IR 05000250/1995010

Insp Repts 50-250/95-10 & 50-251/95-10 on 950430-0526.No Violations Noted.Major Areas Inspected:Plant Operations Including Operational Safety & Plant Events,Maint Including Surveillance Observations,Engineering & Plant Support

ML17353A250
Person / Time
Site:	Turkey Point
Issue date:	06/22/1995
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A249	List: IR 05000250/1995010 ML17353A248
References
50-250-95-10, 50-251-95-10, NUDOCS 9507120059
Download: ML17353A250 (42)

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/95-10 and 50-251/95-10 Licensee:

Florida Power and Light Company 9250 West Flagler Street Niami, 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:

April 30 through Hay 26, 1995 Inspectors:

T.

P.

ohnson, Senior Resident Inspector B. B. Desai Resident Inspector Approved by:

K. D.

andis, Chief Reactor Projects Section 2B Division of Reactor Projects Date Signed Da e Signed SUMMARY Scope:

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

plant operations including operational safety and plant events; maintenance including surveillance observations; engineering; 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.

The inspectors identified the following non-cited violation:

Non-Cited Violation 50-250,251/95-10-01, Failure to Follow the Requirements of Procedure PTNR-93-0813, Material Recovery Group (MRG)

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

9507l20059 950b22 PDR ADQCK 05000250

PDR

Plant 0 erations The licensee demonstrated a conservative and proactive approach to a

balance-of-plant moisture separator reheater safety relief valve leak.

Further, during the related activities strong teamwork among operations, engineering, training, and maintenance personnel, and effective management oversight were demonstrated (section 4.2. 1).

The licensee appropriately responded to an inspector concern relative to concurrent intake cooling system valve maintenance and basket strainer cleaning/backwashing activities (section 4.2.2).

The inspector concluded that the licensee had taken appropriate actions to investigate, explain, and sensitize operators to the potential implications of two reactor coolant pump issues (section 4.2.3).

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

The licensee appropriately responded to a failure of a boric

'cid transfer pump bearing (section 5.2.3).

The licensee had an effective measuring and test equipment program, with noted strong line management and independent oversight (section 5.2.4).

Nuclear instrumentation power range surveillance testing was well performed, with strong procedure compliance.

Further, this testing noted an automatic rod control system failure.

Although this circuit was not safety related, licensee management response and attention to this problem were noteworthy (section 5.2.5).

A moderator temperature coefficient test acceptance criteria, was met and the licensee took appropriate precautions during the performance of the test.

Further, the licensee was responsive to inspector questions regarding this test (section 5.2.6).

The licensee considered key attributes, the system engineer was knowledgeable, and licensee management was sensitive to two charging pump valve failures (section 5.2.7).

En ineerin The licensee appropriately responded to an auxiliary feedwater related information notice and the system engineer was knowledgeable (section 6.2. 1).

License modification plans for installing a diesel driver on one of the standby steam generator feedwater pumps were comprehensive and appropriately initiated (section 6.2.2).

Based on the identification and prompt corrective action performed by the licensee through the condition report process, the inspector concluded that the failure to follow the requirements of procedure PTNR-93-0813, Material Recovery Group (MRG) Project Desktop was a non-cited violation (section 6.2.3).

The licensee demonstrated an appropriate level of safety concern by continuing their investigation into canal grass and algae intrusion into the plant's cooling systems (section 6.2.4).

A licensee event report concerning a Unit 3 manual reactor trip was complete, accurate, and well written (section 6.2.5).

Further, the inspectors determined that licensee sensitivity to sequencer issues was commensurate with its importance and that the licensee appropriately

complied with Technical Specifications (section 6.2.6).

The inspectors reviewed the April 1995 monthly operating report and determined it to be complete and accurate (section 6.2.7).

The system engineer for the security power distribution'ystem was very knowledgeable and demonstrated a strong sense of ownership (section 7.2.2).

Plant Su ort The licensee appropriately responded to an inspector concern regarding the control of containment entries when concurrent load-threatening surveillance testing was ongoing (section 7.2. 1).

The inspector reviewed the security system power distribution scheme and concluded that the licensee had appropriate drawings and procedures, that maintenance was performed, and personnel were knowledgeable (section 7.2.2).

The licensee appropriately responded to a non-credible bomb threat situation (section 7.2.3).

The licensee appropriately and immediately responded to the situation involving an offsite suicide threat by an employee (section 7.2.4).

The licensee has been proactive in the area of hurricane preparedness.

The licensee's procedures provided thorough compensatory measures for equipment or facilities not designed for a hurricane (section 7.2.5).

The licensee appropriately responded to the incident involving a high radiation door's faulty locking mechanism (section 7.2.6).

Brush fires in the low population zone of the emergency planning zone did not pose any danger to communication systems, transmission lines, or evacuation routes and licensee appropriately responded to this event (section 7.2.7).

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

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l. 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

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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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5.0 Maintenance....................................................

5. 1 Inspection Scope.....

5.2 Inspection Findings..

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

6. 1 Inspection Scope.....

6.2 Inspection Findings..

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~ @11 7.0 Plant Support...............................

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..16 7.1 Inspection Scope.....

7.2 Inspection Findings..

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~ 16 8.0 Exit Interviews...................................'.............20 9.0 Acronyms and Abbreviations.....................................21

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

C. Balaguero, Technical Department Supervisor W. H. Bohlke, Vice President, Engineering and Licensing H. J. Bowskill, Reactor Engineering Supervisor J.

E. Geiger, Vice President, Nuclear Assurance J.

H. Goldberg, President, Nuclear Division 0. Hanek, Regulatory Compliance Analyst R.

G. Heisterman, Maintenance Manager P.

C. Higgins, Outage Manager G.

E. Hollinger, Training Manager R. J.

Hovey, Assistant To The Site Vice President M.

P.

Huba, Procurement Supervisor D.

E. Jernigan, Plant General Manager H.

H. Johnson, Operations Hanager H.

D. Jurmain, Electrical Maintenance Supervisor V. A. Kaminskas, Services Manager T.

F. King. Acting Fire Protection/Safety Supervisor J.

E. Knorr, Regulatory Compliance Analyst T. J.

Koschmeder, Acting Instrumentation and Controls Maintenance Supervisor R.

S. Kundalkar, Engineering Manager J.

D. Lindsay, Health Physics Supervisor F.

E. Harcussen, Security Supervisor D.

D. Hiller, Acting Projects Supervisor H.

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

F. Plunkett, Site Vice President R.

E.

Rose, Nuclear Materials Manager A.

M. Singer, Operations Supervisor R.

N. Steinke, Chemistry Supervisor D. J.

Tomaszewski, Acting Technical Manager B.

C. Waldrep, Mechanical Maintenance Supervisor E. J.

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

1.2 NRC Resident Inspectors B.

B. Desai, Resident Inspector T.

P. Johnson, Senior Resident Inspector 1.3 Other NRC Personnel on Site Richard Croteau, Project Manager, Office of Nuclear Reactor Regulation

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W. H. Dean, Senior Regional Coordinator, Office of the Executive Director for Operations D.

B. Hatthews, Project Director, Office of Nuclear Reactor Regulation J.

L. Hilhoan, Deputy Executive Director for Operations

Attended exit interview (Refer to section 8.0 for additional information.)

Note:

An alphabetical tabulation of acronyms used in this report is listed in section 9.0 of this report.

2.0 Other Activities During This Period INPO conducted a plant evaluation during the period April 24 to Hay 5, 1995 period.

J.

L. Hilhoan and W. H.

Dean of the NRC observed portions of the INPO activities.

3.0 Plant Status 3.1 Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near 100% reactor power and had been on line since Harch 9, 1995.

On Hay 2, 1995, the unit was reduced to 80% and then returned to 100% to reseat and test an HSR safety valve (section 4.2. 1).

On Hay 22, 1995, the unit was reduced to 95% and then returned to 100% to place the number 2 TCV test motor in its normal raised position in preparation for the HTC verification test (section 5.2.6).

On Hay 27, 1995, the unit was reduced to 95% and returned to 100% following an indication problem associated with intake travelling screen differential pressure.

3.2 Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near 100% reactor power and had been on line since Harch 12, 1995.

the unit was maintained at 100% for the entire report period.

4.0 Plant Operations (40500, 71707, and 93702)

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

The inspectors accomplished this by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and technical specification compliance, review of facility records, and evaluation of the licensee's management contro.2 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 also performed a review of the licensee's self-assessment capability by including PNSC and CNRB activities, gA/gC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicators.

Inspection Findings Unit 3 Power Reduction During a routine operations peakshift tour on Hay 1, 1995, the turbine building NPO noted steam emanating from one Unit 3 3A/B HSR safety valve tail pipe.

This valve (RV-3-3402) protects the shell side of the 3A and 3B HSRs and is designed to lift at 215 psig.

(Normal HSR pressure at 100% power is 160 psig).

Operations personnel notified management and the licensee began increased monitoring.

Hechanical maintenance personnel were also alerted.

The licensee concluded that either the valve lifted prematurely and failed to reseat completely, or that the valve seat was leaking.

During dayshift on Hay 2, 1995, the licensee formulated a plan which included a power reduction to 80% and a lift test of the valve using Furmanite's trevitest equipment.

This equipment determines the lift setpoint by hydraulically lifting the valve only a few mils, thus preventing full valve blowdown.

In addition, the licensee conducted a simulator scenario for a stuck open HSR safety valve.

Based on the results of the simulator response, the licensee then briefed each crew on the results, including expected automatic and operator actions.

The licensee reduced power to 80%,

and the safety valve subsequently reseated due to lower HSR pressure.

During troubleshooting and inspect'ion activities, the licensee noted that a cotter pin associated with the manual lift device had broken which had allowed a nut to back-off.

This apparently resulted in the valve partially lifting below the actual pressure lift setpoint.

The lift setpoint was, however, not affected.

The licensee replaced the cotter pin and returned the manual lifting device to its normal configuration.

While at 80% power, during peakshift on Hay 2, 1995, the lifttest was performed twice with satisfactory results

.

The valve remained seated, and the licensee returned Unit 3 to 100% power at 11:00.2.2 The inspector examined the valve in the field, observed the simulator scenario, reviewed the trevitest procedure (TT-94026),

attended the PNSC meeting which reviewed and approved the test procedure, observed a portion of the maintenance activities, and discussed this item with licensee personnel.

The inspector noted that the licensee considered the test activity under the requirements of procedure O-ADM-217, Conduct of Infrequently Performed Tests or Evolutions.

The inspector noted that this valve had been tested during the last (Hay 1994) refueling outage, and no other Unit 3 and Unit 4 MSR safety valves (20 total) have had any historical problems.

The inspector concluded that the licensee acted conservatively and proactively in dealing with this issue.

Even though this BOP safety valve is not nuclear safety-related, the licensee considered the potential adverse affect on unit operation.

Also, operations, training, maintenance, and management personnel involvement demonstrated strong performance.

Operations Control of Intake Cooling Water System Work During a routine backshift (peakshift) tour on Hay 3, 1995, the inspector noted a mechanical stem blocking device on the Unit 4A ICW header isolation valve 4-50-310.

Mechanical maintenance was performing preventive maintenance on the manual actuator per PWO 950008926 and procedure 0-PHM-019. 10, Intake Cooling Water Butterfly Valve Operator Inspection.

Operations had a clearance and related tagout, and had listed the valve in the equipment OOS book.

Kowever, no Technical Specification LCO was applicable as the 4A ICW loop was available.

During a similar maintenance activity on Unit 3 several months ago (see NRC Inspection Report 50-250,251/95-06, section 5.2.4),

an ICW header valve with a stem blocking device inadvertently closed due to system vibration and less than adequate torquing.

The licensee initiated adequate corrective actions after this previous problem.

Based on concerns with canal grass and algae, frequent backwashing and cleaning of the ICW to CCW heat exchanger basket strainers have occurred.

These actions remove one of two ICW headers, thus resulting in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO.

The inspector reviewed control room logs for the period that valve 4-50-310 had a stem blocking device, noting several backwashing and cleaning evolutions for the basket strainers.

The inspector questioned the prudence of removing the basket strainer on one header when an ICW valve stem blocking device was on the opposite header, given the recent instance when an ICW header valve unexpectedly closed.

The net safety effect could be a momentary loss of all ICW flow for the affected uni '

The licensee reviewed~

jir procedures and policies and addressed the inspector's conce n a timely manner.

Corrective actions included appropriate p3~=edure changes and crew briefings.

The inspector verified these actions, noting prompt response by the licensee.

4.2.3 Reactor Coolant Pump Issues The inspector reviewed licensee actions pertaining to two unrelated RCP issues.

The 3A RCP has had low number I seal leakoff flow for the entire operating cycle.

The number I seal leakoff for the 3A RCP has progressively decreased from approximately 1.5 gpm to approximately

.9 gpm as compared to a

constant seal leakoff of approximately 1.5 to 2.5 gpm for the 38 and 3C RCPs.

As a result, the licensee took several actions which included increasing seal injection flow and initiating a PWO to replace the 3A seal injection filter.

Further, the system engineer issued a problem status summary report which heightened the sensitivity of the operators to the 3A RCP seal leakoff flows.

Additionally, the STA was instructed to periodically trend seal leakoff flows to detect further reduction.

The inspector discussed the issue with the system engineer.

The inspector noted that the 3A RCP had exhibited historical low number I seal leakoff flows.

(Refer to NRC Inspection Report 50-250,251/94-01).

Additionally, the inspector noted that the 3A RCP number 2 seal leakoff/standpipe levels had not shown any abnor-malities.

Number 2 seal leakoff/standpipe high level is indicative of number 2 seal failure.

Further, if the number I seal failed, the number 2 seal could maintain full pressure integrity.

The other RCP issue involved the intermittent annunciation of the 4C RCP motor oil level alarm.

All other 4C RCP motor parameters, including bearing vibrations and temperatures, remained normal.

Additionally, a visual inspection did not reveal any oil leaks.

The licensee postulated a correlation between higher ICW/CCW temperatures due to higher atmospheric temperatures and the oil level indication.

The licensee theorized that higher CCW temperatures resulted in pressurization of the chamber within the sight glass and the oil level monitoring instrument.

This caused the oil level within the monitoring instrument to be lower causing the oil level annunciator to activate.

The inspector discussed the issue with the operators as well as the system engineer.

The inspector concluded that the licensee had taken appropriate actions to investigate, explain, and sensitize operators to the potential implications of the two RCP issues discussed abov.0 Maintenance (61726 and 62703)

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 sur-veillance documents.

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

Unit 3 HSR RV-3-3402 activities (section 4.2. 1),

3A BATP failure (section 5.2.3),

H&TE calibrations (section 5.2.4),

B S/B SGFP bearing replacement and modifications (section 6.2.2),

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

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

procedures 3/4-0SP-059.4, Power Range Nuclear Instrumentation Analog Channel Operational Test (section 5.2.5),

procedure O-OSP-016.23, Diesel Driven Fire Pump Operability Test, procedure 3-OSP-40. 12, At Power Moderator Temperature Coefficient Measurement (section 5.2.6),

procedure O-OP-026, CAT 400 Operation (section 7.2.2),

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

3A Boric Acid Transfer Pump On April 27, 1995, during routine BAST recirculation operations, the 3A BATP failed, causing the breaker to trip on overload.

The licensee initiated WO 95009815 and Condition Report No.95-366.

Mechanical maintenance and engineering personnel determined that one of the pump bearings had become overheated and was destroyed.

This pump was.recently overhauled on April 8, 1995, and had only a few hours of operation.

Pre-failure surveillance data did not indicate an impending failure.

Vibration, flow, pressure, and temperature parameters were normal.

Based on inspection of the failed bearing and on previous PHT surveillance data, the licensee believes that the cause may be due to a defective bearing.

However, the failure mechanism and the root cause investigation continues.

5.2.4 During the repair activities, the licensee identified issues with the documentation for the spare parts.

Maintenance and personnel issued another condition report (No.95-369).

The inspector reviewed the condition reports, the WO, the surveillance trend data; and examined the failed bearing.

The inspector concluded that the licensee appropriately addressed this failure.

Further, the inspector reviewed Technical Specification 3. 1.2.2 and verified that the 3B BATP was available and operable.

Therefore, no LCO entry was required.

Measuring and Test Equipment The inspector reviewed the licensee's program for the control and calibration of H&TE.

This included a review of the following procedures and program controls:

TgR 12.0, Control of Measuring and Test Equipment, gI 12-PTN-1, Control of Measuring and Test Equipment gI 12-PTN-2, Control of Chemistry and Health Physics measuring and Test Equipment gI 12-PTN-3, Calibration of Installed Plant Instrumentation.

MI-A-000-003, H&TE Process In addition, the inspector interviewed H&TE personnel, toured the H&TE calibration and issue facilities, and reviewed H&TE calibration records and procedures.

A spot check of H&TE used in the field including associated labelling and a review of sample

5.2.5 calibration records were also performed.

Further, the licensee's process for documenting out-of-calibration and out-of-tolerance METE was inspected.

The inspector verified that procedures QI 12-PTN-1, Appendix A and MI-A-000-0023, Attachment 3 were appropriately used.

The inspector verified that QA/QC reviews and audits were being performed per the master audit plan.

A review of a recent audit (QAO-PTN-94-020) noted QA/QC findings in the M&TE area were related to the control of the equipment.

The inspector reviewed the audit response and noted that the CNRB had also reviewed this issue during meeting number 416 during April 1995.

The inspector questioned selected users of H&TE including operators, I&C technicians, electricians, mechanics, engineering personnel, and chemistry and HP personnel.

Personnel were generally knowledgeable regarding program requirements.

The inspector noted that a recent training brief (No.

555 dated Hay 2, 1995)

was issued to operations to remind personnel of procedure QI-12-PTN-1 requirements.

Overall, the inspector concluded that the licensee had a sound H&TE program.

Effective line management and independent (QA/QC)

oversight was noted.

Power Range Testing The inspector witnessed portions of the Unit 3 monthly power range testing on Hay 8, 1995, in accordance with procedure 3-0SP-059.4, Power Range Nuclear Instrumentation Analog Channel Operational Test.

The test was satisfactorily performed and acceptance criteria were met.

The inspector verified that the OSP met Technical Specification Table 4.3-1 surveillance requirements for the high and low power RPS trips, and for RPS interlocks (e.g.

P-7, P-8, and P-10).

The test was well performed, operator procedure compliance was very good, independent verifications were appropriately implemented, and supervisory oversight was apparent.

(See section 7.2. 1 for containment entry issues).

The similar test was performed on Unit 4 on April 26, 1995.

The technical specification related surveillances met the appropriate acceptance criteria.

However, the N-44 power mismatch circuit checks failed to step control rods inward as was expected.

Although, this circuit did not have a safety-related function, the licensee initiated troubleshooting per PWO 95007506 on a priority basis.

The shift tracked this item on the "hot items" list, and I&C considered it as a priority work item.

Operators were made cognizant of the malfunction during shift turnover briefings, on shift relief checklists, and with the use of a caution tag.

The R-28 rods-in power mismatch defeat switch was placed in the bypass positio I&C personnel'identified several problems with the Hagan modules in this circuit.

These included the summator (OH-408F), the derivative (OH-408L),

and the Tavg signal (TH-408C) module circuits.

These modules were replaced and/or repaired,,

and this portion of the rod control system was returned to service on Nay 5, 1995, by completing a

PHT (e.g.,

N-44 portions of procedure 4-0SP-059.4).

The inspector followed up on this Unit 4 issue by reviewing logs, the OSP, operator and I&C actions, the rod control system logic and wiring drawings, the PWO, and other related documents.

The inspector noted that management considered this automatic rod control system input important even though it was not a safety-related or technical specification required system.

Also, the inspector noted that this was another instance of apparent aging problems with Hagan modules (see NRC Inspection Report 50-250,251/95-09, section 4.2. 1).

The inspector noted that the licensee had a dedicated team reviewing these Hagan module issues.

5.2.6 Noderator Temperature Coefficient Heasurement The licensee performed procedure 3-OSP-40. 12, At Power Hoderator Temperature Coefficient Heasurement on Hay 23, 1995 on Unit 3.

This surveillance is performed once per cycle to confirm the predicted NTC values for EOL as required by Technical Specification 4. 1. 1.3.b.

The test involved inserting RCC Bank D

rods from 228 steps to 208 steps which resulted in a reactivity addition of 47.7 pcm.

Tavg dropped from 574.2 to 572.67 degrees F.

Delta T, reactor power, and HWe were held constant by increasing turbine load by opening TCV ¹2.

The ITC was determined to be 31. 18 pcm/degrees F.

Further, a

HTC valve of -29.65 pcm/degrees F (-2.965 E -4 delta k/k/degrees F) was calculated by subtracting the Doppler effect from the ITC.

This calculated NTC value was within the acceptance criteria of less negative than or equal to -30 pcm/degrees F and less than or equal to 0 pcm/degrees F (e.g.,

between 0 and -30 pcm/degrees F).

Following the test, the RCC Bank D rods were returned to 228 steps and TCV ¹2 was returned to its pre-test (pin-closed) position.

This valve had experienced minor oscillations and was being maintained in a pin-closed position to preclude the oscillations.

Unit 3 reactor power was briefly reduced to 95 percent on Hay 22, 1995, and TCV ¹2 was taken out of the pin-closed position and the test motor raised to allow it to open for the performance of procedure 3-OSP-40. 12.

The inspector witnessed the power reduction as well as the performance of procedure 3-OSP-40. 12.

The OSP was conducted under the requirements of procedure O-ADH-217, Conduct of Infrequently Performed Tests or Evolutions.

The inspectors questioned the licensee as to whether the measured HTC was commensurate with predicted NTC and whether being close to the acceptance criteria

e 5.2.7

had any significance.

The licensee stated that the assumed rod worth that was used to measure HTC was slightly more conservative than actual rod worth, which caused the measured HTC value to be slightly different than predicted values.

The licensee also stated that they plan to enhance the OSP to allow use of more accurate rod worth as well as adjustments to minor power changes that occur during this test.

The inspector concluded that the acceptance criteria for the test was met and that the licensee took appropriate precautions during the performance of the test.

The inspector concluded that the licensee was responsive to questions.

Charging Pump Problems The charging pumps are a positive displacement design with valves internal to the pump.

Each pump is equipped with three discharge and three suction valves.

The 4B charging pump experienced problems with valve cracking on Hay 16, 1995, and the 3B charging pump experienced a similar problem with valve cracking on Hay 22, 1995.

A piece of the cracked valve from the 3B charging pump had to be removed from the discharge stabilizer by drilling a hole through it.

Each -unit has three charging pumps and at least two charging pump per unit are required by Technical Specification 3. 1.2.3 to be operable for reactivity control purposes.

The inoperability of the 3B and the 4B charging pump did not result in any action statement as the other pumps were maintained in an operable status.

A condition report (number 95-426)

was initiated and the pump internal valves were sent off to a laboratory for analysis.

The inspector discussed the issue with the component specialist.

Topics that were discussed included the correlation and or similarity between the two failures within a short time span, possible root cause, and reliability of the other four charging pumps.

The inspector concluded that the licensee had considered the attributes discussed above and that the component specialist was knowledgeable.

The inspector also concluded that licensee management was sensitive to the issue and was seeking prompt resolution.

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

6.2 6.2.2 ensuring that the licensee's processes included the identification, resolution, and prevention of problems and the evaluation of the self-assessment and control program.

The inspectors reviewed selected PC/Hs including the applicable safety evaluation, in-field walkdowns, as-built drawings, associated procedure changes and training, modification testing, and changes to maintenance programs.

The inspectors also reviewed the reports discussed below.

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

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

Inspection Findings Auxiliary Feedwater Issues The inspector reviewed licensee response to recent industry problems with the Terry turbine (manufactured by Dresser Rand Corporation).

This problem, associated with Terry turbine overspeed trips, was attributed to corrosion on or around the governor valve stem as discussed in NRC Information Notice 94-66, Overspeed of Turbine - Driven Pumps Caused by Governor Valve Binding.

The inspector verified that Turkey Point had not had a

Terry turbine overspeed condition directly caused due to valve stem corrosion.

However, some valve stem corrosion had been noted during the recent AFW system overhauls.

Actions to purchase higher corrosion resistant valve stems have been initiated.

Further, the AFW turbine is periodically tested approximately twice a month and steam generator chemistry is such that it is not conducive to accelerated corrosion.

Turkey Point has also implemented a five year preventative replacement schedule of the governor valve stems to assure increased system reliability.

The licensee is also monitoring any further industry developments pertaining to this issue and is tracking this issue through condition report number 95-400.

The inspector concluded that the licensee had appropriately responded to the information notice and the system engineer was knowledgeable of the subject matter.

Standby Steam Generator Feedwater Pump Hodifications During the period, the licensee initiated PC/H 94-059 which replaced the motor driver with a diesel engine driver for the B

S/B SGFP.

This PC/H allows the licensee to eliminate the five blackstart diesels (non-safety-related)

which provide backup power to the 3C and 4C 4KV non-vital buses.

Buses 3C and 4C provided

the power to the A and B S/B SGFP motors, respectively.

The A S/B SGFP power supply remains unchanged.

The NRC had previously approved this modification per Technical Specification amendments 164 (Unit 3)

and 158 (Unit 4) in a letter and safety evaluation dated Hay 20, 1994.

The licensee had requested this amendment in a letter dated September 3,

1993, (L-93-200).

The Technical Specification 3/4.7. 1.6 and related bases were modified.

Per Technical Specifications 3.7. 1.6.a and d, and 6.9.2, the licensee submitted a special report (L-95-089) dated April 21, 1995.

This letter described the planned outage for the B S/B SGFP in order to effect the diesel driver PC/H.

The licensee began the scheduled 6 week PC/H on Hay 17, 1995.

In addition, the licensee initiated two related PC/Hs:

PC/H 94-90, to re-power two radiation monitors; and, PC/H 95-060, to modify the electrical distribution system.

The license evaluated the risk impact (PSA) of the PC/H 94-90 (blackstart diesel elimination and B S/B SGFP upgrade),

and of having the B S/B SGFP OOS for 6 weeks.

Results were as follows:

'A 1993 study concluded that the CDF could increase by 3% or decrease by 0.4% due to implementing the PC/H.

This was dependent upon EDG availability data.

With one S/B SGFP 00S for 60 days, the CDF would increase by 0.4%.

The licensee's screening criteria for risk significant changes is a

12% increase in CDF (1.E-6).

Thus, the licensee concluded that the Turkey Point PSA would not be substantially effected.

This was documented in a FPL letter (JPN-N-95-026)

dated April 26, 1995.

The inspectors reviewed the above mentioned documents and the PC/H packages in detail.

The inspectors also reviewed the related changes to design documents and procedures.

The new diesel is a

caterpillar 3508 engine with a 500 gallon fuel oil tank (6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> supply)

and

VDC battery power.

The licensee shipped the B S/B SGFP to the vendor to attach the diesel engine driver.

The inspectors also reviewed the related proposed changes to the S/B SGFP system, the 4C switchgear buses, to the control room indications and controls, and to operating procedures (ONOPs and EOPs).

The inspectors witnessed a portion of field work, and discussed the PC/H with engineering, maintenance, licensing, projects, and operations personnel.

The PHT will be reviewed in a future inspection.

The inspectors concluded that the licensee's implementation plans for these above referenced PC/Hs were comprehensive and appropriat.2.3 Procurement Engineering The inspector reviewed condition report number 95-178, dated March 3,

1995, that was originated during the conduct of activities involving CVCS letdown isolation control valve CV-4-200A replacement.

The cause of the failure of CV-4-200A was discussed in NRC Inspection Report 50-250,251/95-06.

Condition Report 95-178 dispositioned a concern associated with Nuclear Material Management's handling of a storm impacted spare diaphragm plate associated with CV-4-200A.

This spare diaphragm plate had some surface rust from exposure to moisture caused by Hurricane Andrew.

The diaphragm plate had been "written off" and its gC approval revoked.

Due to the failure of CV-4-200A, the licensee was required to use this spare diaphragm plate.

The process to recover a storm damaged warehouse component, such as the diaphragm plate, was described in procedure PTNR-93-0813, Material Recovery Group (HRG) Project Desktop.

This procedure required the HRG cognizant engineer to coordinate the cleaning and recovery process and a

gC technician to visually verify completion of required tasks to re-qualify a storm damaged component.

For the case involving the diaphragm plate, the NHH supervisor, who was not officially qualified to act in the capacity as the HRG engineer carried out the rust removal and cleaning activities.

He did so following unsuccessful attempts to contact the HRG engineer.

Further, a communication misunderstanding between the NMM supervisor and gC led to the issuance of the diaphragm plate to the plant the without an actual gC inspection.

There was however no issue with regard to the quality of the work performed by the NMM supervisor.

The NHH supervisor had discussed his actions with gC via the phone.

Further, the diaphragm plate was checked satisfactorily by the maintenance crew prior to its installation.

The inspector reviewed the condition report, the ensuing corrective actions, and discussed the issue with the licensee, including the NHH supervisor.

The inspector also noted that the NHH manager had initiated his review of the situation upon his discovery of the condition.

The inspector concluded that the intent of the NMH supervisor was to accommodate the plant during the short notice outage.

The inspector did not note any intentions on the NHH supervisors part to willfullyviolate established procedures.

Further, the NHM supervisor was knowledgeable of the cleaning process.

Corrective actions taken by the licensee included: disciplinary action against the NHH supervisor and the gC technician; an independent review by Nuclear Safety Speakout which concluded that the condition report appropriately dispositioned the issue; an evaluation that concluded that there were no technical or operability issues associated with the diaphragm plate; and, a

planned revision to material recovery procedure to reflect alternatives when MRG and/or gC personnel are not available.

Based on the identification and prompt corrective action performed by the licensee through the condition report process, the inspector concluded that the failure to follow the requirements of procedure PTNR-93-0813, Material Recovery Group (MRG) Project Desktop, will not be subject to enforcement action.

This meets the criteria specified in Section VII B. (2) of the Enforcement Policy.

This item will be documented as NCV 50-250,251/95-10-01, Failure to Follow Nuclear Material Recovery Group Procedure.

This item is closed.

6.2.4 Cooling Canal Grass and Algae Mitigation Strategy Team The licensee continued with their followup actions for the March 8-9, 1995, cooling canal grass/algae intrusion event into the plant cooling water systems.

The event, the LER, and radiological aspects of this issue were previously reviewed during NRC Inspections 50-250,251/95-06, 07, and 09.

After the event, the licensee performed line management reviews and conducted an independent ERT followup.

LER 95-003 was issued on April 7, 1995.

Subsequent followup actions included a Grass/Algae Mitigation Strategy Team.

The licensee determined that the March 8-9, 1995, problem was caused by a period of no rain, followed by heavy rain causing a

1.5 foot increase in canal level.

Concurrent high winds caused the grass and algae to dislodge and enter the intake.

The screens and screen wash systems became ineffective and the resultant carry over clogged the ICW/CCW basket strainers.

The licensee's continuing root cause investigation and corrective actions are focused in the following areas:

screen wash effectiveness, procedure ONOP-ll, Screen Wash Malfunction (new procedure)

which ensures screen wash capability, securing of circulating water pumps to protect ICW and screen wash pumps, removal of the grass/algae by use of booms and a pumping system, examining the use of chemical treatment, installation of an air bubbler/curtain system to remove suspended grass and algae,

Relative to hurricane actions, procedure EPIP 20106, ensures that the units are shutdown, that the screens are functioning, and the circulating water pumps are off.

During Hurricane Andrew, a loss of off-site power occurred, and the screens, screen wash and circulating pumps lost power.

Thus, the ICW pumps functioned satisfactorily without a grass/algae problem.

The much higher flows of circulating water (10 times ICW flow) were not available to bring large quantities of grass and algae into the intake system.

The new procedure ONOP-ll addresses actions to protect the ICW system, thus ensuring safety system performance.

Further, the licensee evaluated the radiological aspects of a hurricane to be minimal.

6.2.5 6.2.6 The inspector reviewed these issues, and concluded that the licensee appropriately addressed relevant hurricane concerns, and is continuing their longer term actions.

(Closed)

LER 3-95-04, Hanual Reactor Trip The LER addresses a Unit 3 operator initiated manual reactor trip on April 7, 1995.

The trip occurred during a shutdown to Hode

due to a rod control power supply failure.

The Unit was subcritical, when the C control bank rods locked up due to an urgent rod control failure alarm.

The event was reviewed in NRC Inspection Report 50-250,251/95-09.

The inspector reviewed the LER and determined it to be complete and accurate.

The licensee is still pursuing the root cause of the power supply failure.

The inspector verified corrective actions.

Based on this review, the LER is considered closed.

Emergency Load Sequencer Issue At approximately 12: 17 p.m.

on Hay 24, 1995, during the performance of routine surveillance 3-0SP-024.2, Emergency Bus Load Sequencer Hanual Test, on the 3B sequencer, a sequencer error and a sequencer trouble annunciator were received.

The testing was stopped and IEC, Technical Department, Plant Hanagement, Juno Engineering, and the NRC resident inspector were notified.

During the test, Unit 3 was in an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> action statement pursuant to Technical Specification 3.8.3. 1 as the 3B sequencer was not in the

"Test Off" position.

Upon receipt of the sequencer error annunciator, the licensee conservatively determined that Unit 3 conditions met those described in Technical Specification Table 3.3.2.6.d for Bus Stripping.

This placed the Unit under the required actions of Technical Specification 3.0.3.

Upon review of the circumstances surrounding the test as well as the error code that was reviewed, the licensee determined that the error was such that it affected only certain test portion of the sequencer circuitry and that it was of no consequence to the process function of the sequencer.

Thus, there was no condition

FPL

that affected the operability of the sequencer.

The portion of the test during which the error code was received was re-performed several times.

However, the error did not repeat.

The licensee postulated that an intermittent relay or contact movement possibly caused the error.

6.2.7 The inspector discussed the issue with the licensee to confirm that the operability of the sequencer was not affected as a result of the problem that occurred on May 24, 1995.

The inspector questioned if the 3B sequencer needed to be on an increased test frequency.

However, the licensee currently does not have plans to increase the test frequency.'urther, the licensee has a

PC/M planned to remove the auto test circuity due to problems that occurred in November, 1994 which are discussed in NRC inspection report 94-23.

The licensee plans to address this recent issue during the development of the PC/M.

The inspector concluded that licensee appropriately complied with Technical Specifications.

Further, the inspectors determined that licensee sensitivity to sequencer issues was commensurate with its importance.

The inspectors plan to maintain high awareness of sequencer related issues as well as the forthcoming PC/M.

Monthly Operating Report The inspectors reviewed the April 1995 monthly operating report and determined it to be complete and accurate.

7.0 Plant Support (71750)

7.1 7.2 7.'2. 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.

Inspection Findings Unit 3 Containment Entry On May 8, 1995, engineering, HP, and I&C personnel entered the Unit 3 containment to perform routine maintenance and inspection activities.

I&C personnel additionally recalibrated the Unit 3 RCP seal leakoff flow recorder.

The entry was performed per procedure O-ADM-009, Containment Entries When Containment Integrity Is Established.

The entry was made at 10:40 a.m.

and lasted about one hou.2.2 7.2.3 The inspector reviewed the ADH and RWP No. 309 requirements and discussed the entry with HP personnel at the con'trol point (e.g.,

personnel access hatch).

During the period of the containment entry, the inspector noted that a Unit 3 load threatening surveillance was in progress (see section 5.2.5).

The inspector questioned HP, I&C, and operations personnel relative to the acceptability of performing this type of surveillance procedure with personnel in the containment.

The surveillance has a small probability of initiating a unit transient or trip.

The licensee's procedures did not prohibit these simultaneous activities.

However, the licensee agreed that these activities should not be performed at the same time.

The licensee reviewed their requirements and practices, and initiated a change to procedure 0-ADH-009 and to the RWP.

Security System Power Distribution The inspector reviewed the site's security system power distribu-tion.

The inspector reviewed related operating, maintenance, and test procedures; electrical diagrams; the security plan; and, other relevant documentation.

A walkdown of the power distribution was performed with the system engineer.

Areas examined included the security diesel generator (CAT 400), the 125 VDC battery and support systems, the 4160 and 480VAC switchgear, the uninterruptible power supply, and the load and distribution panels.

In addition, a tour of the CAS and SAS facilities was performed.

Periodic testing of the CAT 400 diesel was reviewed per procedure O-OP-026, CAT 400 operation.

The inspector concluded that site security, operations, maintenance, and system engineering personnel were very knowledgeable of the security system and its power distribution.

The system engineer demonstrated a strong sense of ownership.

Further, the electrical system's material condition was noted to be very good.

Non-Credible Implied Bomb Threat The inspector was informed on Hay 17, 1995 by the licensee of an.

implied bomb threat against FPL corporate officers and the FPL nuclear plants, including Turkey Point.

A customer had included a

letter which had implications of a bomb threat, with the electric bill.

FPL corporate security notified the FBI of the content of the letter.

The licensee did not believe the threat to be credible.

However, the plant remained at a heightened state of security awareness and the licensee made a notification to the NRC pursuant to

CFR 50.72 (b)(2)(vi).

The inspector discussed the issue with the licensee and reviewed the contents of the letter.

The inspector concluded that the licensee appropriately responded to the letter and the bomb threa FPL 7.2.4 Potential Newsworthy Event

7.2.5 The resident inspector was notified by the licensee at approximately 10:00 a.m.

on May 18, 1995 of an incident involving an FPL employee at Turkey Point threatening to commit suicide at his residence in Miami, Florida.

The employee, who worked as an electrician (non-supervisory and non-licensed)

within the maintenance department, did not report to work in the morning.

Following unsuccessful attempts to contact the employee over the phone, the licensee dispatched an individual to determine his status.

The employees residence was found to have been surrounded by law enforcement personnel.

The employee apparently was holding a gun, was threatening to commit suicide, and had stated recent drug use.

The licensee revoked the employees plant access.

Additionally, efforts were initiated to review work that may have been performed by the employee for the last 90 days.

The review did not reveal any deficiencies.

Further, the licensee reviewed the fitness-for-duty data on the employee and determined that the employee had no history of positive drug test results.

The employee did not reveal any aberrant or abnormal behavior during the last contact with plant personnel at Turkey Point on May 17, 1995.

There was local media interest and the licensee made a

notification to the NRC pursuant

CFR 50.72 (b)(2)(vi).

As of 1:00 pm, May 18, 1995, the employee had been taken into custody and transported to Jackson Memorial Hospital.

The inspector concluded that the licensee appropriately and immediately responded to the situation.

Licensee Hurricane Preparations The inspectors reviewed and discussed with the licensee the program and procedures associated with hurricane preparedness.

Hurricane season spans the months of June through November with the most intense activity expected to occur between August and October.

There are procedures, PMs, and other preparatory processes that the licensee performs at the onset of each hurricane season.

Additionally, there are procedures that the licensee would implement upon declaration of a hurricane watch or warning.

The licensee has the following procedures in place to ensure adequate preparation due to a 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 tropical Storm Warning or a Hurricane Watch which includes the Turkey Point site.

(A Hurricane Watch is declared if a hurricane is located between 24 to 48

hours 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 O-SHH-1202.1, 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 from 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 communication 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 the designated storage areas.

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

The inspector questioned the licensee if they had considered incorporating all the performance elements at the onset of the hurricane season into a single document.

The licensee agreed to look into the matter.

Additionally, the inspector noted a minor error in procedure EPIP 20106 which said that the auxiliary

building would be the primary TSC.

The primary TSC building is located 'outside of the auxiliary building.

Upon identification, the licensee initiated actions to rectify this statement in the EPIP.

7.2.6 The inspector concluded that the licensee has been proactive in the area of hurricane preparedness.

The licensee's procedures provide thorough compensatory measures for equipment or facilities not designed for a hurricane.

Locked High Radiation Area Update A non-cited violation resulted during the previous report period (NRC Inspection Report 50-250,251/95-09)

due to a locked high radiation area door found in an unlocked condition.

As a result of this incident, the licensee was verifying the condition of all locked high radiation area doors every shift.

During this verification on Hay 23, 1995, a locked high radiation area door in the radwaste building (South filling room)

became unlocked.

This occurred during the intense shaking that the door was subjected to during the verification.

Apparently, the locking mechanism failed, causing the door to become unlocked.

The door was immediately secured and as an additional measure, the licensee chain-locked the door.

No entries were made into this locked high radiation area which houses the liquid waste demineralizers.

The licensee plans to continue to verify the status of the locked high radiation area doors.

7.2.7 The inspector verified the status of this locked high radiation area door and confirmed that it was chain-locked.

The inspector concluded that the potential for inadvertent entry into this room was extremely low.

Further, the inspector concluded that the licensee appropriately responded to the incident.

Brush Fires Within Several miles of the Plant Brush fires spanning several acres were spotted within the low population area of the emergency planning zone during the period of Hay 22 to 26, 1995.

The licensee notified the local fire department.

The brush fires did not impact any communication equipment, transmission lines, or evacuation routes associated

. with the plant.

These brush fires subsequently subsided.

The licensee determined that no reportability* issue existed.

The inspector concluded that the licensee appropriately responded to these fires.

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 staf FPL

An exit meeting was conducted on June 2,

1995.

(Refer to section 1.0 for exit meeting attendees.)

The areas requiring management attention were reviewed.

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

Dissenting comments were not received from the licensee.

However, the inspectors had the following finding.

Item Number Status Descri tion and Reference 50-250)251/95-10-01 Closed Failure to Follow the Requirements of Procedure ATNR-93-0813, Material Recovery Group (MRG) Project Desktop (section 6.2.3)

Additionally, the following previous item was discussed:

LER 50-250/95-04 Closed LER 95-04, Manual Reactor Trip (section 6.2.5)

9.0 Acronyms and Abbreviations AC ACB ADH AFW ALARA a.m.

amp BAST BATP BIT BOL BOP BSD CAS CAT CCW CDF CET CFR CIV CNRB CV CVCS DC ECC ECCS EDG e.g.

ENS EOF EOL Alternating Current Air Circuit Breaker Administrative Auxiliary Feedwater As Low As Reasonably Achievable Ante Meridiem Ampere Boric Acid Storage Tank Boric Acid Transfer Pump Boron Injection Tank Beginning of Life Balance of Plant Blackstart Diesel Central Alarm System Caterpillar 400 (security diesel)

Component Cooling Water Core Damage Frequency Core Exit Thermocouple Code of Federal Regulations Containment Isolation Valve Company Nuclear Review Board Control Valve Chemical Volume Control System Direct Current Emergency Containment Cooler Emergency Core Cooling System Emergency Diesel Generator For Example Emergency Notification System Emergency Operating Facility End of Life

FPL EOP EPIP ERDADS ERT ESF 0 F F

FBI FC FCV FPL FI FL gpm HP IRC ICW i.e.

INPO ITC JPN JPNS KV LC LCO LER H&TE HI HRG HSR HTC HWe NCR NCV NI NIS NOV NHH NPO NPS NRC NRR NWE ONOP 00S OP

'SC OSEP OSHA OSP pcm PC/H

Display System g)

ation Emergency Operating Procedure Emergency Plan Implementing Procedure Emergency Response Data Acquisition and Event Response Team Engineered Safeguards Feature Degrees Fahrenheit Fuse Federal Bureau of Investigation Flow Controller Flow Control Valve Florida Power and Light Flow Indicator Florida Gallons Per Minute Health Physics Instrumentation and Control Intake Cooling Water That Is Institute for Nuclear Power Operations Isothermal Temperature Coefficient Juno Project Nuclear (Nuclear Engineerin Juno Project Nuclear Safety Kilovolt Level Controller Limiting Condition for Operation Licensee Event Report Measuring and Test Equipment Maintenance Instruction Material Recovery Group Moisture Separator Reheater Moderator Temperature Coefficient Megawatts Electric Non-Conformance Report Non-Cited Violation Nuclear Instrument Nuclear Instrumentation System Notice of Violation Nuclear Material Management Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Nuclear Watch Engineer Off-Normal Operating Procedure Out of Service Operating Procedure Operational Support Center Off-Site Emergency Procedure Occupational Health and Safety Administr Operations Surveillance Procedure percent millirho (reactivity)

Plant Change/Modification

t

p.m.

PMM PHR PHT PNSC PSA psi Pslg PTN PWO PWR PWST QA QAO QC QI RCC

, RCCA RCP RPS RWP RV SAS S/B SGFP SFI SMH STA Tavg TCV TPCW TQR TSC TT VAC VDC WO WR Post Meridiem Preventive Maintenance

- Mechanical Preventive Maintenance

- Preventive Post-Maintenance Test Plant Nuclear Safety Committee Probabilistic Safety Assessment Pounds Per Square Inch Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Pressurized Water Reactor Primary Water Storage Tank Quality Assurance Quality Assurance Organization Quality Control Quality Instruction Rod Control Cluster Rod Control Cluster Assembly Reactor Coolant Pump Reactor Protective System Radiation Work Permit Relief Valve Secondary Alarm System Standby Steam Generator Feedwater Pump Security Force Instruction Surveillance Maintenance

-- Mechanical Shift Technical Advisor average (coolant) temperature Turbine Control Valve Turbine Plant Cooling Water Topical Quality Report Technical Support Center Temperature Transmitter Volt Alternating Current Volt Direct Current Work Order Work Request