IR 05000250/1994011

Insp Repts 50-250/94-11 & 50-251/94-11 on 940529-0702.No Violations Noted.Major Areas Inspected:Plant Operations, Operational Safety & Plant Events,Maint Including Surveillance Observations,Plant Support & Fire Protection

ML17352A752
Person / Time
Site:	Turkey Point
Issue date:	07/22/1994
From:	Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352A751	List: IR 05000250/1994011 ML17352A749
References
50-250-94-11, 50-251-94-11, NUDOCS 9408090187
Download: ML17352A752 (48)

Text

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+~*y4 UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/94-11 and 50-251/94-11 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:

May 29 through July 2, 1994 Inspectors:

T.

P.

J nson, Seni r Resident Inspector Da e Si ed B.

B. Desai, R

iden Inspector Da Si ned L. Trocine, Resident spector D

e S'gned Accompanied by:

R.

P. Schin, Project Engineer, Reactor Projects Section 2B, Division of Reactor Projects Approved by:

K. D.

a is, Chief Reactor Projects Section 2B Division of Reactor Projects D

e igned SUMMARY Scope:

This resident inspection was performed to assure public health and safety, and it involved direct inspection at the site and at the Florida Power and Light Juno Beach offices in the following areas:

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

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

940S090i 87

FOR ADOCK 05000250 PDR

Results:

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

Although violations or deviations were not identified, the following items were identified:

Inspector Followup Item 50-250,251/94-11-01, Core Exit Thermocouple Status and Technical Specifications (section 4.2.3).

Unresolved Item 50-250,251/94-11-02, Incorrect Inservice Inspection of Branch Line Connections to the Reactor Coolant System (section 5.2.8).

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

Plant 0 erations The licensee has a pro-active operator staffing plan in place to ensure that control room licensed operators and non-licensed field operators continue to meet required levels.

Further, current staffing levels met the technical specification requirements (section 4.2. 1).

A review of overtime records did not result in a violation of the technical specification requirements; however, inconsistency resulting from an apparent lack of guidance relative to turnover time was noted (section 4.2.2).

Although the licensee met the technical specification requirement for core exit thermocouple operability, minor deficiencies were noted relative to the licensee's interpretation of and documentation for this required post-accident instrumentation and an inspector followup item was opened (section 4.2.3).

Although malfunctions occurred in the pressurizer pressure control systems, the licensee's response was aggressive and thorough (section 4.2.4).

Plant operators'esponse to a transient caused by the break of a control oil line and subsequent closure of an intercept valve was prompt and efficient, and management attention regarding the troubleshooting and repair was evident (sections 4.2.5 and 6.2.3).

The licensee appropriately documented and tracked equipment issues, and licensee management attention was evident in ensuring that equipment was returned to service in a timely manner (section 4.2.6).

The licensee corrected a

previous weakness in the scaffold control program and improved its controls on placing scaffolds over safety-related equipment.

The licensee's design and construction of selected scaffolds would withstand a safe shutdown earthquake and were adequate to support operability of the affected safety-related equipment (section 4.2.7).

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

Although a deficient repair procedure associated with axial thrust displacement of the 4A steam generator feedwater pump rotating element could have contributed to pump failure, the licensee's

subsequent repairs were conducted with a sufficient level of management attention, and the condition report regarding this issue was comprehensive (section 5.2.3).

The conduct of safety system flow path verification surveillances was excellent (section 5.2.4).

Strong management attention has improved maintenance.

This was evidenced by improved maintenance indicators and equipment performance and availability (section 5.2.5).

Licensee actions to ensure safe and controlled troubleshooting of a switchyard direct current ground were noteworthy.

Good communication between the switchyard and the control room was noted, and good oversight and coordination of the local switchyard activities were evident (section 5.2.6).

The licensee appropriately followed up on an inadvertent 3B emergency diesel generator lockout caused by painting activities (section 5.2.7).

An unresolved item was opened regarding further review of incorrect inservice inspections of branch line connections in the reactor coolant system (section 5.2.8).

En ineerin An engineering safety evaluation concerning a manual feedwater bypass isolation valve was satisfactory (section 6.2. 1).

System engineer knowledge and support of operations for the emergency core cooling systems and metal impact monitoring system were strong (sections 5.2.4 and 6.2.2).

Implementation of a temporary system alteration for the temporary repair of a control oil pipe break in lieu of a weld repair that would require a unit shutdown was viewed as positive (sections 4.2.5 and 6.2.3).

A licensee/Nuclear Regulatory Commission counterpart meeting was beneficial in understanding current licensing issues (section 6.2.4).

A Licensee Event Report and two special reports were accurate and appropriately submitted (sections 6.2.5, 6.2.6, and 6.2.7).

The licensee has been pro-active in the area of hurricane preparedness.

The licensee's procedures provide thorough compensatory measures for equipment or facilities not designed for a hurricane, and the licensee has adequately examined the impact of nonsafety-related equipment on important equipment during external events (section 7.2. 1).

The licensee appropriately responded to a lightning strike near an offsite substation which affected technical support center power.

However, no formal response procedure existed for this condition/event (section 7.2.2).

Although a number of inadvertent fire protection deluge system actuations have occurred, the licensee was aggressive in resolving maintenance issues (section 7.2.3).

Emergency preparedness practice drills and the annual emergency preparedness exercise were appropriately conducted.

Strong communications and interdepartmental team work were evident.

In addition, post drill critiques were appropriately conducted with constructive feedback from the controllers (section 7.2.4).

The licensee's actions with regard to an offsite fire were responsive and thorough (section 7.2.5).

Station dose reduction activities including board reviews were effective and were well supported by licensee management (section 7.2.6).

The licensee took appropriate action with

regard to the identification of radioactive material on a box of old documents (section 7.2.7).

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

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

1.2 NRC Resident Inspectors.....

1.3 Other NRC Personnel On Site

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

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

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 Haintenance....................................................

5.1 Inspection Scope.....

5.2 Inspection Findings..

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10 6.0 Engineering...................................................

6.1 Inspection Scope.....

6.2 Inspection Findings..

16 7.0 Plant Support

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7. 1 Inspection Scope.....

7.2 Inspection Findings..

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8.0 Exit Interviews.....................

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

1.0 Persons Contacted REPORT DETAILS Licensee Employees T. V. Abbatiello, Site guality Manager J.

C. Balaguero, Technical Department Supervisor W.

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

M. Franzone, Instrumentation and Controls Maintenance Supervisor R. J. Gianfrancesco, Maintenance Support Services Supervisor R.

G. Heisterman, Mechanical Maintenance Supervisor P.

C. Higgins, Outage Manager G.

E. Hollinger, Training Manager D.

E. Jernigan, Operations Manager H.

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

E. Kirkpatrick, Fire Protection/Safety Supervisor J.

E. Knorr, Regulatory Compliance Analyst R.

S. Kundalkar, Engineering Manager J.

D. Lindsay, Health Physics Supervisor J.

Harchese, Site Construction Manager F.

E. Harcussen, Security Supervisor H.

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

W. Pearce, Plant General Manager 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 E. A. Thompson, Project Engineer G. A. Warriner, guality Assurance 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 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. Schin, Project Engineer, Reactor Projects Section 2B, Division of Reactor Projects

Attended exit interview on July 7, 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 50-250,251/94-14 June 20-24, 1994 Safeguards/Security Inspection 50-250,251/94-15 June 27-29, 1994 Fitness For Duty 3.0 Plant Status 3. 1 Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near 60% reactor power and had been on line since May 27, 1994.

The unit had previously been shut down in order to facilitate the repair of a condenser tube leak and an orifice associated with the main turbine control oil system.

(Refer to section 3. 1 of NRC Inspection Report No. 50-250,251/94-10.)

The following evolutions occurred on this unit during the inspection period:

Following the plugging of 13 condenser tubes in the A-south waterbox, the licensee re-commenced a load increase at 12:00 p.m.

on Hay 29, 1994, and Unit 3 was returned to 100%

reactor power at 3:00 a.m.

on Hay 30, 1994.

At 3:45 a.m.

on Hay 31, 1994, the licensee commenced a load reduction on Unit 3 due to high cation conductivity in all steam generators.

The unit was stabilized at 60% reactor power at 4:20 a.m.

on Hay 31, 1994.

Following the plugging of 4 condenser tubes in the B-north waterbox, power ascension was commenced at 4:20 a.m.

on June 1,

1994, and 100% reactor power was re-achieved at 8:00 a.m.

on the same day.

At 9:50 p.m.

on June 13, 1994, control room operators noted a slight decrease in main generator output followed by a rapid drop to 70% reactor power and a trip of both heater drain pumps.

(Refer to sections 4.2.5 and 6.2.3 for additional information.)

Following the repair of a break of the control oil supply line to the northeast intercept valve and the plugging of 6 condenser tubes in the A-south waterbox, the licensee commenced power ascension at 10:55 a.m.

on June 16, 1994, and 100% reactor power was re-achieved at 4:00 p.m.

on the same day.

3.2 Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near 60% reactor power in order to facilitate the repair of the

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4A steam generator feedwater pump.

The unit had been on line since Harch 18, 1994.

Following repairs, the licensee returned the 4A pump to service (Refer to section 5.2.3 for additional information.)

and commenced a load increase at 6:30 a.m.

on June 2,

1994, and Unit 4 reached 100% power at 10:35 a.m.

on the same day.

4.0 Plant Operations (40500 and 71707)

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

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

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

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

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

The inspectors performed an inspection designed to verify the status of the Unit 3 and 4 CS, RHR, and HHSI systems.

This was accomplished by performing a complete walkdown of all accessible equipment.

The inspectors reviewed system procedures, housekeeping and cleanliness, major system components, valves, hangers and supports, local and remote instrumentation, and component labelling.

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

Inspection Findings Operations Staffing The inspectors reviewed the operations department staffing levels.

Technical Specification 6.2.2 requires a minimum of two SROs, three ROs, and three ANPOs/NPOs per shift.

The licensee currently has a six-shift operations rotation with three SROs, three ROs, and five or six ANPOs/NPOs per shift.

In addition, a number of operators are in training programs (SRO, RO, ANPO, etc.),

and a

number of operators are in staff positions.

As of June 1,

1994, the licensee had 66 licensed operators (49 SROs and 17 ROs),

34 of

which had degrees.

Further, an STA is assigned on a 12-hour rotational basis.

4.2.2 The inspectors discussed staffing issues and plans with the operations management personnel.

During the current SALP period, the licensee had experienced a

13% per year turnover rate.

Licensee plans included projected hiring and training pipelines over the next several years to ensure a minimum cadre of qualified operations personnel.

In addition, the licensee success rate for licensed operator examinations over the last two years has been very good in that the licensee has achieved a

100% pass rate.

The next examination is currently scheduled for February 1995.

The inspectors concluded that the licensee has a solid and pro-active operating staffing plan in place to ensure that adequate operations department staffing levels exceed the minimum technical specification requirements.

Current staffing levels met the technical specification requirements.

Overtime Issues 4.2.3 The inspectors reviewed licensee overtime usage for portions of the time -period corresponding with the recent Unit 3 Cycle

refueling outage.

Overall overtime usage for various groups as well as individual records were examined by the inspectors to determine compliance with Technical Specification 6.2.2.g.

For the month of April 1994, the inspectors noted that the overall overtime usage was approximately 37% (excluding contractors),

and overtime broken down between various groups was as follows:

operations

- 27%, mechanical maintenance

- 71%, health physics-96%, construction

- 27%, electrical

- 44%,

and ISC - 47%.

With regard to individual overtime records from groups including construction and operations that were examined, the inspectors did not note any cases where an individual violated overtime requirements as defined in Technical Specification 6.2.2.g.

The inspectors discussed the issue of overtime with licensee management.

In particular, the inspectors noted that there was a

lack of guidance as to how much time should be allowed towards shift turnover and to whom it should be applicable.

In addition, the inspectors noted that the times as noted from the security entrance and exit times were not necessarily what employees claimed on the time sheets.

Lunch, personal time, etc.,

accounted for the inconsistencies.

The inspectors plan to monitor this issue during future inspections.

Core Exit Thermocouple Issues During a routine control room tour, the inspectors noted that a

number of Unit 3 and 4 CETs were inoperable.

Further, not all of the inoperable CETs were logged into the technical specification

equipment out-of-service log book.

The on-shift ANPS corrected this immediately.

There are

CETs per unit, and each unit has two trains (channels).

Each train is further divided into four core quadrants with specific CETs assigned.

The following depicted the CET out-of-service status noted during the period:

Unit 3 Unit 4 d <<h

h

B Ch

A h

N-10

None

D-5) A-8

L-14 P-8, M-9 None E-8, B-5 None None D-3 None None R-7 K-3 H-8 None Based on this, the following number of CETs were operable for the specific channels:

Unit 3

~Cd Ch

A h

Unit 4 Channel 4A Channel 4B

4 of 5 5 of 7 6 of 6 6 of 7

6 of 6 7 of 7 5 of 6 6 of 7

5 of 7 3 of 5 6 of 6 4 of 5

7 of 8 6 of 6 8 of 8 6 of 6 Accident instrumentation Technical Specification Table 3.3-5, item No.

14, addressed the CET operability requirements.

This TS required a total number of channels of four CETs per quadrant and also required minimum channels operable of two CETs per quadrant.

With less than the required number of CETs operable, each of these TS requirements had a related shutdown action requirement.

The inspectors questioned licensee personnel, and the licensee's interpretation based on THI action item No. II.F.2 of NUREG 0737 was that a total of 16 CETs were required to meet the required technical specification total number.

However, there was no formal or written interpretation document for this.

Further, a

July 17, 1990, technical department memorandum incorrectly stated that four CETs were required per quadrant per channel.

This was referenced on a control room information tag.

The inspectors contacted NRR to assess the current NRC licensing basis for CETs.

NRR determined that the minimum requirements were 2 CETs per quadrant, 8 CETs per train (channel),

and a total of 16 CETs.

Therefore, based on the above noted Unit 3 and 4 status, the licensee met the current accepted CET licensing basi The inspectors noted the following corrective actions taken by the licensee:

4.2.4 planned to consider modification/enhancement of the technical specifications (long-term),

developed an acceptable technical specification position statement (No.94-005) (short-term),

modified the referenced technical department letter, and ensured that the technical specification equipment out-of-service log reflects the correct CET status.

This issue will be tracked as an inspector followup item; IFI 50-250,251/94-11-01, Core Exit Thermocouple Status and Technical Specifications.

Unit 3 Pressurizer Operation Upon restart from the spring 1994, Unit 3, refueling outage, operators noted that the pressurizer backup heaters were cycling on frequently.

The licensee pursued the proper functioning of the control group heaters KW output and its automatic control system, the pressurizer spray valve controllers, and the settings for the manual mini-spray bypass valves. 'hile this review was ongoing, the A bank of the backup heaters was left on (energized).

Troubleshooting of the control group heaters noted a controller output problem which the licensee repaired.

This returned the control group to its expected heater output of about 350 KW.

The cycling of the backup heaters decreased; however, it was still more than expected.

The licensee believed this to be either a

possible leaking spray valve and/or the setting of the mini-spray bypass valves.

An outage would be required to correct these issues.

The inspectors reviewed the pressurizer pressure control systems, appropriate operating and test procedures, PWOs, and a problem status summary report.

The inspectors discussed this issue with operations and engineering personnel.

Although malfunctions occurred in the pressurizer pressure control systems, the licensee's response was aggressive and thorough.

The inspectors intend to follow the licensee's continued review of this issue.

4.2.5 Unit 3 Transient due to Northeast Intercept Valve Closure At 9:50 p.m.

on June 13, 1994, with Unit 3 at 100% power, control room operators noted a slight decrease in main generator output followed by a rapid drop to 70% reactor power and a trip of both heater drain pumps.

Operators started the third condensate pump, restarted one heater drain pump, and opened the low pressure

feedwater heater bypass valve in order to ensure adequate feedwater pump suction pressure.

Operators noted that the northeast intercept valve was closed resulting in the isolation of steam from the 3C moisture separator reheater to the B low pressure turbine.

Further investigation revealed a break of the control oil supply pipe to the northeast intercept valve which caused the valve to close.

The licensee isolated the oil supply line to the broken pipe, stopping the leak.

All of the oil from the pipe break was contained by the guarded oil pipe and returned to the turbine oil sump.

The licensee determined that the control oil line was completely sheared at the northeast intercept valve servo actuator.

This was apparently due to a fatigue failure in the heat affected zone of the pipe weld.

This 3/4-inch, carbon steel pipe operates at a

pressure range of 25 psig to 50 psig.

Similar failures occurred in 1991, and the licensee performed modifications to support this piping.

Per Westinghouse recommendations, the licensee operated the unit at a reduced load during the troubleshooting activities.

In order to facilitate repairs, the licensee originally planned a

Node 2 outage for the weekend.

However, the licensee successfully implemented a TSA in order to preclude a unit shutdown.

(Refer to section 6.2.3 for additional information.)

Following the repair of this oil line per the TSA, the licensee commenced power ascension at 10:55 a.m.

on June 16, 1994, and Unit 3 was stabilized at 100% reactor power at 4:00 p.m.

on the same day.

As documented in condition report No.94-684, the licensee plans to implement a permanent repair before or during the next refueling outage (before December 31,'995).

The section of pipe encompassing the break was sent to CSI for analysis to determine the mechanism of the break and to aid in the determination of the root cause.

A plant manager action item was also assigned to engineering to provide a final root cause analysis by July 29, 1994.

4.2.6 The inspectors reviewed the licensee's corrective actions, condition report No.94-684, and the implementation of TSA No. 3-94-89-8.

Plant operators responded to this event in a prompt and efficient manner, and management attention regarding the troubleshooting and repair was evident.

Implementation of a temporary system alteration in lieu of a weld repair that would have required a unit shutdown was viewed as positive.

Operational Control of Equipment During this reporting period, the inspectors reviewed the licensee's processes for operational control and accountability of safety-related equipment.

Out-of-service equipment that was required to be operable by technical specifications was logged in the control room equipment out-of-service log book.

In addition, this technical specification-required equipment, as well as other

4.2.7 equipment critical for plant operations, was tracked on the hot items list and was documented for licensee management's review in the plan-of-the-day status report.

The NPSs also generated and maintained an NPS concerns list which documented similar and additional equipment, issues, and problems.

Instrumentation-related problems were further documented and tracked in the plan-of-the-day off-normal annunciators and control room green tag listing.

Plant water and steam leaks were tracked by the plan-of-the-day primary and secondary leak list.

The licensee established repair priorities through discussions in the shift turnover meetings, management status meetings, and plan-of-the-day meetings.

All of these equipment issues were also redundantly documented by a

PWO.

The inspectors noted that the licensee appropriately documented and tracked equipment issues as required by technical specifications.

Problems were identified with a PWO tag or green tag (for the control room panels).

Licensee management attention was evident in ensuring that equipment was returned to service in a timely manner.

Scaffolding over Safety-Related Equipment A weakness in the licensee's program for control of scaffolding over safety-related equipment was noted in section 4.2.3 of NRC Inspection Report No. 50-250,251/94-10.

In that instance, a

scaffold over safety-related equipment was not removed promptly after the related work was completed.

The department erecting the scaffold had incorrectly stated on the scaffold request form that it would not be over safety-related equipment.

Procedure 0-ADH-012, Scaffold Control, required that a scaffold inspection report form be completed promptly after scaffold erection.

That form required inspection of the scaffold by a plant operator, including a determination of whether the scaffold was over safety-related equipment, and approval by the NWE.

However, the licensee could not find a completed scaffold inspection report form for the scaffold in question.

To follow up on that weakness, the inspectors examined two scaffolds (Nos.

2937 and 2938) over safety-related equipment in the Unit 3 CST room.

Both scaffolds were in use for installation and painting of lagging on pipes.

The two related scaffold request forms were properly filed in the control room scaffold control book.

Both forms were appropriately completed and signed.

On each form, the department erecting the scaffolding had incorrectly stated that the scaffold would not be over safety-related equipment.

However, the NWE had changed both forms to correctly indicate that the scaffold would be over safety-related equipment.

In addition, attached to each scaffold request form was a completed scaffold inspection report for The inspectors reviewed nuclear engineering safety evaluation No.

JPN-PTN-SECJ-90-064, Engineering Evaluation of Temporary Scaffolding, revision 0, dated June 22, 1990, and supporting calculation PTN-B-fJC-90-004, Evaluation of Temporary Scaffolding, dated June 20, 1990.

These included a standard design for scaffolding that would withstand a safe shutdown earthquake of 0. 15g horizontal ground acceleration.

(The 0. 15g safe shutdown earthquake was consistent with the approved UFSAR design basis.)

The standard scaffold design would also withstand a safe shutdown earthquake horizontal acceleration of 0.84g, which could be experienced at the highest level where scaffolding might be erected over safety-related equipment, the top level inside containment.

The standard design included a minimum number of mechanical clamps or wire ties to restrain horizontal movement.

This scaffold design information was included in procedure 0-ADN-012.

The inspectors climbed on scaffolds Nos.

2937 and 2938 and determined that they met the above scaffold design requirements.

The scaffolds appeared to be very solidly anchored.

They were also equipped with handrails and toe boards which appeared adequate to restrain the small amount of loose tools and equipment on the scaffolds from falling off.

The inspectors concluded that the licensee had corrected the previous weakness in the scaffold control program and had improved its controls on placing scaffolds over safety-related equipment.

The inspectors also concluded that the licensee's design and construction of these scaffolds would withstand a safe shutdown earthquake and were adequate to support operability of the affected safety-related equipment.

5.0 Maintenance (62703 and 61726)

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

repair of the control oil supply line to the Unit 3 northeast intercept valve (Refer to sections 4.2.5 and 6.2.3 for additional information.),

repair of the 4A steam generator feedwater pump (Refer to section 5.2.3 for additional information.),

and switchyard ground troubleshooting.

(Refer to section 5.2.6 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.

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

procedures 3-0SP-068.3 and 4-0SP-068.3, Containment Spray System Monthly Flowpath Verification (Refer to section 5.2.4 for additional information.);

procedures 3-OSP-202.

1 and 4-OSP-202. 1, Safety Injection/Residual Heat Removal Flowpath Verification (Refer to section 5.2.4 for additional information.);

and operability run of the 3B EDG per procedure 3-0P-023, Emergency Diesel Generator.

(Refer to section 5.2.7 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.

5.2.3 4A Steam Generator Feedwater Pump Failure and Repair On May 26, 1994, a licensee system engineer observed excessive axial thrust displacement of the 4A steam generator feedwater pump rotating element.

Unit 4 load was reduced to approximately 50%

and the 4A steam generator feedwater pump was secured to effect repairs.

The excessive axial thrust displacement of the rotating element had caused an over-thrust condition at the steam generator

feedwater pump motor resulting in the motor bearing being wiped (damaged).

The licensee determined the cause of the axial thrust displacement of the rotating element to be a thrust nut that had loosened and backed off approximately 3/16 inches.

The rotating element had displaced by approximately the same amount.

A root cause analysis was performed by the licensee, and the licensee attributed the loosening of the thrust nut to deficiencies in the feedwater pump repair procedure (procedure O-CNN-074.2, Feedwater Pump Repair).

Procedure O-CNN-074.2 was found to not have the vendor recommended torque requirements.

Repairs including replacement of the rotating element on the 4A steam generator feedwater pump were completed, and the unit was returned to full power on June 2,

1994.

Additionally, procedure O-CNN-074.2 was revised to include vendor recommended torque values for the thrust nut.

The inspectors observed a large portion of the repair activities as well as the power reduction and escalation activities.

In addition, the inspectors reviewed condition report No.94-642 associated with the problem.

The inspectors determined that maintenance and engineering support associated with the repairs were appropriately conducted with sufficient level of management attention.

In addition, condition report No.94-642 was found to be comprehensive in detailing the circumstances and corrective actions associated with the event.

5.2.4 Safety System Flowpath Verifications The inspectors observed portions of the Unit 3 and Unit 4 CS, RHR, and HHSI monthly flowpath verification surveillances.

These were performed on June 3, 1994, by the responsible system engineer.

These surveillances ensured that the safety system valves, breakers, and switches were appropriately aligned to ensure that the respective systems would automatically start and deliver water to meet its intended safety function.

The inspectors noted that each pumps'inimum flow manual recirculation valve was not on the verification checklist.

In order to ensure pump operability when operating

"dead-headed,"

these valves must be opened.

The system engineer did check that these locked valves were open.

The inspectors also noted that these valves (888D-G, 883L, 883K, and 1461-1464)

were verified to be locked open per procedure 0-0SP-205, Verification of Administratively Controlled Valves, Locks, and Switches.

The inspectors concluded the system engineer performed an excellent pro-active walkdown of these system.2.5 5.2.6 Status of Equipment Performance Indicators The inspectors reviewed the licensee's programs for the monitoring of Turkey Point equipment performance and related performance indicators.

In the maintenance area, the licensee monitors the following items:

off-normal (lit) annunciators (goal

- less than or equal to five),

control room green tags (out-of-service instruments)

(goal-less than or equal to five),

primary and secondary non-outage leaks (goal

- less than or equal to ten),

equipment out-of-service (goal

- less than or equal to four),

and PWO backlog (goal

- less than or equal to 1600 total and 340 non-outage corrective maintenance).

The inspectors noted that each of these items was tracked and reported daily by the responsible maintenance group.

Further, management reviewed each of these items (including trends)

at the plan-of-the-day meeting each morning.

The inspectors attended a

sampling of these meetings and noted that most goals were either met or exceeded.

The inspectors concluded that management has demonstrated a pro-active approach in ensuring that the achievement of these goals has improved equipment availability and overall station performance.

Switchyard Ground Troubleshooting During a routine switchyard inspection and tour, licensee protection and control personnel noted a

DC ground on one of the 125-volt DC buses.

On June 15, 1994, the licensee performed a

troubleshooting plan to determine the exact location of the ground.

Prior to the performance of troubleshooting activities, the licensee researched the appropriate electrical drawings with engineering involvement and assistance.

Then, operations and management personnel were briefed on the plan and potential risks.

Because switchyard breaker DC control power would be cycled off and on, there was risk to the units'enerator output breakers and to offsite power supplies.

Plant management deemed this activity to be covered under administrative procedure O-ADH-217, Conduct of Infrequently Performed Tests of Evolutions.

This required the oversight of a manager and the conduct of pre-evolution briefings.

Further, management considered this to be a "red sheet" activity which required plant manager review and approval.

A "red sheet"

activity is an additional licensee control system for risk-related activities.

5.2.7 The troubleshooting was conducted on June 15, 1994, and the licensee found a ground in circuit B9 for the 8W33 breaker backup relay trip panel.

This breaker was one of the Unit 3 main generator output breakers.

The licensee further traced the ground to the T-15 breaker trip coil No.

2 and conducted temporary repairs on June 17, 1994.

Permanent repairs are currently scheduled for an outage.

The inspectors attended the licensee's

"red sheet" and procedure 0-ADH-217 briefings.

The inspectors also observed the troubleshooting in the switchyard and the control room monitoring and oversight of these activities.

The inspectors noted good communication between the switchyard and the control room.

Good oversight and coordination of the local switchyard activities were evident as an SRO, system engineer, and protection and control supervisor were present and involved.

In summary, licensee actions to ensure safe and controlled troubleshooting of the switchyard DC ground were noteworthy.

Inadvertent 3B Emergency Diesel Generator Lockout At approximately 9:00 a.m.,

on June 28, 1994, the Unit 3 control room received the EDG trouble alarm, lost the ready-to-start light on the 3B EDG, and received a 3B EDG lockout indication.

The 3B EDG was in the standby mode just prior to the receipt of these indications.

A turbine operator was dispatched to the B

EDG room.

A review of the local alarm panel indicated that the 3B EDG had tripped on overspeed.

Additionally, the turbine operator noted that painting activities were ongoing in the vicinity of the 3B EDG governor.

The overspeed and lockout were immediately reset.

However, the 3B EDG remained technically inoperable, and the appropriate action statement was entered in accordance with Technical Specifications 3.8. 1. 1 and 3.5.2.e.

The painter was questioned by the licensee, and the painter indicated that he was applying a top coat in the vicinity of the governor trip switch.

It is postulated that during this time, the governor trip switch was inadvertently tapped causing the 3B EDG lockout.

All painting activities were stopped, and the licensee verified that no painting had recently been done on the other three EDGs.

The licensee informed the inspectors of the event and discussed the impending testing requirements to declare the 3B EDG back in service.

The 3B EDG was successfully tested in accordance with procedure 3-0P-023, Emergency Diesel Generator.

The test involved starting the EDG and running it at its rated frequency and voltage.

The 3B EDG was declared operable at 1:20 p.m.

on the same da The inspectors discussed the issue of controls over painting activities and the potential affect on safety-related equipment with the licensee.

The licensee believes that controls in place are adequate; however, a condition report (No.94-703)

was generated to document the event and pursue corrective action if deemed necessary.

The inspectors concluded that the licensee appropriately pursued this issue, and the inspectors plan to monitor licensee performance in this area.

Incorrect Inservice Inspection of Branch Line Connections to the Reactor Coolant System During the recent Unit 3 Cycle 14 refueling outage, the licensee discovered that incorrect ISI had been performed on seven RCS piping branch line nozzle connections on each unit.

These nozzles were noted to be of a set-on type weld configuration rather than a

set-in type weld configuration for which they had been inspected.

This meant that the weld location was different than the ISI checks.

The ultrasonic type volumetric (UT) ISI on the welds had been performed assuming the set-in configuration.

Consequently, the UT exams performed on the welds were misdirected and did not inspect the welds.

The seven branch line connections to the RCS included three ECCS cold leg injection lines, two pressurizer spray lines, one pressurizer surge line, and one RHR suction line.

Each of these seven branch line connections are at least four inches in diameter and are considered class

(RCS pressure boundary)

pipe.

A condition report (No.94-698)

was initiated on June 24, 1994, to document and resolve the issue.

The NRC resident inspectors and the Region II office were informed of the situation on June 28, 1994.

Turkey Point Units 3 and 4 were built in accordance with ASNE piping code B31. 1 and are subject to the requirements of the ISI requirements as described in the summer 1975 edition of ASNE Section XI.

Currently, Units 3 and 4 are in the second 10-year ISI interval which ends in 1994.

The ISI program issued by the licensee for the third 10-year ISI period conforms to the 1989 edition of ASNE Section XI.

Pursuant to ASNE Section XI requirements, the licensee believes that the subject welds had been correctly inspected during the first 10-year ISI period.

As per Table IWB-2500-1, Examination Category B-J of ASNE Section XI, all seven locations were optionally inspected and were in excess of the required 25% of all system welds.

These welds were optionally re-inspected during the second 10-year ISI period.

However, these inspections were incorrectly performed assuming set-in weld configurations.

Consequently, the UT exams performed on the welds were misdirected, thereby, failing to

inspect the subject welds.

The licensee believes that no code requirements were violated as the licensee met the 25% inspection criteria as required by Table IWB-2500-1 of ASNE Section XI without counting the seven inappropriately conducted inspections.

The licensee also determined that there was no immediate operability issue as a result of the improper inspections because no rejectable welds have thus far been identified in any similar weld locations and because RCS leakage is monitored on a daily basis by the licensee per technical specification requirements.

During a further review, however, the licensee realized that one of the seven locations, specifically, the pressurizer surge nozzle connection weld, is required to be inspected per the ISI program for the third 10-year ISI period.

This requirement could be met provided the pressurizer surge line weld is correctly inspected during the upcoming Unit 4 and Unit 3 outages.

The licensee intends to re-inspect the pressurizer surge line weld and also the other six welds during the upcoming Unit 4 and Unit 3 outages.

The inspectors consider the discovery of the error by the licensee as a strength.

However several issues came to light during the inspectors'eview of the event.

These included the circumstances surrounding the false assumption that the welds were set-in type configuration, the need for reviewing other work that was performed by the licensee's ISI inspector, the cause for the delay in the issuance of a condition report, and some problems in the dissemination of information from engineering to the ISI group.

Pending further review of this issue by both the resident inspectors and regional specialists, this issue will be tracked as URI 50-250,251/94-11-02, Incorrect ISI of Branch Line Connections to the RCS.

6.0 Engineering (37551, 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 accomplish this by ensuring that the licensee's processes included the identification, resolution, and prevention of problems and the evaluation of the self-assessment and control program.

The inspectors 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 applie.2 6.2.1 Inspection Findings Body-to-Bonnet Leak on Unit 3 Valve 3-20-232 Upon restart from the spring 1994, Unit 3, refueling outage, the licensee noted that valve 3-20-232 (manual downstream isolation valve for the 3B steam generator feedwater regulating bypass valve)

had a body-to-bonnet leak of 5 cc/minute.

The leak was through the pressure seal gasket between the valve body and bonnet; Based on experience, the licensee concluded that the leak would worsen over time.

Since a cold shutdown would be required to repair the valve, the licensee pursued operating with the valve closed, thereby stopping the leak because the valve has a double disc gate.

Engineering performed a safety evaluation (JPN-PTN-SEMS-94-036)

which concluded that Unit 3 power operation could continue with the valve closed.

The evaluation addressed the following issues:

steam generator operability as required by the technical specifications, RCS leakage requirements per the technical specifications, RCS activity per the technical specifications, steam generator tube rupture scenario per the UFSAR, containment isolation per the,UFSAR,

CFR Part 50, Appendix R, (fire protection)

per the UFSAR, and use of the feedwater regulating bypass valve during plant startups and shutdowns.

The licensee concluded that safe unit operation could continue with valve 3-20-232 closed.

Since this flowpath would be required for a fire in the AFW cage, the licensee placed a caution tag on the valve and made appropriate changes and conducted operator briefings to ensure that the valve would be re-opened.

A tag was also placed in the control room to remind operators of this condition.

The inspectors reviewed the evaluation, the condition report (No.94-614) which initially reported the problem, the applicable technical specification and UFSAR sections, plant drawings, and plant procedures.

The inspectors also discussed this issue with maintenance, engineering, and operations personnel.

The inspectors examined the valve in the field and verified licensee compensatory actions.

The inspectors concluded that the licensee acted appropriately regarding this conditio.2.2 6.2.3 Unit 4 Metal Impact Monitoring System Alarms During this inspection report period, several Unit 4 MIMS alarms on various steam generator channels occurred.

Each steam generator has three noise monitors to sense for possible loose parts in the primary or secondary system in the containment.

Operators responded the these alarms per the alarm response procedure and off normal procedure 4-ONOP-099. 1, Response to Metal Impact Monitoring System.

System engineering personnel also were involved in the followup.

The licensee listened to the audible noise, reviewed past experiences, contacted vendor representatives, and evaluated plots of noise spectrum.

Based on these items, the licensee concluded that bin A-l, channel 5, for the 3C steam generator was invalid.

This channel was receiving higher than expected noise, and when alarmed, it affected the other channels in proximity at the control room panel.

Therefore, the licensee removed this channel from service.

No further problems occurred.

The inspectors reviewed control room logs, procedures, and the UFSAR and discussed this issue with the system engineer.

The inspectors concluded that the licensee acted appropriately.

The inspectors also noted that MIMS was not a technical specification-required system.

Further, the inspectors noted that the system engineer was very knowledgeable and provided positive support for operations.

Temporary System Alteration for Temporary Repair of Broken Control Oil Line On June 13, 1994, a break of a control oil line resulted in the closure of the Unit 3 northeast intercept valve and a subsequent plant transient.

(Refer to section 4.2.5 for additional information.)

In lieu of a weld repair that would require a unit shutdown, the licensee developed and successfully implemented TSA No. 3-94-89-8.

This TSA provided a temporary repair which replaced the welded control oil fitting to the northeast intercept valve servo actuator with a slip-fit 0-ring sealed fitting.

As documented in condition report No.94-684, the licensee plans to implement a permanent repair before or during the next refueling outage (before December 31, 1995).

The inspectors reviewed the TSA and its implementation.

The licensee's implementation of this temporary repair in lieu of a weld repair that would require a unit shutdown was viewed as positive.

At the close of the inspection period, four TSAs were active.

The licensee's goal is to have less than or equal to seven active TSA.2,4 6.2.5 Licensee/NRC Counterpart Heeting An FPL/NRC counterpart meeting was conducted at the FPL corporate office in Juno Beach, Florida, on June 23, 1994.

Representative from the licensee's Turkey Point, St. Lucie, and corporate offices as well as representatives from the NRC's resident, regional, and NRR offices were in attendance.

The licensee lead discussions involving various licensing issues for both the Turkey Point and St.

Lucie plants, licensing and special programs, the St.

Lucie steam generator replacement project, an update on the issue of thermolag, the stretch power project status for Turkey Point, and IPEEE.

NRC representatives lead discussions involving license renewal and various other issues.

This meeting was beneficial in understanding current licensing issues.

(Closed)

LER 50-250/94-002, Inadvertent Engineered Safety Feature Actuation 6.2.6 This event, its causes, the licensee's corrective actions, and the NRC inspectors'ctions were previously documented in detail in section 4.2.2 of NRC Inspection Report No. 50-250,251/94-10.

This LER adequately documented the event, its causes, and the licensee's corrective actions.

Based on the inspectors'eview of this LER and the inspectors'eview of this event during a

previous inspection, this LER is closed.

3A EDG Failure Special Report This EDG failure occurred during the performance of the Unit 3 engineered safeguards integrated testing with Unit 3 in Hode 5.

(Refer to section 5.2.8 of NRC Inspection Report No. 50-250,251/94-10 for additional information regarding the safeguards testing and this EDG failure.)

Following the successful completion of a 24-hour full load test and full load rejection test on Hay 7, 1994, the licensee shut down the 3A EDG and then restarted it again within 5 minutes by simulating a loss of offsite power signal on a 3A 4160-volt bus.

The 3A EDG came up to speed within the required 15 seconds, but the output breaker did not close onto the bus.

The licensee's initial investigation indicated that the ready-to-load relay had not picked up as expected.

Following additional investigation, the licensee determined that the 3A EDG output breaker did not close onto the 3A 4160-volt bus because of a high setting on a voltage monitoring relay which provided input to the ready-to-load permissive.

The drift of this relay had gone undetected from its last setpoint check three weeks earlier because of higher than normal 4160-volt bus voltage during shutdown conditions.

Approximately 30 minutes after the failure of the 3A EDG output breaker failed to close, the 3A EDG output breaker closed

automatically during troubleshooting.

The licensee determined that this occurred for one of the following two reasons:

either the electrician inadvertently placed voltmeter test leads across both voltage monitoring relay output wire lugs or the EDG output voltage drifted slightly higher and satisfied the relay setpoint.

Additional troubleshooting focused on detecting whether or not the voltage monitoring relay coil was energized.

Voltmeter leads placed in the sensing circuit of the relay coil caused C-phase metering circuit fuse FS to open.

Because this metering circuit also fed the voltage regulator and protective relaying equipment, the voltage regulator sensed a drop in voltage and increased excitation to compensate.

This excitation increase caused the exciter field circuit breaker to open creating a loss of excitation to the generator.

In order to correct these problems, the licensee took the following actions:

The'icensee replaced the 3A EDG voltage monitoring relay and potential transformer fuses F7 and FS and satisfactorily meggar tested the generator and voltage regulator isolation transformer.

The licensee repaired and re-installed the 3A EDG field circuit breaker and tested the 3A EDG excitation circuit relays with satisfactory results.

The 3B EDG voltage monitoring relay and field circuit breaker were also tested with satisfactory results.

The licensee re-tested a sample of relays with adjustable setpoints in the 3A and 3B EDG start panels, and no significant setpoint drift was identified.

The failed voltage monitoring relay was bench tested for drift when energized and subjected to an over-voltage condition similar to that which occurred during the 3A EDG test runs.

Similar drift of the relay was seen during the bench test.

The failed voltage monitoring relay was subsequently returned to the vendor for additional inspection and analysis.

In addition, the licensee re-tested the 3A EDG with satisfactory results.

The full load rejection test and the integrated safeguards test were also repeated.

All testing was successfully accomplished.

The failure count for the Unit 3 EDGs was transvalued to zero at the end of the dual unit outage (1991) concurrent with the implementation of the licensee's revised technical specifications and the dual unit outage overhaul.

This failure was the second failure of the 3A EDG since the count was re-zeroed.

6.2.7 The inspectors reviewed the licensee's special report, the associated determination, root cause, and corrective actions.

The inspectors concluded that this special report was accurate and appropriately submitted.

3B EDG Failure Special Report This EDG failure occurred during the performance of the Unit 3 engineered safeguards integrated testing with Unit 3 in Mode ~

~

~

(Refer to section 5.2.8 of NRC Inspection Report No. 50-250,251/94-10 for additional information regarding the safeguards testing and this EDG failure.)

On May 9, 1994, an attempt was made to fill the surge tank on the cooling water system of the 3B EDG while it was running unloaded at 900 rpm.

Due to the system lineup at the time, the operator inadvertently drained the surge tank, and the 3B EDG tripped on low cooling water (35 psig)

immediately following the reset of the SI signal as per the safeguards testing.

The EDG trouble alarm had annunciated approximately three minutes prior to the reset action.

However, with the EDGs running in the emergency mode, the low water pressure trip was bypassed as a non-essential trip until the SI signal was reset.

Following the EDG trip the level was approximately six inches below the low level mark during standby.

No leaks were found.

Engine temperatures were normal after the shutdown indicating that there was no overtemperature condition as a result of the low water pressure.

The licensee attributed the cause of this failure to inadequate guidance given in the EDG procedure.

Section 5.2 of procedure 3-OP-023, Emergency Diesel Generator, provided direction to place the 3B EDG in normal standby condition, and it contained a note stating that water should be added to the radiator if a low level exists.

The same note provided the number and location of the fill valve, However, the note did not indicate that a separate procedure section exists for adding water to the cooling water system (section 7.8, Makeup to EDG Cooling Water Surge Tank(s)).

As a result, the radiator fill valve was manually opened in an attempt to fill the cooling water system with no condensate transfer pump in operation.

The result was that the cooling water system began draining rather than filling.

As a result of this event, the licensee filled the cooling water system after the EDG was stopped.

Caution tags were also placed on the makeup valves for the 3A and 3B EDGs.

These tags now require notification of the control room prior to opening in order to verify that the condensate transfer system is pressurized.

In addition, the licensee is in the process of making procedure changes to ensure that condensate pressure is available before any fill attempt is made to ensure that section 7.8 of procedure 3-OP-023 is used to perform the evolution.

This failure was the second failure of the 3B EDG since the count for the Unit 3 EDGs was re-zeroed, but it was considered to be non-valid because it was attributed to operating error.

The evolution that resulted in the error (filling the cooling water system)

would not normally be performed if the EDG started in a response to an actual emergency signa The inspectors reviewed the licensee's special report, the associated determination, root cause, and corrective actions.

The inspectors concluded that this special report was accurate and appropriately submitted.

6.2.8 Monthly Operating Reports The inspectors reviewed the May 1994 Monthly Operating Report and determined it to be complete and accurate.

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

7.2 Inspection Findings 7.2. 1 Licensee Hurricane Preparations Hurricane season spans the months of June through November with the most intense activity expected to occur between August and October.

There were a number of lessons learned from Hurricane Andrew's August 24, 1992, impact on Turkey Point.

Among the numerous lessons learned were the need to evaluate the adequacy of compensatory measures for equipment for facilities not designed for a hurricane and the adequacy of examination of the, impact of nonsafety-related equipment on important equipment during external events.

During this inspection period, the inspectors reviewed the licensee's adverse weather procedures to identify any potential vulnerabilities in these two areas.

The licensee has the following procedures in place to ensure adequate preparation for the onset of another hurricane:

Procedure O-ONOP-103.3, Severe Weather Preparations, provides instructions for the preparation of the site for severe weather conditions not resulting in implementation of the Emergency Plan.

This procedure would be entered upon the notification of a Hurricane Watch.

(A Hurricane Watch is declared if a hurricane is located between 24 to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> from and is approaching the United States coast.

A Hurricane Watch area includes approximately 100 miles on either side of the expected landfall location.)

Instructions and guidelines for preparing, controlling, and recovering the plant following activation of the Emergency

Plan for a natural emergency are provided in procedure EPIP-20106, Natural Emergencies.

This comprehensive procedure addresses tornadoes and hurricanes but is to be used for any severe weather disturbance which results in the activation of the Emergency Plan.

It also contains specific guidance for coping with the possible flood conditions associated with more intense hurricanes.

This procedure would be entered in advance of a Hurricane Warning.

(A Hurricane Warning is declared if a hurricane is located between 12 and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from and is approaching the United States coast.

A Hurricane Warning area includes approximately 50 miles on either side of the expected landfall location.)

Procedure 0-SNH-102. 1, Flood Protection Stoplog and Penetration Seal Inspection, is utilized by the licensee to verify operability and adequate inventory of flood protection equipment.

Security force instruction SFI-3002, Hurricane Preparedness, provides guidance for security activities in preparation for, during, and following hurricane threats or actual conditions.

The FPL Nuclear Power Plant Recovery Plan is an FPL corporate document which establishes a pre-planned organization and action plan to recover form a nuclear power plant emergency and minimize unfavorable impact on the FPL plants and the public.

The licensee's preliminary preparations for hurricane season have been completed.

The satellite up-link capability is on site and ready for use, and the stoplog walkdown inspections have been performed, The licensee has also procured and stored non-perishable food supplies and the storm supply inventory for preparatory actions required by procedures.

Prior to the onset of a hurricane, these items would be moved to pre-designed areas.

For example, many of the dewatering pumps would be moved to the 18-foot elevation of the turbine area for protection against potential flooding and flying debris and for easy access during and following the storm.

In order to improve communications capabilities if the TSC had to be relocated to the cable spreading room, the licensee has also completed installation and testing of the additional (approximately ten) telephone jacks in the cable spreading room.

During Hurricane Andrew, the failure of nonsafety-related equipment damaged certain important equipment in that the elevated water storage tank collapsed onto one of the raw water tanks and portions of the fire protection/service water system.

The failure of nonsafety-related equipment also threatened safety-related equipment in that the damaged Unit 1 chimney could have potentially collapsed onto the Unit 4 EDG building.

These events

were not fully anticipated at the time.

As a result, the licensee developed a lessons learned action plan after Hurricane Andrew to track system restoration and to develop modifications or contingency plans where needed.

The inspectors reviewed the licensee's procedures, storm stock inventory lists, and PWOs regarding the flood protection stoplog inspection and various floor drain inspections.

The inspectors evaluated the possibi.lities of any direct interaction with equipment onsite as a result of a hurricane.

The inspectors did not identify any direct interaction possibilities with equipment on site.

However, the following vulnerability was noted and documented in paragraph 9.c on NRC Inspection Report No. 50-250,251/93-17:

Various tanks such as the RWSTs, PWSTs, DWSTs, Unit 3 EDG fuel oil storage tank, upper portion of the CSTs, and both raw water tanks are exposed to potential damage from flying debris.

The licensee has performed a

PRA analysis regarding the potential loss of these miscellaneous tanks due to flying debris and has determined that the risks are acceptable.

In summary, the licensee has been pro-active in the area of hurricane preparedness.

The licensee's procedures provide thorough compensatory measures for equipment or facilities not designed for a hurricane, and the licensee has adequately examined the impact of nonsafety-related equipment on important equipment during external events.

7.2.2 Lightning Strike and Affect on Emergency Facilities At 3:45 p.m.

on May 28, 1994, a lightning strike associated with a severe storm caused the loss of the McGregor substation.

This substation is located within the owner controlled property about a

half mile west of the site.

It provides power to the site for building services, the water treatment plant, and the TSC.

The power supply for the TSC automatically switched to its backup power supply via the 3C 4160-volt bus and 3G load center.

Power was restored to the substation at 5:40 p.m.

on the same day.

The inspectors became aware of the event by reviewing the control room logs on May 31, 1994.

The inspectors questioned emergency preparedness and operations personnel regarding the licensee's actions to ensure that TSC power remained available.

Further, the inspectors noted that no response procedure existed for the loss of this substation (non-safety related).

Although not required, the inspectors believed that a response procedure would be prudent.

The licensee agreed and plans to develop an ODI procedure.

The licensee is currently tracking this action item on the CTRAC syste.2.3 The inspectors concluded that regardless of the lack of a response procedure, the licensee reacted appropriately to the loss of the HcGregor substation.

Further, the inspectors noted that the licensee was responsive to the inspectors'oncern that no response procedure existed.

Fire Protection Deluge System Problems During the period, the Unit 4 main transformer fire protection deluge system inadvertently actuated twice resulting in fire protection water spray downs.

Previously (during 1994),

several other pre-action deluge systems inadvertently actuated in the Unit

CCW and charging pump rooms.

Each event was documented with a condition report.

Based on the collective significance of these events, the licensee formed a special task force to evaluate equipment performance.

The task force included personnel from fire protection, engineering, I&C, the technical department, and a

vendor representative.

The licensee determined that misoperation of the transformer deluge mercury switches resulted in the two transformer deluges.

This was apparently caused by setpoint drift.

The licensee recalibrated these switches providing additional margin and enhanced the training of I&C personnel with the support of a vendor.

The CCW room deluges were apparently caused when operations would reset a false alarm.

The licensee reviewed system design, environmental conditions, and equipment conditions.

A defective module was replaced, and longer-term design modifications are planned.

The charging pump room deluge was caused when a worker inadvertently bumped the local pull station.

The individual was counselled and other personnel were reminded to exercise care when working in the vicinity of critical equipment.

The inspectors reviewed the condition reports, observed troubleshooting activities in the field, and discussed these issues with licensee engineers and fire protection personnel.

The inspectors plan to follow up on licensee activities in this area.

The inspectors concluded that the licensee has appropriately addressed these inadvertent fire protection system deluge actuations.

7.2.4 Emergency Preparedness Practice Exercise/Drills and Annual Exercise/Drill In preparation for the annual emergency exercise, the licensee performed practice drills on June 17 and 27, 1994.

The licensee conducted its annual emergency exercise on June 29, 199 Different scenarios were utilized in each drill.

The annual emergency exercise involved a steam generator tube leak scenario.

The inspectors monitored these exercises from the simulator, OSC, and TSC.

The exercises were appropriately conducted.

Strong communications and interdepartmental team work were evident.

In addition, post drill critiques were appropriately conducted with constructive feedback from the controllers.

7.2.5 Offsite Fire At 2:30 a.m.

on June 21, 1994, a raccoon caused an operating bus fault at the McGregor substation located approximately 1/2 mile west of the plant.

When the fault occurred, the bus differential relays initiated trip signals to the lockout relay.

The lockout relay coil picked up and partially rotated the lockout before binding.

The lockout relay operated enough to send a lockout alarm signal to the system control center but not enough to initiate the tripping of the transformer F-switch to interrupt the fault.

This failure to clear the fault resulted in a fire located on the low voltage side (13 KV) of the substation.

The fire could be seen from approximately 10 miles away, and it attracted some media attention.

The fire was initially sighted by plant operators and was promptly reported to the FPL system control center.

After verifying the fire to be at the McGregor substation, the system control center dispatcher cleared the fault and stopped the fire at 2:36 a.m.

by de-energizing the Florida City 230-KV transmission line.

The other seven transmission lines to the site and the operation of the Turkey Point nuclear plants were not affected.

The site did, however, lose some non-essential electrical power for approximately l-l/2 hours including normal power supplies to the administrative buildings, water treatment plant, and TSC.

The power supply to the TSC automatically switched to the backup when the normal supply was lost.

Two members of the licensee's fire brigade responded to" the fire, and the Metro-Dade Fire Department was called as a precaution.

The licensee also made a courtesy call to the NRC regarding this event and notified the senior resident inspector at home.

A press release was not issued, but the licensee did have a representative available to respond to questions from the media and public.

As a result of this event, the licensee replaced the failed lockout relay (GE 12HEA63C238X2 - date code December 1991).

Investigation revealed that the lockout handle shaft pin had jammed against the front plate of the reset foil assembly preventing the lockout from rotating to its full position.

This condition was repeated in a laboratory and is considered to be a

manufacturing defect.

The licensee is currently working with GE to determine how widespread this problem is and to develop a

solution to implement on any defective lockouts.

There are currently 591 of these relays in the FPL system.

There are approximately 12 internal to the plant, and there are none in the

7.2.6 switchyard.

The 12 relays internal to the plant were inspected by a representative from the site's protection and control group, and no problems were identified.

The licensee has also written two condition reports to document this event.

Condition report No.94-694 documents the fire and the immediate actions, and condition report No.94-706 documents the licensee's ongoing actions regarding the failed lockout relay.

Following the repair of extensive damage to both feeder and standby breakers and their associated lines and equipment, the McGregor substation was returned to service on June 28, 1994.

The inspectors responded to this event, examined the substation, and had discussions with licensee personnel.

The inspectors also reviewed an executive summary on the lockout failure and the condition reports.

The licensee's actions with regard to this event were responsive and thorough.

ALARA Review Board 7'.7 The licensee's ALARA program included a job review process, procedures, goals, a suggestion program, and an ALARA review board.

Administrative procedure O-ADM-602, ALARA Program, described the board composition, its function, meeting agenda, and documentation requirements.

The board was scheduled to meet at least quarterly.

During the period, the inspectors attended two ALARA review board meetings.

Items reviewed included personnel contamination events, job estimates, outage dose results, and other programs under review designed to reduce dose, The inspectors determined that meetings were conducted in accordance with program requirements.

The inspectors noted that the on-site engineering and construction managers were not voting members although these organizations were routinely represented at the board meetings.

This item was discussed with health physics and plant management personnel.

The inspectors concluded that the ALARA review board is well supported by management and it appeared to be effective in ensuring that station radiation exposure is indeed as low as possible.

Radioactive Material At approximately 1:00 p.m.

on June 24, 1994, a box of blueprints from document control alarmed the portal monitor upon exit from the protected area.

The box contained records and old drawings from the 1970s.

Health physics personnel took control of the box and identified Cobalt-60 and Cesium-137 radio-isotopes during a

fast scan.

The activities were below licenses quantities, and the licensee determined that this event was not reportable.

Health physics personnel also surveyed document control and body counted all personnel in document control.

No activity was detected.

In

e

addition, the licensee generated condition report No.94-699.

The root cause of this event is still under investigation, and the licensee plans to document its determinations with the closeout of the condition report.

The inspectors discussed this event with the licensee, verified the reportability determination, and reviewed the condition report.

The inspectors plan to follow up on the licensee's root cause determination and long-term corrective actions during future inspections.

The licensee's actions with regard to this event were appropriate.

8.0 Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the site vice president and selected members of his staff.

An exit meeting was conducted on July 7, 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 inspections Dissenting comments were not received from the licensee.

Although violations or deviations were not identified, the inspectors had the following findings:

Item Number Status Descri tion and Reference 50-250)251/94-11-01 (Opened)

IFI - Core Exit Thermocouple Status and Technical Specifications (section 4.2.3)

50-250,251/94-11-02 (Opened)

URI - Incorrect ISI of Branch Line Connections to the RCS (section 5.2.8)

Additionally, the following previous items were discussed:

Item Number Status Descri tion and Reference LER 50-250/94-002 (Closed)

LER - Inadvertent Engineered Safety Feature Actuation (section 6.2.5)

9.0 Acronyms and Abbreviations ADH AFW ALARA ANPO ANPS ASHE CC CCW CET CFR CHH Administrative Auxiliary Feedwater As Low As Reasonably Achievable Associate Nuclear Plant Operator Assistant Nuclear Plant Supervisor American Society of Hechanical Engineers Cubic Centimeter Component Cooling Water Core Exit Thermocouple Code of Federal Regulations Corrective Haintenance

- Hechanical

LJ

CNRB CS CSI CST CTRAC DC DWST ECCS EDG EPIP F

FJC FPL g

GE HHSI IKC IFI IPEEE ISI IWB JPN KV KW LER MIMS NPO NPS NRC NRR NWE ODI ONOP OP OSC OSP PNSC PRA psig PTN PWO PWST QA QC RCS RHR RO rpm RWST SALP SECJ SEMS Company Nuclear Review Board Containment Spray Component Specialists and Inspections Condensate Storage Tank Commitment Tracking Direct Current Demineralized Water Storage Tank Emergency Core Cooling System Emergency Diesel Generator Emergency Plan Implementing Procedure Fuse Juno Civil Calculation Florida Power and Light Acceleration of Gravity General Electric High Head Safety Injection Instrumentation and Control Inspector Followup Item Individual Plant Examination for Externa Inservice Inspection ASME Section XI Requirements for Class I Juno Project Nuclear (Nuclear Engineerin Kilovolt Kilowatt Licensee Event Report Metal Impact Monitoring System Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear Watch Engineer Operations Directive Instruction Off Normal Operating Procedure Operating Procedure Operational Support Center Operations Surveillance Procedure Plant Nuclear Safety Committee Probable Risk Assessment Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Primary Water Storage Tank Quality Assurance Quality Control Reactor Coolant System Residual Heat Removal Reactor Operator Revolutions Per Minute Refueling Water Storage Tank Systematic Assessment of Licensee Perfor Safety Evaluation Civil - Juno Safety Evaluation Mechanical

- Site 1 Events Components g)

mance

SFI SI SMN SRO STA TNI TS TSA TSC UFSAR URI UT

Security Force Instruction Safety Injection Surveillance Maintenance

- Nechanical Senior Reactor Operator Shift Technical Advisor Three Nile Island Technical Specification Temporary System Alteration Technical Support Center Updated Final Safety Analysis Report Unresolved Item Ultrasonic Testing