IR 05000250/1995001

Insp Repts 50-250/95-01 & 50-251/95-01 on 950101-28.No Violations Noted.Major Areas Inspected:Plant Operations, Maint & Engineering

ML17352B053
Person / Time
Site:	Turkey Point
Issue date:	02/24/1995
From:	Binoy Desai, Johnson T, Landis K, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17352B052	List: IR 05000250/1995001 ML17352B051
References
50-250-95-01, 50-250-95-1, 50-251-95-01, 50-251-95-1, NUDOCS 9503080160
Download: ML17352B053 (34)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTASTREET. N.W., SUITE 2900 ATLANTA.GEORGIA 303234198 Report Nos.:

50-250/95-01 and 50-251/95-01 Licensee:

Florida Power and Light Company 9250 West Flag1er Street Miami, FL 33102 Docket Nos.:

50-250 and 50-251 License Nos.:

DPR-31 and DPR-41 Facility Name:

Turkey Point Units 3 and

Inspection Conducted:

Jan y

1 through 28, 1995 Inspectors:

T.

P.

J nson, Sen r Resident Inspector Da e Si ned B.

B.

Des

,

esident Inspector Da e

S g ed L. Trocine, Resident I spector Accompanied by:

J.

F.

King>;- Intern, Office of Approved by:

K. D, Landis, Chief Reactor Projects Section

Division of Reactor Projects

Date Si ned Nuclear Reactor Regulation Date Signed SUMMARY Scope:

This resident inspection was performed to assure public health and safety, and ft 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.

9503080l60 950224 POR ADOCK 05000250 Q

PDR

Results:

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

The inspectors did not identify any regulatory compliance issues.

However, the following inspector followup items were identified.

Inspector Followup Item 50-250,251/95-01-01, Probabilfstic Safety Assessment Actions (section 4.2.2)

Inspector Followup Item 50-250,251/95-01-02, Steam Generator Level Control

~vstem Calibration (section 5.2.3)

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

Plant 0 erations Emergency operating procedure steps were clear as well as performable to mitigate the consequences following a steam generator tube rupture event should one occur {section 4.2.1).

The licensee was not sensitive to unit common, non-safety-related service water pump status and how this affected core damage frequency.

As a result, this is an inspector followup item (section 4.2.2).

Operator response to several steam generator level control system induced transients affecting both units was timely and appropriate (section 4.2.3).

Operators appropriately responded to a Unit 4 secondary plant perturbation; however, the licensee was unable to determine the cause of the initiating event (section 4.2.4).

As demonstrated by on-site and off-site review coaeittees, by quality assurance, and by line management, the licensee has effective self-assessment programs (section 4.2.5).

An open item regarding administrative procedures was closed (section 4.2.6).

The observation of an oil level anomaly during safety injection pump testing and the decision to shut down the pump by the operator coordinating the

'est in the field was a strength (section 5.2.8).

Haint nance Inspector observed station maintenance and surveillance testing activities were completed in a satisfactory manner.

Strong teamwork was noted during all observed surveillance tests (sections 5.2. 1 and 5.2.2).

The licensee appropriately addressed problems associated with maintenance calibration and control of spare modules for the steam generator level control system.

Instrumentation and control technicians'rrors resulted in steam generator level control system oscillations and an unplanned Unit 3 load decrease.

These issues are collectively an inspector followup item (section 5.2.3).

A quality assurance assessment of Unit 4 blender problems was thorough and demonstrated effective self-assessment (section 5.2.4).

A planned outage for the Unit 3 spent fuel cooling system was well planned, effectively implemented.

and demonstrated strong teamwork (section 5.2.5).

Emergency load sequencer manual testing was well performed with

excellent procedural compliance and strong oversight by both line management and quality assurance (section 5.2.6).

The licensee has an adequate fuse control program and is appropriately addressing fuse list discrepancies.

Further, licensee initiated efforts to improve the program demonstrated effective self-assessment (section 5.2.7).

A Unit 4 safety injection pump repair procedure did not specifically address the installation location of the oil bubbler, and maintenance personnel performing the procedure should have sought clarification prior to installation {section 5.2.8).

The licensee appropriately dispositioned an issue associated with vendor controls (section 5.2.9).

Strong teamwork, effective communications, very good procedural compliance, and appropriate adherence to technical specifications were noted during containment air lock testing (section 5.2. 10).

Mith respect t~

a previous violation involving an inadequate work instruction for a mechanical cable pull, the licensee's corrective actions were comprehensive and effective in'preventing recurrence

{section 5.2. 11).

En ineerin Strong system engineer and component specialist involvement during the 4A safety injection pump oil bubbler problem resolution was noted (section 5.2.8).

Information Notice 94-84 was appropriately dispositioned, auxiliary feedwater system work order backlog was low, no repetitive problems associated with auxiliary feedwater system in the recent past have occurred, and system engineer cognizance and ownership of the system was evident (section 6.2. I).

The issues associated with containment spray automatic start have minimal impact on plant safety, and the licensee appropriately dispositioned the issue (section 6.2.2).

A weakness in the design review and implementation process resulted in an inadvertent disconnection of a Unit 4 control room instrument air alarm; however, there was minimal safety impact due to the availability of a redundant Unit 3 alarm (section 6.2.3).

Licensee periodic reports were determined to be comple'te and accurate (section 6.2.4).

A Unit 3 licensee event report regarding an automatic reactor trip was accurate and well written {section 6.2.5).

Although discrepancies were noted in work order task descriptions, the licensee's corrective actions with respect to Eagle-21 system power distribution panel failures were effective in ensuring that the Eagle-21 system power distribution panels in the plant were appropriately modified.

This resulted in the closure of a previous inspector followup item (section 6.2.6).

Plant Su ort The as-low-as-reasonab'ly-achievable review committee was effective in addressing radiation exposure issues.

Recent site radiation exposure results have been very good (section 7.2. 1).

Licensee efforts to modify and upgrade the access control and the dosimetry program demonstrated sound planning and effective implementation (section 7.2.2).

Health physics coverage of the Unit 3 spent fuel pool cooling work was strong with effective controls (section 7.2.3).

Overall auxiliary building cleanliness and housekeeping was good.

The licensee appropriately responded to some minor issues (section 7.2.4).

Fire brigade response

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

1.1 1.2 1.3 Licensee Employees..........,...............

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

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

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~ ~

~

~

~ ~

~

~

o I 2.0 Other NRC Inspections Performed Ouring This Period

~

~

~

~

~

~

~

~

~

~

~

~

~

3.0 Plant Status........

~.................,...

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

3ol Unit 3 o

~

~

~

~

~

~

~

~

~

~

~

~

~

~

3o2 Unit 4 o

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~ ~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

.0 Plant Operations......................,........................

4. 1 Inspection Scope...

4.2 Inspection Findings

~

~

~

~

~

~

~

~

~

~

5 o

.0 maintenance.......,.......

~.............................:.....'.

5. 1 Inspection Scope...

5.2 Inspection Findings

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

o S

6.0 Engineering...,...............................................

6.1 Inspection Scope...

6.2 Inspection Findings

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

16 7.0 Plan'. Support,..........................

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~ 25 7. I Inspection Scope...

7.2 Inspection Findings

~

~

~

~

~

~

~

o

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~....

~

~

~

~

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

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

REPORT 'DETAILS Persons Contacted Licensee Employees T. V.

R. J.

J.

C.

W. H.

H. J.

S.

M.

Sup J.

E.

R. J.

J.

H.

R.

G.

P.

C.

G.

E.

H.

P.

D.

ED H. H.

H.

D.

V. A.

J.

E.

J.

E R.

S J.

D.

F.

E.

H.

N.

H. 0.

T.

F.

D.

R.

R.

E.

A. H.

R, N,

B.

C.

E. J.

Abbatiello, Site guality Manager Acosta, Company Nuclear Review Board Chairman Balaguero, Technical Department Supervisor Bohlke, Vice President, Engineering and Licensing Bowskill, Reactor Engineering Supervisor Franzone, Instrumentation and Controls Maintenance ervisor Geiger, Vice President, Nuclear Assurance Gianfrancesco, Haintenance Support Services Supervisor Goldberg, President, Nuclear Division Heisterman, Maintenance Hanager Higgins, Outage Manager Hollinger, Training Hanager Huba, Procurement Supervisor Jernigan, Plant General Manager Johnson, Operations Manager Jurmain, Electrical Maintenance Supervisor Kaminskas, Services Manager Kirkpatrick, Fire Protection/Safety Supervisor Knorr, Regulatory Compliance Analyst

.undalkar, Engineering Hanager

';ndsay, Health Physics Supervisor Harcussen, Security Supervisor Paduano, Manager, Licensing and Special Projects Pearce, Projects Supervisor Plunkett, Site Vice President Powell, Technical Hanager Rose, Nuclear Materials Manager Singer, Operations Supervisor Steinke, Chemistry Supervisor Waldrep,'echanical Maintenance Supervisor 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 L. Trocine, Resident Inspector 1.3 Other NRC Personnel on Site J.

F. King, Intern, Office of Nuclear"Reactor Regulation K. D. Landis. Chief, Reactor Projects Section 2B, Division of Reactor Projects, Region II

• 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 50-250,251/95-02 January 17-20, 1995 Training/Operator Requal i fi cation (parti al )

NOTE:

NRC inspection No. 50-250,251/95-02 is currently scheduled to be continued during the next resident inspector reporting period.

3.0 Plant Status 3.1 Unit 3 3.2 At the beginning of this reporting period, Unit 3 was operating at or near full power and had been on line since December 29, 1994.

On January 23, 1995, Unit 3 was reduced in load to 15K'o effect repairs to the 3C steam generator level control system.

Refer to section 4.2.3 for additional information.

The unit was returned to full power on January 24, 1995.

Unit 4 During this reporting period, Unit 4 operated at or near full power.

This unit had been on line since December 2,

1994.

4.0 Plant Operations (40500, 71707, and 92901)

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 control.

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

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

The inspectors verified that required notifications were made to the NRC and that licensee followup including event chronology, root cause determination, and corrective actions were appropriat The inspectors also performed a review of the licensee's self-assessment capability by including PNSC and CNRB activities, gA/gC audits and reviews, line management self-assessments, individual self-checking techniques, and performance indicators.

In addition, t".e inspectors reviewed one open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

4.2 Inspection Findings 4.2.

Steam Generator Tube Rupture Emergency Operating Procedure Review The inspectors reviewed procedures 3/4-EOP-E-3, Steam Generator Tube Rupture, as well as observed several simulator runs of this event.

Operators were noted to be well trained in order to perform the required steps.

The inspectors concluded that the procedure steps outlined in the EOP were clear as well as performable to mitigate the consequences of a steam generator tube rupture event should one occur.

4.2.2 Service Mater Pumps On January 17, 1995, during both the morning control room tour and management meeting, the inspectors learned that only one of the four service water pumps was available.

At Turkey Point, the service water system is common and is not safety-related.

The system provides water for auxiliary cooling, drinking, sanitary use, and building services.

Three pumps (A, 8, and C) are motor driven, and the fourth pump (D) is diesel driven.

The status of the service water pumps was the following:

A - in service supplying service water needs, B - valved out of service for a leaking check valve, C

- out of service for high vibration, and D - out of service for an impeller failure and oil seal replacement Based on the Turkey Point PSA, service water is a risk important

'ystem because it provides backup (emergency)

cooling to the charging pumps.

Thus, for a loss of off-site power concurrent with a common-mode failure of CCW or ICW scenario, the RCP seals would lose cooling/injection.

This would lead to a LOCA from RCP seal failure after about 90 minutes.

The PSA concluded that this scenario represents 12% of the CDF contribution.

Further, based on a January 17, 1995, licensee PSA group analysis (JPN-NR-95-005),

having the D service water pump out of service for two weeks increased the CDF by about 15%.

Therefore, the diesel driven

service water pump (D) is an important risk-related component at Turkey Point.

Based on interviews with station personnel including maintenance, operations, and management; the inspectors concluded that the above described scenarios and service water system importance relative to CDF and PSA was not widely known.

The licensee is currently conducting PSA training, but not all appropriate personnel have taken the course.

Based on this experience, the licensee committed to or completed the following corrective actions:

The plant returned out-of-service service water pumps to a functional status; the PSA group continued with PSA related training; the PSA group will review this.important risk scenario for additional operator actions which could reduce significance; and the PSA group will provide plant management and control room operators with a tool to monitor current CDF status.

(The outage group currently has a tool, and this will probably be expanded.)

The inspectors concluded that the licensee was not completely sensitive to the service pump status and how this affected the overall CDF.

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

However, the inspectors plan to review the open corrective actions during a

future inspection.

This item will be tracked as IFI 50-250,251/95-01-01, Probabilistic Safety Assessment Actions.

4.2.3 Steam Generator Level Transients During the inspection period, steam generator level transients and control system problems occurred on both units.

At 3: 10 a.m.

on January I, 1995, the Unit 3 RCO noted that the 3C steam generator level had decreased a few percent while in automatic control.

lhe RCO placed the feedwater regulating valve (FCV-3-498) in manual and increased feedwater flow to return level to normal.

Since the problems experienced with 3C steam generator level control system (Refer to section 4.2.9 of NRC Inspection Report No. 50-250,251/94-24.),

the licensee had stationed an extra RCO to monitor the 3C steam generator and had maintained a

recorder hooked up to monitor the control system inputs and outputs.

I5C personnel were called out to address this issue.

Based on operator indications and recorder traces, the licensee concluded that the Hagan system level comparator card (LC-498A) had faile IKC personnel found an intermittent problem associated with a solder connection.

A spare card was obtained; however, IKC personnel experienced difficulty in performing a bench calibration.

Apparently, the vendor had made modifications to this card, and the licensee was not aware of the specifics of this new configuration.

The licensee is currently pursuing this issue per a condition report and special task team.

Refer to section 5.2.3 for additional information.

ILC personnel modified this card per current configuration drawings and placed it into service at 5:40 p.m.

on January I, 1995.

During the period of troubleshooting and card replacement, the extra RCO maintained FCV-3-498 in manual control.

The recorders and an extra RCO were maintained to monitor 3C steam generator level perf i mance.

No additional problems were noted, and on January 6,

1995, the extra RCO was secured.

Subsequently, on January 9,

1995, the recorder was disconnected.

At 12:05 a.m.

on January 3,

1995, the 4C steam generator feedwater flow began spiking causing minor level transients of a few percent.

Operators swapped the controlling feedwater flow and leveI channels, and the flow spiking stopped.

Subsequently, the licensee traced the problem to an input from level channel LT-4-498.

On January 5,

1995, the licensee replaced this level transmitter and returned it to service.

During this troubleshooting phase, the licensee hooked up a recorder to monitor the level channel inputs and outputs and stationed an extra RCO to monitor the 4C steam generator level control system.

Upon successful troubleshooting and repair, the extra RCO was secured, and the recorder was removed on January 13, 1995.

At 12:40 a.m.

on January 23, 1995, the 3C steam generator again experienced a perturbation and level decreased from 68'o 53'1..

Operators took manual control of the feedwater regulating valve (FCV-3-498)

and restored level to normal (60/).

Operators then returned FCV-3-498 to automatic.

Based on recent problems, management elected to reduce unit load to 805 in order to better respond to a possible transient.

During the downpower, problems were experienced with the bumpless transfer from automatic to manual control and from manual to automatic control.

An ERT was initiated to determine the root cause and to propose corrective actions.

IAC technicians hooked up a multi-channel recorder to monitor the control system.

Unit load was reduced to 70't. to monitor the 3C steam generator level control system.

During the load drop, ERT members noted that the flow controller (Hagan module FC-498)

had its rate and reset switches incorrectly set and that the manual/automatic station (Hagan module FC-498F)

had not been modified such that bias signal was incorrect.

{It was set at-5 volts in lieu of 0 volts).

The ERT concluded that these abnormalities could explain these recent problems.

The rate and reset switches were correctly set to "off" and 200 seconds, respectively.

Unit load was reduced to 155 by 9:05 p.m.

and the manual/automatic station was replaced.

The unit was then returned

4.2.4 to 80% by 2:30 a.m.

on January 24, 1995.

The 3C feedwater regulating valve responded as expected during the power increase.

As part of PHT process, the licensee performed procedure TP-1133, Post-Haintenance Testing of 3C S/G Level Control System, to ensure that the 3C control system was appropriately functioning.

The TP was successfully performed.

Unit load was returned to 10M't 5:45 p.m.

on January 24, 1995.

The licensee maintained an extra RCO to monitor the control system until January 27, 1995, and the multi-channel recorder was maintained hooked up.

The inspectors monitored licensee actions including operator response to these transients, engineering and ERT involvement, and Ihc'aintenance troubleshooting.

The inspectors discussed these issues with plant management expressing a concern relative to the reliability of the steam generator feedwater level control system.

Recent problems have been experienced with the 4B (Refer to NRC Inspection Report No. 50-250,251/94-.23 for additional information.), the 3C (Refer to this section and to NRC Inspection Report No. 50-250,251/94-24 for additional information.),

and the 4C (Refer to this section for additional information.)

steam generator level control systems.

The inspectors concluded that operator response to these transients was timely and appropri te.

The inspectors did not identify compliance issues.

Secondary Plant Perturbation At approximately 2:45 pm on January 5,

1995, with Unit 4 at full power, the control room received annunciator alarms associated with high HSR levels.

In addition, feedwater pump suction pressure was noted to have decreased to approximately 230 psig.

The RCO immediately started the third condensate pump in order to restore feedwater suction pressure.

The heater drain pumps remained in service.

The secondary plant oscillation caused a

momentary loss of approximately 15 HWe.

The licensee performed an investigation and postulated that the perturbation was initiated due to the heater drain pump discharge level control valve (CV-4-1510A) going closed.

The licensee was not able to identify the root cause of the valve closure.

The secondary system reacted as expected to the perturbation.

The inspectors walked down portions of the secondary system that were suspected to have been involved in the perturbation.

The inspectors did not note any abnormalities during the walkdown.

In conclusion, the operators appropriately responded to this secondary plant perturbation; however, the licensee was unable to determine the cause of the initiating event.

The inspectors intend to review any secondary plant anomalies that could initiate plant transients as well as licensee response and resolution of such event.2.5 Self-Assessment Activities 4.2.6 During the period, the inspectors reviewed licensee self-assessment activities.

This included the following: several PNSC meetings; the nuary 11, 1995, PTN status meeting; the January 17, 1995,CNRB meeting; the January 18 and 19, 1995, safety meetings; gA/gC independent activities; line management initiated reviews; a licensing initiated review of the operating experience feedback program; and the ALARA review comnittee.

The inspectors noted on-site presence of FPL corporate management at the CNRB and the PTN Status Meetings.

The inspectors also noted that line management and independent reviews and assessments were self-critical and demonstrated conservative operation of the nuclear units.

In summary, the inspectors concluded that FPL has effective programs relative to self-assessment which ensured nuclear safety, (Closed)

IFI 50-250,251/94-05-02, Administrative Procedure Upgrade The licensee completed the upgrade of the old style APs to the new ADM format, FPL internal letter PTN-PCC-94-274 dated December 30, 1994, documented the completion of this effort.

The inspectors reviewed the letter and verified that all APs were either satisfactorily upgraded to the ADM format or canceled and rolled into another station procedure.

The inspectors reviewed procedure indices dated December 27, 1994, for original procedures (old AP format)

and for upgraded procedures (which included ADM format).

Further, the inspectors reviewo0 selected upgraded procedures and attended PNSC meetings wh>ch reviewed and approved these procedures.

The inspectors also interviewed licensee supervisors responsible for this upgrado project.

Based on this, the IFI is considered closed.

5.0 Maintenance (61726, 62703, and 92902)

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.

The inspectors also reviewed a previous noncompliance to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirement Pjy ~Q jp'Pp)

j'yle I

5.2 Inspection Findings 5.2. 1 Haintenance Activities Mitnes"

The inspectors witnessed/reviewed portions of the following maintenance activities in progress:

procedure 4-0P-049, Reactor Trip Breaker Operation for Maintenance; 3C charging pump maintenance; steam generator level control system troubleshooting (Refer to section 5.2..3 for additional information.);

Unit 3 spent fuel pool cooling system outage (Refer to section 5.2.5 for additional information.);

and troubleshooting and repair of 4A HHSI oil bubbler abnormality.

(Refer to section 5.2.8 for additional information.)

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

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

procedure 3-OSP-075. 1, Auxiliary Feedwater Train

Operability Verification; procedure 3-0SP-075.9, AFM Overspeed Test; procedure 4-SM1-071.5, Steam Generator Protection Set III (gR-18) Analog Channel Test; procedure 3-0SP-024.2, Emergency Bus Load Sequencers Manual Test (Refer to section 5.2.6 for additional information.);

procedure 4-OSP-051. 1, Containment Emergency Air Lock Seal Vacuum Test (Refer to section 5.2.10 for additional information.);

and procedure 4-0SP-051.4, Containment Emergency Air Lock Pressure Test.

(Refer to section 5.2.10 for additional information.)

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

Strong teamwork was noted during all observed tests.

5.2.3 Steam Generator Level Control System Based on several recent problems with the steam generator level control system (Refer to section 4.2.3 for additional information.), plant management directed an ERT and ISC management and maintenance personnel to initiate an assessment of the system and related problems.

This included a review of the availability of replacement Hagan modules, aging issues with the electronics, configuration differences, personnel errors, and reliability of the.system.

The assessment involved vendor personnel, engineering, materials control and procurement, technical department and system engineering, IEC, and other site groups.

The licensee completed its review and documented the results and recommendations in a special ERT report, in condition reports, and in several CRNs.

The licensee concluded that adequate spares are available; however, failed modules are in need of on-site repair and return to stores.

Further, similar modules that may require dedication will be purchased.

This should address the obsolescence issue.

CRNs were written to address the configuration differences.

In addition, a person from the material recovery group will assist I&C to repair failed modules and to train IKC technicians.

Further, engineering is reviewing a

long-term modification.

Relative to the subsequent 3C steam generator level control system problems noted on January 23, 1995, the licensee determined that several IEC errors occurred.,

These errors resulted in the installation of the manual/automatic station (FC-498F) without the correct bias and installation of the flow controller (FC-498) with incorrect rate and reset switch settings.

Although these errors did not cause a significant unit transient or trip, they did result in an unnecessary unit power reduction.

The steam generator level control system is not safety-related; however, it can cause unit transients.

The licensee intends to conduct an independent human factors review of these errors.

The inspectors discussed these items with the plant and maintenance'manager and with 18C personnel.

The inspectors reviewed the results of the ERT and other issues.

The inspectors concluded that the licensee has appropriately addressed these issues.

Further, the inspectors reviewed the recent 3C steam generator level control problems and confirmed that personnel errors by IEC occurred associated with this non-safety-related system.

The inspectors expressed concern relative to the possible impact on safe plant operations.

The inspectors also reviewed the pMOs and Mls related to this gob.

The inspectors intend to review

18C maintenance calibration of and licensee control of spare modules for the steam generator level control system during a

future inspection.

This item will be tracked as IFI 50-250,251/95-01-02, Steam Generator Level Control System Calibration.

( ~

~

5.2.4 5.2.5 Quality Assurance Review of the Unit 4 Chemical Volume and Control System Blender'Problems Based on problems associated with the Unit 4 CVCS blender, QA performed a review in December 1994.

Performance monitoring report No.

6 (QAO-PTN-94-025), dated January 6,

1995, documented this review, This issue was also reviewed in sectior, 4.2.8 of NRC Inspection Report No. 50-250,251/94-24.

QA identified concerns relative to the MI development and review process, post-maintenance testing, and the PWO cancellation process.

QA discussed these items with plant and maintenance management.

The inspectors reviewed the QA report including QA's findings 'and recommendations.

The inspectors held discussions with QA management and auditing personnel.

The inspectors noted that the QA assessment was thorough and demonstrated an effective self-

.

assessment by the licensee.

Unit 3 Spent Fuel Pool Cooling Outage The licensee removed the Unit 3 SFP cooling system from service at 9:45 p.m.

on January 9,

1995, to perform corrective and preventive maintenance on system valves and pumps.

In order to get an adequate isolation, the licensee was required to use two freeze seals.

The system outage was concurrent with the systems'cheduled quarterly maintenance window.

Operators removed the SFP cooling system from service per procedure 3-0P-033, Spent Fuel Pit Cooling System.

With an out-of-service cooling system, operators periodically checked pool level and temperature.

The temperature at the start of the outage was 75'F, and as required by procedure 3-0P-033, the licensee calculated a 0.7'F per hour heat-up-rate, The outage was scheduled For 2-1/2 days; therefore, the expected temperature rise was about 42 F.

The licensee administratively limited the temperature rise in the SFP to 140'F.

(The procedure limit was 170'F, and the UFSAR limit was 180'F.)

Prior to each shift assuming the watch, the licensee performed briefings per procedure O-ADM-217, Conduct of Infrequently Performed Tests and Evolutions.

Maintenance personnel initiated the freeze seals per procedure 0-GMM-102.5, Freeze Seal Application.

Valve and pump work was accomplished per various PWOs and Mls.

The work was completed, and the system was filled, vented, and returned to operation at 12:45 a.m. during midshift on January 13, 1995.

This was a little

5.2,6 5.2.7 more than 3 days after the system was removed from service.

The highest SFP temperature was 124'F.

The inspectors reviewed the OP and GMH procedure",

selected PWOs and HIs, and procedure 3-ONOP-033. 1, SFP Cooling System Malfunction.

The inspectors also attended one of the 0-ADM-217 briefings.

In the field, the inspectors reviewed the work in progress, the freeze seal controls, HP coverage and supervisory oversight.

The inspectors noted good control of work activities, constant coverage by freeze seal personnel, maintenance oversight by first and second line supervision, and appropriate oversight by the control room.

The inspectors also noted strong teamwork.

Emergency Load Sequencers Hanual Testing As part of corrective actions for the sequencer design issues (Refer to NRC Inspection Report No. 50-250,251/94-23 for additional information.), the licensee stopped the monthly manual testing.

This testing was not required by technical specifications.

The licensee performed a safety evaluation (Refer to section 6.2.2 for additional information.) to justify recommencing this manual testing.

Procedures 3/4-0SP-024.2, Emergency Bus Load Sequencers Manual Test, were revised per OTSC Nos.95-003 and 95-004, respectively, and were approved by the PNSC on January 5,

1995.

On January 11, 1995, the licensee performed these tests on all four sequencers, Pri'or to the first test on the 3A sequencer, the licensee performed a briefing per procedure O-ADM-217, Conduct of Infrequently Performed Tests and Evolutions.

After completion of test prerequisites, operators proceeded to the switchgear room to test the 3A sequencer.

The test was successful.

It took about

minutes, and the 8-hour action statement for Technical Specification 3.8.3.1.a was entered for about 55 minutes.

Subsequent tests fo.

3B, 4A, and 4B were also successful with similar times associated with the test duration and action statement entry.

The inspectors reviewed the OSPs and observed the briefing in the control room.

The inspectors observed the test noting good procedural compliance and attention to detail.

The inspectors also noted that the licensee appropriately declared the 3A 4KV bus out of service per applicable procedural and technical specification requirements.

OA/gC and operations management personnel were noted to be present during the test.

In conclusion, the inspectors noted excellent test performance and strong oversight by l,ine management and gA/gC.

Fuse Control The inspectors reviewed the licensee's fuse control program.

Administrative procedure O-ADM-030, Control of Fuses, delineated

the program requirements and controls.

The ADH addressed fuse control and fuse replacement including the process necessary to dedicate replacement fuses.

The procedure addressed the issue of conflicting information among drawings, the fuse list, and the installed fuse.

The licensee has a controlled fuse listing per documents 5610-,

5613-,

and 5614-E-855A, Fuse List.

The procedure also addressed the issue of how to involve engineering if a replacement fuse cannot be found or if discrepancies exist.

The licensee used the condition report process to document and to disposition this type of discrepancy.

The inspectors reviewed the ADN, the fuse lists, and NRC Information Notice 91-51, Inadequate Fuse Control Programs.

The inspectors spot checked a number of fuses in the field against the fuse list and plant drawings.

The licensee adequately addressed several noted deficiencies, and operability issues did not occur.

Further, longer-term corrective actions will include walkdowns to update and validate the fuse list. The inspectors interviewed system engineering, design engineering, operations, and maintenance personnel.

The inspectors noted that the licensee has an initiative underway to review and address fuse control issues.

The licensee has identified a timeliness issue relative to obtaining spare fuses.

Further, the licensee also noted that some information was missing from the fuse list and that the process to dedicate replacement fuses is inefficient and time consuming.

Bases on these findings, the licensee initiated a number of corrective actions.

5.2.8 The inspectors concluded that the licensee has an adequate fuse control program.

Further, licensee-initiated efforts to improve the program demonstrated effective self-assessment.

4A High Head Safety Injection Pump Bearing Oil Leak On January 12, 1995, during inservice testing of the 4A HHSI pump per procedure O-OSP-062.2, Safety Injection Pump Inservice Test, the outboard pump bearing ofl level decreased such that the oil level was no longer visible in the oil bubbler.

When the pump was secured, the oil level recovered in the bubbler and eventually overflowed.

The pump was declared out of service, the action statement was entered, and a

PWO was originated.

The interior of the bearing housing was inspected, and abnormal conditions were not identified.

However, it was noted that the oil bubbler on the 4A HHSI pump inboard and outboard bearings were located on the opposite side of the bearing housing as compared to what was noted on the 3A, 3B, and 4B HHSI pumps.

The outboard bearing for the HHSI pumps is a back-to-back type

.Kingsbury thrust bearing that utilizes a slinger ring which supplies oil from a reservoir to the bearings for lubrication.

The oil bubb1er provides makeup and surge capability for the oil

reservoir and can be physically installed on either side of the bearing housing.

The licensee contacted the vendor (Dresser-Rand)

and discussed the issue.

The vendor postulated that the oil bubbler was installed such that it was on the discharge side of the slinger and that while the pump was running, the oil level profile within the bearing housing was such that ft was higher on the side opposite to where the bubbler was located.

This caused the oil from the bubbler to drain and makeup oil to the bearing housing.

When the pump was stopped, the oil level equalized, and the oil level recovered in the bubbler.

However, during this outflow from the bearing housing, the oil took a path of least res,stance, and some leaked out of a coupling located on the bubbler.

If the bubbler had been located on the suction side of the bearing, the oil level profile within the bearing housing would have precluded the need for the oil bubbler to makeup to the bearing housing.

Therefore, the oil level in the bubbler would not have changed.

(The terms

"suction" and "discharge."

side of the slinger, fs used for explanation purpose and is a function of pump rotation.)

The inboard bearing is of a different design, and.,the oil bubbler location has no relevance.

This was the first time that this phenomenon was noted at Turkey Point.

Upon further investigation, the licensee determined that the 4A HHSI pump had been overhauled approximately one year ago.

Following this overhaul, the oil bubbler was installed on the incorrect side.

Maintenance procedure 0-CME-62. 1, SI Pump Motor Repair, did not have specific instructions as to which side the oil bubbler should be installed.

Additionally, vendor instructions did not have any clarification associated with oil bubbler installatfon.

The licensee re-installed the bubbler on the correct side and initiated a condition report to address this issue.

The licensee p1ans to revise the HHSI pump repair procedure to clarify bubbler installation.

The pump was tested satisfactorily and declared operable on January 14, 1995.

The inspectors questioned the operability of the 4A HHSI pump with the oil bubbler installed on the incorrect sfde.

The licensee determined that pump operability was not affected as the capability to lubricate the bearing was always maintained due to the oil in the bearing housing reservoir.

The licensee also confirmed this with the vendor.

The inspectors also questioned the licensee to determine whether or not the vendor was aware of other licensees experiencing this problem and why the vendor had not included appropriate instructions to prevent this from happening.

The licensee discussed these concerns expressed by the inspectors with the vendor.

The vendor did not recall any other pump users experiencing a similar problem.

The inspectors concluded that th'e licensee appropriately and aggressively pursued and rectified the problem.

The inspectors

also noted strong system engineer and component specialist involvement during problem resolution.

Additionally, the observation of the oil level anomaly and decision to shut down the pump by the operator coordinating the test was a strength.

The inspectors also concluded that maintenance personnel performing the procedure should have sought clarification of location prior to oil bubbler installation.

5.2.9 Vendor Controls The inspectors reviewed an investigation conducted by the licensee's Nuclear Safety SPEAKOUT program pertaining to vendor c~ntrols.

The investigation was focused on a particular vendor who is a supplier of calibration devices.

The vendor also performs electrical testing to support FPL's commercial grade dedication program.

The licensee reported the results of the investigation in a letter (L-94-235) dated September 9,

1994.

The inspectors concluded that the licensee appropriately conducted and documented the investigation.

5.2. 10 Containment Air Lock Testing Ouring the period January 24-26, 1995, the licensee performed periodic pressure testing on the containment air locks in accordance with Technical Specifications 4.6. 1.3.a and b.

All four pressure tests passed with observed leak rates between 300-900 cc/minute.

(The limit was 3,750 cc/minute.)

These results did not exceed the allowable containment leak rate criteria.

After completing the pressure testing, the licensee tested each door's seals by performing a vacuum test.

The Unit 3 emergency air lock inner door and the Unit 4 emergency air lock outer door both failed these initial tests.

This placed the units in a 24-hour action statement.

The licensee found small amounts of debris on the sealing surfaces, cleaned them, and performed satisfactory retests.

Ouring the Unit 3 failure, operators experienced difficulty in closing the equalizing valve.

This placed Unit 3 in a 6-hour action statement which was exited after 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and

minutes.

The inspectors witnessed portions of testing including preparation, coordination and test conduct.

The inspectors noted strong teamwork among the technical department, operators, IKC, HP, and security.

Procedural compliance was very good, and face-to-face communications and reports to the control room were effective.

The inspectors reviewed the test results for all four air locks and technical specification compliance for the failed tests.

Violations or deviations were not identifie.2. II (Closed)

VIO 50-250/93-20-01, Failure to Provide Adequate Procedure for Performance of Safety-Related Cable Pull This violation involved the performance of a mechanical cable pull of a motor lead cable for the 38 charging pump without the calculation of a pull stress limit or use of a device to measure the induced pull stress on the cable on Hay 20, 1992.

The work

. instruction was inadequate in that it directed the craft to pull the 3B charging pump motor lead cable but did not provide instructions which conformed to the applicable plant specification or referenced the specification.

Apparent1y, the need to pull cable in order to land the,rotor leads to the 3B charging pump was not 'recognized until the work was in progress, and the work instruction was changed in the field when it was recognized that the cables were too short to reach the pump motor terminals.

When changing the work instruction, the field supervisor.was unaware of.he detailed cable pull requirements of the applicable specification.

In order to verify that over stressing of the 'cable did not occur, the licensee subsequent1y calculated a maximum allowable tension and re-pulled the cable.

Nore cable was successfully pulled using a less than maximum tension.

Therefore, no over stressing of the cable occurred during the initial pull, and no further action concerning the cable was required.

In order to prevent recurrence, the licensee performed the following corrective actions:

All electrical maintenance department field supervisors, maintenance engineers, and planners attended a specification overview training session on engineering supplied specifications.

An electrical shop meeting was held to make all electrical maintenance personnel more aware of the availability and content of specifications and the need to consult with supervision if they see a need for their use.

Cycle 2 of electrical continuing training program for 1993 was provided to all electricians and chief electricians and it included specification overview awareness training and a

discussion of the violation.

These continuing training sessions were completed on November 5, 1993.

The licensee also developed Information Bulletin No.93-045, Cable Pull Specification for Electricians, on September 20, 1993.

This bulletin documented the above actions and was discussed in Cycle 2 of the electrical continuing training program for 199 :

In addition, a Harch 31, 1994, revision to specification No.

SPEC-E-005, Installation, Inspection, and Testing Details for Electrical Equipment and Cable at PTN, was included as a

discussion topic in Cycle 1 of the electrical continuing training program for 1994.

This cycle was completed on August 26, 1994.

The inspectors reviewed the licensee's violation response of September 10, 1993, reviewed applicable licensee documentation, and verified the performance of the licensee's corrective actions.

The licensee's actions were comprehensive and effective in preventing recurrence.

This item is closed.

6.0 Engineering (37551, 90712, 90713, 92700, and 92903)

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

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

The inspectors reviewed 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.

In addition, the inspectors reviewed an open item to assure that corrective actions were adequately implemented and resulted in conformance with regulatory requirements.

Inspection Findings Auxiliary Feedwater System Review The inspectors reviewed the AFW system including its recent maintenance history, reliability, availability, and applicability of NRC Information Notice 94-84, Air Entrainment in Terry Turbine Lubricating Oil System.

The inspectors discussed this information notice with the AFW system engineer.

The licensee concluded that the information notice was not applicable to Turkey Point due to several design

~

%

y I

~ =

ta

~

6.2.2 differences.

Unlike the designs discussed in the information notice, Turkey Point AFW turbine bearings are supplied oil though a metered orifice line that is located in the center if the bearing housing, and the bearings are not slinger fed.

This results in a dry bearing housing which precludes froth and aeration.

Additionally, the drain lines at Turkey Point are adequately sized to drain to a reservoir instead of an equalization pipe.

The governor oil system is also independent of the turbine oil system.

The inspectors reviewed the AFW system design and verified that the licensee's assumptions and conclusions were appropriate.

The inspectors reviewed all work orders associated with the A, B, and C AFM turbine/governors and pumps that had been generated in the last two years.

Additionally, the inspectors reviewed the technical department AFM system unavailability indicators for the last year.

The review of the work orders did not indicate any recurring type problems associated with the AFW system.

AFM system unavailability was noted to be particularly high for the fourth quarter of 1994.

This was due to the corrective actions that the licensee conducted as a result of an a

pump trip during testing.

The pump had tripped due to two set screws associated

,

with the trip tappet assembly on the B AFW pump coming loose.

This issue was discussed in NRC Inspection Report No. 50-250,251/94-20.

Overall, the inspectors concluded that the information notice was appropriately dispositioned, and AFW system work order backlog was low.

In addition, there were no repetitive problems associated with AFW system in the recent past, and system engineer cognizance and ownership of system was evident.

Emergency Load Sequencer Issue The issue associated with emergency load sequencer logic defects was identified by the licensee in November 1994 and discussed in NRC Inspection Report No. 50-250,251/94-23 dated December 1,

1994.

A Notice of Violation associated with the sequencer logic defects was issued by the NRC on January 10, 1995.

The licensee issued LER 50-250/94-005 documenting completed and planned corrective actions.

This included placing the sequencer in the test mode OFF position and discontinuing manual testing of the sequencers pending an engineering evaluation.

Additionally, the licensee committed to performing an independent assessment of the sequencer design, software design, validation and verification, and engineering software control procedures for program logic computers.

The inspectors reviewed an engineering safety evaluation JPN-PTN-SEEP-94-041, Revision 4, Safety Evaluation for Operation of the Emergency Load Sequencers with Software Logic Oei ct in Test Modes, dated December 29, 1994.

That evaluation concluded that

the sequencers are operable when the test mode selector switch is fn the OFF position.

Further, the sequencers are inoperable when the test mode selector switch is not in the OFF position.

Additionally, the evaluation recommended that the sequencer manual test be performed on a monthly basis.

During the test, the sequencer should be declared inoperable, and an 8-hour action statement pursuant to Technical Specification 3.8.3. I would be in effect.

Technical Specification 3.8.3. I is associated with 4KV bus outage.

This monthly sequencer test would test the logic as well as certain outputs and would be performed on a staggered basis, i.e.

one sequencer at a time.

The action statement was determined to be the most limiting action statement as there is no technical specification directly pertaining to the sequencers.

The licensee performed manual tests on all four sequencers during January 1995.

The inspectors witnessed significant portions of the manual testing.

(Refer to section S.2.6 for additional information.)

The inspectors also reviewed results of the independent assessment.

The assessment identified a potential vulnerability associated with the automatic starting of the CS pumps.

The CS pump vulnerability was postulated to occur upon receipt of high-high containment pressure of 20 psig by the sequencer during an approximate 60 millisecond time window just prior to the end of load block 3 following LOCA or LOOP/LOCA events.

Oue to a minimum pulse required to assure CS pump breaker closure and a potential relay race with a CS pump start permissive from the SI logic, the CS pump breaker may not receive a close signal of sufficient duration to assure breaker closure.

The receipt of the high-high containment pressure signal during this small time window would inhibit the sequencer from providing a second CS pump start signal later in the loading sequence, i.e. during load block 8.

The li'censee determined that the condition could only preclude an automatic pump start capability and that the capability to manually start th~

CS pumps would not be affected.

Further, plant EOPs have addressed this evaluated condition.

Using the guidelines in NRC Generic Letter 91-18, Resolution of Degraded and Non-Conforming Conditions, the licensee concluded that the automatic start function of the CS pumps remained operable based on reasonable reliability of the safety function.

Further, in the improbable case that the condition were to occur, simple operator action to start the CS pumps would ensure compliance with the safety system functions.

The conclusion regarding equipment reliability was based on the unlikely potential for the high-high containment pressure signal being received by the sequencer during the 60 millisecond window relative to the reliability of the entire CS system.

The ability to manually start the CS pumps as much as 10 minutes into the event to maintain the required containment conditions was supported by analysis, procedures, and training.

Consequently, the plant specified PSA model For Turkey Point calculated a

6.2.3 negligible increase in COF of 3.6 x 10E-9/year (baseline CDF is 6.63 x 10E-5/year).

The inspectors reviewed this issue and discussed it with the licensee.

The inspectors also attended the PNSC meeting that approved the CS operability evaluation as documented in JPN-PTN-SEIP-95-001, Operability Assessment and Safety Significance Evaluation For Potential Automatic Start Fai,lure Of Containment Spray Pumps.

With regard to the manual testing of the sequencers, the inspectors concluded that the evaluation was thorough and that the manual testing was appropriately recommenced.

Additionally, with regard to the findings of the independent assessment team (including the CS issue discussed above),

the inspectors concluded that the issues identified have minimal impact on plant safety and that the licensee appropriately dispositioned the issue.

Loss of Unit 4 Low Instrument Air Pressure Annunciation At 7:55 p.m.

on January 15, 1995, annunciator I-6/1, INST AIR HI TEHP/LO PRESS, was not received in the control room as expected

. during the performance of section 7. 12 of procedure 4-0SP-200.3, Secondary Plant Periodic Tests.

The licensee's subsequent investigation revealed that the removal of terminal box No. TB4040 during the performance of work associated with Unit 4 PC/H No.93-109, Instrument Air System Compressor Upgrade, resulted in the disconnection of leads from pressure switches PS-4-2004 and PS-4-2035 to control room annunciator I-6/I.

This in effect disconnected the low instrument air pressure alarm function and rendered these inputs to the annunciator inoperable.

These actions were performed in accordance with the PC/H process sheets.

The licensee attributed this to the failure to adequately review and address the risks and consequences of a change.

The PC/H was issued to facilitate the removal and replacement of the old instrument air compressors which are no longer utilized.

This PC/H also involved the removal of additional auxiliary equipment including terminal box No.

TB4040.

This terminal box was to be replaced with a new terminal box and local annunciator.

It was discovered that due to supervisor and field engineer oversight, the removal of terminal box No. TB4040 was not covered in a walk down performed by a mechanical projects supervisor, IKC projects supervisor, electrical field supervisor, and system engineer prior to the start of the job.

This resulted in the misconception that no operating systems would be affected during the removal process.

It was concluded that it was acceptable to begin work based on this walk down, and the NPS was contacted.

Work proceeded for the electrical removals per work order No.

W094029176-01 and process sheet No.94-220.

During this work,

cable 4K36/4C05-TB4040/1 (the input from terminal box No. TB4040 to control room annunciator panel window I-6/1) was disconnected, taped at the terminal box end, and coiled to await re-connection in the new terminal box when the new terminal-box could be installed.

The two cables coming from pressure switches PS-4-2004 and PS-4-2035 were also disconnected, coiled, and taped at terminal block No.

TB4040 on January 9,

1995.

The remaining wiring was disconnected, and the old terminal box was removed.

The fact that the wires to the annunciator were energized was brought to the attention of the pro)ect supervisor, and the decision was made to go ahead and disconnect the wires "hot" because it was thought that the window would need to remain in service for the other inputs as shown on drawing 5610-E-27, sheet No. 26.

In order to correct the PC/H, the licensee generated change request notice No. E-15181.

This allowed the temporary re-connection of the pressure switches to the annunciator circuit until a new terminal box could be installed.

This action was completed on January 17, 1995 (restoring the alarm function),

and the circuits were satisfactorily tested.

The licensee also generated a condition report, stopped all work related to this PC/H, recalled the process sheets, and verified that no other problems existed with the implementation of the PC/N.

The system engineer has become more actively involved with the operating system's requirements, and the process sheets for the same modification on Unit 3 have been changed to reflect the lessons learned.

These process sheets have also been sent to the system engineer for review and approval prior to submission to the PNSC or PHSC subcommittee.

In addition to these actions, the licensee documented the following planned corrective actions in condition report No. 95-0037:

The licensee plans to revise procedure O-ADH-045, Preparation of Process Sheets and Installation Lists, and procedure 913-PTN-I, Design Control, to require system engineer review of all drawings and approved implementation instructions for modifications performed on equipment or systems while they are fn service.

This action is currently scheduled for completion by February 26, 1995.

The licensee plans to instruct the system engineers to issue a pre-implementation training brief to maintenance and operations for all PC/Hs affecting modifications to in-service equipment (i.e., not in the equipment out-of-service log book or on a clearance).

In addition, the technical department plans to develop a process sheet screening sheet (similar to a "red sheet")

to be used on all process sheets prior to approval for implementation.

These actions are currently scheduled for completion by February 26, 199 The licensee plans to circulate condition report No. 95-0037 to JPN engineering, all maintenance disciplines, and projects for training of the field supervisors, engineers, and foreman.

This action is currently scheduled for completion by February 7,

1995.

Because these actions were documented in a plant general manager approved condition report, they will become open items on the plant manager's action item list.

This will help to ensure resolution of these issues.

The,inspectors reviewed the applicab1e documentation, discussed the issues and toured the affected areas of the pl ';,t with the electrical maintenance supervisor, and verified the performance of the corrective actions completed by the end of this inspection period.

In order to determine the significance of the impact of rendering the low instrument air pressure inputs to Unit 4 control room annunciator I-6/I to plant operations, the inspectors interviewed licensed operators and reviewed various documentation including plant P810s; procedure 4-ARP-097.CR, Control Room Annunciator Response; and procedure O-ONOP-013, Loss of Instrument Air.

The inspectors determined that the instrument air system at Turkey Point is considered to be non-safety-related, and it is normally cross-tied between the units via distribution header pressure control valves CV-3-1506 and CV-4-1506.

The instrument air system can also be manually cross tied via valves IAS-3-012 and IAS-4-012.

This would bypass the air receiver and two filters on one of the units.

Upon an actual loss of instrument air on either unit, there would be several automatic actions.

Control room annunciator I-6/I would be received on both units when system air pressure decreased to 95 psig.

This would occur whether the system was cross tied normally or manually.

Therefore, with the low instrument air pressure inputs disconnected from the Unit 4 alarm, the Unit 3 alarm would still be received upon an actual loss of instrument air on either unit.

Additional Unit 3 and 4 temporary diesel air compressors would automatically start if pressure reached 92-94 psig and 95-96 psig, respectively.

The five temporary diesel instrument air compressors have been supplying the Unit 3 and

loads for a number of years.

This Unit 4 PC/N and a similar PC/H for Unit 3 will replace these temporary diesel instrument'air compressors.

In addition, if instrument air pressure were to decrease to 85 psig, the distribution header pressure control valves (valves CV-3-1506 and CV-4-1506) would automatically close in order to protect the unaffected unit.,If instrument air pressure were to drop below the nitrogen pressure control valve setpofnts of 90 psig for Unit 3 and 89 psig for Unit 4, both units'ORVs would be automatically supplied by the safety-grade nitrogen backup system.

The Unit 3 HSIVs would automatically be

supplied by the air operator saFety-grade nitrogen backup system if instrument air pressure dropped below the nitrogen pressure control valves setpoint of 80 psig, and the Unit 4 HSIVs would automatically be supplied by the safety-grade HSIV air accumulators.

6.2.4 6.2.5 6.2.6 In addition to these automatic actions, section 4.0 of procedure 0-ONOP-013 requires two operator immediate actions.

Actual instrument air pressure is required to be determined on control room pressure indicators PI-3-1444 and PI-4-1444, and any available diesel air compressor is required to be started if instrument air pressure is less than 95 psig.

Based on these automatic and immediate actions, the actual safety impact to the operation of the plant was minimal because the instrument air systems for each unit are cross tied and because of the availability of a redundant Unit 3 alarm.

However, an oversight permitted the inadvertent disconnection of the leads from two pressure switches and rendered these inputs to the Unit 4 low instrument air pressure alarm in the control room inoperable.

This oversight indicated a weakness in the design review process and the development of process sheets which facilitate the implementation of design changes in the plant.

Periodic Reports The inspectors reviewed the December 1994 monthly operating report and the quarterly safeguards event report and determined them to be complete and accurate.

(Closed)

LER 50-250/94-006, Automatic Reactor Trip/Turbine Trip Due to Hain Feedwater Control Valve Failing Closed The licensee issued LER 50-250/94-006 regarding a Unit 3 automatic reactor trip on December 26, 1994, when the 3C feedwater regulating valve failed closed.

The event was reviewed during NRC Inspection Report No. 50-250,251/94'-24.

The LER concluded that root cause was a failure of the electro-pneumatic transducer due to loose terminal which resulted in an intermittent open circuit in the current loop.

This LER is closed.

The inspectors reviewed the LER and determined it to be accurate and well written.

The inspectors attended the PNSC meeting which reviewed and approved this LER.

(Closed)

IFI 50-250,251/94-18-01, Hodification of Eagle-21 System Power Distribution Panels On August

and 31, 1994, Eagle-21 system power distribution panel failures occurred on instrument racks 4gR14 and 3(ROI, respectively.

These failures appeared to be similar to one of the problems documented in a

CFR Part 21 notification issued by

Zion on April 8, 1994.

(Refer to sections 4.2.5 and 6.2.5 of NRC Inspection Report No. 50-250,251/94-17 and to sections 4.2.4 and 6.2.

1 of NRC Inspection Report No. 50-250,251/94-18 for additional information.)

The problems experienced at 2fon involved the premature failure of power supplies used in the Westinghouse plant reactor protection system.

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

The 2ion root cause investigation concluded that one problem was caused by the failure of an aluminum electrolytic capacitor and that this end-of-life failure was accelerated by localizod heating within the module due to a resistor in close proximity to the capacitor.

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

NRC Information Notice 94-33, Capacitor Failures in Westinghouse Eagle-21 Plant Protection Systems was promulgated on this issue on Hay 9, 1994.

In response, the licensee performed an operability assessment (No.

019-94)

on April 14, 1994, and determined that a failure of this type would not prevent the RPS from performing its safety function to de-energize and trip the reactor.

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

As a

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

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

The licensee also planned to send the power distribution panels in all six (three per unit) Eagle-21 instrument racks back to Westinghouse for modification if any rack experienced this condition.

Following the Eagle-21 system power distribution panel failure on August

and 31, 1994, the licensee changed its action plan to include the modification of the power distribution panels in all six Eagle-21 instrumentation racks, the training rack, and stores.

A third Eagle-21 system power distribution panel failure (instrument rack 3I)R14) occurred on December 9,

1994, prior to the completion of all of the planned power distribution panel modifications.

The licensee promptly installed a modified panel as a result of this failure.

The inspectors reviewed the licen ee's action plan, the applicable work orders, and the I)C receipt inspection reports in order to verify that the Eagle-21 system power distribution panels in the plant had been modified.

The inspectors noted that the work order task descriptions were not accurate in some cases based on a

~

~

'

~

~

~

I

'

I

~

'

I I

~

~

~

I I

~

~

~

I I

~

I

~

I I

~

~

~

I

~

'

I

~

~

I

~

I I

'

~

~

~

'

~

~

~

.

~

~

~

~

~

I

~

~

~

~

~

I I

I

~

I

~

~

~

~

I

~

~ I

~

~

~

'

I

~

~

~

~

~

~

I

~

~ I I

~

~

~ I

~

~

~

~

I

~

.

~

~ ll

~

~

~

I

~

I

~

~

~

I I

~

~

~

j

~

~

~

~

1.

~ I

~

~

~

~

~

~

I

~

~

I

~

~

~

~

~

I

~

~

~ ~

~

~

'

Ins t.

Orig inal Rack Un-Mod.

Panel Failure Removal Date Date Un-Mod.

Panel Installed

'odified Panel Installed Date Installed Train-ing SW1108 08-31-94 Current Plan-s W1108 (from 3QROI (Refer to Note

below.)

Spare SW16968 Approx.

06-30-94 based on IN 94-33 Current Plan-13762 (from 3QR14 (Refer to Note

below.)

Note 1:

The licensee recently received modified power distribution panel No.

SW1108 (which had originally been taken out of the training rack and temporarily installed in instrument rack 3QR01 in its unmodified form) from Westinghouse and currently plans to re-install this modified panel back into the training rack.

Note 2:

On January 3,

1995, the licensee returned power distribution panel No.

13762 (which had failed in instrument rack 3QR14 on December 9,

1994)

back to Westinghouse for modification.

The modified panel is currently expected to be returned to the licensee during February 1995 and is currently intended to be used as a

spare.

The licensee is also in the process of ordering three modified power distribution panel to be used as additional spares.

The inspectors concluded that although discrepancies were noted in the work order task descriptions, the licensee's corrective actions with respect to this issue were effective in ensuring that the I:agle-21 system power distribution panels in the plant were appropriately modified.

This item is closed.

7.0 Plant Support (71750)

7.1 Inspection Scope The inspectors verified the licensee's appropriate implementation of the physical security plan; radiological controls; the fire protection program; the fitness-for-duty program; the chemistry programs; emergency preparedness; plant housekeeping/cleanliness conditions; and the radiological effluent, waste treatment, and environmental monitoring program.2 7.2.1 7.2.2 7.2.3 Inspection Findings As-Low-As-Reasonably-Achievable Review Coaeittee The inspectors attended an ALARA review coamittee meeting on January 6,

1995.

At this meeting, the licensee discussed the ALARA plan for 1995, site historical exposure data, and refueling outage exposure results for the two 1994 outages.

The 1994 exposure result was 468 Rem with a goal of 475 Rem.

The 1992 and 1993 results were 325 Rem and 275 Rem, respectively, This resulted in the three year average for Turkey Point to be 179 Rem per unit per year.

The inspectors noted that all departments were in attendance at the meeting including site and plant management personnel.

The inspectors also noted that recent exposure results have been very good and that the 1995 goal appears to be sound.

Access Control and Oosimetry Issue The inspectors reviewed RCA access control and personnel dosimetry issue procedures.

The licensee is currently changing the RCA access control system including the type of alarming dosimeter.

The control point area was modified in Oecember 1994, and the licensee now uses a Merlin-Gerin digital alarming dosimeter, Ouring January 1995, the licensee began testing a new automated access control system.

HP personnel instituted the program initially.

The remaining site personnel are scheduled to begin using the system in February 1995.

The inspectors reviewed these changes including licensee planning, training.

and implementation effectiveness.

Licensee efforts were sound and proactive.

Health Physics Controls For Spent Fuel Pool Cooling Work As discussed in section 5.2.5 of this report, the inspectors reviewed maintenance activities associated with the Unit 3 SFP cooling system.

The inspectors noted positive controls by HP technicians and supervisor personnel.

RMP preparation, review, and implementation was appropriate.

The inspectors noted use of cameras and remote video displays which lowered the HP personnel exposure while ensuring adequate oversight of the radiological aspects of the work.

The dose estimate for the SFP cooling system work was appropriate, and actual dose was less than the estimate.

The inspectors concluded that HP technician oversight was strong, with effective radiological controls of all observed wor.2.4 Radiation Control Area and Auxiliary Building Housekeeping and Cleanliness The inspectors performed an inspection of the RCA and the auxiliary building.

Items checked included cleanliness, housekeeping, leak identification and containment, equipment identification ta'gging, overall equipment and plant material condition, and work in progress.

The inspectors also toured the Unit 4 containment tendon gallery'and the steam generator storage bui 1 ding.

Overall, the inspectors noted generally good housekeeping and cleanliness.

Contaminated areas were kept at a minimum.

The less frequented areas were generally clean.

The licensee was in the process of cleaning grease, deposits in the Unit 4 containment tendon gallery.

The inspectors did identify some minor issues relative to gob work sites, documentation of 1eaks, and missing tags for valve and penetration identification.

These items were discussed with maintenance and operations personnel, and the licensee initiated appropriate actions.

7.2.5 Fire Drill The licensee conducted a fire drill during the afternoon of January 23, 1995.

Licensee fire protection personnel simulated a

fire in the AFW pump cage area.

The fire brigade responded as directed by the control room announcement.

The inspectors monitored both the control room fire announcement and fire brigade actions at the scene.

The control room appropriately used procedure 0-ONOP-016. 10, Pre-fire Plan Guidelines and Safe Shutdown Manual Actions, and the appropriate attachment (fire area No. 84 for the AFW area).

The inspectors noted timely and appropriate response by the fire brigade as well as good drill conduct and critique by the fire protection personne1.

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

An exit meeting was conducted on January 30, 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.

The inspectors did not identify any regulatory compliance issues.

However, the inspectors had the following findings:

'

t Nmbr

at escr and e

e c

50-250,251/95-01-01 50-250,251/95-01-02 (Open) IFI - Probabil istic Safety Assessment Actions (section 4.2.2)

{Open) IFI - Steam Generator Level Control System Calibration (section 5.2>>3)

Additionally, the following previous items were discussed:

Item Number Status Descri on a

efere ce 50-250,251/94-05-02 (Closed)

IFI - Administrative Procedures Upgrade (section 4.2.6)

50-250/93-20-01 LER 50-250/94-006 50-250,251/94-18-01 (Closed)

VIO - Failure to Provide Adequate Procedure for Performance of Safety-Related Cable Pull (section 5.2.11)

(Closed)

LER - Automatic Reactor Trip/Turbfne Trip Due to Hain Feedwater Control Valve Failing Closed {section 6.2.5)

(Closed)

IFI - Modification of Eagle-21 System Power Distribution Panels (section 6.2.6)

9.0 Acronyms and Abbreviations

ADM AFW ALARA AP Approx.

ARP CC CCW CDF CFR CHE CNRB CRN CS CV CVCS EOP ERT

~ F FC FCV FPL GHM HHSI Administrative Auxiliary Feedwater As Low As Reasonably Achievable Administrative Procedure Approximately Annunciator Response Procedure Cubic Centimeter Component Cooling Water Core Damage Frequency Code of Federal Regulations Corrective Maintenance

- Electrical Company Nuclear Review Board Change Request Notice Containment Spray Control Valve Chemical Volume Control System Emergency Operating Procedure Event Response Team Degrees Fahrenheit Flow Controller Flow Control Valve Florida Power and Light General Maintenance

- Mechanical High Head Safety Infection

HP IKC IAS ICW IFI IN Inst.

JPN KV LC LER LOCA LOOP LT Hl Hod.

HSIV HSR MRe NPS NRC ONOP OP OSP OTSC PKIO PCC PC/H PEG PI PMT PNSC PORV PS PSA psig PTN PRO QA QAO QC Ql QR RCA

'CO RCP Rem RPS RRP SEEP SE IP SFP Health Physics Instrumentation and Control Instrument Air System Intake Cooling Water Inspector Followup Item Information Notice Instrument Juno Project-Nuclear {Nuclear Engineering)

Kilovolt Level Controller Licensee Event Report Loss-of-Coolant Accident Loss of Offsite Power Level Transmitter Maintenance Instruction Hodified Hain Steam Isolation Valve Moisture Separator Reheater Megawatts Electric Nuclear Plant Supervisor Nuclear Regulatory Commission Off Normal Operating Procedure Operating Procedure Operations Surveillance Procedure On-the-Spot Change Piping and Instrumentation Oiagram Plant Change Control Plant Change/Modification Production Engineering Group Pressure Indicator Post-Maintenance Test Plant Nuclear Safety Committee Power-Operated Relief Valve Pressure Switch Probabilistic Safety Assessment Pounds Per Square Inch Gauge Project Turkey Nuclear Plant Work Order Quality Assurance Quality Assurance Organization Quality Control Quality Instruction Quality Rack Radiation Control Area Reactor Control Operator Reactor Cnolant Pump Roentgen Equivalent Han Reactor Protective System Radiation Work Permit Safety Evaluation Electrical

-

PEG Safety Evaluation 15C

-

PEG Spent Fuel Pit {Pool)

S/G SI SHI SPEC TB TP UFSAR VIO MO Steam Generator Safety In)ection Surveillance Maintenance

- I8C Specification Terminal Block Temporary Procedure Updated Final Safety Analysis Report Violation Work Order