IR 05000250/1994003

Insp Repts 50-250/94-03 & 50-251/94-03 on 940130-0226.No Violations Noted.Major Areas Inspected:Operational Safety, Plant Events,Maint Observations,Surveillance Requirements & Followup on Previous Items

ML17352A515
Person / Time
Site:	Turkey Point
Issue date:	03/23/1994
From:	Binoy Desai, Johsnon T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352A514	List: IR 05000250/1994003 ML17352A512
References
50-250-94-03, 50-250-94-3, 50-251-94-03, 50-251-94-3, NUDOCS 9404110144
Download: ML17352A515 (33)

Text

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

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

50-250/94-03 and 50-251/94-03 Licensee:

Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspectors:

Inspection Conducted:

January 30 through February 26, 1994

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P.

ohns n, Senior Resident Da e Signed Inspector

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B. Desai, eside Inspector Dat Signed L. Trocine, Resident Inspector Dat Signed Approved by:

K. D. Landes, Chief Reactor Projects Section 2B Division of Reactor Projects te Signed SUMMARY Scope:

This resident inspection to assure public health and safety involved direct inspection at the site in the areas of operational safety, plant events, maintenance observations, surveillance observations, followup on previous items, and review of written reports.

Backshift inspections were performed in accordance with Nuclear Regulatory Commission policy.

Results:

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

The following unresolved item, inspector followup item, and two non-cited violations were identified.

Unresolved Item 50-250,251/94-03-01, Technical Specification Interpretation Regarding Containment Isolation Valves (section 4.2. I).

9404110l44 940325 PDR ADOCK 05000250

PDR

Inspector Followup Item 50-250,251/94-03-02, Moisture Separator Reheater Drain Line Leaks (section 5.2.3).

Non-Cited Violation 50-250,251/94-03-03, Hissed Inservice Inspection on the 4A Intake Cooling Water Pump (Section 6.2.4).

Non-Cited Violation 50-250,251/94-03-04, Hissed Technical Specification Required Monthly I&C Surveillance (section 7.2.5).

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

0 erations An unresolved item was opened involving the licensee's technical specification interpretation regarding containment isolation valves (section 4.2. 1).

Operator simulator training was effectively conducted, and licensee management presence was noted (section 4.2.2).

During routine plant tours and various operational observations, the licensee demonstrated safe plant operation (section 4.2.3).

The licensee demonstrated appropriate action in dealing with unexpected turbine generator load swings during Unit 4 turbine valve testing activities (sections 5.2.2 and 7.2.2).

Although initial operator actions contributed to the load swings, prompt operator responses appropriately stabilized the unit and prevented a turbine trip/reactor trip on high steam generator level (section 5.2.2).

Operators responded appropriately to a Unit 4 steam leak on the 3D moisture separator reheater drain line (section 5.2.3).

An inspector followup item was opened with regard to the root cause analysis of this leak in relation to two previous leaks on the 3B moisture separator reheater drain line.

Inattention to detail by operations personnel was noted during surveillance test activities (sections 6.2.4 and 7.2.4).

Maintenance and Surveillance Observed maintenance and surveillance activities were performed in a satisfactory manner (sections 6.2. 1 and 7.2. 1).

The repair work to stop a packing leak on the 4C feedwater regulating valve was performed in accordance with licensee procedures (section 6.2.2).

However, the safety evaluation did not address long-term effects on the valve stroke times.

The licensee's actions with regard to the repair of a failed component cooling water system outlet isolation valve associated with the 3C emergency containment cooler were prompt and thorough, and strong inter-departmental teamwork was noted (section 6.2.3).

A logging error by an Assistant Nuclear Plant Supervisor contributed to a missed inservice inspection (section 6.2.4).

A non-cited violation was issued regarding this matter, and the identification of this error during a

routine inservice inspection technician tour was noted as a strength.

The Unit 4 turbine valve test briefing and conduct was professional, thorough, and safety conscious; and excellent teamwork among participants was observed (section 7.2.2).

The 4B emergency diesel generator weekly test was well performed; however, out-of-service

monitoring instrumentation made it more difficult for the operator to conduct the test (section 7.2.3).

An inattention to detail issue by a non-licensed operator was noted during an AFW pump test, and the identification of the wrong size weld by guality Assurance personnel was noted as a strength (section 7.2.4).

A weakness on the part of the planner caused a technical specification required surveillance to be missed, and a non-cited violation was issued regarding this matter (section 7.2.5).

En ineerin and Technical Su ort The written evaluation for the 4C feedwater regulating valve packing leak repair failed to address the longer-term*affects on valve stroke time (section 6.2.2).

The inspectors reviewed work pertaining to a previous inspector followup item involving emergency containment cooler valve failures, and this item remains open (section 8.2. 1).

Plant Su ort Radiation Controls Emer enc Pre aredness Securit Chemistr Fire Protection Fitness For Out and Housekee in Controls The licensee's actions relative to the reporting of a fitness-for-duty issue were appropriately conducted (section 5.2. l).

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

P 1.1 Licensee Employees...........................

1.2 NRC Resident Inspectors......

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

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2.0 Other NRC Inspections and Visits 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 Operati onal Safety Verificat ion.........

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4.2 Inspection Findings........

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

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6.0 Haintenance Obser vations

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

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8.1 Inspection Scope...........

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9.0 Onsite Followup and In-Office Review of Written Repo rts.......

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

9.2 Inspection Findings........

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18 10.0 xit Interview................................................

E

'1.0 Acronyms and Abbreviations..................................

REPORT DETAILS 1.0 Persons Contacted Licensee Employees T.

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V. Abbatiello, Site guality Manager J. Bowskill, Reactor Engineering Supervisor H. Franzone, Instrumentation and Controls Maintenance Supervisor J. Gianfrancesco, Haintenance Support Services Supervisor G. Heisterman, Mechanical Maintenance Supervisor C. Higgins, Outage Manager E. Hollinger, Training Manager E. Jernigan, Operations Manager H. Johnson, Operations Supervisor A. Kaminskas, Services Manager E. Kirkpatrick, Fire Protection/Safety Supervisor E. Knorr, Regulatory Compliance Analyst S. Kundalkar, Engineering Manager D. Lindsay, Health Physics Supervisor Harchese, Site Construction Manager E. Marcussen, Security Supervisor W. Pearce, Plant General Manager 0. Pearce, Electrical Maintenance Supervisor F. Plunkett, Site Vice President R. Powell, Technical Manager E.

Rose, Nuclear Materials Manager N. Steinke, Chemistry Supervisor B. Wayland, Maintenance Manager J.

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

1.2 1.3 NRC Resident Inspectors

• B.

B. Desai, Resident Inspector T.

P. Johnson, Senior Resident Inspector L. Trocine, Resident Inspector Other Personnel On Site D.

C. Anderson, Principal Inspector, Nuclear Installations Inspectorate, United Kingdom (escorted access)

• Attended exit interview on February 28, 1994 Note:

An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this repor t 2.0 Other NRC Inspections and Visits Performed During This Period Re or t No.

Dates Area Ins ected 50-250,251/94-02 February 14-18, 1994 Station Blackout/Electrical Haintenance None February 15-18, 1994 Preparation for Initial Operator Examinations 3.0 Plant Status 3.1 Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near 100% power and had been on line since January 17, 1994.

The following evolutions occurred on this unit during this period:

On February 20, 1994, at approximately ll:20 a.m.,

a leak on the 3D HSR drain line occurred.

Consequently, power was reduced, and the turbine was taken off line at approximately 3:09 a.m.

on February 21, 1994.

Following repairs, the unit was placed on line a'gain at 10: 19 a.m.

on February 22, 1994, and it attained 100% power at 2:00 a.m.

on February 23, 1994.

The reactor was maintained critical during the repairs.

(Refer to section 5.2.3 for details.)

3.2 Unit 4 At the beginning of this reporting period, Unit 4 was operating at or near 100% power and had been on line since August 17, 1993.

The following evolutions occurred on this unit during this period:

At 7:22 p.m.

on January 31, 1994, the licensee commenced a

planned Unit 4 load reduction in order to facilitate the performance of turbine valve testing, a packing leak repair on the 4C feedwater regulating valve, a weld repair, the repair of an unisolable steam leak on the 4D MSR, replacement of the anodes on the 4B TPCW heat exchanger, and condenser waterbox cleaning.

At 9: 15 p.m.

on January 31, 1994, the licensee stabilized reactor power at 40%,

and turbine valve testing was commenced at 9:30 p.m.

During the performance of this testing, the unit experienced a load swing event at 11:15 p.m.,

and operators stabilized the unit.

(Refer to sections 5.2.2 and 7.2.2 for additional information.)

The licensee re-commenced the Unit 4 load reduction at 12:15 a.m.

on February 1,

1994.

The unit was stabilized at approximately 10% power at 1:00 a.m.,

and the licensee commenced work on the 4C feedwater regulating valve (Refer

to section 6.2.2 for additional information.)

and the 4D MSR.

Following the repairs of the 4D NSR and 4C feedwater regulating valve, the licensee commenced power ascension at 10:40 a.m.

on February 1,

1994, and reactor power was stabilized at 30% at 11:25 a.m.

The licensee commenced another load increase at ll:55 a.m.

and stabilized reactor power at 40% at 1:00 p.m.

Following the performance of a modified turbine valve test (Refer to section 7.2.2 for additional information.), the licensee commenced power ascension at 8:30 p.m.

on February 1,

1994, and 60% reactor power was achieved at 10:45 p.m.

Power ascension was re-commenced at 10:30 a.m.

on February 2,

1994, and 100%

reactor power was attained at 2:30 p.m.

on the same day.

4.0 Operational Safety Verification (71707)

4. 1 Inspection Scope The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers, and monitored instrumentation.

The inspectors verified proper valve/switch alignment of selected safety systems, verified that maintenance work orders had been submitted as required, and verified that followup and prioritization of work was accomplished.

The inspectors reviewed tagout records, verified compliance with TS LCOs, and verified the return to service of affected components.

By observation and direct interviews, verification was made that the physical security plan was being implemented.

The implementation of radiological controls, fire protection, fitness-for-duty, chemistry, emergency preparedness, and plant housekeeping/cleanliness conditions were also observed.

Tours of the intake structure and emergency diesels, auxiliary, control, and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, and excessive vibrations.

4.2 Inspection Findings 4.2. 1 Containment Isolation Valves During followup of the 3C ECC CCM outlet isolation valve failure (Refer to section 6.2.3 for additional information.), the inspectors questioned the licensee's interpretation of and compliance with TS 3.6.4 regarding CIVs.

On February 2,

1994, during a test, the CCM outlet isolation valve for the 3C ECC (valve CV-3-2907) failed to close and was leaking.

TS 3.6.4 requires CIVs to be operable with an acceptable isolation tim With an inoperable CIV, actions to isolate the associated penetration must be performed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.,

The licensee declared the valve inoperable; however, the licensee did not initiate the action required by TS 3.6.4 due to an interpretation that valve CV-3-2907 was not a CIV.

The inspectors reviewed UFSAR section 6.6; Tables 6.6-1 and 6.6-3; and Figure 6.6-1, sheets 1 through 8.

Valve CV-3-2907 is included in Table 6.6-1, Containment Penetrations and Valving, and Figure 6.6-1, Valve Arrangement; however, it is not included in Table 6.6-3, Automatic Containment Isolation Valve Closure Times.

The inspectors discussed the issue with the licensee; and a conference call among NRC resident, regional, and headquarters personnel and representatives of the licensee's staff was also conducted on February 3, 1994.

The licensee performed a

PNSC approved safety evaluation (JPNS-PTN-94-0080)

dated February 3, 1994.

That evaluation concluded that valve CV-3-2907, along with the other Unit 3 and 4 related valves (CV-3/4-2903 through 8 and 11, 12, and 14), are not CIVs in that they do not receive automatic closure signals; are not leak tested per

CFR Part 50, Appendix J (type C, local leak rate test);

and have no associated closure times.

Further, the licensee concluded that containment integrity was maintained by the intact CCW loop within the primary containment boundary.

Further, the licensee had initiated an engineering task (PC/M No.89-581, Revision 1) which better defined containment isolation functions (including CIVs) and the criteria to which Turkey Point was designed (e.g.,

GDC 53).

Even though the TS for CIVs was not entered the licensee ensured that the penetration was unisolated for less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as follows:

4.2.2 initially when valve CY-3-2907 failed and clearance No. 3-94-02-014 isolated the path (February 2, 1994),

during maintenance when valve CV-3-2907 was removed (February 3, 1994),

and during maintenance installation activities (February 4, 1994).

Pending NRC resident, regional, and headquarters staff review of the Turkey Point CIV issue, this item is considered to be unresolved.

It will be tracked as URI 50-250,251/94-03-01, TS Interpretation Regarding CIVs.

Operator Simulator Training During the period, the inspectors observed portions of licensed operator requalification training at the Turkey Point simulato The inspectors observed scenario performance and critique activities.

The inspectors noted that operations and training management were involved in training evaluation and assessment activities.

Further, the inspectors concluded that the training was effective and that operator performance was very. good.

4.2.3 General Results As a result of routine plant tours and various operational observations, the inspectors determined that the general plant and system material conditions were satisfactorily maintained, the plant security program was effective, and the overall performance of plant operations was good.

5.0 Plant Events (93702)

5. 1 Inspection Scope 5.2 The following plant events were reviewed to determine facility status and the need for further followup action.

Plant parameters were evaluated during transient response.

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

The inspectors verified that required notifications were made to the NRC.

Evaluations were performed relative to the need for additional NRC response to the event.

Additionally, the following issues were examined, as appropriate:

details regarding the cause of the event; event chronology; safety system performance; licensee compliance with approved procedures; radiological consequences, if any; and proposed corrective actions.

Inspection Findings 5.2. 1 Fitness-For-Duty Event On February 2,

1994, the licensee informed the inspectors that an HP supervisor was confirmed positive for a random FFD test administered on January 28, 1994.

The test results were received at 8:15 a.m.

on February 2,

1994, and the licensee initiated action to remove the individual's site access and to review the individual's recent work performance.

The licensee reported this event to the NRC duty officer per the 24-hour reporting requirement of 10 CFR 26.73.

In that report, the licensee indicated that the individual was confirmed positive for marijuana and that the individual was appealing the test results.

The split sample results were also confirmed positive for marijuana; and as a result, the individual's employment was terminated.

The inspectors determined that the reporting requirements associated with this event were met in a timely manne.2.2 Unexpected Unit 4 Generator Load Swings During Testing At 10:15 p.m.

on January 31, 1994, the licensee reduced Unit 4 reactor power to 40% and conducted a briefing for the performance of procedure 4-0SP-089, Hain Turbine Valves Operability Test.

The licensee commenced this quarterly test at 10:30 p.m.

Following the successful testing of both stop valves and all 4 control valves, the intercept valve test solenoid isolation valves were opened per step 7.3.25 of the procedure.

At 11: 15 p.m., the RCO turned the test switch to close the northwest reheat valves per step 7.3.27.

When the intercept valve's test solenoid opened, turbine control oil pressure dropped unexpectedly.

This caused the control valves to close somewhat; and as a result, header pressure increased, and turbine generator power and first stage pressure decreased.

When the unit RCO noticed the load decrease from approximately 240 HWe to 120 HWe, he raised control oil pressure in an attempt to recover load.

This raised the control oil setting to a higher pressure.

The test RCO then released the test switch by direction of the ANPS.

As a result, the test solenoid closed, and control oi.l pressure was restored to the new higher pressure.

This caused turbine generator load to increase to approximately 460 HWe.

The ANPS then instructed the test RCO to position the switch to test while the unit RCO began lowering control oil pressure with the load limit device.

The test RCO released the test switch, the unit RCO continued to adjust load to stabilize the unit, and load was returned to approximately 240 HWe.

This transient resulted in steam generator level swings ranging from 35% to 78% on the narrow range.

(The turbine trip setpoint for high steam generator level is 80% narrow range level.)

The turbine valve test was subsequently completed the following evening by closing the orifice in the control oil line to the intercept valves.

(Refer to section 7.2.2 for additional information.)

Two of the three intercept valves tested in this manner did not close when the orifice was initially closed.

Hechanical agitation of the combined orifice and ball check valve was necessary to seat the ball check and close the intercept valve.

This does not affect the intercept valve's ability to close on a turbine trip or overspeed protection controller actuation since the ball check will open and rapidly dump control oil pressure from the intercept valve.

This event was caused by the ball check valve in the intercept valve control oil line sticking open.

The check valve is combined in parallel with a flow control orifice which serves to limit control oil flow to drain when the test solenoid is opened.

The ball check valve's failure to seat caused excess flow to drain and reduced the operating pressure of the control oil system.

The licensee determined that the ball check valve's sticking was probably caused by rust in the valve or foreign particles lodging between the ball and seating surface.

In spite of the oil system

being cleaner than specified, foreign particles could still prevent the ball from seating in the check valve.

The combination ball check valve and orifice was not inspected after this event because the unit remained on line.

5.2.3 In order to prevent recurrence, the licensee has generated short notice outage work requests (Nos.

94001675, 94001676, 94001678, and 94001679)

to replace the combination ball check valve and orifice in each intercept valve control oil line as well as in the auto stop oil line to the stop valves'rip pilot valve when the lines are disassembled for valve or low pressure turbine maintenance.

This schedule will replace the part every other refueling for the stop valves and at a minimum every three refuelings for the intercept valves.

Planning for these actions is currently scheduled for completion by Harch 15, 1994.

The licensee also plans on revising the stop valve and intercept valve overhaul procedures to require the replacement of the flow control orifice and ball check valve.

In addition, the licensee plans on revising the turbine valve test procedures to caution operators to respond to a load drop during reheat valve testing by first releasing the test switch and then, if necessary, adjusting control oil pressure to restore load.

These procedure revisions have been scheduled for completion by Har ch 1, 1994.

The licensee documented these corrective actions in condition report No.94-049.

These actions have also been added to the plant manager'

action item list in order to ensure completion.

An inspector witnessed portions of the turbine valve testing on January 31, 1994, and was present in the control room during the transient.

Although initial operator actions contributed to the load swings, prompt operator responses appropriately stabilized the unit and prevented a turbine trip/reactor trip on high steam generator level.

The inspectors reviewed the condition report and the applicable plant parameters.

An inspector also witnessed the performance of the retest on February 1,

1993.

The inspectors concluded that the licensee demonstrated appropriate action in dealing with this event.

Steam Leak on the 3D HSR Drain Line On February 20, 1994, at approximately 11:20 p.m.,

a leak of the 3D HSR drain line occurred causing a large amount of steam to be observed on the turbine deck area.

A 5 HWe/minute load reduction was initiated in accordance with procedure 3-GOP-103, Power Operation to Hot Standby.

The leak was confirmed to be from the 3D HSR drain line to the 3B heater drain tank.

Appropriate plant management as well as the resident inspector were notified.

The resident inspector responded to the site to observe licensee activities associated with the leak.

The Unit 3 turbine was taken off line at approximately 3:09 a.m.,

February 21, 1994.

The unit was maintained critical while repairs were in progres The HSRs and associated piping are non-safety-related components that carry non-radioactive steam and/or water.

The leaking HSR drain line has a design pressure of 200 psig at 400 F.

The pipe is 10 inches with a nominal thickness of 0.365 inches.

The material is ASTH A-53, grade B, schedule 40.

The fluid pressure and temperature at full power are approximately 150 psig and 300'F, respectively.

The HSR drain lines are not ASHE Code pipes and the Code repair requirements of Generic Letter 90-05 are not applicable.

The 3D MSR drain line was found to have a hole of approximately 1.5 square inches.

A temporary repair was performed to restore the integrity of the drain line.

This consisted of welding two circumferentially rolled plates over the affected portion of piping.

A PWO was also originated to replace the affected piping during the next outage of sufficient duration.

A UT scan of other similar Unit 3 and Unit 4 pipe did not indicate any substantial degradation.

The inspector discussed this event with the licensee in reference to the erosion/corrosion protection program as modeled by CHECKMATE.

The inspector also questioned as to whether the failed portion of the pipe had been inspected for thinning.

Two leaks had previously occurred on the 3B HSR drain line.

The first occurred in December 1992.

This involved a straight section down stream of an elbow off the 3B MSR.

The root cause of the pipe failure was attributed to a fit-up problem during original construction that led to a localized erosion down stream of the joint.

This portion of the pipe was replaced.

The other failure occurred in July 1993.

This failure also occurred on the 3B HSR drain line upstream of an elbow.

A welded clamp was installed to repair the leak, and the licensee planned to replace this section of the drain line during the upcoming refueling outage which is scheduled to begin in April 1994.

A root cause of this failure will be performed following the replacement of the pipe.

Following the July 1993 leak, the licensee surveyed various HSR drain line locations, including the location on the 3D MSR drain line identical to the 3B HSR drain line failure.

No significant thinning was observed.

However, due to presence of asbestos, the location of the recent failure was not inspected.

The licensee had scheduled to inspect this location for the first time during the upcoming refueling outage (April 1994).

Following the repair of the 3D HSR drain line leak, the unit was placed on line at 10:19 a.m.

on February 22, 1994, and it reached, full power at 2:00 a.m.

on February 23, 1994.

A conference call to discuss this issue was also conducted between NRR, Region II, and licensee personnel.

The inspector concluded that the licensee responded appropriately.

However, pending the root cause analysis of the 3B and 3D HSR drain line leaks this issue will be

considered as IFI 50-250,251/94-03-02, Moisture Separator Reheater Drain Line Leaks.

6.0 Maintenance Observations (62703)

6. 1 Inspection Scope Station maintenance activities of safety-related systems and components were observed and reviewed to ascertain they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the TSs.

The following items were considered during this review, as appropriate:

LCOs were met while components or systems were removed from service; approvals were obtained prior to initiating work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and repair records accurately reflected the maintenance performed; functional testing and/or ca'librations were performed prior to returning components or systems to service; gC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; gC hold points were established and observed where required; fire prevention controls were implemented; outside contractor force activities were controlled in accordance with the approved gA program; and housekeeping was actively pursued.

6.2 Inspection Findings 6.2. I Maintenance Witnessed The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

troubleshooting and repair of the CCW outlet valve (CV-3-2907) for the 3C ECC (Refer to sections 4.2.1 and 6.2.3 for additional information.),

repair of the 3D MSR drain line steam leak (Refer to section 5.2.3 for additional information.),

packing adjustment and Furmanite leak repair of the 4C steam generator feedwater regulating valve (FCV-4-498) per PWO No.

94000298 (Refer to section 6.2.2 for additional information.),

replacement of 4A ICW pump and motor per work order Nos.

92036908 and 94002323 (Refer to section 6.2.4 for additional information.),

and

6.2.2 modification of the SVs associated with the ECC outlet valves per PC/N 94-05.

(Refer to section 8.2.1 for additional information.)

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

4C Steam Generator Feedwater Regulating Valve Packing Leak Repair During the Unit 4 load reduction, (Refer to section 3.2 for additional information) while on the steam generator feedwater regulating valve bypass valves, the licensee attempted to repair a

packing leak on the 4C steam generator feedwater regulating valve (FCV-4-498).

Valve packing gland adjustments and repacking activities were not successful due to inability to get a good isolation on the work area.

Thus, the licensee proceeded with its contingency to Furmanite repair the valve.

Prior to the work, the licensee performed an engineering evaluation and a safety evaluation screening per condition report No.94-005.

Those evaluations concluded that the Furmanite repair of the valve packing gland was acceptable in accordance with Furmanite procedure N-94005 and administrative procedure 0-ADN-723, On-Line Leak Repait s.

The licensee proceeded with the repair per PWO No. 94000298 on February 1,

1994.

The inspectors reviewed the above mentioned documents and observed portions of the maintenance activity.

The inspectors noted that the evaluations addressed the ability of valve FCV-4-498 to meet its required closure time of 6.8 seconds with the sealant material injected.

The sealant material contained silicone oils to ensure that the valve's stroke time would not be affected.

The licensee verified that the stroke time met the IST criteria after the Furmanite maintenance was completed.

The inspectors questioned the long-term affect of valve stroke time as the evaluations did not specifically address this time dependency issue.

Licensee engineering representatives stated that in the long term, the repair would not be affected and stroke time would be acceptable.

This was based on experience and the type of sealant material.

The inspector stated that the licensee's written evaluations should address this, and the licensee agreed that future evaluations would consider this long-term time stroking issue.

Further, the licensee stated that its evaluation and current practice required a permanent repair prior to restart from the next refueling outage.

The inspector confirmed that PWO No.

93012013 had been initiated to track the final repair work.

The inspector concluded that the repair work to stop a packing leak on valve FCV-4-498 was appropriately performed in accordance with licensee procedures.

However, the written evaluation failed

6.2.3 to address the longer-term affects on valve stroke times.

3C ECC CCW Outlet Isolation Valve Failure At 10:00 p.m.

on February 2,

1994, the 3C ECC CCM outlet isolation valve (CV-3-2907) failed to close following a test.

The valve also had a packing leak.

As a result, the licensee entered a 72-hour action statement in accordance with TS 3.6.2.2 which required

ECC units to be operable when the unit is in Modes 1, 2, 3, or 4.

Unit 3 was operating at 100% reactor power at the time of this failure.

A PWO was promptly submitted, and maintenance began to troubleshoot the problem.

The licensee also generated and approved a safety evaluation for the repair activities associated with this valve.

The valve repair work was performed with the unit at rated power and with the affected ECC (3C) unavailable and under its associated 72-hour LCO action statement.

At 11:25 p.m.

on February 2,

1994, the licensee loosened the flange bolts on this valve while monitoring local leakage and CCM surge tank level.

The valve body was removed for repair at 2:50 a.m.

on February 3, 1994, and a spool piece flange was installed at 3:20 a.m.

Upon removal of the valve, the licensee determined that a failure of the rubber valve liner prevented the valve from fully closing.

Following replacement of the liner on February 4,

1994, the licensee loosened the first bolt on the spool piece flange at 8:39 a.m.,

and the valve was fully re-installed in the closed position at 9:12 a.m.

The licensee also generated and approved a temporary procedure (TP-1038, Filling/Venting of the 3C ECC Loop) to provide guidance for the filling and venting of the CCM header that serves the 3C ECC.

A briefing for the performance of this procedure was. held with operations, health physics, technical, and maintenance personnel in attendance, and the containment personnel latch was unlocked to allow entry at 5:47 p.m.

Per a note and'steps 5.2.6 and 5.2.10 of this temporary procedure, the licensee entered and met the 1-hour action TS statement (TS 3.6. 1. 1) for primary containment integrity upon the opening and closing of the drain valve for the CCW line in containment from the 3C ECC (valve 3-10-287).

All personnel exited containment at 6:30 p.m.

The licensee satisfactorily performed and reviewed procedure 3-0SP-055.1, Emergency Containment Cooler Operability Test, for the 3C ECC at 9:45 p.m.

and procedure TP-1038 at 9:55 p.m.;

and the 3C ECC was returned to service at 10:10 p.m.

The inspectors witnessed portions of the troubleshooting and maintenance preparation activities, attended the pre-job briefing, the ERT, and the PNSC meetings where the safety evaluation and TP-1038 were approved.

The licensee's actions with regard to this repair were prompt and thorough, and strong inter-departmental teamwork was noted.

Management and supervisory involvement in

6.2.4

repairs, evaluation, and assessment activities was strong.

The inspectors also participated in discussions with licensee management and NRC management pertaining to the licensee's interpretation of the TS regarding CIVs.

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

Missed ISI on the 4A ICW Pump On February 10, 1994, following replacement of the 4A ICW pump and motor, the 4A ICW pump was returned to service without a functional test including an ISI as required by ASME Section XI.

Upon discovery, a satisfactory ISI was performed, and the 4A ICW pump was returned to service within the times allowed by the TS action statement.

The 4A ICW train had been removed from service on February 6,

1994, for scheduled replacement of the pump and motor.

An oversight on part of the maintenance foreman associated with the job, the ANPS giving permission to do the job, and the ANPS declaring the 4A ICW pump in service following completion of the job contributed to the error.

The work package had been routed through the ISI group and appropriately identified as one requiring an ISI.

However, the ANPS giving permission to commence the job entered that ISI was not required on the equipment out-of-service log book.

Following completion of the replacement of the pump and motor, a

pump performance test was satisfactorily performed and the pump was returned to service.

However, ISI involving a visual leak check inspection of the pump had not been performed as required by procedure O-ADM-737, Post-Maintenance Testing.

An ISI technician performing a routine tour of the plant noticed the pump in service and questioned as to why the pump was in service as he did not recall performing an ISI on the pump.

Upon discovery, the pump was satisfactorily inspected.

As corrective action, a condition report associated with the event was written.

The licensee plans to modify the PMT sheet of procedure 0-ADM-737 to clearly include the ISI notification and testing requirements.

The issue was also discussed in the control room night order book, and the licensee plans to stress the requirements of ISI during licensed operator training.

The failure to perform an ISI inspection as required by procedure is a violation.

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

This item will be tracked as NCV 50-250,251/94-03-03, Missed ISI on the 4A ICW Pump.

This item is close.2.5 Failed Auxiliary Contact Block on 3B ECF On February 9,

1994, during performance of a routine surveillance in accordance with procedure 3-OSP 56. 1, Emergency Containment Filter Fans Operating Test, the control fuse for the 3B ECF fan blew.

The 3B ECF was declared out-of-service, and a 7-day action statement was entered in accordance with TS 3.6.3.

A contactor coil associated with the ECF breaker was initially replaced.

However, the fuse blew again following energization.

Then the contactor was replaced, and again the fuse blew upon energization.

Subsequently, the auxiliary contact block was replaced, and the contactor was energized successfully without any further problems.

A bench test was performed on replaced components, and the licensee concluded that the fuse was blowing due to a failed auxiliary contact block preventing the contactor from closing in rapidly, thereby causing higher in-rush current to be drawn for longer duration.

The licensee is postulating the failure of the auxiliary contact block to age.

The licensee is considering replacing the auxiliary contact blades periodically to prevent simi1 ar failures.

The inspector concluded that appropriate action statements were entered and that licensee resolved the matter appropriately.

t 7.0 Surveillance Observations (61726)

7.1 7.2 7.2.1 Inspection Scope The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TSs; testing was performed in accordance with adequate procedures; test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate.

For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.

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

procedure 4-0SP-089, Hain Turbine Valves Operability Test (Refer to sections 3.2, 5.2.2, and 7.2.2 for additional information.);

procedure 4-OSP-023. 1, Diesel Generator Operability Test.

(Refer to section 7.2.3 for additional information.);

and procedure 3/4-0SP-75.1, Auxiliary Feedwater Operability Test.

(Refer to section 7.2.4 for additional information.)

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

7.2.2 Unit 4 Hain Turbine Valves Test Based on the problems encountered during the performance of procedure 4-0SP-089, Hain Turbine Valves Operability Test, on January 31, 1994 (Refer to sections 3.2 and 5.2.2 for additional information.);

the licensee revised the test procedure method.

The PNSC approved this change to the surveillance procedure on February 1,

1994.

The licensee determined that the retest of procedure 4-OSP-089 would be done per procedure O-ADM-217, Conduct of Infrequently Performed Tests and Evolutions.

Thus, a test director was established, and a pre-evolution briefing was performed.

Operators, component specialists, engineers,'nd maintenance personnel were present during the briefing and test conduct.

The licensee normally tests the turbines intercept and reheat stop valves using a remote test switch which operates solenoid valves.

The valves open and drain the appropriate control or auto stop oil pressure from the respective servo relay piston.

This in turn drains the high pressure oil from the servo motor piston resulting in intercept/reheat stop valve closure by a spring.

The revised test procedure stroked the reheat stop valves individually from the control room test switch.

In addition, the intercept valves were manually stroked by locally closing the control oil supply throttle value.

This in turn caused a bypass ball check valve to seat, resulting in control oil drain and eventual valve closure.

The licensee also concluded that this problem only affected the test portion of system, and that all turbine valves would close on a trip or overspeed demand.

Haintenance personnel, as verified by the on-shift NWE, locally unlocked and closed the control oil throttle valves.

In several instances, the ball check valves had to be reseated by mechanical agitation.

Using this procedure, the licensee cycled all the turbine intercept and reheat stop valves with expected turbine generator effects.

The licensee has initiated plans to replace these ball check valves during a short notice or refueling outage..

In the interim, the licensee intends to test these valves using the above stated methodology.

The inspectors reviewed the test procedure method, attended the PNSC meeting and pre-evolution briefing, and observed the Unit 4

7.2.3 7.2.4

test from the control room and locally at the valves.

Further, the inspectors discussed the methodology with plant management, component and system engineers, operators, and maintenance personnel.

The inspectors verified that abnormality with the test loop (ball check valves)

would not result in the turbine steam admission valves (stop, control, intercept, and reheat stop)

failure to close on a turbine generator automatic or manual trip demand or on an 'overspeed condition.

The inspectors also verified that the licensee intends to replace those ball check valves.

The inspector concluded that the licensee demonstrated appropriate actions in dealing with this problem.

Further, the inspectors noted that the test briefing and conduct was professional, thorough, and safety conscious; and excellent teamwork among all participants was observed.

EDG Testing The licensee continued with its weekly surveillance testing of the 4B EDG due to recent failures.

(Refer to NRC Inspection Report No. 50-250,251/94-01 for additional information.).

Four successful tests were conducted during this report period.

The inspector observed the test conducted on February 16, 1994, and concluded that the operators involved were very knowledgeable and professional.

During the test, the inspector noted that two instruments used for EDG readings were inoperable with a PWO tag.

These instruments were PI-4-6719B (engine air start pressure-left) and TI-4-6121B (cooling water outlet temperature).

As a result, the operator was required to take local readings in lieu of readings from the EDG controls areas and panel.

Further, the inspector noted that PI-4-6719B was on the 10 oldest PWO list (opened since Hay 5, 1993).

The inspector discussed this issue with licensee management.

A AFW Pump Problems On February 7,

1994, during an operability test of the A AFW pump, the resident inspector noted a small leak (less than 0.5 gpm)

on the threaded connection between the AFW turbine oil cooling water line and the upper AFW casing.

The inspector reported the leak to the Unit 4 ANPS.

The ANPS confirmed the leak and initiated a work request as well as a condition report to effect repairs on the line.

The leak was insignificant as compared to the 600-gpm rated flow of the pump.

Additionally, the effect on the cooling water to the AFW turbine lube oil coolers was minimal.

However, the licensee made a conservative decision to declare the pump inoperable and enter a 72-hour action statement affecting both units in accordance with TS 3.7.1.2.

A new 316 L stainless steel pipe was threaded to the pump casing and the other end was welded to an existing flange.

A review of

7.2.5

the paperwork following the repairs by gA identified that the weld was narrower than required.

The planner for the job had misread the chart used to identify weld sizes.

The pipe was rewelded to the flange and the pump was returned to service within the time allowed by the action statement on February 8, 1994.

A condition report (No.94-063)

was initiated and corrective action included a gA audit (gAO-PTN-94-003) to determine the cause of the problem.

The gA audit concluded personnel errors on part of the planner as well as the gC verifier as the cause of the problem.

The licensee also decided that future weld packages shall have an independent review from another planner who is knowledgeable of the weld program.

The inspector expressed.

concern to the NPS that the non-licensed operator observing the AFW pump test did not question and consequently notify the control room of the leak.

The licensee appropriately counseled the operator and discussed the issue with other operators.

The inspector concluded that licensee's approach to the resolution of the problems discussed above was appropriate, and the identification of the wrong size weld by gA personnel was considered to be a strength.

Hissed TS Required Surveillance On February 23, 1994, the licensee discovered that TSs 4.3. 1 and 4.3.2 required monthly surveillance (procedures 4-SHI-071.1, 2,

and 3, Steam Generator Protection I,II, and III Analog Channel Tests)

had not been performed within the time allowed by TSs including the 25% grace period.

These surveillances demonstrate operability of the steam/feedwater flow mismatch portion of the RPS and the steam line break protection portion of the fSF system.

The fore-mentioned surveillances were last performed successfully on January 14, 1994, and were scheduled to be performed on February 21, 1994, per the plant surveillance tracking system.

February 21, 1994, was automatically selected by the system as it happened to be a Honday, the normal day for performing surveillances.

February 21, 1994, was not 31 days from the previous completion; however, it was within the 25%-grace period (7 days)

allowed by TS 4.0.2.

The PWO which triggers the initiation of the surveillance activity also indicated that the surveillances were due on February 21, 1994, and the "drop dead day" (25%-grace period)

was February 28,.

1994.

This "drop dead day" was selected by the planner who erroneously thought that February 21, 1994, was within 31 days from the previous surveillance.

With the PWO indicating the "drop dead day" to be February 28, 1994, IEC performed the surveillances on February 23, 199 The error was recognized by a compliance technician during a

routine review of the documentation associated with completed Channel I and Channel II surveillances.

Upon discovery, the control room was notified.

As a conservative measure, the bistables associated with Channel III were put in a tripped state.

The surveillance on Channel III was successfully completed within the 24-hour period allowed by TS 4.0.3.

The corrective actions to preclude recurrence include issuance of a condition report associated with this. event, planned enhancement of the PWO system covering all disciplines (IEC, Electrical, and Mechanical) to schedule surveillances based on the last completed date, requirement for the NPS to review the "red book" to double check surveillance due dates, and a report to plant management of surveillances that are 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> from the "drop dead date" prior to a long weekend.

An LER pursuant to

CFR 50.73 will be also be issued.

The inspector confirmed this to be an isolated incident and that no similar incidents had occurred in the recent past.

In addition, the inspector discussed the scheduling philosophy at Turkey Point with the Plant Manager.

The inspector verified that surveillances were not routinely scheduled to take advantage of the grace period.

The failure to perform the TS required surveillances within the required interval is a violation.

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

This item will be tracked as NCV 50-250,251/94-03-04, Missed TS Required Monthly 18C Surveillance.

This item is closed.

8.0 Followup on Previous Items and Noncompliances (92702 and 92701)

8.1 8.2 8.2.1 Inspection Scope A review was conducted of the following noncompliance and open items to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

Verification of corrective. action was achieved through record reviews, observation, and discussions with licensee personnel.

Licensee correspondence was evaluated to ensure the responses were timely and corrective actions were implemented within the time periods specified in the reply.

Inspection Findings (Open) IFI 50-250,251/93-26-01, Emergency Containment Cooler Valve Failures This issue was discussed in detail in NRC Inspection Report N,251/94-01, dated February 15, 1994.

The licensee completed the modification of the SVs associated with the ECC outlet valves on both the units.

The inspector reviewed the status of the modification and inspected completed portions of it.

The SYs were modified from a normally energized to a normally de-energized configuration.

The license is continuing to test the modified ECC SVs on a three-day frequency.

Pending PNSC approval, the frequency will be changed to weekly and eventually to monthly.

No ECC SV failures have occurred since the modification.

The residents are continuing to monitor the issue.

This IFI remains open.

9.0 Onsite Followup and In-Office Review of Written Reports (90712, 90713, and 92700)

9.1 Inspection Scope The reports discussed below were reviewed.

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

Additionally, the inspectors verified the licensee had reviewed each event, corrective actions were implemented, responsibility for corrective actions not fully completed was clearly assigned, safety questions had been evaluated and resolved, and violations of regulations or TS conditions had been identified.

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

9.2 Inspection Findings 9.2.1 Honthly Operating Report The inspectors reviewed the January 1994 Honthly Operating Report and determined it to be complete and accurate.

9.2.2 Special Report for 4B EDG Failure On February 9,

1994, the licensee issued a Special Report in accordance with TS 4.8.1.1.3.

This report documented the circumstances associated with the 4B EDG failure that occurred on January 12, 1994.

This issue is also discussed in section 5.2.2 of NRC Inspection Report No. 50-250,251/94-01.

The inspector reviewed the report and found it to be timely and appropriate.

The inspectors are continuing to monitor the issue.

9.2.3 (Closed)

LER 50-250/92-008, Analog Channel Operational Test for Overpressure Hitigation System Not in Accordance with Technical Specifications On July 23, 1992, procedure 3-0SP-041.4, Overpressure Hitigation System Nitrogen Backup Leak and Functional Test, was reviewed to prepare for an upcoming outage.

During the review, operations

personnel identified that the procedure performed a functional test as required by the TSs in affect prior to August 28, 1991.

The TSs in affect since August 28, 1991, required an analog channel operational test which included the injection of a simulated signal into the channel as close to the sensor as practicable to verify the operability of alarm, interlock, and/or trip functions.

The analog channel operational test was also to include adjustments, as necessary, of the alarm, interlock, and/or trip setpoints such that the setpoints were within the required range and accuracy.

The analog channel operational test is required by the TSs to be performed within 31 days prior to entering a condition in which the PORVs are required to be operable and at least once per 31 days thereafter when the PORVs are required to be operable.

Contrary to the TS definition, testing done on the OMS only provided a zero voltage signal to one side of the pressure comparator circuit, which artificially reduced the setpoint of the comparator to zero psig.

The comparator is designed to send an open signal to the pressurizer PORVs when the system pressure is greater than the setpoint pressure based upon an OMS setpoint of 415 psig

+ 15 psig.

The 415 psig setpoint is designed to be in affect at all times when OHS is activated and the RCS temperature is below 285'F.

Since the setpoint is artificially reduced to zero psig during the functional test, the alarm and trip setpoint had only been verified during calibration, which is required by TSs every 18 months.

However, with the setpoint artificially reduced to zero psig, any pressure input would result in the opening of the PORV being tested.

The following dates are those which the respective units were taken to a temperature less than 285'F and, therefore, by procedure required the operability of the OHS system:

Unit 3 - April 29 through Hay ll, 1992 Unit 4 - January 28 through February 4, 1992 Unit 4 - December 11 through December 17, 1991 For each of these cooldowns and for the heatup following the dual unit outage in September and October of 1991 for Units 3 and 4, respectively, the OHS system was placed in service using the inadequate functional test procedure.

The licensee attributed the root cause of the inadequate analog channel operational test to be an inadequate procedure.

The procedures which controlled the functional test at the time did not provide for the test of the setpoints and adjustments as appropriate.

As a result of this issue, procedures 3/4-0SP-042.4 were revised

to incorporate analog operational tests on July 28, 1992.

The licensee also reviewed other TS required analog channel operational test procedures to ensure that each test would be completed in accordance with the analog channel operational test definition.

The licensee reviewed the last few years of calibration as found data, which revealed that the channels would have been considered operable during an Analog Channel Operational Test if the test had checked the setpoints.

Therefore, there was a high degree of confidence that the setpoints had been at levels required by TS.

The inspector concluded that the missed analog channel operational tests were of minor safety importance.

The inspectors verified the licensee's corrective actions and determined them to be appropriate.

This item is closed.

10.0 Exit Interview The inspection scope and findings were summarized to site management during interviews held throughout the reporting period and during the exit meeting conducted on February 28, 1994.

The areas requiring management attention were reviewed.

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

Dissenting comments were not received from the licensee.

The following new items were discussed.

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

URI - TS Interpretation Regarding CIVs (section 4.2.1).

50-250,251/94-03-02 50-250,251/94-03-03 (Open) IFI - Moisture Separator Reheater Drain Line Leaks (section 5.2.3).

(Closed)

NCV - Hissed ISI on the 4A ICW Pump (section 6.2.4).

50-250,251/94-03-04 (Closed)

NCV - Missed TS Required Monthly IEC Surveillance (section 7.2.5).

Additionally, the following previous items were discussed.

Item Number Status Descri tion and Reference 50-250,251/93-26-01 LER 50-250/92-008 (Open) IFI - Emergency Containment Cooler Valve Failures (section 8.2. 1).

(Closed)

LER - Analog Channel Operational Test for Overpressure Mitigation System Not in Accordance with Technical Specifications'section 9.2.3).

11.0'cronyms and Abbreviations

ADM AFW ANPS ASHE ASTH CCW CFR CHECKMATE CIV CV oF DP ECC ECF EDG ESF ERT FCV FFD GDC GOP gpm HP INC ICW IFI ISI IST JPNS LCO LER HSR MWe NCV NPS NRC NRR NWE OMS OSP PC/M PI PMT PNSC PORV pslg PTN PWO QA QAO Administrative Auxiliary Feedwater Assistant Nuclear Plant Supervisor American Society of Mechanical Engi American Society for Testing and Ma Component Cooling Water Code of Federal Regulations Computer Program Modeling Erosion C

Containment Isolation Valve Control Valve Degrees Fahrenheit Differential Pressure Emergency Containment Cooler Emergency Containment Fan Emergency Diesel Generator Engineered Safety Features Event Response Team Flow Control Valve Fitness-For-Duty General Design Criteria General Operating Procedure Gallons Per Minute Health Physics Instrumentation and Control Intake Cooling Water Inspector Followup Item Inservice Inspection Inservice Testing Juno Project Nuclear Safety Limiting Condition for Operation Licensee Event Report Moisture Separator Reheater Megawatts Electric Non-Cited Violation Nuclear Plant Supervisor Nuclear Regulatory Commission Nuclear Reactor Regulation Nuclear Watch Engineer Overpressure Mitigation System Operations Surveillance Procedure Plant Change/Modification Pressure Indicator Post Maintenance Test Plant Nuclear Safety Committee Power Operated Relief Valve Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Quality Assurance Quality Assurance Organization neers terials orrosion

QC RCO RCS RPS SMI SV TI TP TPCW TS UFSAR URI UT

Quality Control Reactor Control Operator Reactor Coolant System Reactor Protective System Surveillance Maintenance

- I&C Solenoid Valve Temperature Indicator Temporary Procedure Turbine Plant Cooling Water Technical Specification Updated Final Safety Analysis Report Unresolved Item Ultrasonic Test