits as defined in Technical Specification 6.2'.

The inspectors will continue to monitor licensee performance in this area.

Both Standby Steam Generator Feedwater Pumps Out of Service At 3:55 a.m.

on April 7, 1994, the licensee declared both the A

and B standby steam generator feedwater pumps to be out of service for Unit 4.

This was necessary in order to isolate a

common valve (4-20-130) in order to repair a Unit 3 valve (DWDS-3-012).

This system is common to both units.

Unit 3 was in a refueling outage and this system was not required to be operable for Unit 3.

However, it was required to be operable for Unit 4.

The action statement for Technical Specification 3.7.1.6 required that the system be restored within 30 days, that a 24-hour notification be made, and that a 30-day special report be submitted.

The licensee appropriately complied with these technical specification requirements.

The B pump was returned to service at 2:00 p.m.

on April 7, 1994, and the A pump was returned to service on April 13, 1994.

The inspector reviewed the special report (L-94-098) dated April 25, 1994, and the applicable condition report (No.94-232).

The

4.2.6 4.2.7 inspector also discussed the reporting issues, the maintenance activities, and the system requirements with licensee management personnel.

Portions of the post-maintenance surveillance test were also witnessed.

The inspector concluded that the licensee adequately addressed this issue including technical specification requirements and maintenance aspects.

Degraded 4A RHR Pump Room Sump In the 4A RHR pump room, the inspector observed that the metal screen over the room drain sump was mispositioned so that it did not cover the sump access and did not prevent debris from entering the sump.

In addition, debris was on the floor that could potentially enter the sump and interfere with sump pump operation, including a large rag, two plastic shoe covers, a small piece of wood, and a flashlight.

At the time, Unit 4 was in Node I, and the 4A RHR pump was required to be operable.

The inspector informed the NPS of this condition, and the licensee promptly corrected the condition and also checked that the other three RHR pump rooms had no similar conditions.

The operability of the RHR pumps was not affected.

Control Room Instrumentation and Control Panel Inspections The inspector observed a buildup of about one-half inch of fine loose dust in the bottom of a Unit 3 vertical instrumentation and control panel in the control room.

The dust was obscured by wires and cables but could be seen by using a flashlight.

In addition to the dust, there were also loose pieces of wire insulation and paper in the bottom of the panel.

Above the areas of dust buildup, there were large holes in the top of the panel where newer-looking cable conduit had been installed.

Above the holes in the top of the panel, there was no personnel access or loose object that could fall into the cabinet.

At the time, Unit 3 was defueled, and equipment affected by the panel was not required to be operable.

Other Unit 3 and Unit 4 control room vertical instrumentation and control panels had no holes in their tops and had much less dust inside.

The inspector was concerned that the dust and paper could potentially be ignited by a small heat source such as an electrical ground or short circuit.

The inspector informed the NPS of this condition, and the licensee promptly initiated a

condition report.

The condition report resulted in a prompt engineering fire analysis which concluded that there was no fire hazard because the weight of dust and paper was very small in comparison to the allowed fire loading of the control room.

The fire analysis also recommended that the dust and debris be removed from the panel.

The inspectors verified that the licensee cleaned the dust and debris from the pane.2.8 Uncalibrated HOV Position Indicators 4.2.9 In the Unit 4 CCW room, the inspector observed that the local position indicator for valve HOV-4-856B, HHSI Pumps Recirc. to RWST, indicated that the valve was 76% open.

This position indicator had a circular face (marked 0% to 100%) with a pointer.

The similar local position indicator for adjacent valve HOV-4-856A, HHSI Recirc. Isol. Valve to RWST, indicated 104% open.

At the time, Unit 4 was operating in Hode 1, and both of these valves were required to be open.

Each of these similar valves also had horizontal round bars attached to the vertical valve stem that protruded into vertical slots in the valve yoke and travelled up and down with valve movement.

There were no valve position markings by these vertical slots; but for both valves, the horizontal bars were much closer to the top of the slots than the bottom - indicating that the valves were most of the way open.

Further, the control room remote position indicators (lights)

indicated that the valves were open.

The inspector informed the NPS of the apparent incorrect reading of the local position indicator for valve HOV-4-856B.

Subsequently, the plant general manager informed the inspector that the licensee did not calibrate local HOV position indicators.

The plant general manager agreed that having local position indicators for safety-related valves that indicated incorrect valve positions was undesirable and that he would pursue the matter.

The inspectors plan to follow up on this issue.

Unit 4 Operations During Unit 3 Refueling Outage Activities The inspector reviewed the licensee's efforts to ensure that the Unit 3 refueling outage did not adversely affect continued Unit 4 power operations.

This effort was based on recent industry events involving wrong unit/train issues.

The licensee's preventive actions included the following:

the use of signs on Unit 4 informing/reminding personnel that the unit was at power (These signs were placed in the turbine and auxiliary buildings and at the entrances to vital electrical rooms.);

dissemination of recent industry events at pre-outage meetings held by the plant general manager; and continued reminders of the Unit 4 status at the daily and shift outage meetings, at shift turnover meetings, at management meetings, and at craft tailboard meetings.

The inspectors reviewed the licensee's efforts, monitored Unit 4 status, questioned workers in the plant, and attended meetings during the period.

The inspectors concluded that the licensee's

efforts appeared effective in assuring that Unit 3 outage activities did not adversely impact Unit 4 operation.

4.2. 10 CNRB Meeting No. 405 CNRB meeting (No. 405)

was held at Turkey Point on April 19, 1994.

The NRR Project Manager attended the meeting and verified that the following technical specification items were satisfied:

meeting frequency per Technical Specification 6.5.2.5, quorum per Technical Specification 6.5.2.6, and review and audit items per Technical Specifications 6.5.2.7 and 6.5.2.8; The following topics were discussed at this meeting:

a proposed license amendment regarding surveillance requirements for ISI and IST in addition to a proposed license amendment to change the containment spray system surveillance interval for Turkey Point Units 3 and 4, the Turkey Point Unit 3 Cycle 14 reload safety evaluation, a followup presentation on gA assuming ISEG technical review responsibilities, a review of LERs and NRC Inspection Reports, and audit review No. (AO-PTN-93-024.

NRC Inspection Report No. 50-250,251/94-01 noted that the 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 CNRB continued this performance during meeting No. 405.

5.0 Plant Events (93702)

5. 1 Inspection Scope The inspectors reviewed the following plant events to determine facility status and the need for further followup action.

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 and that licensee followup including event chronology, root cause determination, and corrective actions were appropriat.2 5.2.1 Inspection Findings Unescorted Visitor in the Protected Area On March 30, 1994, at approximately 9:40 a.m., the inspector noted an unescorted visitor on the second floor of the TSC building located within the protected area.

The inspector escorted the visitor to his assigned escort.

The visitor had earlier been allowed to go to the restroom without an escort.

The restroom was down the hallway and around several corners.

The inspector observed the visitor while the visitor was enroute from the restroom to the training room where his escort was located.

The escort was under the impression that there were not any exits between the restroom and the training room.

However, the inspector pointed out an obvious exit from the hallway.

The inspector notified the security department.

The security department performed a followup investigation and determined that the visitor should have been escorted to and from the restroom.

This event was also classified as a security loggable event (SIR No. 94-0330-1).

The escort was appropriately counselled and disciplined.

The inspector will closely monitor licensee performance in this area.

This failure to properly escort a visitor is a violation.

However, this violation will not be subject to enforcement action because the licensee's efforts in correcting the violation meet the criteria specified in Section VIII.B of the NRC Enforcement Policy.

This item will be tracked as NCV 50-250,251/94-07-01, Unescorted Visitor Within the Protected Area.

This item is closed.

5.2.2 Personnel Contamination Event On April 4, 1994, the inspectors observed the licensee's handling of a personnel contamination event.

After completing an inspection tour through most of the uncontaminated areas in the auxiliary building, the inspector set off an alarm in a personnel radiation monitor at the RCA exit.

By monitoring with a frisker, the inspector found that the bottom of his left shoe indicated about 120 cpm.

Site health physics personnel confirmed that the shoe was slightly contaminated and were able to decontaminate the shoe by scrubbing with a wet brush.

Health physics personnel then completed a personnel contamination report, a radiological investigation report, and a condition report.

As a part of this process, site health physics personnel checked the areas through which the inspector had walked (with entire room smears)

and found no contaminated areas.

The licensee stated that this was the first personnel contamination event of the Unit 3 outage.

The inspectors concluded that the licensee's handling of this personnel contamination event was prompt and thoroug.2.3 5.2.4 Personnel Injury - Climbing Without Fall Protection At about 5:00 a.m.

on Apr'il 5, 1994, an operator fell inside containment and injured his elbow when it caught between two pipes.

The operator had been climbing about seven feet above the floor to reach a valve and was not using any fall protection (ladder, scaffold, or safety belt).

The operator was taken for medical examination and X-ray to verify that the injury was not serious and was returned to a work status.

The inspectors questioned plant safety personnel about the site and OSHA height limits for free climbing without fall protection.

Plant safety personnel stated that the operator had been climbing in an area where a ladder or scaffold could not be used and that a

safety belt with a standard six foot line would not have prevented this injury.

They found that the site had no height limit for climbing without fall protection.

OSHA had various height limits for working aloft without fall protection for different industries or applications.

For example, the limit for maritime was five feet, and the limit for construction was ten feet.

The site construction contractor used a limit of ten feet for climbing without fall protection, and St. Lucie nuclear plant also used a

limit of ten feet.

The plant safety personnel stated that a site height limit for climbing without fall protection was needed and that they would promulgate one.

The inspectors concluded that the injury was not caused by climbing excessively high without personnel fall protection.

However, the lack of a specified height limit for climbing without fall protection was a deficiency in the licensee's safety program.

The inspectors plan to follow up on the establishment of a site height limit for climbing without fall protection.

Loss of Unit 3 CCW System Capability Due to Air Binding At 7:30 a.m.

on April 18, 1994, with Unit 3 defueled (all fuel in the SFP)

and the 3A CCW header out of service, the 3C CCW pump was secured and placed in pull to lock due to indications of air binding.

This resulted in a loss of all CCW flow because the 3A and 3B CCW pumps were already out of service.

Procedure 3-ONOP-030, Component Cooling Water Malfunction, was entered, and an operator was dispatched to the SFP to monitor temperature.

The SFP temperature was reported to be 122'F, and the predicted SFP heatup rate was 13.5'F per hour.

The licensee vented the CCW system high points and the 3C CCW pump casing per procedures 3-ONOP-030; 3-0P-030, Component Cooling Water System; and TP-1033, Draining of 3A and 3B Component Cooling Water Headers.

The licensee continued to remove entrained air following the restart of the 3C CCW pump at 8: 11 a.m. with the discharge valve throttled.

CCW header flow was re-established at 8:20 a.m.,

the 3C CCW pump discharge valve was opened, and pump discharge pressure was stabilized at 110 psig.

At this time, local SFP

temperature was reported to be 124'F.

The highest local SFP temperature reported was 125'F at 8:35 a.m.

The licensee attributed this event to improper configuration of the temporary drain/pump-back system.

The 3A CCW header was being drained for maintenance work, and the drained fluid was being recirculated to the 3B CCW header without adequate CCW surge tank venting of the air entrained in the fluid.

Both the 3A and 3B CCW header drain schematics (attachments 1 and 3 of procedure TP-1033)

had the draining CCW header water inventory recirculated via a temporary pneumatic air pump to valve 3-1173.

This valve is the temporary drain supply isolation valve which can supply water to the CCW 3B train line from the CCW surge tank.

Valve 3-709 is the complimentary CCW 3A train valve.

Both of these lines are connected to different ends of the CCW surge tank, and the surge tank contains an internal baffle to provide partial separation within the tank.

The licensee determined that if the draining 3A CCW header water inventory had been routed to valve 3-709 (3A train) versus valve 3-1173 (3B train), then the draining air entrained water would have been returned to the CCW system via the 3A train side of the surge tank and that this would have prevented the air entrained water from entering the 3B CCW header and subsequently the operating 3C CCW pump.

Using this logic, the 3B CCW header drain schematic would have correctly performed this function via valve 3-1173.

Another plausible method would have been to supply the air entrained water to the top of the CCW surge tank.

5.2.5 In order to correct this situation, the licensee stopped recirculating the draining 3A CCW header water back to the 3B CCW header'and aligned the drainage to the storm drain per procedure TP-1033.

The licensee also performed a vibration check of the 3C CCW pump on the following day, and no problems were identified.

In order to prevent recurrence of this event, the licensee plans to discontinue the use of this procedure when the Unit 3 CCW system work scope is completed (by June 1, 1994).

The licensee also generated a condition report (No. 94-0402)

and interviewed all personnel involved.

The inspector was in the control room at the time of the event and monitored the licensee's response activities.

Operations personnel promptly responded to mitigate the consequences and restore cooling to the SFP heat exchangers.

The inspector also reviewed the licensee's condition report, reviewed procedure TP-1033, and discussed the event with licensee management.

The inspectors plan to follow up on any future use of this TP.

Waste Holdup Tank Overflow On April 27, 1994, a non-licensed operator assigned to the auxiliary building noted during his rounds that the No.

WHT level gauge was pegged high.

The waste evaporator feed pump which

was being used to transfer radioactive water from No.

WHT to the No.

WHT was secured.

It was later confirmed that No.

WHT had overflowed as an estimated 2800 gallons of water was observed in the berm that houses the No.

WHT located within the radwaste building.

The sources of water being pumped into No.

WHT included laundry discharges and containment sump discharges.

The berm is designed to contain spills from the No.'

WHT.

Upon discovery, a condition report (No.94-516)

was originated.

The inspector walked down the portions of the liquid waste disposal system and discussed the event with the operations manager.

While the investigation is not complete, there are several factors that may have contributed to the event.

These factors include the electrical logic for the waste evaporator feed pump switch, level annunciation, and administrative controls associated with the transfer evolution.

The spill did not result in any inadvertent discharges outside the RCA, any increase in the contaminated floor space, or any significant radiation contamination or exposure.

Licensee corrective actions will be based on the root cause determination of the problems.

The inspectors determined that the license is aggressively pursuing the resolution of the problem.

The inspector plan to monitor the issue through,its final resolution as well as monitor licensee performance in this area.

6.0 Maintenance Observations (62703)

6.1 6.2 Inspection Scope The inspectors observed selected station maintenance activities of safety-related systems and components and reviewed to ascertain they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the technical specifications.

Inspection Findings Maintenance Observed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

procedure O-GMM-043.7, Reactor Vessel Stud Detensioning; procedure O-GME-102.8, Motor Operated Valve Operator, Inspection and Overhaul; various procedures and PWOs for the overhaul inspections of the 3A and 3B EDGs;

6.2.2 procedure O-GMN-043.6, Reactor Vesse]

Cavity Seal Ring Installation (Refer to section 6.2.2 for additional information.);

troubleshooting of the Unit 3 containment upender malfunctions (Refer to section 10.2.4 for additional information.);

and several activities involving erosion/corrosion inspections and repairs.

(Refer to section 10.2.5 for additional information.)

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.

Unit 3 Reactor Cavity Seal Leak The inspectors noted that the Unit 3 seal leak rate was about 1.5 gpm with the cavity at normal operating water level (57 feet).

The seal is designed with a redundant safety-related passive seal and a backup inflatable (non-safety-related)

boot.

Licensee procedure 3-0P-201, Filling/Draining the Refueling Cavity and the SFP Transfer Canal, requires a leak check prior to, during, and after cavity filling.

The leak rate was about 2 gpm prior to inflating the backup boot seal.

Acceptance criteria was less than 5 gpm.

The inspector questioned operation and engineering personnel regarding the historical seal leak rates.

For the previous two refueling outages, the leak rate was 0. 1 gpm (October 1992)

and 0.4 gpm (Nay 1990).

The inspector reviewed plant drawings, training information, and PC/N Nos. 86-14,87-100, and 91-116.

The current seal was modified in 1986/87 in response to NRC Bulletin No. 84-03.

After core offload, the licensee drained the cavity and checked for possible leak paths.

This included the NIS well and sandbox (shield) covers and the cavity well liner as well as the seal.

The licensee inspected and resealed all of the well covers and also noted that the liner leak tracing system indicated a small leak.

The licensee proceeded to fill the cavity for core reload.

Once again the necessary leak checks were performed.

The liner leak tracing system indicated a leak of 0. 1 gpm with total leak rate of about 1.7 gpm.

Although this was within the acceptable design leak rate, the licensee initiated actions to monitor for and determine the leakage source.

At the close of the inspection, no cause could be found.

This issue will be tracked as IFI 50-250,251/94-07-02, Cavity Seal Leakage During Refuelin.0 Surveillance Observations (61726)

7.1 Inspection Scope The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance packages.

The inspectors verified that the surveillance tests were performed in accordance with technical specification approved procedures and NRC regulations.

7.2 Inspection Findings 7.2. 1 Surveillance Tests Observed The inspectors witnessed/reviewed portions of the following test activities:

/

procedure TP-1011, Unit 3 Safety Injection Accumulator Check Valve Full Flow Test; DP testing of valves HOV-3-843A and B per procedure TP-1027, Differential Pressure Testing of Safety Injection Hotor Operated Valves HOV-3-869 and HOV-3-843A h B; operability testing of the 3B EDG per procedure 3-0SP-023.1, Diesel Generator Operability Test; procedure 3-0SP-051.5, Local Leak Rate Tests; procedure O-OSP-074.3, Standby Steam Generator Feedwater Pumps Availability Test (Refer to section 4.2.5 for additional information.);

and procedure 3-0SP-072.5, Hain Steam Safety Valve Setpoint Verification Test.

(Refer to'section 7.2.2 for additional information.)

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

7.2.2 Hain Steam Safety Valve Test During the performance of the main steam safety valve setpoint test on April 4, 1994, the inspector observed the test activities to be well organized and to proceed smoothly.

The test supervisor effectively coordinated and directed test activities and witnessed setpoints that were measured and recorded.

The inspector noted that the test procedure required no gC involvement and also required no independent verification of any data.

The inspector also noted that the procedure did not require

that the as-found condition of the valves be noted as satisfactory or unsatisfactory.

On completion of the test, the test director stated that seven of the nine valves tested lifted low, outside the plus or minus 1% technical specification acceptance criteria.

As part of the test procedure, those seven valves had been adjusted and retested to lift inside the specified pressure range.

The inspector found that the data for another valve indicated that it also lifted low (by about 4 psig)

on its initial test.

That valve had subsequently lifted within the specified pressure range with no adjustments.

The test director agreed that the as-found condition of that valve was also unsatisfactory.

The inspector noted that after the as-found condition of several valves was found to be unsatisfactory, the testing scope was not increased to include the other three main steam safety valves.

The test supervisor, who was also the IST coordinator, stated that increasing the testing scope used to be required but was not under the new IST program, which had recently been submitted to the NRC and which the licensee had elected to become effective for Unit 3 in February 1994.

The inspector reviewed the new IST program's referenced ASHE Code Section XI, 1989 edition; OMA Part 10; and OHA Part 1 of 1987, Requirements for Inservice Testing of Nuclear Power Plant Pressure Relief Devices.

OHA Part 1 addressed only corrective action for periodic testing of installed valves that tested outside of plus or minus 3%.

All nine of the licensee's main steam safety valves tested this time had lifted within plus or minus 3% of the specified setpoint.

The inspector checked with NRR technical personnel who confirmed that the new code requirements were not clear and that they did not, in this case, require that the testing scope be increased.

The inspector asked if a condition report would be written on the eight main steam safety valves whose as-found condition was unsatisfactory.

A condition report would initiate a safety review of plant operation with the out-of-tolerance condition and would also initiate consideration of long-term corrective action to prevent recurrence.

The test director and IST coordinator stated that in this case a condition report would be initiated because the plant general manager had asked for one.

'However, he stated that a,condition report was not otherwise required because the out-of-tolerance conditions had been corrected within the procedure.

He stated that main steam safety valves had in the past routinely been found during IST to lift outside of the technical specification acceptance criteria and condition reports (or their predecessor, nonconformance reports)

had not been written.

The inspector found that neither procedure 3-0SP-072.5, Hain Steam Safety Valve Setpoint Verification Test, nor procedure O-ADH-502, In-Service Testing (IST) Program, addressed the use of condition reports nor nonconformance reports.

However, procedure O-ADH-518, Condition Reports, stated that ASHE Section XI failures shall be

documented as a nonconformance on a condition report.

It also stated that for discrepancies associated with setpoints, conditions that may affect operability were required to be documented in a condition report.

CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires that for significant conditions adverse to quality, corrective measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.

IST of valves and pumps was performed by operators.

An operations NPS, an STA, and the operations supervisor stated that they were not aware of a requirement to write a condition report if a valve or pump failed an IST and that, to their knowledge, condition reports had not been written for past IST failures.

The inspector reviewed condition report No.94-211 which stated that seven of the nine main steam safety valves tested on April 4, 1994, lifted outside the technical specification allowable range of plus or minus 1%.

The condition report referenced safety evaluation No. PTN-SEFJ-94-009, which concluded that the as-found main steam safety valve set pressures would not have resulted in any detrimental impact on plant safety limits at any time during Cycle 13.

It also stated that long-term corrective action in the form of a technical specification change request had already been initiated (to change the technical specification allowable range to plus or minus 3%).

The condition report concluded that no further action was required except to complete an evaluation for reportability.

The inspector reviewed the one other IST conducted during this outage that had failed.

In that case, the 3A boric acid transfer pump had failed its IST because a test gauge had failed.

With a replacement test gauge, the pump passed the IST.

The inspector concluded that the lack of IST program supervisory personnel knowledge of and IST procedure guidance on the need to initiate a condition report for IST failures was a deficiency.

The condition report that was written for the main steam safety valve setpoint test was adequate.

The inspector found no other r'ecent valid IST equipment failures that would need a condition report.

The licensee plans to revise procedure 0-ADM-502 to require that ASHf Section XI failures be documented as a

nonconformance on a condition report.

In addition, the licensee plans to revise procedure 3-0SP-072.5 to require independent verification of the test data and to include a determination of the as-found condition of each tested valve as satisfactory or unsatisfactory.

The licensee's corrective actions for this IST program deficiency will be tracked as IFI 50-250,251/94-07-03, Licensee Corrective Actions for IST Progra.0 Followup on Previous Items and Noncompliances (92701)

8.1 8.2 8.2.1 Inspection Scope The inspectors reviewed the following open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

Inspection Findings (Open) IFI 50-250,251/93-26-03, Safety Injection Pump Motor Rotor Bar Cracking During this inspection period, the licensee completed inspections at the vendor's facility for the 4B HHSI pump motor.

No rotor bar cracking was identified.

To date, the 4A and 4B HHSI pump motors have been replaced with upgraded (swaged) rotor bars.

Further, the motor vendor (Westinghouse)

issued technical bulletin No.

NSD-TB-94-01-20 describing the issue.

(Refer to NRC Inspection Report Nos. 50-250,251/93-26 and 93-29 for additional information).

The licensee has also revised condition report No.93-953.

Based on the 4B HHSI pump motor inspection results, the licensee delayed the scheduling for the 3B and 3A HHSI pump motor replacements from March and July 1994 to July and December 1994, respectively, (e.g. after the refueling outages).

The inspector reviewed the vendor bulletin and discussed the issue with licensee engineering and management personnel.

The IFI remains open pending completion of 3A and 3B HHSI pump motor change-outs with modified (swaged) rotor bars.

9.0 Onsite Followup and In-Office Review of Written Reports and

CFR Part 21 Reviews (90712, 90713, and 92700)

9.1 9.2 9.2.1 Inspection Scope The inspectors 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.

Inspection Findings Honthly Operating Report The inspectors reviewed the Harch 1994 Honthly Operating Report and determined it to be complete and accurat.2.2 (Closed)

LER 50-250/92-010, Containment Ventilation Isolation and Control Room Ventilation Isolation Due to Spurious Signal At 1:45 p.m.

on October 2, 1992, a spurious actuation signal caused a containment ventilation isolation and control room ventilation isolation while Unit 3 was in Node 6.

This engineered safety feature actuation was caused by welding in the immediate vicinity of the R-3-11/R-3-12 radiation detectors.

Following this event, the licensee installed a new R-ll/R-12 skid for Unit 3 and tested it for sensitivity to welding in the area by striking an arc immediately adjacent to the skid and noting the effect on the control room indications.

Three tests were performed on November ll, 1992, with the welding machine located to the left, right, and center of the new skid-mounted monitors.

Prior to the tests, the key-lock bypass switches were placed in bypass, and the operator was requested to note any increase in readings or alarms.

The results of the welding test were negative.

There was no detectable increase in background for either R-3-11 or R-3-12, there was no detectable increase on the ERDADS user trend, and no alarms were received.

In addition to these actions, the licensee revised procedure 0-ADN-046, Control of Welding Special Processes, on November 25, 1992, to include a warning about the potential for spurious signal generation during welding processes near electromagnetic equipment.

The licensee also posted placards near each unit's R-11/R-12 skid on December 12, 1992, to request workers to notify the control room of welding activities near the R-ll/R-12 skid prior to striking an arc within 25 feet of the machine.

The inspector verified the test results and completion of the referenced corrective actions by reviewing portions of the test data (including an ERDADS trend graph and photographs of the welder's location during the welding), portions of condition report No. 92-0196, the corrective action forms, the commitment tracking system printout, and the PNSC approved procedure changes.

The licensee's corrective actions were effective and appropriate.

This LER is closed.

9.2.3 (Closed)

LER 50-250/92-011, Failure of Source Range Neutron Detectors At 4:25 a.m.

on October 8, 1992, with Unit 3 in Mode 6 and Cycle 12 fuel offload in progress, the licensee declared source range neutron detector N-31 out of service due to high count rate (greater than 1500 cps).

As a result, the licensee used a

combination of source range neutron detector N-32 for audio and visual indication and one backup flux monitor for visual indication to meet the minimum requirements of Technical Specification 3.9.2.

At 1:09 a.m.

on October 9, 1992, fuel assembly DD-16 (the only.fuel assembly in the core with a

secondary source assembly)

was offloaded; and at I:30 a.m., the licensee noticed that there was no audio count rate and ceased fuel movement.

Following the performance of procedure 3-OSP-059.6, High Flux at Shutdown, the audio count rate was re-established at 2:I5 a.m,,

and fuel movement was recommenced.

The licensee completed the core offload at 6:06 a.m.,

and primary source range detector N-32 was declared out-of-service at 8: 14 a.m.

due to high count rate (greater than 400 cps)

when a reading of less than 10 cps was expected following core offload.

On October 14, 1992, the licensee determined that both primary source range neutron detectors had degraded to the point of failure.

Degradation of the N-32 detector was gradual over several days.

This raised the possibility that during the last steps on the core offload procedure, Unit 3 core alternations may not have been performed in accordance with Technical Specification 3.9.2.

Apparently, the N-32 source range indication had increased to approximately 500 cps during some point in the offload, and this value was less than the setpoint limit on the source range high flux at shutdown alarm.

As a result, the alarm did not annunciate.

The fact that the detector had failed was only discovered after the offload was completed and the detector count rate had not dropped off.

Based on the ERDADS trend report and the fact that the audio indication on detector N-32 was lost almost immediately after the only fuel assembly in the core with a secondary source assembly (fuel assembly DD-16) was offloaded, the licensee concluded that the N-32 detector was operable up to this point.

Therefore, the period from 2:15 a.m. to 6:06 a.m.

on October 9, 1992, represents the only time interval that the operability of the N-32 detector was in question.

However, based on the core offload pattern and the relative assembly power and burnup conditions of the remaining assemblies, minimum reactivity changes would have been expected during that interval.

In addition, the bases for Technical Specification 3.9.2 states that the operability of the source range neutron flux monitors ensures that redundant monitoring capability is available to detect changes in the reactivity condition of the core.

Since the detector degradation was gradual over several days, the licensee was unable to definitively state whether or not the N-32 detector could have performed its intended function of detecting changes in reactivity during the time interval when the operability of the N-32 detector was in question.

However, during this time frame, both backup source range neutron flux monitors (gammametrics)

were operable, and no positive reactivity changes were noted.

Following the offload, the N-31 and N-32 detectors were removed from their wells, inspected, and tested.

Both detectors were found to be wet as a result of the failure of the detector cover gaskets during the refueling operation.

In addition, evidence of some boric acid crystals was present.

The presence of moisture in

the detector assembly was believed to be the cause for the detector failures.

The detector failures were non-catastrophic; taking place over a period of several days due to the wet condition of the detector.

As the performance of the detector degraded, the noise level increased and the detectors'ensitivity to neutrons decreased.

The licensee determined that the gaskets for the NIS access covers had been installed wi'th the wrong gasket material due to a lack of design information/plant procedures which dictate the proper gasket material and gasket installation procedures (i.e., mounting hardware, torque requirements, RTV applications)

and due to a failure by plant personnel to specify the proper gasket material.

Prior to the 1993 Unit 3 Cycle 13 reload, the licensee replaced sour'ce range neutron detectors N-31 and N-32 and installed the NIS well covers with the proper gasket material.

The licensee also revised procedures O-CMI-059.8, Replacement of Source Range and Intermediate Range Nuclear Instrumentation Detectors, and 0-CMI-059.9, Replacement of Power Range Nuclear Instrumentation Detectors, on December 8,

1992, to reflect the proper gasket material, mounting hardware, torque requirements, RTV application, and RTV cure time.

A field supervisor hold point was also added to these procedures for tightening the well cover nuts in order to verify proper torque values.

In addition, the licensee revised plant drawing No. 5610-C-209, Reactor Refueling Pit Liner Plate Details, on January 11, 1993, to reflect the proper gasket material, mounting hardware, and torque requirements.

The drawing was not revised for RTV application or cure time because this information was included in the appropriate procedures.

The inspector reviewed the procedure and drawing revisions and verified that the licensee's corrective actions had been taken.

The effectiveness of these corrective actions was also verified during the monitoring of the core offload and reload activities for the current 1994 Unit 3 Cycle 14 refueling outage.

NIS cover leakage was not a problem during this outage.

As a result, this LER is closed.

9.2.4 LER 50-251/94-002, Plant Shutdown Required Due to Reactor Coolant System Pressure Boundary Leakage This LER was issued by the licensee as a result of the technical specification required Unit 4 shutdown that was initiated on March 10, 1994.

A small, non-quantifiable pressure boundary leak on a

flux mapper guide tube was identified by the licensee that resulted in the Technical Specification 3.4.6.2, Operational Leakage, required unit shutdown.

The affected section of the guide tube and associated fitting adapter was removed, and a new fitting adapter was installed.

The RCS was pressure leak tested following the repairs, and subsequently, Unit 4 was returned to service.

The licensee determined the root cause to be transgranular stress corrosion cracking due to chloride

contamination from improper cleaning techniques.

The licensee will review the post-maintenance cleanliness measure for potential enhancements.

9.2.5 9.2.6 The inspector reviewed this LER including root cause and corrective action and determined it to be appropriate with a sufficient level of detail.

In addition, this issue was discussed in sections 5.2. 1 and 6.2.6 of NRC Inspection Report No. 50-250,251/94-05.

Based on this, this LER is closed.

LER 50-251/94-003, Four Analog Rod Position Indicators Greater than Twelve Steps from Group Step Counter; Technical Specification 3.0.3 Entry This LER was issued by the licensee as a result of a condition on Unit 4 that resulted in an entry into Technical Specification 3.0.3 on Narch 18, 1994.

The condition involved four analog RPIs in control bank D indicating more than twelve steps from the group step counter which was indicating 190 steps.

Technical Specification 3.0.3 was entered as there is no technical specification action statement for more than one inoperable RPI within a bank.

An incore flux map verified that the rods were at 190 steps and that the RPIs were in error.

The RPIs for the four rods were adjusted, and Technical Specification 3.0.3 was exited.

The inspectors reviewed the LER as well as observed licensee's actions during the event.

The inspectors noted that Unit 4 was in Technical Specification 3.0.3 for approximately 10 minutes and that the determination to issue an LER was conservative.

The inspectors concluded that overall response to the problem was appropriate.

This issue was also discussed in section 5.2.2 of NRC Inspection Report No. 50-250,251/94-05.

This LER is closed.

CFR Part 21'eview The inspectors reviewed licensee actions associated with a

CFR Part 21 notification involving failures of components in the Westinghouse Eagle-21 plant protection system.

The Part

notification was issued by Zion on April 8, 1994.

The first problem involved failure of capacitors causing a loss of power supply voltage.

The defective capacitors were supplied over a specific time,period.

The licensee determined that the capacitors utilized at Turkey Point were supplied during a

different time period as well as by a different manufacturer.

Therefore, the licensee determined that this particular problem was not applicable to Turkey Point.

The second problem involved failure of Douglas-Randall time delay relays used in the Eagle 21 plant protection system.

This was caused by failure of a capacitor due to heating within the module caused by a resistor in close proximity of the capacitor.

The

licensee has contacted Westinghouse to determine if Turkey Point is susceptible to the same failure mode.

In addition, the licensee performed an operability assessment (No. 019-94)

and determined that if a failure of the capacitor were to occur, the protection channel would trip.

This would place the RPS from a two-out-of-four trip matrix to one-out-of-two trip matrix.

The failure would therefore not prevent a unit trip from occurring.

Notwithstanding the above, if Westinghouse determines that Turkey Point is susceptible to the problem, the licensee plans to consider whether or not a modification will be performed.

The inspector reviewed the operability assessment as well as discussed the issue with the licensee and determined that the licensee's approach to the resolution associated with the subject Part 21 notifications was aggressive and appropriate.

10.0 Unit 3 Refueling Outage Activities (60710)

10. 1 Inspection Scope The inspectors performed a review of the licensee's activities during the Unit 3 refueling outage.

10.2 Inspection Findings 10.2. 1 Unit 3 RCS Draindown In order to support Unit 3 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/midloop operation (less than 3.0 feet below the RPV flange).

However, the inspectors reviewed the following documents:

generic letter No. 88-17 and FPL responses to this generic letter; operating procedures 3-0P-041.7, Draining the Reactor Coolant System, and 3-0P-041.9, Reduced Inventory Operations; abnormal operating procedure 3-0NOP-050, Loss of RHR; surveillance procedure 3-OSP-051. 14, Reduced Containment Penetration Alignment Verification; various plant drawings; training lesson plans and system description No. 007, Reactor Coolant System; control room log books; and

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refueling outage schedules.

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

Level devices LIS-6421 and LIS-6423 provided remote readout in the control room, and a tygon level tube device, LI-6422, provided indication in the containment.

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

The inspectors also verified that redundant temperature devices were available, were being used and logged, and were within tolerances.

These temperature devices included RHR pump and heat exchanger, wide range loop cold leg, wide range loop hot leg, gSPDS, and ERDADS readouts.

Prior to draindown, the inspectors toured the containment to review and verify availability of installed instrumentation, vent and drain devices, personnel, and associated radiological and operational conditions.

The inspectors noted that I&C personnel were completing the calibration of the LIS-6421 and LIS-6423 devices.

The inspectors also verified that operations and IKC personnel in the containment were knowledgeable relative to level device operation and calibration, draindown procedures, and overall draindown precautions.

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

The licensee performed draindown during the afternoon of April 6, 1994.

Level was maintained at 50% on LI-6421 and LI-6423 and at 5 feet

inches on LI-6422.

This corresponded to about 1.5 feet below the RPV flange.

The inspectors noted that once a steady level was obtained, no further readings were obtained from LI-6422 (containment tygon tube).

Although this was in accordance with licensee procedures, it appeared prudent to periodically monitor and record LI-6422 indications.

The inspector discussed this issue with licensee operations personnel, and the licensee modified its requirements such that a shiftly (once per eight hours) reading of LI-6422 was taken and documented.

The inspector concluded that the licensee demonstrated conservatism in its decision not to go to midloop with fuel in the vessel, but rather to wait until complete core offload.

Further, licensee actions to drain the RCS to 1.5 feet below the flange were effectively conducted with good procedure compliance and with strong oversigh ~

~ I

10.2.2 Unit 3 Containment Tours During the inspection period, periodic tours of the Unit 3 containment were performed.

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 items.

The inspectors concluded that the overall containment conditions were adequate.

Some areas indicated less than adequate housekeeping.

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 effectively controlling the radiological aspects of work in progress in the containment.

10.2.3 Unit 3 RPV Disassembly The licensee utilized procedures 3-OP-038. 1, Preparations for Refueling Activities, and 3-0P-038.9, Refueling Activities Checkoff List, for the prerequisites, precautions, limitations, and instructional guidance to perform the necessary checks and surveillances prior to RPV head stud detensioning, reactor disassembly, refueling, and the start of any core alterations.

At 3:45 a.m.

on April 8, 1994, the licensee began detensioning the Unit 3 RPV head studs, and Unit 3 entered Mode 6.

The incore thimbles were retracted by 9:50 p.m.

on April 10, 1994, and the RPV head was lifted and placed on its stand at 3: 15 a.m.

on April 11, 1994, 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 were also lifted and placed on the stand at 8:00 p.m.

on the same day per procedure O-GMM-043.9, Reactor Vessel-Removal of Upper Internals.

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

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

10.2.4 Unit 3 Core Offload and Reload In addition to the refueling preparations made via the procedures referenced in section 10.2.3 above, the licensee utilized procedure 3-0P-040.2, Refueling Core Shuffle.

Procedures TP-1051, Unit 3 Cycle 13 Core Offload, and TP-1053, Unit 3 Cycle 14 Core Reload, were also utilized for the core offload and reload activitie The licensee commenced fuel offloading at 12:40 a.m.

on April 12, 1994, and fuel movement was stopped at 2:20 p.m.

due to a

malfunction of the containment upender assembly.

It stopped at a

45'ngle with a fuel assembly inside.

As a result, the licensee entered procedure 3-ONOP-038. I, Fuel Transfer System Hanual/Emergency Operation.

Investigation revealed that one of the fuses for the frame hoist motor had blown a'nd that the power supply breaker had not tripped.

In accordance with procedure 3-ONOP-038. 1, the licensee attempted to manually lower the upender, but the upender would not move in manual.

A vendor representative determined that there may have been a problem with the gear box.

The upender was successfully restored to the upright position at 8:40 p.m.,

and the fuel assembly was returned to the core at 9:52 p.m.

The licensee formed an ERT and continued to troubleshoot the malfunction.

Condition report No.94-313 was also generated to determine if the proper fuse was used.

Engineering subsequently recommended that Fusetron time delay FRS-R-15 fuse be used in lieu of an ECO one-time B96-77 fuse.

Both fuses are 15-amp, 600-volt fuses.

As an enhancement, the licensee replaced the blown fuse with a time delay fuse, and a plant manager action item was issued to engineering to update the Unit 3 drawings to show the correct size and type fuse.

(These fuses had been installed on Unit 4 during the last refueling outage.)

The licensee also installed a

replacement hoist for the containment fuel upender assembly so that additional investigations could be performed on the gear box.

The malfunctioning hoist had a cast iron motor end bell, and the replacement hoist had a light-weight aluminum motor end bell.

Following successful testing of the fuel transfer system, the licensee began moving fuel again at 11:00 p.m.

on April 13, 1994.

At 5:48 a.m.

on April 14, 1994, the containment upender assembly stopped again at a 45'ngle with a fuel assembly inside.

The licensee manually lowered the upender and transferred the cart containing the fuel assembly to the SFP.

Inspection revealed a

large (270') circumferential crack on the aluminum motor end bell, but the motor end play measurements were within acceptable tolerances.

The aluminum motor end bell was replaced, and the new end bell cracked in half during testing.

The licensee was unable to manually engage the hand crank on the upender motor, and it was noted that the shaft was moving horizontally.

The drive spindle engaging nut had spun off the main shaft, the cotter pin for the drive spindle engaging nut (which should have been installed by the vendor during hurricane recovery)

was missing, and the motor rotor on the opposite end of the hoist was protruding by approximately three quarters of an inch.

As a result, the licensee replaced the end bell, torqued the drive spindle engaging nut, and installed a roll pin in lieu of a cotter pin in order to provide increased shear strength.

A caution was also added to the operating procedure regarding excessive forc Following successful testing of the fuel transfer system, the licensee began moving fuel again at 2:30 a.m.

on April 15, 1994.

The licensee completed core offload at 12:30 p.m.

on the following day.

Core reload was commenced at 1: 10 p.m.

on April 27, 1994, and Mode 6 was entered when the first fuel assembly was 'placed in the core at 2:26 p.m.

Core reload was completed at 6:52 p.m.

on April 29, 1994.

The inspectors observed portions of these activities and reviewed the applicable procedures.

An inspector also attended one of the ERT meetings on April 12, 1994, reviewed the condition report, and followed up on the licensee's efforts in troubleshooting the containment upender malfunctions.

These activities were performed in a professional manner, and interdepartmental teamwork was noted.

10.2.5 Erosion/Corrosion, Steam Generator, and ISI Activities During the Unit 3 refueling outage the licensee performed inspections, assessments, and repairs associated with the erosion/corrosion program, the steam generator tubes, and ISI activities.

This included involvement by FPL corporate and site groups and by contractor organizations.

Erosion/corrosion inspections and ISI activities were performed in accordance with approved program plans.

The licensee performed inspections of 100% of the steam generator tubes, with the following tube plugging results:

steam generator 3A - one; steam generator 3B - two (one repair);

and steam generator 3C - two.

The licensee documented this in a letter to the NRC (L-94-114) dated May 2, 1994.

Erosion/corrosion inspections noted piping below minimum wall thickness for the MSR drain lines, extraction steam lines, and in the turbine cross over and cross under piping.

Appropriate repairs were made.

The inspectors observed a sampling of the above mentioned activities including field work, data retrieval and assessment, and repairs.

Further, NRC Inspection Report No. 50-250,251/94-08 also documented inspections in this area.

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

No negative findings were identified.

11.0 Design, Design Changes, and Modifications (37700 and 37828)

Inspection Scope The inspectors reviewed selected PC/Ms including the applicable safety evaluation, infield walkdowns, as-built drawings,

11.2 11.2.1 associated procedure changes and training, modification testing, and changes to maintenance programs.

Inspection Findings Unit 3 Temporary Spool Piece on Penetration 65A During the current Unit 3 refueling outage, the electrical cables and hoses required to perform eddy current testing and sludge lancing activities on the steam generators were temporarily installed through ILRT penetration 65A.

During previous outages, the cables were routed through the equipment hatch.

The technical specification requirement to have the equipment hatch closed during fuel alterations interrupted the steam generator related activities.

To avoid these interruptions, the licensee installed a temporary spool piece and bolted it to the outboard flange associated with penetration 65A.

The electrical cables and hoses for steam generator related activities were routed through the spool piece.

The spool piece is designed to prevent communication between the containment and outside atmosphere during fuel movement activities at zero containment pressure conditions.

In addition, the spool piece had the capability to be closed with a blind flange for a condition that results in a higher containment pressure.

The inspectors reviewed the safety evaluation (No. JPN-PTN-SEMS-93-012) associated with the temporary installation.

Additionally, the inspectors witnessed portions of the installation of the spool piece, the use of the spool piece while fuel movement was in progress, and the procedure and staging material in place for the installation of the blind flange if required.

The inspectors did not note any deficiencies in the evaluation or in its implementation.

The spool piece was used only during the defueling activity.

The spool piece was removed, and penetration 65A was local leak rate tested to assure containment integrity.

11.2.2 'C/M No.93-041, Turkey Point Unit 3 Cycle 14 Reload The licensee initiated PC/M No.93-041 for the Unit 3 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.

The inspector reviewed the package for PC/M No.93-041 including the design bases and analyses, the safety evaluation, core loading plan, and other pertinent data.

The inspector 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 No.93-041 was well documented and

11.2.3 adequately implemented by refueling procedures.

(Refer to section 10.2.4 for appropriate procedures.)

PC/H No.93-047, Annunciator Dark Board Modifications, for Unit 3 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.93-047 on Unit 3 this refueling outage.

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

Thirteen Unit 3 alarms were in this condition (e.g. illuminated normally).

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

These alarm windows effected included RCP seal water bypass, source range high/loss voltage, gland steam exhauster stopped, breathing air trouble, RHR seal exchanger high/low flow, PAHHs trouble, reactor vessel draindown level, desuperheater temperature/pressure, battery charger trouble, and HVAC trouble.

The inspector noted that the PAHM alarm will be implemented non-outage.

The inspectors reviewed PC/H package No.93-047 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 fieldwork, discussed the PC/H with design and construction engineering personnel, and observed post-modification testing.

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

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

This PC/H is scheduled for Unit 4 during the fall 1994 refueling outage.

PC/H No.93-125, Inspection, Repair, and Modification of the Unit 3 Intake Structure The licensee's 1985 and 1986 inspections of the Unit 3 and

intake structure revealed corrosion of the reinforcement within the circulating water pump thrust beams, horizontal struts, and the deck support beams for the ICW pumps.

Due to the degree of damage, the licensee removed and replaced the circulating water pump thrust beams and performed immediate repairs on the strut beams at the 1-foot 9-inch elevation and on the ICW pump support beams.

Based on the physical findings and test reports of a licensee contractor in 1986, the licensee initiated an inspection and repair program to assure adequate long-term performance of the intake structure.

Based on the significance of the individual structural members with regard to the overall integrity of the ICW system and the level of degradation that was observed at the time;

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the licensee performed repairs to the ICW pump deck support beams to restore the protection for the concrete reinforcement, developed modifications to assure long-term performance of the intake structure, and continued to have inspections on the thrust beams, strut beams, and bay walls.

Based on a study by another independent consultant in 1990, the licensee issued specification CN-2.28 in December 1990, in order to provide a 6-year plan to direct the implementation of the permanent repairs and modifications.

This plan included the installation of reinforcing beams under the ICW pump support beams, various modification to features above the deck that are intended to significantly reduce the rate of intrusion of chlorides into the ICW pump support beams, and the performance of regular inspections of the bays including visual inspection of the bay walls.

The licensee has implemented the key elements of this comprehensive testing and rehabilitation program for the intake structure and expects to complete the balance of the work by 1996.

(Prior to the current Unit 3 refueling outage, 2 out of 4 bays in each unit had received the deck beam reinforcement with the remaining 2 bays to be completed during future refueling outages.)

In addition, the licensee developed procedure SPEC-C-015, Inspection Procedure for Turkey Point Units 3 and 4 Intake Structure Bay Walls, in order to confirm that the structural integrity of the bay walls will not be compromised for the duration of plant life.

Implementation of this procedure is scheduled for completion in the Unit 3 Cycle 14 and Unit 4 Cycle 15 refueling outages.

These issues were also addressed during an NRC audit of structures and civil engineering features conducted during the week of January 13, 1992.

The licensee developed PC/M No.93-125, Inspection, Repair, and Modification of the Unit 3 Intake Structure, to provide the necessary design, documentation, references, and instructions for the performance of the following work during the current Unit 3 refueling outage:

inspections and repairs, as required, of the concrete slab supporting screen wash pumps P14 and 3P14; The inspection results of the existing condition of the slab

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supporting screen wash pumps P14 and 3P14 were reported to engineering via CRN No. C-6910, Inspection of 3B2 Intake Bay Screen Wash Slab.

For those areas identified by engineering as requiring repair, the repair method involved the removal of any damaged concrete by chipping to sound concrete, the preparation of the concrete surface for grout placement, and the epoxy coating of any exposed reinforced stee modification of the degraded concrete slab supporting the 3B ICW pump; and The modification of the 3B ICW pump support slab involved the removal of any damaged concrete and preparation of the concrete surface for grout placement; the enlargement of the existing V-notch in the concrete at the top of the support walls and installation of new grouted shear lugs; the installation of plates on the underside of the slab utilizing grout, welded headed concrete anchors, and concrete expansion anchor bolts; the coating of exposed reinforcement steel with epoxy and grouting of the slab to original dimensions; the welding of steel beams to the underside of the plates; and the coating of all exposed carbon steel material with a system designed for severe service.

This work was performed under PWO No. 93028800-01, Repair/Hodification of 3A2 Intake Bay.

(The slabs supporting the 3A and 3C ICW pumps were previously modified by PC/H Nos.91-198 and 89-439, respectively.)

inspections of the structural concrete walls in the 3B2 circulating water pump bay.

The bay wall inspections for the 3B2 circulating water pump bay involved visual inspection of the concrete wall surfaces, half cell potential testing, total chloride content testing, and visual inspection of portions of the reinforcement (rebar)

which were exposed and subsequently recovered per this PC/H.

Samples collected for chloride content testing were also tested for pH levels.

These bay wall inspections were completed in accordance with procedure SPEC-C-015 and PWO No. 94005808-01, CWP 3B2 Bay Wall Inspection.

The inspection results were documented by gC in an inspection report, and the half cell potential testing results were documented in the form of equipotential contour maps.

The analysis of the chloride content and pH testing from the concrete samples is currently being performed by an independent laboratory, and the results are scheduled to be submitted in the form of a report during Hay 1994.

The results of all of these tests will then be submitted to QPN engineering for evaluation and final disposition.

Preliminary results revealed that the rebar was in good condition.

The inspectors reviewed the PC/H, various drawings, the PWOs, procedure SPEC-C-015, CRN No. C-6910, the gC inspection report, and the equipotential contour maps which documented the potential survey of the intake by walls.

The history of the intake structure restoration project, scope of the PC/H, and preliminary inspection results were also discussed with members of the licensee's engineering staff.

In addition, the inspectors witnessed portions of the modification of the degraded concrete

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slab supporting the 3B ICW pump and portions of the inspections of the structural concrete walls in the 3B2 circulating water pump bay.

The work performed under this PC/H was conducted in a thorough and professional manner.

The inspectors plan to follow up on the final inspectjon results and engineering disposition during future inspections.

11.2.5 PC/H No.93-208, Containment Isolation Barrier Testing Enhancements, for Unit 3 The licensee implemented this Unit 3 modification (PC/H No.93-208) to enhance the local leak rate testing capability.

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

The inspector reviewed the PC/H package including the design bases and analyses and the safety evaluation.

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

The post-modification tests, including local leak rate tests associated with the penetrations affected by the modifications, have not been completed as of the end of this reporting period.

The inspector plans to complete this review following completion of the PC/H.

12.0 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 staffs and during an exit meeting conducted on Hay 5, 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 inspectors had the following findings:

Item Number 50-250,251/94-07-01 50-250,251/94-07-02 50-250)251/94-07-03 Status Descri tion and Reference (Closed)

NCV - Unescorted Visitor Within the Protected Area (section 5.2. 1).

(Open) IFI - Cavity Seal Leakage During Refueling (section 6.2.2).

(Open) IFI - Licensee Corrective Actions for IST Program (section 7.2.2).

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Additionally, the following previous items were discussed:

Item Number Status Descri tion and Reference 50-250,251/93-26-03 LER 50-250/92-010 LER 50-250/92-011 LER 50-251/94-002 LER 50-251/94-003 (Open) IFI - Safety Injection Pump Motor Rotor Bar Cracking (section 8.2. 1).

(Closed)

LER - Containment Ventilation Isolation and Control Room Ventilation Isolation Due to Spurious Signal (section 9.2.2).

(Closed)

LER - Failure of Source Range Neutron Detectors (section 9.2.3).

(Closed)

LER - Plant Shutdown Required Due to Reactor Coolant System Pressure Boundary Leakage (section 9.2.4).

(Closed)

LER - Four Analog Rod Position Indicators Greater than Twelve Steps from Group Step Counter; Technical Specification 3.0.3 Entry (section 9.2.5).

13. 0 Acronyms ADM amp ASME CCW CFR CMI CN CNRB cpm cps CRN CWP

oF DP DWDS EDG ERDADS ERT FPL GME GMM gpm HHSI HVAC I&C ICW and Abbreviations Administrative Ampere American Society of Mechanical Engineers Component Cooling Water Code of Federal Regulations Corrective Maintenance

-

I&C Specification Number Company Nuclear Review Board Counts Per Minute Counts Per Second Change Request Notice Circulating Water Pump Degrees Degrees Fahrenheit Differential Pressure Demineralized Water Degasification System Emergency Diesel Generator Emergency Response Data Acquisition Display System Event Response Team Florida Power and Light General Maintenance

- Electrical General Maintenance

- Mechanical Gallons Per Minute High Head Safety Injection Heating Ventilation and Air Conditioning Instrumentation and Control Intake Cooling Water

l

IFI ILRT ISEG ISI IST JPN LER LI LIS MOV MSR NCV NIS NP NPS NRC NRR NSD NWE OMA ONOP OP OSHA OSP PAHM PC/M pH PNSC ppm Pslg PTN PWO QA QAO QC QSPDS RCA RCP RCS RHR RPI RPV RPS RTV RWST SEFJ SEMS SFP SIR SPEC STA TB

Inspector Followup Item Integrated Leak Rate Test Independent Safety Engineering Group Inservice Inspection Inservice Testing Juno Project Nuclear Licensee Event Report Level Indicator Level Indicator Switch Motor Operated Valve Moisture Separator Reheater Non-Cited Violation Nuclear Instrumentation System Nuclear Policy Nuclear Plant Supervisor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear Safety Division Nuclear Watch Engineer Operations and Maintenance Addenda Off Normal Operating Procedure Operating Procedure Occupational Health and Safety Administration Operations Surveillance Procedure Post Accident Hydrogen Monitor Plant Change/Modification Hydrogen Ion Concentration Plant Nuclear Safety Committee Parts Per Million Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Quality Assurance Quality Assurance Organization Quality Control Qualified Safety Parameter Display System Radiation Control Area Reactor Coolant Pump Reactor Coolant System Residual Heat Removal Rod Position Indication Reactor Pressure Vessel Reactor Protective System Room Temperature Vulcanizing (Silicone Rubber)

Refueling Water Storage Tank Safety Evaluation Fuels

- Juno Safety Evaluation Mechanical

- Site Spent Fuel Pit Security Incident Report Specification Shift Technical Advisor Technical Bulletin

TP TSC WHT Temporary Procedure Technical Support Center Waste Holdup Tank

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