IR 05000250/1994018

Insp Repts 50-250/94-18 & 50-251/94-18 on 940828-0930.No Violations Noted.Major Areas Inspected:Operational Safety & Plant Events,Chemistry,Fire Protection & Housekeeping

ML17352A874
Person / Time
Site:	Turkey Point
Issue date:	10/18/1994
From:	Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352A873	List: IR 05000250/1994018 ML17352A872
References
50-250-94-18, 50-251-94-18, NUDOCS 9411070259
Download: ML17352A874 (62)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/94-18 and 50-251/94-18 Licensee:

Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Inspection Conducted: 'ug st 28 through September 30, 1994 Inspectors:

T.

P.

Jo nson, Se or Resident Inspector B. B.

De ai, Resi nt Inspector L. Trocine, Resid Date Si ned D

e S gned to ah Dat Si ned nspector Docket Nos.:

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Approved by:

K. D. Landis, Chief Reactor Projects Section 2B Division of Reactor Projects lo Da gn d

SUMMARY Scope:

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

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

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

Results:

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

Violations or deviations were not identified.

The following inspector followup item was identified:

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Inspector Followup Item 50-250,251/94-18-01, Modification of Eagle-21 System Power Distribution Panels (section 6.2.1)

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

Plant 0 erations The licensee's preparations for the Unit 4 refueling outage including risk assessment, new fuel movement, plant management involvement, and quality assurance involvement were very good (section 4.2. 1).

The licensee was responsive in resolving minor housekeeping and labeling deficiencies noted by the inspectors during general plant tours (section 4.2.2).

The licensed operator requalification training program assured that qualified operators were available.

Simulator training conducted for outage-related events was effective (section 4.2.3).

Operator actions with regard to a Unit 3 Eagle-21 system power distribution panel failure were appropriate (section 4.2.4).

Unit 4 power reduction, condenser tube leak repair, and unit restart activities were performed in a controlled efficient manner, and operator professionalism was evident (section 4.2.5).

Licensed operators effectively responded to a Unit 4 reactor trip, and licensee followup was thorough (section 4.2.6).

Maintenance During preventive maintenance activities, a sticking 4160-volt non-vital bus breaker cubicle door caused protective relays to actuate, and this concurrent with a failure of a rod control power supply resulted in an automatic Unit 4 reactor trip (section 4.2.6).

The inspector observed maintenance and surveillance testing activities that were completed in a satisfactory manner (sections 5.2. 1 and 5.2.2).

The licensee's foreign material exclusion program effectively ensured that plant equipment and systems were not degraded by potential foreign material introduction (section 5.2.3).

En ineerin The licensee's actions with regard to both followup on an industry event involving an Eagle-21 system power distribution panel failure and to similar events at Turkey Point were prompt and comprehensive.

However, an inspector followup item was opened regarding the modification of the Eagle 21 system power distribution panels (section 6.2. 1).

The inspectors concluded that the licensee's decision to train operators on the lessons learned from a May 1994 emergency diesel trip event was a

strength.

However, the inspectors noted a minor weakness in the licensee's knowledge demonstrated during that May 1994 followup relative to diesel response following a reset of the safety injection signal (section 6.2.2).

The licensee has appropriately given attention to Unit 3 main turbine control valve cycling, and its investigation is ongoing (section 6.2.3).

Two opened items were appropriately addressed by the licensee and were closed (sections 6.2.4 and 6.2.5).

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Plant Su ort The licensee's followup to a spill of radioactive water into the radwaste building was thorough and aggressive, and it'included an independent review by quality assurance (section 7.2. 1).

The post accident sampling system's availability over the past several years was noted to be satisfactory; however, at times, the system was out of service for maintenance and design changes (section 7.2.2).

minor weaknesses were noted in the licensee's contamination control and personnel saFety programs during new fuel movement operations (section 7.2.3).

Three open items were appropriately addressed by the licensee and were closed (sections 7.2.4 through 7.2.6).

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

1.1 1.2 1.3 Licensee'Employees.......................................

NRC Resident Inspectors..................................

Other NRC Personnel On Site.....................

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.. 1 2.0 Other NRC Inspections Performed During This Period

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3 3. 1 Unit 3.............

3.2 Unit 4.............

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4.0 Plant Operations...............

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4. 1 Inspection Scope...

4.2 Inspection Findings

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6.0 Engineering...................................................

6. 1 Inspection Scope...

6.2 Inspection Findings

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.0 Plant Support.................................................

7 7. 1 Inspection Scope 7.2 Inspection Findings

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

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Acronyms and Abbreviations

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1.0 Persons Contacted REPORT DETAILS Licensee Employees T. V.

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Sup R. J.

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Abbatiel'lo, Site guality Manager Bowskill, Reactor Engineering Supervisor Franzone, Instrumentation and Controls Maintenance ervisor Gianfrancesco, Maintenance Support Services Supervisor Goldberg, President, Nuclear Division Heisterman, Mechanical Haintenance 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 Harcussen, Security Supervisor Pearce, Plant General Manager Pearce, Electrical Maintenance Supervisor Plunkett, Site Vice President Powell, Technical Manager Rose, Nuclear Materials Manager Steinke, Chemistry Supervisor Wayland, Maintenance Manager 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 B. A. Boger, Acting Director, Division of Reactor Projects, Region II D.

G. Crain, Co-op, Technical Support Staff, Division of Reactor Projects, Region II

Attended exit interview on September 30, 1994 Note:

An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this repor.0 Other NRC Inspections Performed During This Period None 3.0 Plant Status 3.1 Unit 3 3.2 At the beginning of this reporting period, Unit 3 was operating at full reactor power and had been on line since May 27, 1994.

Unit load was reduced to 40% power on September 19, 1994, in order to perform secondary plant testing and maintenance.

Full power was re-achieved on September 21,. 1994.

Unit 4

At the beginning of this reporting period, Unit 4 was operating at full power and had been on. line since March 18, 1994.

The unit was taken off line on September 1,

1994, due to a condenser tube leak.

(Refer to section 4.2.5 for additional information.)

The unit remained in Mode 2, and was returned to full power on September 3,

1994.

The unit tripped from full power when the 4C 4160-volt bus was lost on September 23, 1994.

(Refer to section 4.2.6 for additional information.)

The unit was returned to full power on September 25, 1994.

4.0 Plant Operations (40500, 60705, 71707, and 93702)

4.1 Inspection Scope The inspectors verified that FPL operated the facilities safely 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 a review of the licensee's self-assessment capability by including PNSC activities, gA/gC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicator.2 Inspection Findings 4.2.1 Unit 3 Refueling Preparations Unit 4 is scheduled for a 44-day refueling outage during the period October 3 to November 17, 1994.

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

This included the following activities:

fuel receipt, inspection, and movement procedures; outage schedule, critical path, and goals; PC/H scope; major maintenance and testing activities; plant conditions and mode changes; core offload and reload activities; operator training relative to shutdown conditions; RPV draindown; outage risk assessment; control of contractors and temporary employees; shift director schedules and functions; plant manager briefings; and licensee commitments and technical specifications.

The inspectors reviewed in detail administrative procedure 0-ADH-051, Outage Risk Assessment and Control.

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

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

The licensee also established a risk assessment team and leader whose function was to review schedule, key shutdown functions, and key equipment availability.

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

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

Another good practice was the use of a handout outage book given

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to each employee.

This book included important outage facts and other pertinent information.

A telephone conference call with licensee and NRC representatives was held on September 22, 1994, to discuss the upcoming Unit 4 refueling outage.

This discussion was beneficial in understanding critical path, outage schedule, goals, and other information items.

The inspectors observed the new fuel receipt, storage, and transfer process from the new fuel storage room to the spent fuel pool.

Personnel from reactor engineering, Westinghouse (fuel vendor), operations, and HP were involved.

The inspectors noted excellent teamwork among the participants including good procedure usage and good communications.

The inspectors also verified that the control room was cognizant of all activities.

(Refer to section 7.2.3 for additional information relative to radiation and personnel safety.)

The inspectors also reviewed gA/gC involvement in Unit 4 new fuel receipt, inspection, and transfer operations.

gA/gC performed monitoring and surveillance activities of the spent fuel pool housekeeping, new fuel shipping containers receipt and inspection, new fuel handling equipment, and new fuel transfer operations.

The gA/gC housekeeping inspection noted loose material in the vicinity of the pool.

The appropriate personnel were notified, and this material was removed prior to new fuel movements into the spent fuel pool.

The inspectors concluded that the licensee is appropriately prepared for the Unit 4 Cycle 15 refueling outage.

The risk assessment process appears effective.

4.2.2 Plant Tours The inspectors noted and reviewed the following issues during general plant tours conducted during the inspection period:

Unit 4 containment isolation valve CV-4-204 on the RCS letdown line was noted to have a work request due to a body-to-bonnet leak.

The leak was minor, and no significant boric acid buildup was noted.

In addition to the work request, condition report No.94-793 had been initiated to document an operability evaluation as a result of the leak.

The evaluation concluded that when valve CV-4-204 closed following a phase A containment isolation signal, the valve internals would be isolated from containment by virtue of the fact that the valve is a globe type valve.

Therefore, the safety-related containment isolation capability of the valve was unaffected.

Additionally, a visual inspection conducted by the licensee had not identified any corrosion on the valve body.

The leak could not be immediately fixed

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due to the operational constraints, and maintenance is planned during the upcoming Unit 4 refueling outage.

The inspectors concluded that licensee actions were appropriate and had no further questions at this time'.

During walkdowns of the Unit 3 and 4 pipe and valve rooms, the inspector noted an erroneous penetration tag number on.

penetration No.

14 on Unit 4.

The tag was immediately removed upon notification.

The Unit 4 RHR suction line located in the pipe and valve room was noted by the inspectors to be hot to the touch.

This line was connected to the RCS cold leg and was isolated by two valves during power operations.

Upon notification, the licensee initiated an investigation which included taking temperature readings on the RHR suction line on both units.

The temperature of the pipes was noted at approximately 145'F.

The licensee concluded that the temperature was normal and attributed it to conduction from the existing RCS piping temperatures in containment.

An RCS leak into the RHR suction line was ruled out because there were no significant changes in RCS leakage rates.

The inspectors concluded that licensee was very responsive to the inspectors observation and was aggressive in its resolution.

The inspectors noted a temporary electrical cord laying on the Unit 4 blowdown sample line in the pipe and valve room.

The cord was a potential fire hazard as the blowdown sample line routinely is put into service to sample the steam generators.

This was brought to the attention of the shift supervisor, and the cord was immediately removed.

The inspectors walked down portions of the Unit 3 HHSI system with particular emphasis on valve alignments.

Negative observations or safety issues were not noted.

The inspectors also noted an increase in the number of scaffolds in preparation for the Unit 4 refueling outage.

Negative observations or safety issues were not noted.

The inspectors concluded that minor housekeeping deficiencies existed in the plant; however, upon notification, the licensee immediately corrected or addressed the issues.

4.2.3 Licensed Operator Training The inspectors reviewed portions of the licensed operator requalification training program including simulator training and actions taken upon individual examination failures.

The inspectors reviewed procedure AP-0301, Licensed Operator

Continuing Training Program.

This procedure describes the requalification program requirements.

During the week of August 29, 1994,,three licensed operators failed one por'tion of a requalification training segment.

The licensee immediately removed these individuals from licensed operator duties and logged them into the operator out-of-service log book.

The training department conducted remedial training, and the effected operators passed this training.

The operators were subsequently re-certified and then removed from the out-of-service log and allowed to perform licensed duties.

The inspectors verified these actions and discussed the overall program with training department management personnel.

The inspectors noted that this operator out-of-service log was referenced in operation's turnover sheets; however, the log was not addressed in the AP.

The licensee stated it would address this issue.

The inspectors also observed portions of current requalification cycle simul.ator training.

The inspectors noted.

that due to the failures, operations was required to staff the control room with the use of overtime in order to meet the minimum licensed operator complement.

Unit 4 was in the process of returning to full power, and extra operators were required.

(Refer to section 4.2.5 for additional information.)

The inspectors verified that overtime and staffing were consistent with technical specification and administrative requirements.

The inspectors concluded that the licensed operator continuing training and requalification program was effective in assuring well qualified operators were available.

In addition, the inspectors noted the effective use of refueling outage-related simulator scenarios including loss of power, loss of RHR, and loss of coolant while shutdown.

4.2.4 Unit 3 Eagle-21 Reactor Protection System Power Distribution Panel Failure At 2:04 p.m.

on August 31, 1994, Unit 3 annunciator J-7/4, EAGLE-

TROUBLE, began alarming intermittently, and it locked in at 2:25 p.m.

Operators implemented the appropriate ARP, and at 2: 10 p.m.,

IKC verified that a problem existed with instrument rack 3(R01.

At 3: 15 p.m., the licensee removed Eagle-21 channel 1 from service and entered procedure 3-0NOP-049, 1, Deviation or Failure of Safety-Related or Reactor Protection Channels, and the action statements for Technical Specifications 3.3. 1 and 3.3.2.

The licensee also subsequently tripped the appropriate RPS bistables in order to meet the technical specificati'on action statements.

Troubleshooting revealed a problem with an internal power distribution panel.

This failure was determined to be similar to the August 11, 1994, failure of instrument rack 4(R14.

(Refer to sections 4.2.5 and 6.2.5 of NRC Inspection Report No. 50-250,251/94-17 for additional information.)

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4.2.5 The licensee replaced the affected power distribution panel with an unmodified power distribution panel which had been taken out of a training rack.

The licensee then returned Eagle-21 channel 1 to service at 11:05 p.m.

on the same day.

The licensee subsequently returned the failed power distribution panel to Westinghouse for further root cause analysis and modification.

The licensee also currently plans to send the power distribution panels in the remaining four Eagle-21 racks (3QRll, 3QR14, 4QR01, and 4QR11)

back to Westinghouse for modification if the root cause determination identifies a failure mechanism similar to the one that occurred at Zion.

(Refer to sections 4.2.5 and 6.2.5 of NRC Inspection Report No. 50-250,251/94-17 and section 6.2.1 of this report for additional information.)

Similar power distribution panels do not exist elsewhere in the plant.

The inspectors reviewed the licensee's actions with regard to this event and deemed them to be appropriate.

The inspectors plan to follow up on the final root cause determination and additional licensee corrective actions during future inspections.

Unit 4 Condenser Tube Leak Following maintenance on the 4B2 circulating water pump motor, the 4B2 circulating water pump was started at 1:25 p.m.

on September 1,

1994, and the pump was stopped approximately five minutes later due to increasing motor bearing temperatures.

At 1:40 p.m.,

a secondary system high conductivity alarm was received, and chemistry was notified.

Conductivity in the 4A south and 4B south waterboxes had increased to greater than 20 micromhos per centimeter, and the conductivity in all 3 steam generators had increased to greater than 20 micromhos per centimeter within 2 minutes.

This placed Unit 4 in Action Level 3 for steam generator cation conductivity (greater than 7.0 micromhos per centimeter)

per procedure 4-ONOP-071. 1, Secondary Chemistry Deviation From Limits.

As a result, the licensee increased blowdown to a maximum of 150,000 pounds mass per hour per steam generator.

In addition, per procedure 4-GOP-103, Power Operation to Hot Standby, the licensee commenced a load reduction at 1:45 p.m.,

and took the unit off line at 2:55 p.m.

The unit remained in Mode 2.

The licensee's investigation revealed a small hole in one tube approximately 1-1/2 inches past the tube sheet in the 4B south waterbox.

The tube also had an existing plug approximately

inches past the tube sheet.

The licensee hypothesized that either the existing condenser tube plug was covering an old leak and a.

new leak appeared or the existing plug moved and exposed a

previously existing hole following a hydraulic transient caused by the starting of the 4B2 circulating water pump.

(Apparently, a

lightening strike in the vicinity of the intake on August 25, 1994, had damaged the motor for the 4B2 circulating water pump.

The licensee generated condition report No.94-811 and subsequently sent the motor out for repairs.

These repairs in

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turn resulted in some of the motor windings being jumpered out.

This change was evaluated as satisfactory.)

As a result of'this event, the licensee installed another plug in the leaking condenser tube and performed a visual inspection of the remaining plugs.

The licensee currently plans to remove the affected tube during the upcoming Unit 4 refueling outage and to.

perform an analysis to determine whether or not the existing plug moved.

The licensee is also currently evaluating the expected lifetime for the plug material and evaluating the feasibility for using plugs with a larger outside diameter washer for future tube plugging or plug replacements.

Following the tube leak repair, Unit 4 entered Mode 1 at 9:40 a.m.

on September 2,

1994.

The turbine was placed back on line at 10:05 a.m.,

and reactor power was stabilized at 30% at 10:40 a.m.

for a chemistry hold because the unit was still in Action Level

for steam generator sodium (greater than 20 ppb) per procedure 4-ONOP-071. 1.

Power ascension was recommenced at 5:00 p.m.

on the same day, and 100% reactor power was achieved at 5:00 a.m.

on September 3,

1994.

The inspectors monitored the licensee's shutdown, repair, and restart activities.

All of these activities were performed in a controlled efficient manner, and operator professionalism was evident.

4.2.6 Unit 4 Reactor Trip Unit 4 automatically tripped from 100% reactor power at 2:47 p.m.

on September 23, 1994.

The trip occurred when the 4C 4160-volt non-vital bus was lost due to a differential relay lockout.

This was caused when maintenance electricians closed breaker 4ACOl cubicle door.

Apparently, the door was sticking, and the closure jarred the protective relays and resulted in actuation of the C

phase differential lockout.

The electricians were performing preventive maintenance on the breaker.

The loss of the 4C bus resulted in a loss of 48 steam generator feedwater pump and a loss of one of two power supplies to the rod control power cabinet (panel)

lAC.

The other power supply from the motor generator set (PS-3)

was degraded such that it failed when loaded resulting in a complete loss of control power to panel 1AC.

Panel 1AC provided the controls for the control rods in group 1 of shutdown bank A and control banks A and C.

Thus, the twelve rods in these groups de-energized and caused the reactor to shut down.

About 1.5 seconds later, the reactor automatically tripped due to an overtemper ature differential-temperature signal.

This was due to the flux decrease and associated input into the trip parameter.

The reactor trip breakers opened as expected.

All conditions were normal on the reactor trip response.

AMSAC and AFW actuated on low steam generator level.

Operators entered

the appropriate EOPs and ONOPs and maintained the unit in Mode 3.

The 4C bus and normally fed load centers and motor control centers were subsequently re-energized.

The licensee made an ENS call, initiated a condition report (No.94-890),

and convened an ERT.

The licensee confirmed that plant response was as expected by running the same scenario on the simulator and by reviewing UFSAR section 14. 1.4.

Troubleshooting confirmed that PS-3 was degraded.

The licensee verified that the rod control power supplies were checked during the last Unit 4 refueling outage (April 1993).

The licensee further concluded that if PS-3 would have completely failed, a non-urgent rod control alarm would have occurred to alert operators.

Additional licensee followup noted that the cubicle door for breaker 4AC01 had been opened and closed multiple times during the day.

However, some cubicle door sticking did occur during this attempt, and it may have been caused by the daytime heating effect of this outdoor switchgear.

The three phase differential relays were checked to be satisfactory.

Licensee short-term corrective actions included completion of an ERT and post-trip review, PNSC review, rod control system power repairs and testing, and stopping of the 4160-volt breaker work.

Longer-term actions included plans to inspect the failed PS-3 power supply to determine its failure mechanism; to review the 4C 4160-volt bus breaker cubicle door arrangements, protective relay locations, and maintenance during power operations; to review the rod control power scheme history; and to recommend changes.

The PNSC authorized restart on September 24, 1994, and the licensee updated the ENS call.

Unit restart began at 6:15 a.m.

on September 24, 1994.

The control rods in the A shutdown bank were withdrawn to 228 steps, and operators commenced the performance of procedure OP-1604.1, Full Length RCC - Periodic Exercise., At the rod deviation/axial flux panel (control room back panel),

an abnormal light indication was noted for the 8 shutdown bank rods.

The operator tapped the extinguished light causing a flash and trip of 4P07 supply breaker (10 amps).

This resulted in the indicated rod position going to 135 steps for the shutdown bank A control rods.

The operators manually opened the reactor trip breakers, and the unit remained in Mode 3.

The licensee initiated another ERT, developed another condition report (No.94-891),

and made another'ENS call.

The licensee determined that a light bulb burned out and subsequently shorted when tapped by the operator.

This tripped the supply breaker (4P07-20)

which in turn de-energized the rod deviation/axial flux panel.

The rod position input was affected and resulted in the rods in shutdown bank A indicating abnormally at 135 steps.

The licensee replaced the socket and light bulb, tested the circuit, checked other similar ones, and confirmed the observed control rod

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position indication effects that were noted by the operators.

The PNSC subsequently authorized unit restart.

Criticality was achieved at 2:08 p.m.

on September 24, 1994, and the unit was placed on line at 6:00 p.m.

Unit 4 achieved full reactor power at 3:45 a.m.

on September 25, 1994.

The inspectors observed post-trip conditions from the control room.

The ANPS was noted to be following EOPs and ONOPs.

Due to shift turnover in progress, extra RCOs were available to assist.

RCO performance was very good.

Management and gA presence was

'lso observed.

STA involvement in EOPs, DDPS, SPDS, and ERDADS and operations'ommand and control were both strong.

The inspectors reviewed the condition reports, the ERT reports, and the post-trip review.

The PNSC meeting on September 24, l994, and the unit restart were also observed.

The inspectors concluded that the licensed operators effectively responded to trip.

Licensee followup appeared to be timely, thorough, and addressed nuclear safety.

The associated reports were professionally done.

Root cause and corrective actions were appropriately addressed.

The licensee intends to submit an L'ER for these events.

The inspectors did not identify any regulatory compliance issues.

5.0 Maintenance (62703, 61726, and TI 2515/125)

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 documents.

5.2 5.2.1 Inspection Findings Maintenance Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

B AFW pump preventive maintenance; Unit 3 secondary plant maintenance (TPCW, condenser, heater drain pumps, and condensate pumps);

procedure 0-GME-102. 1, Troubleshooting and Repair Guidelines, for the 3B EDG (Refer to section 6.2.2 for additional information.);

and

I

PASS troubleshooting and calibration.

(Refer to section 7.2.2 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 procedures and activities:

procedure 3-0SP-050.2, Residual Heat Removal System Inservice Test; procedure 3-0SP-068.2, Containment Spray Pump Inservice Test; procedure O-OSP-075.2, B Auxiliary Feedwater Train

Operability by Verification;'rocedure 0-OSP-075. 11, Auxiliary Feedwater Inservice Test, for the B AFW pump; and procedure 4-0SP-300.3, Safe Shutdown and Alternate Shutdown Operability Test.

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 Foreign Material Exclusion The inspectors reviewed the licensee's program for FHE.

This was performed in accordance with NRC Temporary Instruction 2515/125.

The following procedures and documents were reviewed:

procedure gI-2-PTN-3, Fluid System Cleanliness Control; procedure gI-2-PTN-4, Housekeeping; procedure O-ADH-008, Management and Supervisor Field Walkdowns; procedure O-ADM-009, Containment Entries When Containment Integrity is Established; procedure O-ADH-552, Work Requirements for Maintaining Cleanliness in the Spent Fuel Rooms; procedure O-ADM-701, Control of Plant Work Activities;

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I

procedure O-ADM-713, Confined Space Entry; procedure O-ADM-714, Conduct of Maintenance Training; procedur'e O-ADM-737, Post Maintenance Testing; Information Bulletin No. 92-07, FHE at Turkey Point; plant manager's walkdown lists; Information Bulletin No. 93-33, Revision 2, The Effects and Prevention of Fuel Rod Integrity Failures; selected NRC information notices; and selected maintenance procedures and PWOs.

The inspectors concluded that the above procedures appropriately addressed the prevention of foreign material introduction into

.

safety-related systems and components.

The licensee's FHE program included work performed on safety and non-safety related systems.

Specific FHE requirements and precautions are incorporated into PWOs and the respective maintenance implementing procedure.

The licensee performed a

self-assessment of its FME program and controls.

Results were documented in a report dated January 22, 1992.

Findings and corrective actions were appropriately addressed.

The inspectors reviewed that.1992 self-assessment and recent FHE inspections and findings.

The condition report system was also reviewed for the past 12 months.

There were no FHE-related failures, equipment damage, or vulnerabilities.

The inspectors also reviewed QA/QC maintenance inspection for the previous

months.

One unsatisfactory finding was noted.

Quality Report No.

QRNO-94-074 dated September 6,

1994, noted that the area surrounding the Unit 4 spent fuel pit did not meet the cleanliness requirements of procedure 4-0P-040.3, Refueling Preshuffle in the Spent Fuel Pit.

Items found loose included gloves, tape, face shields, and tools.

These items were appropriately removed.

During followup tours of spent fuel pit areas, the inspectors noted several bags of radwaste near the pool.

HP personnel were informed, and these bags were removed immediately.

The inspectors observed work in progress in order to assess the licensee's FME controls.

Work observed included the 4B CCW heat exchanger cleaning and testing, the 3B TPCW heat exchanger cleaning and tube plugging, the Unit 3 main condenser waterboxes cleaning and inspection, and the 3B condensate pump seal replacement.

The inspectors also interviewed personnel involved in FME controls and related work.

Personnel were knowledgeable regarding the FHE program and related precautions and control II

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Based on the FHE program review, field observations, recent experiences, and personnel knowledge; the inspectors concluded that the licensee had a strong FHE program that effectively ensured that plant equipment was not degraded by foreign material introduction.

'.0 Engineering (37551 and 92903)

6.1 6.2 6.2.1 Inspection Scope The inspectors verified that licensee engineering problems and incidents were properly reviewed and assessed for root cause determination and corrective. actions.

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

The inspectors reviewed a previous noncompliance and an open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

The inspectors reviewed the report 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

CFR Part 21 Followup and Similar Events at Turkey. Point The Unit 3 Eagle-21 system power distribution panel failure that occurred on August 31, 1994 (Refer to section 4.2.4 for additional information.),

appeared to be similar to a Unit 4 Eagle-21 system power distribution panel failure on August 11, 1994.

(Refer to sections 4.2.5 and 6.2.5 of NRC Inspection Report No. 50-250,251/94-17 for additional information.)

It also appeared to be similar to one of the problems documented in a

CFR Part

notification issued by Zion on April 8, 1994.

The problems experienced at Zion involved the premature failure of power supplies used in the Westinghouse plant protection system.

Instrument rack de-energization and re-energization problems occurred due to failure of Douglas-Randall time delay relays in the Westinghouse Eagle-21 plant protection system.

The Zion root cause investigation concluded that one problem was caused by the failure of an aluminum electrolytic capacitor and that this end-of-life failure was accelerated by localized heating within the module due to a resistor in close proximity to the capacitor.

The corrective action at Zion was to relocate the resistor to the outside of the epoxy module to separate it from the capacitor.

An

6.2.2 NRC Information Notice regarding this issue (NRC Information Notice 94-33, Capacitor Failures in Westinghouse Eagle-21 Plant Protection Systems)

was promulgated on May 9, 1994.

In response to'he Zion 10 CFR Part 21 notification, the licensee performed an operability assessment (No. 019-94)

on April 14, 1994, and determined that a failure of this type would not prevent RPS from functioning.

The licensee's subsequent discussions with Westinghouse also revealed that the power distribution panels installed in the Turkey Point Eagle-21 system did contain the Douglas-Randall time delay relays which were the subject of the Zion 10 CFR Part 21 notification.

As a result, the licensee documented an action plan regarding the Eagle-21 power distribution panels on Hay 27, 1994.

The actions recommended by this plan included the shipment of the spare power distribution panel to Westinghouse for modification by June 30, 1994, and the monitoring of the Turkey Point Eagle-21 system for these problems.

The licensee also planned to send the power distribution panels in all six instrument racks back to Westinghouse for modification if any rack experienced this condition.

Following the Eagle-21 system power distribution panel failure on August 31, 1994, the licensee modified its action plan to include the modification of all six instrument racks, the training rack, and the spare rack in stores by November 20, 1994.

This issue will be tracked as IFI 50-250,251/94-18-01, Modification of Eagle-21 System Power Distribution Panels.

The inspectors reviewed the licensee's initial actions in= response to the

CFR Part 21 notifications during a previous inspection and determined that the licensee's initial approach to the resolution of this issue was aggressive and appropriate.

(Refer to section 9.2.6 of NRC Inspection Report No. 50-250,251/94-07 for additional information.)

The inspectors also monitored the licensee's recent actions with regard to this issue, interviewed the system engineer involved, and reviewed the documentation relative to this issue.

The inspectors concluded that the licensee's actions were prompt and comprehensive.

EDG Issues During safeguards testing performed on Hay 9, 1994, the 3B EDG had tripped on low cooling water pressure following reset of the SI signal.

(Refer to sections 5.2.8 and 6.2.7 on NRC Inspection Report Nos. 50-250,251/94-10 and 50-250,251/94-11, respectively.)

An SI reset should not have resulted in the 3B EDG to trip as there is a lock-in circuit following an SI.

This lock in circuit is reset only after the EDG is manually shutdown.

At the time of the event, the EDG trip following the SI reset was perceived to be normal by the operators as well as system engineering specialist The low cooling water pressure condition occurred approximately

minutes prior to the reset action and was caused when an operator manually opened a radiator fill valve.

Because no condensate pressure was available due to the existing shutdown plant condition, thi's resulted in the draining of the 3B EDG condensate system and a subsequent low water pressure condition.

As a result of this incident, the licensee had initiated a

condition report (No.94-580)

and a special report was issued to the NRC on June 7,

1994, in accordance with Technical Specification 4.8. 1. 1.3.

The special report was written under the assumption that the EDG trip following the SI reset was normal.

As corrective action, the licensee revised procedure 3-0P-023, Diesel Generator Operability Test, to ensure that condensate pressure is available prior to makeup to the EDG cooling system.

At a later date, during simulator training which recreated the Hay 9,

1994, scenario, the EDG did not trip following SI reset with an existing low cooling water pressure condition.

The operations

.

crew on the simulator was also the same crew that was on shift during the event.

The crew noted that the EDG had performed differently in the plant as compared to during the simulator training.

The issue was brought to the attention of the EDG specialists.

A review of the EDG design logic diagrams confirmed that the Hay 9, 1994, 3B EDG trip following reset of the SI was contrary to the design and should not have occurred.

The low cooling water pressure trip should have remained locked out until the EDG was manually stopped.

In an accident scenario, had the EDG loaded onto the bus due to a LOOP, the low cooling water pressure trip would have been locked out for the LOOP.

Since it was not understood why the 3B EDG tripped following the SI reset, the licensee decided to perform further investigation on a future date.

On September 15, 1994, the 3B EDG was taken out of service to perform an investigation by simulating the events that occurred in Hay 1994.

This included lifting and jumpering leads within the 3B EDG start circuitry.

During the investigation, the licensee was not able to recreate the 3B EDG shutdown following SI reset that had occurred in Hay 1994, i.e., the 3B EDG performed as designed.

The 3B EDG circuitry was restored to its required configuration and tested satisfactorily on the same day.

The inspectors discussed this event with the licensee and concluded that the special report that was issued on June 7,

1994, associated with the event needed to be revised to included the abnormality that had occurred during the EDG test in Hay 1994.

The licensee currently plans to revise the special report.

During the time that the 3B EDG was out of service, the licensee also replaced two leaking relief valves on the 3B EDG A and B air receiver tanks.

These relief valves were in the IST program and were required by the code to be tested to obtain as-found dat I

However, the maintenance. work order did not specifically call out for the maintenance technicians to retain the old relief valves.

6.2.3 Therefore, the'maintenance technicians discarded the two old relief valves.'ince the as-found data could not be obtained, the licensee conservatively assured that the two relief valves would have failed the IST test.

This would have require'd an increase

.in the periodic valve testing sample size.

The licensee is still trying to locate the two relief valves.

If the valves are not located, the licensee intends to implement the requirements that are applicable assuming failure of the as-found valves.

A condition report was originated to prevent a similar future occurrence.

A planned corrective action is to enhance the work planning process such that the IST requirements would be highlighted.

The inspectors concluded that the licensee's decision to train the operators with the lessons, learned from the Hay 1994 EDG trip event to be a strength.

However, the inspector noted a minor weakness in the licensee's knowledge relative to EDG response following a reset of the SI/LOOP logic signals.

Unit 3 Turbine Control Valve Drift Problems Two of the four turbine control valves (No.

2 and No. 4)

on Unit 3 have been noted to drift on an irregular basis without change in control oil pressure.

The cycling of the control valves has resulted in minor (2-5 HWe) load swings.

These swings have been occurring for approximately one year.

To better understand the cause of the control valve swings, the licensee implemented a temporary procedure which connected test equipment to the turbine control system to monitor numerous parameters including main oil pump pressure, smoothing oil pressure, control oil pressure, and control valve position.

To date, the licensee has not been able to directly correlate the cause of the control valve swings to any of the operating parameters.

The licensee is postulating that an instability in the servomotor associated with the control valve could be a

potential cause.

The servomotors for the two control valves are due for refurbishment during the next Unit 3 refueling outage (September 1995).

In the mean time, the licensee is continuing to monitor the problem with appropriate attention being given by the system engineer.

Additionally, to minimize the impact on load due to control valve drift, the licensee has closed the No.

2 control valve and positioned the No.

4 control valve such that a swing in the control valve has minimal impact on steam flo I I

t

6.2.4 6.2.5

The inspectors concluded that the problem is being given due attention.

The inspectors plan to continue to monitor this issue during future inspections.

(Closed)

VIO 50-250,251/89-48-01, Drawing Discrepancies In reviewing system and design engineering involvement in a hydraulic lock failure of RHR valve NOV-4-751 which was documented in LER 50-251/89-04, the inspectors identified errors on drawing Nos.

5610-TE-4501, sheet 1,

and 5610-TE-4510, sheet 2.

The first drawing depicted the Unit 4 RHR hot leg suction line coming from the loop C hot leg in lieu of the loop A hot leg.

The second drawing gave incorrect flow directions and drawing references from the line containing valve HOV-4-751.

The licensee attributed these drawing discrepancies to oversight and corrected them before the end of the inspection period (November 17, 1989).

The licensee also agreed to perform a review for identification and correction of any similar discrepancies.

A violation for these discrepancies was issued on November 31, 1990, and the licensee responded to the violation by letter dated February 27, 1990.

As a result of the violation, the licensee issued a memorandum to operations personnel on February 14, 1990, re-emphasizing procedure O-ADH-510, Request for Engineering Assistance, as being the method for documenting drawing discrepancies.

In addition, on February 20, 1990, the licensee revised the system walkdown guidelines for the system engineers to clarify that system walkdowns include the entire system (i.e.,

accessible portions of the system inside and/or outside the containment building).

A conference call between representatives from the NRC Region II and licensee staffs was also conducted on Harch 12, 1990, regarding the licensee's violation response.

In the violation response, the licensee took credit for system engineer walkdowns as the means by which the drawings were being verified against the as-build configuration of the plant.

As a result of this call, the licensee issued a supplemental response on March 26, 1990, to provide more detail related to the effectiveness of system engineering walkdowns in identifying drawing discrepancies.

The inspectors verified the licensee's corrective actions and reviewed the applicable documentation.

The licensee's corrective actions were appropriate.

This item is closed.

(Closed)

URI 50-250,251/89-54-04, Weep Holes Not Provided for Terminal Boxes Containing Environmentally gualified Terminal Blocks On December 23, l989, Unit 4 experienced a reactor trip due to the rapid closure of the 4A NSIV.

The closure of this valve was attributed to terminal block corrosion which lead to a short

I I

circuit between contacts and the blowing of a control power fuse.

The licensee subsequently found approximately 1/8 inch of water inside the 4A MSIV and approximately 6 inches (I/2 gallon) of water inside the 3C MSIV B train terminal box.

The licensee also identified that the terminal box cover was not properly secured for the 4A MSIV terminal box which could have accounted for the water intrusion.

However, the 3C MSIV terminal box was secured, properly.

This led the licensee to believe the water could have been entering the terminal boxes from inside the conduit system or through the conduit hubs.

Because the conduit system was not completely sealed, water could enter at-a high point and drain to a low point.

These terminal boxes were installed during the previous Unit 4 refueling outage.

They were specified as being NEMA 4 stainless steel terminal boxes which meant that they were weatherproof but not necessarily watertight.

The specification that was used for installation did not require these terminal boxes to have a weep hole.

Problems related to moisture intrusion were addressed in NRC Information Notice No. 84-57, Operating Experience Related to Moisture Intrusion in Safety-Related Electrical Equipment at Commercial Power Plants, dated July 27, 1984.

The NRC study documented in this information notice revealed that most of the electric components were short-circuited and corroded when failure occurred and that in most cases, the shorting was caused by moisture leaking into the equipment housing and junction boxes.

Additionally, the NRC issued Information Notice No. 89-63, Possible Submergence of Electrical Circuit Located Above the Flood Level Because of Water Intrusion and Lack of Drainage, on September 5,

1989, alerting licensees that electrical circuits within electrical enclosures could become submerged in water if appropriate drainage was not provided.

This notice further emphasized the information contained in Information Notice No. 84-57 concerning the terminal box drain holes and the conformance with the Eg test set up.

The licensee addressed Information Notice No. 84-57 in September 1985.

The electrical maintenance department recommended emphasizing proper work practices in future training and a change to MOV procedures to check for moisture problems.

The IEC department evaluated the problem and determined that all safety-related equipment installed required environmental seals such as NEMA enclosures and the use of Raychem seals.

This related to Eg installations inside containment which would be subject to the harsh post-LOCA environment.

However, since that time, Eg terminal blocks were installed outside containment in certain areas where they could potentially be subject to a high energy line break harsh environment.

Additionally, IKC had not experienced electrical circuit shorts due to moisture intrusion to safety-related equipment.

Therefore, the only action taken by ILC was to counsel the supervisors and technicians on this issu f E

I

The licensee was in the process of reviewing Information Notice No. 89-63 at the time of the event; and therefore, the licensee's actions had not been completed.

However, considerations of this notice had previously been implemented in procedures O-CHE-102.1; Hotor-Operated'alve Haintenance, and procedure O-PHE-102.4, Hotor-Operated Valve Operator Inspection.

These procedures provided the criteria for inspection of HOV valve compartments, operator lubricants, and power conduits and connections for moisture, integrity, and condition when operator maintenance is performed.

The licensee's ERT concluded that weep holes or the lack of weep holes did not have an effect on the corrosion process and that the weep holes only prevented flooding of the terminal boxes.

In order to specifically define water tight requirements for outdoor terminal and pull boxes containing terminal blocks and electrical devices and in order to clarify the use of weep holes in electrical terminal/pull boxes, Bechtel Power Corporation issued Drawing Change Notice No.

42 to drawing No. 5177-E-302 on January 12, 1990.

This clarification required the use of weep holes in future electrical box installations.

The licensee evaluated and inspected existing terminal boxes, and the terminal blocks were either cleaned or replaced.

On February 28, 1990, a list of terminal boxes requiring weep holes to allow water drainage was also issued.

The terminal boxes referenced on this list were located in outdoor/steam environments including the AFW area, auxiliary building roof, steam generator blowdown area, CCW area, feedwater area, ICW area, and HSIV platform.

In addition, the licensee submitted REA Nos.90-535 and 90-536 which proposed the use of either an approved corrosion inhibitor coating or replacement of the terminal blocks with Raychem splices.

These REAs were addressed by engineering with the issuance of PC/H 91-058, Conformal Coating to Eliminate Corrosion Problems on Terminal Blocks, on June 3, 1991.

This PC/H was completed on August 2, 1991.

6.2.6 The inspectors reviewed the licensee's corrective actions and the applicable documentation.

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

This item is closed.

Honthly Operating Reports The inspectors reviewed the August 1994 monthly operating report and determined it to be complete and accurate.

7.0 Plant Support (71750 and 92904)

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

l

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

The inspectors'eviewed previous open items to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

7.2 Inspection Findings 7.2. 1 Radwaste Building Spill At 7: 15 p.m.

on August 30, 1994, HP personnel noted water coming out of the north and south filling rooms in the radwaste building and onto the floor.

HP personnel entered the south filling room and noted water draining from the Chem-Nuclear water processing skid.

The HP personnel closed drain valve CA/D-I on the skid and stopped the flow to the room drain (trough).

KP personnel proceeded to contain and clean up the spill.

Water did not get.

outside the radwaste building.

Initial surveys indicated contamination levels ranging from 2,000 to 22,000 dpm per 100 square centimeters.

HP decontamination efforts cleaned up the effected areas.

The licensee initiated an investigation into the cause of the spill.

A condition report (No.94-814)

was initiated, and the inspector was notified at home.

The licensee also initiated independent reviews including one by gA and one by the technical department human performance group.

The licensee determined that the following evolutions/conditions were present and/or ongoing at the time of the spill:

The No.

2 waste holdup tank was being filled from the C

waste monitor tank, the 8 monitor tank was being discharged to the cooling canal, the north filling room drains (troughs)

were being deconned using pure water, the water filtration equipment (Chem-Nuclear)

skid had at least one valve out of position, and the north and south filling room drains were clogged.

The licensee could not explicitly determine root cause.

However, corrective actions completed or planned included the following:

deconned and unplugged the drains and sump, added drain cleaning to the preventive maintenance program,

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added independent verification steps to the Chem-Nuclear procedures, added chemistry department signoffs in the Chem-Nuclear procedures, reviewed and revised operations procedures for water transfers, initiated hourly tours of the radwaste building during transfers, and administratively controlled the Chem-Nuclear skid inlet and outlet valves when not in use.

The inspectors followed up on this event by reviewing the condition report, gA report, HP survey and decon records, operator and HP logs, liquid radwaste system operating procedures, system drawings, and other pertinent technical information.

Further, the inspectors walked down portions of the liquid radwaste system and interviewed chemistry, operations, HP, radwaste, and management personnel.

The inspectors concluded that licensee actions to combat the spill were timely and appropriate thus minimizing any radiological effects.

Further, the licensee's followup, root cause, and corrective action activities were aggressive even though root cause was not fully determined.

7.2.2 Post Accident Sampling System Availability During the current and previous inspection periods, the inspectors noted that several of the PASS monitors were out of service.

In particular, the isotopic monitor had a failed detector.

The oxygen analyzer's probe was refurbished, the chloride analyzer had a leak, the boron analyzer had a failed power supply, and the PASS flow transmitter (FT-6451)

was malfunctioning.

This resulted in poor availability for the months of July and August 1994.

The Turkey Point Unit 3 and

PASS consists of the following sub-systems; grab samples of the RCS, grab samples of containment, RCS and containment isotopic monitor, dissolved hydrogen analyzer, dissolved oxygen analyzer, chloride analyzer,

7.2.3 Ph analyzer, and boron analyzer.

Technical Spec'ification 6.8.4.d requires a

PASS program including training, procedures, and maintenance.

No availability nor action statement requirement exists.

The licensee has established a goal of 90% equivalent availability.

This goal was achieved for the past 12 months, except for August 1994.

Previous to that, design problems and PC/H implementation resulted in the goal not being met.

The inspectors reviewed the licensee PASS program including maintenance, availability date, sampling and analytical procedures, and training.

The licensee's chemistry department operates the system weekly both for personnel training and to ensure system functionality.

Preventive and corrective maintenance is planned and performed as required.

The inspectors observed sampling and calibration activities and walked down the system in the field.

The PASS system engineer was also interviewed as well as chemistry and management personnel.

The inspectors noted that the system engineer and chemistry personnel were very knowledgeable of the PASS system.

Haintenance programs appeared to be appropriate; however, the systems availability for 1992, the first half of 1993, and for August 1994 were poor.

The licensee acknowledged this issue stating that it was continually monitoring system performance and availability.

The inspectors intend to review this issue in future inspections.

Unit 4 New Fuel Transfer Radiation Protection and Personnel Safety Issues The inspectors observed the radiation protection and personnel safety aspects of the new fuel transfer operations between the Unit 4 new fuel storage room and the Unit 4 spent fuel pit.

The inspectors verified that workers were signed in on the appropriate RWPs (Nos.94-501 and 502)

and that constant HP coverage was available during critical steps.

Workers were noted to be knowledgeable of the RWP requirements.

The inspectors noted that the spent fuel pool area was contaminated and the new fuel storage room was posted as a clean area.

The hoist used to lift the new fuel assemblies from the new fuel storage racks to the fuel pool area travelled between these clean and contaminated areas.

HP personnel required operators to frequently change their gloves and required periodic wiping down of the hoist grapple.

Thus, some level of contamination control was apparent.

However, due to the high area background radiation level, no contamination swipes were counted on the spent fuel pit floor.

The inspectors questioned this practice, and licensee

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personnel modified their practice to ensure that periodic swipes were counted.

7.2.4 The inspectors noted that the opening on the spent fuel pit floor to the new fuel storage room (below one level) did not have a

safety rail on one side.

Thus, the possibility of falling existed.

Operators had safety belts for fall protection available; however, they were not used all the time.

This was corrected on the spot by an operator in charge of the fuel movements.

The inspectors informed licensee personnel safety and operations management personnel of this issue.

The licensee appropriately ensured that FPL fall protection requirements were adhered to.

(Refer to section 4.2.1 for additional information.)

(Closed)

IFI 50-250/89-14-01, Improve Maintenance Mockup Training Program to Include Health Physics and Use of Protective Clothing and Respirators This item was identified as part of weakness No. 50-250/89-14-04 in paragraphs S.a and 13 of NRC Inspection Report No. 50-250,251/89-14 dated May 12, 1989, and the licensee responded to this weakness by letter dated June 12, 1989.

The licensee's response stated that the ALARA supervisor had reviewed the mockup training program and had provided recommendations to the training department on the use of protective clothing and respiratory protection equipment to ensure realistic mockup scenarios.

The licensee also committed that the HP department would provide recommendations to the training department to improve mockup utilization and HP participation by June 30, 1989.

In order to meet this commitment, the ALARA supervisor, maintenance and specialty development supervisor, and maintenance and specialty instructor supervisor met to discuss this issue on May 23, 1989.

Written recommendations were then provided on June 21)

1989.

The inspectors reviewed the licensee's corrective actions and associated documentation.

The licensee's actions were adequate.

This item is closed.

7.2.5 (Closed)

IFI 50-250/89-14-02, Provide Specific ALARA Training for Design Engineers This item was identified as part of weakness No. 50-250/89-14-04 in paragraphs 5.b and 13 of NRC Inspection Report No. 50-250,251/89-14 dated May 12, 1989, and the licensee responded to this weakness by letter dated June 12, 1989.

In this response, the licensee stated that training for design engineers would take place in two phases.

The initial phase was to involve training of two nuclear engineering ALARA coordinators by June 1989, and the second phase was to involve issuance of an engineering gI and

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training of the engineering department during the first quarter of 1990.

7.2.6 In order to provide screening of PC/Hs for potential impact on personnel radi'ation exposure, the licensee issued instruction JPN-gI-3. 13, ALARA Design Requirements, in January 1990.

This procedure also provided specific ALARA design considerations for.

those PC/Hs identified by the ALARA screening process to have the potential for significant personnel radiation exposure.

The licensee also gave a course to engineers to provide them with the necessary level of knowledge to produce designs which incorporate ALARA requirements and with the base level knowledge needed to implement instruction JPN-(1-3. 13.

This course consisted of an overview of the licensee's commitment to ALARA, a discussion of ALARA design, and a discussion of instruction JPN-gI-3. 13.

Participants in the various training courses included licensee personnel, contract personnel, and selected architect engineer employees.

The inspectors reviewed the licensee's actions with regard to this matter and deemed them to be appropriate.

This item is closed.

(Closed)

IFI 50-250/89-14-03, Revise Post-Job ALARA Review Criteria This item was identified as weakness No. 50-250/89-14-05 in paragraphs 6.a and 13 of NRC Inspection Report No. 50-250,251/89-14 dated Hay 12, 1989, and the licensee responded to this weakness by letter dated June 12, 1989.

In this response, the licensee stated that the trigger level for post-job ALARA review would be reduced from a collective dose exceeding 50 man-rem to 10 man-rem and that HP procedures would be revised to incorporate that change by September 1,

1989.

The licensee revised procedure O-HPA-001, Radiation Work Permit Initiation and Termination, and procedure O-HPA-006, ALARA Program, to incorporate this change on August 24, 1989.

Procedure 0-HPA-006 has since been canceled, and its requirements have been incorporated into procedure O-ADH-602, ALARA Program, and procedure O-HPA-071, ALARA Job Reviews.

Step 5.4. 1. 1 of procedure 0-HPA-071 currently requires a post-job review if the total actual exposure for the RWP of job equals or exceeds 5 man-rem.

The inspector reviewed the licensee's actions with regard to this issue and deemed them to be appropriate.

This item is closed.

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

An exit meeting was conducted on September 30, 1994.

The areas

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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.

Violations or deviations 'were not identified.

The inspectors had the following finding:

Item Number Status Descri tion and Reference 50-250,251/94-18-01 (Opened)

IFI - Modification of Eagle-21 System Power Distribution Panels (section 6.2. 1)

Additionally, the following previous items were discussed:

Item Number

'0-250,251/89-48-01 50-250,251/89-54-04 50-250/89-14-01 50-250/89-14-02 50-250/89-14-03 Status Descri tion and Reference (Closed)

VIO - Drawing Discrepancies (section 6.2.4).

(Closed)

URI - Weep Holes Not Provided for Terminal Boxes Containing Environmentally gualified Terminal Blocks (section 6.2.5)

(Closed) IFI - Improve Maintenance Mockup Training Program to Include Health Physics and Use of Protective Clothing and Respirators (section 7.2.4).

(Closed) IFI - Provide Specific ALARA Training for Design Engineers (section 7.2.5).

(Closed) IFI - Revise Post-Job ALARA Review Criteria (section 7.2.6)

9.0 Acronyms and Abbreviations AC ADM AFW ALARA amp AMSAC ANPS AP ARP ATWS CCW CFR CME CV DDPS dpm EDG Alternating Current Administrative Auxiliary Feedwater As Low As Reasonably Achievable Ampere ATWS Mitigation System Actuation Circuitry Assistant Nuclear Plant Supervisor Administrative Procedure Annunciator Response Procedure Anticipated Transient Without Scram Component Cooling Water Code of Federal Regulations Corrective Maintenance

- Electrical Control Valve Digital Data Processing System Disintegrations per minute Emergency Diesel Generator

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ENS EOP Eg ERDADS ERT 0F FME FPL FT GME GOP HHSI HP HPA I&C

,ICW IFI IST JPN LER LOCA LOOP MOV MSIV MWe NEMA NRC ONOP OP OSP P21 PASS PC/M Ph PME PNSC ppb PS PTN PWO gA gC QI ORNO RCC RCO RCS REA rem RHR RPS RPV

Emergency Notification System Emergency Operating Procedure Environmental gualification Emergency Response Data Acquisition and Display System Event Response Team Degrees Fahrenheit Foreign Material Exclusion Florida Power and Light Flow Transmitter General Maintenance

- Electrical General Operating Procedure High Head Safety Injection Health Physics Health Physics

- Administrative Instrumentation and Control Intake Cooling Water Inspector Followup Item Inservice Test Juno Project Nuclear (Nuclear Engineering)

Licensee Event Report Loss-of-Coolant Accident Loss of Offsite Power Motor-Operated Valve Main Steam Isolation Valve Megawatts Electric National Electrical Manufacturers Association Nuclear Regulatory Commission Off-Normal Operating Procedure Operating Procedure Operations Surveillance Procedure

CFR Part

Post-Accident Sampling System Plant Change/Modification Hydrogen Ion Concentration Preventative Maintenance

- Electrical Plant Nuclear Safety Committee Parts Per Billion Power Supply Project Turkey Nuclear Plant Work Order guality Assurance guality Control guality Instruction guality Report Number Rod Control Cluster Reactor Control Operator Reactor Coolant System Request for Engineering Assistance Roentgen Equivalent Man Residual Heat Removal Reactor Protective System Reactor Pressure Vessel

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RWP SI SPDS STA'I TP TPCW UFSAR URI VIO

Radiation Work Permit Safety Injection Safety Parameter Display System Shift Technical Advisor Temperature Indicator Temporary Procedure Turbine Plant Cooling Water Updated Final Safety Analysis Report Unresolved Item Violation

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