IR 05000250/1995011

Insp Repts 50-250/95-11 & 50-251/95-11 on 950528-0701.No Violations or Deviations Noted.Major Areas Inpected:Plant Operations Including Operational Safety & Plant Events,Maint Including Surveillance Observations & Engineering

ML17353A309
Person / Time
Site:	Turkey Point
Issue date:	07/28/1995
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A308	List: IR 05000250/1995011 ML17353A306
References
50-250-95-11, 50-251-95-11, NUDOCS 9508100142
Download: ML17353A309 (37)

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/95-11 and 50-251/95-11 Licensee:

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

Hay 28 through July 1, 1995 Inspectors:

T.

P.

Jo nson, Sen or Resident Inspector Da e S'gned Approved by:

B. B. Desai, Resident Inspector W. J.

obin, Se Physical Security Speciali t, Region II

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Lan

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Chief Reactor Projects Section 2B Division of Reactor Projects te gned SUHHARY 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.

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

9508100i42 950728 PDR ADOCK 05000250

PDR

Plant 0 erations The licensee's corrective actions for valve manipulation and configuration control issues were aggressive (section 4.2. 1).

Unit 4 and Unit 3 power reductions to perform testing and maintenance were well planned, professionally conducted, and demonstrated strong teamwork (section 4.2.2).

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

The approach taken to resolve a post-accident hydrogen monitor insulation maintenance process weakness was conservative and actions taken to preclude recurrence were appropriate.

Technical specification action statements for post-accident hydrogen monitor were not exceeded and the identification of the condition by quality assurance personnel was a strength (section 5.2.3).

An observed reactor protection system logic test was well performed, with noted strong teamwork, effective communications, and very good procedure compliance.

However, the licensee was conducting load-threatening reactor protection system testing more frequently than required (section 5.2.4).

Electrical maintenance personnel demonstrated very good performance during an electrical ground troubleshooting evolution.

Further, the licensee was responsive to inspector noted procedure enhancements (section 5,2.5).

En ineerin The decision to replace the power-operated relief valve block valve stems due to a possible material embrittlement as soon as practicable was conservative (section 6.2.1).

Modification work associated with the Unit 3 containment equipment hatch ramp expansion was very good.

= Further, the licensee was responsive to related questions and concerns relative to the protection of safety equipment (section 6.2.2).

The licensee identified, corrected, and reported errors associated with the small break loss-of-coolant-accident analysis (section 6.2.3).

The licensee appropriately addressed operability and dispositioned two Component Cooling Mater related issues related to system supports (section 6.2.4).

Two 10 CFR part 21 reports were appropriately dispositioned and no operability concerns existed (section 6.2.5).

Operability of the emergency load sequencers as it relates to the load center breakers was appropriately determined.

Further, the licensee's identification of this condition was a strength (section 6.2.6).

Reviewed reports were well written and appropriately submitted (section 6.2.7).

.PplS pt The licensee took appropriate and conservative actions for Hurricane Allison which formed in the Gulf of Mexico during the inspection period (section 7.2. 1).

Health Physics personnel were knowledgeable of and demonstrated very good control of radwaste building radioactive material

,

storage.

Further, the licensee has a sound program to reduce the amount of on-site radioactive material and to improve the radwaste building material condition (section 7.2.2).,

The licensee has a good respiratory protection training and qualification program, and is currently addressing issues related to vision acuity when wearing respirators'section 7.2.3).

A fire drill observed. by the inspector was appropriately conducted and critiqued (section 7.2.4).

The licensee's Speakout organization appropriately addressed a fitness for duty concern (section 7.2.5).

TABLE OF CONTENTS 1.0 ersons Contacted.............................................

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

1.2 NRC Resident Inspectors

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

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

3.0 lant Status.................................................'.

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4.2 Inspection Findings..

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5.0 aintenance...................................................

H 5. 1 Inspection Scope.....

5.2 Inspection Findings..

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

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6. 1 Inspection Scope.....

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7.0 lant Support................................................

p 7.1 Inspection Scope.....

7.2 Inspection Findings..

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15 8.0 E t 0xit Interview................................................

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

REPORT DETAILS 1.0 Persons Contacted l. 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, Haintenance Manager P.

C. Higgins, Outage Manager G.

E. Hollinger, Training Manager R. J.

Hovey, Assistant to the Site Vice President H.

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 Super visor 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. H. 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 D. B. Forbes, Radiation Specialist, Region II W. J. Tobin, Senior Physical Security Specialist, Region II R. Hsu, NRR

D.

N. Orrik, NRR H. S. Warren, NRR

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 NRC Inspections Performed During This Period Re ort No.

Dates Area Ins ected None 50-250,251/95-12 3.0 Plant Status June 20-21, 1995 June 26-30, 1995 Operational Safeguards Readiness Evaluation Followup Radiation Protection 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 April 9, 1995.

Unit load was reduced to 40% power on June 16, 1995, to perform testing and maintenance (see section 4.2.2);

and was returned to full load on June 18, 1995.

Unit 4 3.3 At the beginning of this reporting period, Unit 4 was operating at full reactor power and had been on line since March 12, 1995.

The unit was reduced to 40% power on June 9, 1995, to perform testing and maintenance (see section 4.2.2);

and, was returned to full load on June 11, 1995.

Personnel Changes During the period, R. J.

Hovey reported to Turkey Point as the Assistant to the Site Vice President.

4.0 Plant Operations (40500 and 71707)

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 4.2.1 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 inspector's 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, QA/QC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicators.

Inspection Findings Valve Manipulations and Configuration Control Based on recent issues with valve manipulations (see NRC Inspection Report 50-250,251/95-09),

the licensee initiated a

number of corrective actions and program enhancements.

Procedure ODI-C0-018, Valve Manipulation Expectations, dated May 24, 1995, was developed to provide for an organized methodology for valve operations and related independent verifications.

The licensee developed checklists to delineate valve manipulation and independent verification guidance.

This provided a

common and baseline information for operators.

In addition, guidance was developed for supervisory (NPS/ANPS) oversight and checking.

The guidance included and stressed self-checking techniques and independent verifications including expected system and parameter response.

The inspector reviewed the ODI and checklists, discussed them with operators and management, and observed implementation in the field.

The inspector concluded that the licensee responded aggressively and appropriately to an identified issue.

Based on recent results, corrective actions and'nhancements appeared to be effective.

4.2.2 Unit 3 and Unit 4 Power Reductions For Testing and Maintenance The licensee reduced power on Unit 4 to 40% on June 9, 1995, and on Unit 3 to 40% on June 16, 1995, in order to perform the periodic turbine valve test and to conduct BOP periodic maintenance.

Maintenance included TPCW heat exchanger cleaning, condenser water box cleaning, screen wash spray deflector plate replacements, BOP pump preventive maintenance, and other miscellaneous activities.

While at 40% power on June 10, 1995, during the midshift, two minor Unit 4 secondary plant transients occurred that resulted in heater drain pump trips.

This caused a decrease in SGFP suction

pressure, and operators responded by starting a standby condensate pump.

SGFP suction pressure returned to normal and the heater drain system was restored.

The licensee concluded that the heater drain tank level control valves (CV-4-1510 A and B) experienced a

perturbation during BOP pump swaps while at 40% power.

Normally, these control valves are tuned for full reactor power.

The licensee maintained a second condensate pump running while at 40%

power as a conservative measure.

No further perturbations were noted.

Unit 4 was returned to full power on June ll, 1995, and Unit 3 was returned to full power on June 18, 1995.

The inspector observed portions of operations and maintenance activities during deep backshift inspections.

The inspector reviewed control room logs and discussed the Unit 4 secondary plant transients with operators and management personnel.

The inspector also noted that the licensee replaced all the Unit 3 and Unit 4 screen wash spray deflector plates in all four travelling screens.

This was part of the corrective actions for the cooling canal algae/grass intrusion event in March 1995 (see section 6.2;4 of NRC Inspection Report No. 50-250,251/95-10).

The licensee believes that this action should improve the effectiveness of the screen wash system.

The inspector noted that the scheduling of activities was distributed in advance per the plan-of-the-day document.

Further, the inspector concluded that the power reductions were well planned and controlled and effectively implemented, with strong teamwork noted.

5.0 Maintenance (61726 and 62703)

'I 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 Activities Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

miscellaneous Unit 3 and

BOP maintenance activities (section 4.2.2),

procedure 0-PMM-011. 1, Screen Wash Spray Nozzle Inspection (section 4.2.2),

'nit 3 equipment hatch ramp expansion per PC/M 95-44 (section 6.2.2),

4B 125 VDC ground troubleshooting (section 5.2.5).

B S/B SGFP Modification PC/M 94-59, and refueling equipment transfer.

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

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

procedure 3-OSP-049. 1, Reactor Protection System Logic Test (section 5.2.4),

and procedure TP-1154, Unit 3 ICW Header Crosstie Valve Leak 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 Containment Post-Accident Hydrogen Monitor Heat Tracing On May 24, 1995, an individual within the gA department noted missing insulation from the 3B and 4B PAHM tubing.

The control room was notified and an investigation was initiated.

Condition report 95-448 was also initiated.

Technical Specification 3.6.5 requires each unit to have two PAHM trains.

The action statement allows one train to be inoperable for up to 30 days and both trains to be inoperable for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The PAHM tubing is heat traced and insulated in order to maintain minimum temperature for operability greater that 290 degrees F to preclude condensation.

Following this discovery, a walkdown of the PAHM system was performed for both units and it was determined that insulation, on approximately 25 feet of tubing on the 4B PAHM and approximately

feet of tubing on the 3B PAHM was missing.

Contact temperature

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readings on the tubing ranged from 105 to 115 degrees F.

Consequently the 3B and 4B PAHM trains were declared inoperable and each unit entered a 30 day action statement.

Further, it was determined that the insulation had -been taken off either on Hay 22 or 23, 1995, by maintenance to install insulation of a better type to address a management identified deficiency.

The process that controlled insulation-related maintenance activity was controlled by a general work order.

This general work order was designed for work on non-safety related insulation and it did not have the controls commensurate with work on safety related systems such as detailed notification to the NPS prior to initiation of the work order.

Consequently, prior to initiation of work on the PAHN tubing insulation, the control room was not fully appraised of the scope of the activity and a technical specification action statement was not entered upon removal of the insulation.

5.2.4 Upon identification of the condition, a 30 day technical specification action statement was entered on both units.

New insulation on the tubing was installed and both PAHH trains were returned to service on Hay 26, 1995, well within the 30 day allowed action statement.

Additionally, the licensee took corrective actions addressing the process involving insulation related maintenance.

The PAHH is the only system that requires heat tracing for operability.

To preclude inadvertent removal of insulation off the heat traced PAHH tubing, the standing general work order was changed such that a step was added that cautioned against the use of the standing work order for PAHH related insulation work.

Future PAHN related insulated work will be performed under a specifically generated work order.

Further, the PAHH heat traced lines were stencilled to indicate

"Heat Traced Lines, Do Not Remove Insulation".

The inspector reviewed and discussed the circumstances surrounding the event.

The inspector concluded that technical specification action statement was not exceeded.

Further, the approach taken by the licensee to resolve the insulation maintenance process weakness was conservative and the actions taken to preclude recurrence were appropriate.

Additionally, the identification of the condition by gA personnel was a strength.

Reactor Protection System Logic Testing The licensee tested the RPS logic and the reactor trip and bypass breakers per procedures 3/4-OSP-049. 1, Reactor Protection System Logic Test.

During the period, the inspector observed portions of Unit 3 testing from the control room, the cable spreading room (RPS logic cabinets),

and the 3B HCC room (reactor trip and bypass breakers).

The OSP implements Technical Specification Surveillance Requirements in Table 4.3-1, for items 19, =20, and 21.

The technical specification surveillance requires a 62 day

staggered train test frequency.

Thus, one RPS train (A and B)

should be tested every 31 days or monthly.

In actuality, the licensee was more conservative as they were testing both trains monthly.

The inspector questioned licensing, operations, system engineering, and management personnel as to the reason why RPS was being tested monthly in lieu of every other month.

The licensee stated that they would review the basis of their. more-frequent-than-required testing.

The licensee considered this testing as load threatening; thus, more frequent testing placed the units at risk more than the technical specifications required.

After further review, the licensee changed their testing frequency from monthly to bi-monthly per technical specifications.

The inspector concluded that the observed RPS test was well conducted, with strong communications and procedure compliance.

Also excellent teamwork was noted among the three test stations, and between operations and electrical maintenance.

5.2.5 4B 125 VDC Bus Ground At 1:35 p.m.

and 1:55 p.m.

on June 12, 1995, control room alarms J5/1 and X9/2, respectively annunciated.

Indications of a DC ground on the 4B 125 VDC bus were confirmed by operators.

At the time, the spare battery was supplying the 4B 125 VDC bus while the 4B battery was OOS for maintenance.

No LCO was necessary as the spare battery was fully qualified for this'safety-related application.

Operators entered procedure 0-ONOP-003. 11, Auxiliary 125VDC-Location of Grounds.

In addition, electrical maintenance personnel began their ground detection procedures using a red sheet PMO and procedure 0-GHE-102. 1 Troubleshooting and Repair Guidelines.

The electricians used their "ground-buster" equipment which inputs a low frequency AC signal and monitors for positive/negative current differences.

Neither the ONOP nor the

"ground-buster" equipment located the source of the ground, and at 5:15 p.m. the ground cleared.

The inspector observed operator and maintenance department actions in the control room and locally at the 4B 125 VDC bus.

The inspector noted good teamwork and good use of electrical safety precautions.

Involvement by the system engineer and by electrical maintenance supervision was also noted.

The inspector noted that the ONOP did not reference the "ground buster" equipment, nor did the ONOP address the priority for operator/electrician actions.

Further, the ONOP did not take into account indications/actions relative to a spare battery being-connected to the DC bus.

Also, the electrical work package had information for both the "ground-buster" and a previously used

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"scout" equipment.

The inspector discussed these procedure and work package enhancements with operations and maintenance management personnel.

The licensee stated they would review their procedures and make changes as appropriate.

6.0 Engineering (37551 and 90713)

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

The inspector's 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 Power-Operated Relief Valve Block Valve Issues The inspector reviewed and discussed fracture toughness test results associated with PORV block valve HOV-4-536.

The test results on this valve that was replaced during the previous refueling outage indicated a

90% reduction in fracture toughness.

The inspe'ctors also reviewed condition report 95-480 which dispositioned this issue and documented the evaluation for the other PORV block valves (HOV-3-535, HOV-3-536, and HOV-4-535.)

Further, the inspectors reviewed NRC Information Notice 92-60, Valve Stem Failure Caused By Embrittlement which alerted licensees to "17-4 PH" stainless steel valve stems susceptible to embrittlement and failure when used in environments that exceed 600 degrees F.

The licensee performed an operability assessment and concluded that

'no immediate operability concerns existed.

This was based on the following:

lack of tensile loading on the block valve stem, no indication of stress corrosion cracking, no prior industry failure prior to stress corrosion cracking formation, increased material strength, and lack of credible impact loads.

However, the licensee decided to replace the installed stems for both units

6.2.2 as soon as practicable and no later than the next refueling outage.

Further, the licensee plans to modify the material specification for the replacement stems to ensure stems procured in the future will support a replacement life of two fuel cycles by having metallurgical chemistry that is equivalent to, or better than, the'ost limiting stems currently installed.

The inspectors concluded that the licensee appropriately addressed this issue and conservatively decided to replace the PORV block valve stems as soon as practicable and no later than the next refueling outage.

Further, the licensee was responsive to inspector questions.

Unit 3 Containment Equipment. Hatch Access Ramp Expansion During the period, the licensee began an expansion of the Unit 3 containment equipment hatch access ramp in order to support the fall 1995 refueling outage.

PC/H 95-044 was developed by engineering and was approved by the PSNC.

Implementation was conducted by the projects group of the maintenance department.

The licensee desired to expand the Unit 3 equipment hatch access ramp to support refueling outage temporary trailers and staging equipment for HP, security, maintenance, and contractor projects.

The scope of project included the building of retaining walls and backfilling material from an onsite low level radioactive material.

The licensee contacted the state of Florida to notify them of their intentions.

This low level radioactive material (1.0E-08 micro Ci/gm of Cobalt-60 and'Cesium-137)

was excavated from past spills and has been stored onsite in the RCA for years.

The licensee planned to relocate this material to the ramp expansion area, still within the RCA.

The licensee concluded that current regulations allowed this movement within the RCA.

The material would not be released to the environment.

The inspector reviewed the PC/H package, discussed it with licensee design, HP, construction and operations personnel, and observed field activities.

The inspector noted that the licensee took precautions to protect safety-related equipment and facilities.

The Unit 3 EDG fuel oil tank was in close proximity to the excavation work.

The licensee built a temporary berm to protect the tank and to ensure continued containment of the fuel oil.

Based on field observations, the inspector discussed possible enhancements with the NPS and the maintenance support field engineer.

The licensee stopped the work until these additional equipment protection enhancements were implemented.

The inspector also reviewed excavation precautions for this work.

Safety-related piping and electrical ducts traversed beneath the excavation areas.

The inspector reviewed the applicable civil drawings and discussed precautions with engineering personne.2.3 The inspector observed the licensee to be responsive to questions and concerns.

The inspector further concluded that PC/H implementation was appropriate with noted good teamwork among maintenance, engineering, the contractor, HP, and security personnel.

Errors in Small Break Loss-of-Coolant-Accident Analysis On Hay 19, 1995,- during power uprate review and re-analysis activities, Westinghouse identified a non-conservative error in the Turkey Point SBLOCA analysis.

This error resulted in an increase in the PCT of 146'F.

The SBLOCA PCT value is currently 1963'F, which is less than the limit of 2200'F.

The LBLOCA remains limiting, with a PCT value of 2086'F.

The licensee reported this error in a letter to the NRC (L-95-155)

as required by 10 CFR 50.46.

The licensee concluded that the reporting requirements of 10 CFR 50.72 and 73 were not applicable as ECCS design limits were not exceeded.

The licensee initiated condition report No.'95-465 to document the error, to evaluate reportability/operability, to initiate and document a root cause analysis, and to track corrective actions.

The licensee concluded the cause to be human error by the fuels contractor (Westinghouse).

The error was an incorrect input into the LOCA model for cold leg and accumulator line diameters.

These errors occurred in 1991.

A complete and detailed root cause review per licensee procedure NP-700, Nuclear Problem Report is pending.

Corrective actions taken or planned included:

licensee will complete root cause analysis by August 7, 1995; nuclear fuels will prepare an interim report by July 1, 1995, and a final report by September 1,

1995; licensing reported the issue to the NRC per

CFR 50.46; licensee will develop a detailed corrective action plan; gA and site engineering audited the Westinghouse fuel group and related processes; and, licensing will update the UFSAR.

The inspector reviewed the condition report, the

CFR 50.46 report, the Westinghouse analyses and related correspondence, UFSAR section 14, and other related documentation.

The inspector also discussed the issue with licensing, engineering, and fuels personnel.

The inspector also attended the PNSC meeting which reviewed the condition report and the related corrective action The inspector concluded that the licensee appropriately reported this issue, and that no violations of 10 CFR 50.46 ECCS design requirements occurred.

6.2.4 Component. Cooling Mater Issues During evaluations performed under the thermal power uprate

'project, the licensee identified two potential concerns pertaining to CCW piping supply to the ECC system.

The first issue affected

. both units and involved CCW flow through the ECCs 'following a design basis event coincident with a failure of an ECC outlet valve to open.

In. this scenario, the ECC fans would induce heat into the ECC and ultimately into the CCW system piping.

With the ECC outlet valve closed, CCW flow for that ECC would be reduced to 200 gpm through the by-pass line.

With this low flow, the piping from the ECC with the failed closed valve could experience temperatures in excess of what was used for the pipe stress analysis.

The licensee performed an evaluation (JPN-PTN-SECP-95-015)

and determined that operability of the CCW system was not in question.

This operability evaluation was based on several factors.

These included that the design rating of the affected CCW piping was not exceeded.

A detailed review was performed that concluded that all of the piping and supports met the functionality criteria following a HHA and the ensuing thermal stresses on CCW piping.

The other issue involved a portion of Unit 4 CCW system outside containment where stress calculations did not use maximum accident temperatures associated with use of the ECCs.

The current thermal expansion analysis uses the maximum operating temperature.

The licensee performed an evaluation and concluded that the CCW system would remain functional until the next refueling outage.

The licensee is planning to modify this portion of the CCW system located in the pipe and valve room during the Unit 4 refueling outage.

The modification would most likely involve removal of an existing pipe support.

The inspector discussed the issues with the licensee and reviewed the condition report associated with the event.

The inspector concluded that the licensee was proactive in resolving the conditions identified as a result of the thermal uprate project.

6.2.5

CFR Part 21 Issues On June 21, 1994, a

GE HEA63 lockout relay, had partially tripped during a bus fault at FPL's McGregor Substation (see NRC IR 50-250,251/94-11).

The lockout relay bound before the normal open contacts closed, thereby preventing a clearing of the fault.

The binding occurred when the handle shaft disengaged from the reset solenoid coupler.

This caused the lockout handle shaft 'holding pin to jam against the front plate of the reset coil assembly.

The root cause of the failure was attributed to the handle end

shaft length not cut to the proper length causing binding.

The shortened shaft was due to human error during the manufacturing process.

Consequently, on April 28, 1995, Horrison Knudsen issued a

CFR 21 reporting the defect.

These GE HEA63 lockout relays are used throughout the FPL system including the Turkey Point EDGs.

Failure of the lockout relay to trip would result in economic loss to equipment since failure to trip associated protective devices would not have any un-analyzed impact on the plant.

Therefore the licensee concluded that no operability concern existed.

Nevertheless, following the problem that occurred at HcGregor Substation in June 1994, Turkey Point initiated condition report 94-706 and satisfactorily inspected the Unit 4 EDG relays during the 1994 refueling outage.

Further, the licensee concluded that the relays on Unit 3 do not apply to the

CFR 21 because they were installed prior to the affected manufacturing date.

The relays on Unit 3 were also satisfactorily inspected.

Additionally, during each refueling outage, the EDG lockout relays are tested for operability and there had not been any anomalies noted during these previous tests.

The inspector reviewed the condition report, the

CFR 21 notification, and the operability-assessment performed by the licensee.

The inspector concluded that the licensee had been proactive in resolving the issue even prior to receipt of the

CFR 21 notification.

Further, the

CFR 21 issued by Horrison Knudsen was due to prompt notification by FPL to the vendor of the relay problem at the HcGregor Substation.

The inspector also reviewed condition report 95-464 which dispositioned an information notice issued by SOR, Inc.

on Hay 17, 1995.

This information notice concerned set-point shift of pressure and temperature switches due to mechanical interference.

SOR determined that the conduit seal, sensing body, and pressure port associated with the pressure and/or temperature switches had the potential for extending beyond the base surface of the housing.

When this condition exists, the housing may be distorted when bolted to a rigid mounting surface.

If the switch had been calibrated prior to mounting, the set-point would shift upon installation due to housing distortion.

Switches that are calibrated in service, i.e, after mounting, do not experience set-point shift since the housing is already bolted down.

The licensee performed a TEDB search and a field walkdown and determined that the pressure switches were utilized in the Unit 3 A, B, and C HSIV nitrogen supply regulators.

The switch functions to provide a high pressure alarm associated with the nitrogen supply.

The licensee also determined that one of the three switches had some interference problem as described above.

An operability assessment was performed by the licensee that concluded that since the pressure switches only provide an alarm

function, there was no operability concern.

Further, a

PWO was written to correct the problem with the switch that was noted to have some interference problems.

The licensee also plans to incorporate the information notice in the maintenance procedure to preclude future calibration and installation problems.

The inspector concluded that the licensee appropriately dispositioned both

CFR Part 21 issues and that no operability concerns existed.

6.2.6 Emergency Load Sequencer Issues Based on continuing emergency load sequencer followup reviews and corrective actions, the licensee determined on June 19, 1995 that an emergency load sequencer anomaly existed such that certain safety related 480 volt load center breakers may fail to automatically close as designed during certain unique LOCA/LOOP events.

These load centers are the first load block that are loaded by the sequencer.

This in turn feeds the 480 volt motor control centers which provide power to HOVs, ECCs, battery chargers, and other plant equipment.

Additionally, the load centers provide power to the containment spray and charging pump motors.

The anomaly was such that during a 0.5 second window of vulnerability, a simultaneous load center breaker close and open signal could be present.

These opposite breaker demand signals could be caused by a

LOOP followed by a LOCA on the same train or by a

LOOP followed by LOCA on the other unit.

With the load center breaker receiving a simultaneous close and an open signal, the anti-pump feature of the breaker would have precluded automatic closing of the breaker.

This would then prevent automatic load initiations.

The sequencer is designed to initiate bus stripping approximately 1 second after the undervoltage input from LOOP, and the sequencer loads the EDG approximately 8 seconds following the LOOP.

The first LOOP load block, (i.e. the load centers)

are sequenced 16.5 seconds after the LOOP.

Further, if a SI signal were received within 16 seconds following the LOOP, the intended design was to sequence the LOOP and LOCA loads on the buses without re-stripping the bus.

However, due to an error in the sequencer logic, if an SI signal was received after the diesel breaker was closed, the LOOP loads would be restripped from the bus, the sequencer timers would reset and after a time delay, and the LOOP/LOCA loads would be sequenced on.

The sequencer pulse to strip the bus was

second in duration.

The design implementation failed to account for the duration of time between closing of the EDG breaker, which was the permissive for re-stripping, and the beginning of LOOP load sequencing at 16 seconds.

During this window of time, if an SI signal were received, an unnecessary strip pulse occurs.

This strip pulse for the most part was inconsequential since the bus was already stripped.

However, if the strip pulse occurred between 1 second and 0.5 seconds prior to the first LOOP load

I

block, i.e.

between 15.5 and 16 seconds after LOOP, the strip pulse overlapped the breaker close pulse precluding the automatic closing of the load center breakers.

Consequently, an operability evaluation (JPN-PTN-SENP-95-012)

related to this condition concluded that the affected load centers remained operable.

The operability evaluation was predicated on manual operator action as allowed by guidance provided in NRC Generic Letter 91-18, Information to Licensees Regarding Two NRC Inspections on Resolution of Degraded and Nonconforming Conditions and on Operability.

The manual operator action involved closing the 4. 16 KV bus to 480 load center breaker's from the control room vertical panel board while implementing procedure EOP-E-O, Reactor Trip or Safety Injection.

A night order was written discussing this issue and the EOP was changed to specifically verify the status of the load center breakers.

Further, several crews were challenged during a simulator scenario involving the vulnerability.

During these simulator exercises, each crew demonstrated that the capability to diagnose the failure and to appropriately manually close the load center breaker within the time such that core/cladding damage would not occur.

The licensee also performed a probabilistic safety assessment and concluded that this condition constituted a core damage frequency of 1.05 E-8/year even without taking credit for any manual operator action.

Among the factors that made this condition "risk insignificant" were the low probability of a small break LOCA and a

LOOP induced plant trip combined with an exact timing of the break that generates an SI signal during the 0.5 second window of vulnerability.

The licensee reported this condition to the NRC pursuant to

CFR 50.72 (b) (2) (iii) (A) and also plans to issue an LER in the near future.

The resident inspectors were also informed in a timely

- manner..

A software design defect associated with the sequencers was discovered in November-1994.

As part of the corrective actions following this discovery, the licensee committed to perform certain modifications to the sequencers during the September 1995, Unit 3 refueling outage and the March 1996, Unit 4 refueling outage.

This condition associated with the load center breakers was discovered during the verification and validation process associated with the modification.

The resident inspectors have closely followed sequencer related issues.

Recent sequencer issues have been documented in NRC in Inspection Reports 50-250,251/94-23, 95-01, and 95-10; and, LERs 50-250,251/94-005-00 and 94-005-01.

The resident inspectors discussed this issue with the licensee, reviewed the operability evaluation, verified certain assumptions, and reviewed the EOP and the night order.

Further, the operability evaluation was reviewed by NRR personnel and a regional specialist.

The inspectors concluded that the licensee appropriately determined the

6.2.7 operability of the sequencer as it relates to load center breakers.

Further, the inspectors concluded that the identification of the condition to be a strength.

The inspectors plan to follow this issue, including modification, during future inspections.

The inspectors also concluded that the core cooling and ECCS requirements of 10 CFR 50.46, and that the UFSAR commitments were met as determined by the operability assessment contingent upon manual operator actions.

Reports Review The inspectors reviewed the Hay 1995 monthly operating report and the periodic

CFR 50.59 report (L-95-138),

and determined them 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 Hurricane Allison During the weekend of June 3 and 4, 1995, Hurricane Allison developed in the Gulf of Hexico.

Hurricane warnings were posted for the Florida gulf coast from Tampa to Pensacola.

Tropical storm warnings were also posted for selected areas.

Although the Turkey Point site was not under any warnings or watches, licensee personnel tracked the storm and took precautions.

The licensee did not enter any ONOPs or EPIPs nor was the site under any official emergency declarations.

However, licensee EP personnel kept the inspector informed of the storm track and licensee actions.

The inspector monitored the storm track, reviewed licensee procedures, and made contact with control room and EP personnel.

The inspector reviewed the licensee's seasonal hurricane preparedness during the'ast monthly inspection (see NRC Inspection Report No. 50-250,251/95-10).

The inspector walked down the flood protection stoplogs and reviewed procedure 0-OSP-102. 1, Flood Protection Stoplog Inspection.

Each stoplog was appropriately tagged and noted to be functional.

The inspector noted that stoplog number 4 had been removed with the related

opening permanently sealed.

However, the OSP had not been updated to delete the stoplog reference.

The inspector informed licensee operations personnel who corrected the procedure.

The inspector concluded that the licensee took appropriate and conservative actions relative to Hurricane Allison.

7.2.2 Radwaste Building Tour The inspector walked down the radwaste building with licensee representatives to assess material condition and to determine the status of the buildings'adioactive material storage.

The inspector examined all accessible areas including the north and south filling rooms, the high level storage room, tank rooms, evaporator rooms, decontamination and work facilities, and other building areas.

The inspector noted that the building was clean and that housekeeping and material condition were appropriate.

The licensee had a good inventory of storage items and had plans to further decontaminate certain areas and to paint the building floors and walls.

The inspector also noted that the licensee has removed and shipped a large quantity of solid radioactive waste to an off-site burial facility.

This has resulted in a reduced risk of lost material and a lower radiation source term.

7.2.3 7.2.4 The inspector concluded that HP personnel were cognizant and knowledgeable of the radi.oactive material stored in the radwaste building and that recent efforts in shipping waste material offsite were noteworthy.

The inspector intends to review licensee efforts to further improve the radwaste building's appearance and material condition in a future inspection.

Respiratory Protection Training The inspector reviewed the licensee's'rogram for the training and the qualification of personnel to wear respiratory protection equipment.

This included self contained breathing apparatus, filtered respirators, and air-line fed equipment.

The inspector reviewed procedure O-ADM-600, Radiation Protection Manual training handouts, and the respirator fit test process.

Based on information from St. Lucie, the Turkey Point licensee initiated actions to ensure that personnel who wear both corrective lenses and respiratory protective equipment were appropriately trained and prepared.

These actions are scheduled for completion by September 1,

1995.

The inspector concluded that the licensee has a good program.

Fire Drill The inspector. observed a routine fire drill conducted on June 14, 1995, at the intake structure.

The inspectors concluded that personnel appropriately and adequately responded to the simulated fire.

Further, the inspector noted that the fire protection coordinator appropriately critiqued the dril e 7.2.5 Fitness For Duty

8.0 A Region II safeguards inspector 'reviewed the licensee's Speakout organization investigation of a fitness-for-duty concern.

The Speakout investigation did not substantiate the concern.

The inspector found that the Speakout investigation was timely and thorough.

The inspector was on-site as a member of the NRC's Operational Safeguards Readiness Evaluation Team (section 2.0).

Exit Interview 9.0 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 July 7, 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.

Acronyms and Abbreviations AC ADM AFW ALARA a.m.

amp ANPS

'NSI BOP CCW CFR Ci CNRB CV DC E

ECC ECCS EDG e.g.

EOP EP EPIP 0F FPL GE gm GME gpm HEA Alternating Current Administrative Auxiliary Feedwater As Low As Reasonably Achievable

'nte Meridiem Ampere Assistant Nuclear Plant Supervisor American National Standards Institute Balance of Plant Component Cooling Water Code of Federal Regulations Curies Company Nuclear Review Board Control Valve Direct Current Scientific Notation Emergency Containment Cooler Emergency Core Cooling System Emergency Diesel Generator For Example Emergency Operating Procedure Emergency Preparedness Emergency Plan Implementing Procedures Degrees Fahrenheit Florida Power and Light General Electric gram General Maintenance

- Electrical Gallons Per Minute Relay type

f

HP I&C ICW i.e.

JPN JPNS KV L

LBLOCA LC LCO LER LOCA LOOP LT HCC HHA HOV HSIV NP NPS NRC NRR ODI-CO ONOP 00S OP OSP P21 PAHH PC/M PCT PCV p.m.

PHH PNSC PORV ppb ppm PTN PWO PWR QA QC RCA RPS SB LOCA S/B SGFP SECJ SECP SGFP SI

Health Physics Instrumentation and Control Intake Cooling Water That Is Juno Project Nuclear (Nuclear Engineering)

Juno Project Nuclear Safety Kilovolt (Licensing) Letter Large Break LOCA Level Controller Limiting Condi.tion for Operation Licensee Event Report Loss-of-Coolant Accident Loss of Off-Site Power Level Transmitter Motor Control Center Maximum Hypothetical Accident Motor-Operated Valve Hain Steam Isolation Valve Nuclear (Department)

Procedure Nuclear Plant Supervisor Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Operations Department Instruction - Control of Operations Off-Normal Operating Procedure Out of Service Operating Procedure Operations Surveillance Procedure

CFR Part

Post-Accident Hydrogen Monitor (Containment)

Plant Change/Modification Peak (Fuel) Cladding Temperature Pressure Control Valve Post Meridiem Preventive Maintenance

- Mechanical Plant Nuclear Safety Committee Power-Operated Relief Valve Parts Per Billion Parts Per Million Project Turkey Nuclear Plant Work Order Pressurized Water Reactor Quality Assurance Quality Control Radiation Control Area Reactor Protective System Small Break LOCA Standby Steam Generator Feedwater Pump Safety Evaluation Civil - Juno Safety Evaluation Civil -

PEG Steam Generator Feedwater Pump Safety Injection

TEDB TP TPCW TS UFSAR VDC WO WR

Total Equipment Data Base Temporary Procedure Turbine Plant Cooling Water Temperature Switch Updated Final Safety Analysis Report Volt Direct Current Work Order Work Request

le 0