ML20135C851

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Insp Repts 50-424/96-14 & 50-425/96-14 on 961222-970201. Violations Noted.Major Areas Inspected:Aspects of Licensee Operations,Engineering,Maintenance & Plant Support
ML20135C851
Person / Time
Site: Vogtle  Southern Nuclear icon.png
Issue date: 02/24/1997
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20135C844 List:
References
50-424-96-14, 50-425-96-14, NUDOCS 9703040340
Download: ML20135C851 (26)


See also: IR 05000424/1996014

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U. S. NUCLEAR REGULATORY COMMISSION (NRC)

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REGION II

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Docket Nos. 50-424 and 50-425

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License Nos. NPF-68 and NPF-81

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Report No:

50-424/96-14. 50-425/96-14

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Licensee:

Georgia Power Company

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Facility:

Vogtle Electric Generating Plant Units 1 and 2

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Location:

7821 River Road

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Waynesboro. GA 30830

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Dates:

December 22. 1996 - February'1. 1997

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Inspectors:

C. Ogle. Senior Resident Inspector

M. Widmann. Resident Inspector

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K. O'Donohue. Resident Inspector (in training)

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Approved by:

P. Skinner. Chief

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Reactor Projects Branch 2

Division of Reactor Projects

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Enclosure

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9703040340 970224

PDR

ADOCK 05000424

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EXECUTIVE SUMMARY

Vogtle Electric Generating Plant Units 1 and 2

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NRC Inspection Report 50-424/96-14, 50-425/96-14

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This integrated inspection included aspects of. licensee operations.

engineering, maintenance, and plant support. The report covers a six-week

period of resident inspection.

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ODerations

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In general, the conduct of operations was satisfactory (Section 01.1).

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A non-cited violation (NCV) was identified for operations personnel

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improperly venting air from a nuclear service cooling water (NSCW)

system supplied component prior to restoration of the component to

ser. ice following maintenance (Section 02.1).

An NCV was identified as a result of a solenoid valve vent port which

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became blocked by painting. This resulted in an inadvertent partial

depressurization of one train of starting air for the Unit 2 train A DG

(Section 02.2).

An example of an ap)arent violation was identified following discovery

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by the inspectors tlat the DG 2A air start receiver outlet valve was

open and unlocked. The valve is normally locked open (Section 02.3).

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The second example of an apparent vMlation was identified as a result

of an observation by the inspectors that a jumper installed in the

control circuit of valve 1-HV-8802A, Safety Injection (SI) Pump A to Hot

leg 1 and 4 Isolation Valve, was improperly positioned (Section 02.4)

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A third example of an apparent violation was identified as a result of a

discovery by the inspectors that fifteen spare breakers on motor control

centers (MCCs) 1BBE and 2BBE were open instead of shut.

While the

safety consequences of this mispositioning were minimal, it represents

another example of inadequate configuration control (Section 02.5).

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The inspectors reviewed the circumstances associated with the licensee's

discovery of potentially inadequate testing of the turbine trip from

reactor trip circuit. P-4 interlock.

Pending further review by the

inspectors, this was identified as an unresolved item (Section 03.1),

Maintenance

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Maintenance activities were generally completed thoroughly and

professionally (Section M1.1 and M1.2).

Enclosure

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An NCV was identified for inadequate maintenance in the re) air of a

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failed journal bearing on the Unit 2 train A centrifugal clarging pump

(CCP) speed increaser. Specifically, maintenance personnel failed to

properly follow work package and vendor manual instructions during

performance of the repairs (Section M2.1).

The licensee's identification of missed steps in the reassembly of the

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Unit 2 train A CCP speed increaser was an example of good attention to

detail (Section M2.1).

Two examples of an NCV were identified for deficiencies associated with

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the licensee's development and implementation of procedures to test the

turbine trip from reactor trip circuit (Section M3.1)

Enaineerina

A strength was identified for the efforts by the event review team to

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determine the root cause of the failed journal bearing on the Unit 2

train A CCP speed increaser.

The corrective actions develo]ed as a

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result of the team's efforts should provide data to trend t1e pump's

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performance in the future (Section E7.1).

Plant Suooort

In general, conduct in the plant security area was satisfactory

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(Section S1.1).

Minor deficiencies were identified in the protected area (PA) barrier,

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but these did not rise to the level of a regulatory non-compliance

(Section S2.1).

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Enclosure

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Report Details

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Summary of Plant Status

Unit 1 operated at 100% Rated Thermal Power (RTP) throughout the inspection

period.

Unit 2 operated at 100% RTP throughout the inspection period.

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Doerations

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Conduct of Operations

01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent

reviews of ongoing plant operations and, in general

the reviews

indicated that the conduct of operations was satisfactory.

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Operational Status of Facilities and Equipment

02.1 Air Bindina of Nuclear Service Coolina Water (NSCW) Supolied Motor

Coolers on Safety In.iection (SI) Pumo 2A

a.

Insoection Scooe (71707)

The inspectors reviewed resolution of a loss of NSCW flow condition

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identified for one of the Unit 2 Train A SI pump motor coolers.

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inspectors reviewed maintenance work orders (MW0s) associated with

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plenum orientation verifications: Preventive Maintenance (PM) checklist

SCL02677. NSCW Heat Exchanger - Periodic Inspections; control room logs:

and Procedures 13150-1 and 13150-2. Nuclear Service Cooling Water System

(Units 1 and 2. respectively).

The inspectors also interviewed

personnel involved with plenum orientation verification activities and

cognizant management as to their review of this issue.

b.

Observations and Findinas

On December 18. 1996, a plant equipment operator (PEO) observed that the

inboard motor cooler on the Unit 2 SI pump train A had a higher return

3iping temperature than that of the corresponding outboard motor cooler.

ion-intrusive measurements revealed that no NSCW flow existed through

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the inboard motor cooler.

On December 19. following troubleshooting.

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the licensee determined that the no flow condition was the result of air

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binding of the inboard motor cooler.

Following this discovery, the

licensee addressed the potential air binding condition by venting NSCW

supplied components.

No other incidents of air binding were identified.

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Upon discovery of the no flow condition maintenance personnel

disassembled the motor cooler piping for SI pump 2A to identify any

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potential sources of blockage.

No foreign material was identified in

Enclosure

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either motor cooler's NSCW piping. After reassembly. NSCW flow was

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restored to the SI pump motor without venting. Again, a no flow

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condition developed: however, this time it occurred on the outboard side

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motor cooler.

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The licensee determined that the original no flow condition was probably

the result of air introduced into the system during maintenance

undertaken to verify plenum baffle plate orientation.

During that

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maintenance. the motor cooler alenum drain plugs were removed and a

small tool was inserted ir.to t1e plenum to determine the orientation of

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the internal baffle plate.

The drain plug was then reinstalled.

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this. activity, small amounts of water drained from the isolated motor

coolers. Air )otentially introduced into the system during this

activity then

3ecame trapped in the return )iping of the motor cooler.

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After the cooler was returned to service, t1e resultant flow was not

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enough to sweep the air through the NSCW system.

The licensee

determined that the air binding occurred at the SI pump due to

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configuration of the NSCW piping. The licensee informed the inspectors

that the other emergency core cooling system pumps have a different

piping configuration and may not be susceptible to the air binding

phenomenon.

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Procedures 13150-1 and 13150-2. Precautions and Limitations section.

provided instructions to operations personnel to thoroughly vent all

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isolated NSCW supplied components prior to returning them to service.

This action would minimize the potential for system performance

degradation due to air entrapment.

Based on observations and

discussions with the licensee the inspectors concluded that following

this maintenance, operations personnel did not vent the isolated NSCW

supplied components prior to restoration.

During discussions with

operations management, the licensee acknowledged that guidance was not

provided to operators to vent affected components following this

maintenance. The licensee indicated that draining, filling and venting

a system is " skill of the craft" and that specific guidance to perform

these activities was unnecessary. The operations shift crew supervision

stated that support of the maintenance activity to isolate NSCW supplied

components did not constitute draining the system, therefore, no formal

process to install a clearance and restore the system to service was

coordinated for the operations activities.

Upon identification of the no flow condition on December 18. the

licensee took a)propriate immediate corrective action to vent other NSCW

components whic1 could have been affected. The licensee stated their

intention to counsel operations personnel involved regarding their

methods used to isolate and return systems to service following

maintenance activid os.

The licensee also )lans to review NSCW system

operation to determine if air is presently ]eing entrained and if

further venting is required.

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Enclosure

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c.

Conclusions

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The inspectors concluded that although this activity is considered by

the licensee to be a " skill of the craft" activity. the guidance.

instructions, or training which is provided to operations personnel must

be sufficient to ensure that equipment remains operable.

The inspectors also concluded that the no flow condition in the SI

pump 2A probably resulted from air introduced into the NSCW piping

following maintenance as a result of the pump being returned to service

without being properly vented.

This is contrary to the Precautions and

Limitations of Procedures 13150-1 and 13150-2.

However, consistent with

Section VII of the NRC Enforcement Policy this was identified as

Non-Cited Violation (NCV) 50-425/96-14-01. NSCW Motor Cooler Not Vented

Prior To Being Returned To Service.

02.2 Unit 2 Diesel Generator (DG) Air Start Block Valve Stickina Ooen

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a.

Insoection Scooe (71707)

The inspectors reviewed an inadvertent, partial depressurization of the

Unit 2 train A DG air receiver tank number 2 which occurred as a result

of an air start block valve that failed to shut. This review included:

the deficiency card (DC) written in response to the issue:

Procedure 25021-C. Coating: the MWO associated with troubleshooting the

suspect solenoid valve: Updated Final Safety Analysis Report (UFSAR)

Section 9.5.6. DG Starting System: and commitments /open items written

against Procedure 25021-C.

The inspectors discussed this issue with the

plant maintenance and modifications managers. licensing department

personnel, and operations management.

b.

Observations and Findinas

On December 18. 1996, while starting the Unit 2 train A DG. air receiver

number 2 was depressurized to approximately 80 pounds per square inch

gauge (psig) as a result of a malfunctioning solenoid valve. This

resulted in the air start block valve remaining open after the diesel

had started.

The solenoid valve malfunctioned as a result of paint

blocking a vent port on the valve.

The operator at the diesel took

immediate corrective action to stop the inadvertent depressurization by

isolating the air receiver.

As a result of this isolation, the number 2 air receiver tank was not

available to provide supplemental starts to the DG if required. The

UCSAR states that each air receiver contains sufficient air to start the

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diesel at least five times.

The DG remained operable since the number 1

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cir receiver tank was available during the post-event maintenance

activities.

Following replacement of all four vent ports on the train A

DG the licensee returned the number 2 air receiver tank to service.

The restoration to normal operating pressure was performed without

Enclosure

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incident.

Upon identification of the solenoid vent port plugging, the

licensee conducted a walkdown of the other DGs.

No other similar

discrepancies were identified.

The inspectors determined that on November 7, 1996, painting personnel

were given approval 'to commence painting the Unit 2 train A DG.

Painting was finished on December 3.1996.

Procedure 25021-C contains a coating request form (CRF) that is used to

identify and authorize )aintwork and review its potential impact on

plant equipment. A wal(down using the CRF is normally performed by the

plant modification group and operations personnel prior to beginning

work.

However, in this case, operations supervision informed the

inspectors of their assumption that the painting to be performed on the

Unit 2 train A DG was routine in nature and, therefore. did not.

necessitate a CRF-specific walkdown. The inspectors also determined

that no special instructions were given to the painters prior to the

painting activity.

The inspectors identified that earlier revisions of the CRF included a

more descriptive checklist of items to be reviewed prior to painting.

In particular, the checklist in Revision 12 of Procedure 25021-C.

included a specific step to assess instrument and control (I&C)

equipment to be painted and masked including vent ports.

This step,

and several others, were deleted during subsequent revisions. The

licensee was unable to provide justification to the inspectors for the

deletion of

avious details of the earlier CRF.

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As correcti.

aon. the licensee stated their intention to:

revise

the Procedure 25021-C CRF checklist to require a more comprehensive

pre-painting walkdown, require the system engineer to participate in a

walkdown of the items / areas to be painted, and provide a basic

mechanical systems class to onsite painters to aid in their

understanding of the type of equipment their efforts could impact.

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Conclusions

The inspectors concluded that the painters did not have adequate

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procedural guidance to address potential issues with painting, such as

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obstruction of vent ports.

This lack of procedural guidance. coupled

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with the lack of a pre-painting walkdown resulted in mis-applied paint

which impacted the operation of a portion of the DG 2A starting air

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system.

This is contrary to the requirements of 10 CFR 50. Appendix B.

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Criterion V. Instructions. Procedures, and Drawings. which specifies

.that activities affecting quality be prescribed by documented

instructions and procedures.

However, consistent with Section VII of

the NRC Enforcement Policy this was identified as NCV 50-425/96-14-02.

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Inadequate Procedure Results in Loss of One Train of Starting Air for

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the Unit 2 DG Train A.

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Enclosure

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02.3 Unlocked DG Air Start Receiver Discharae Isolation Valve

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a.

Insoection Scone (71707)

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The ins)ectors reviewed the circumstances surrounding valve

2-2403-J4-765. Unit 2 DG A Air Start Receiver Number 1 Discharge

Isolation Valve, being discovered open and unlocked.

(This valve is

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normally open and locked.) This review included interviews of operators

responsible for the last manipulation of the valve: review of the

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Safety-Related Locked Valve Manipulation Log Sheet of Procedure 11888-C

)re)ared for that manipulation: and Procedure 11867-2. Safety-Related

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_octed Velve Verification Checklist. The inspectors also reviewed the

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DC generated for this issue.

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Observations and Findinas

On December 30, 1996, during a routine tour, the inspectors observed

that valve 2-2403-U4-765 was o)en with a chain and unlocked padlock

attached. The unlocked padloc( was through both sides of the chain.

After verification of this observation by operations personnel, the

padlock was closed, as required.

The licensee generated a DC in

response to the issue. This valve is the DG 2A air receiver number 1

discharge isolation valve and, per Procedure 11867-2. is a normally

locked open valve.

The valve position and lock status were last verified following

maintenance troubleshooting on the engine on December 19. 1996. The

initial restoration and independent verification were documented on a

Procedure 11888-C. Safety-Related Locked Valve Manipulation. Log Sheet.

Two operators signed the data sheet indicating that the valve was locked

open and independently verified in that position.

During interviews, the operators described the method they used to

verify the valve's position and status of its lock. The inspectors

noted that their descriptions were consistent, plausible, and in

accordance with valve verification practices observed by the inspectors

on previous occasions. The inspectors also noted from reviewing

security access records, that both operators were in the appropriate

DG room about the time the verifications were documented as complete.

The inspectors noted that neither individual could recall pulling on the

lock during the positioning or verification to verify that the lock

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remained locked.

The inspectors noted that though the valve was unlocked, it was in the

proper position.

Hence, not locking the valve did not impact the

operability of the DG.

Enclosure

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c.

Conclusions

The safety consequence of not maintaining valve 2-2403-U4-765 locked, as

required by Procedure 11867-2. was minimal. However, this represents

another example of a configuration control deficiency identified by the

inspectors as well as a failure of the two-party verification system.

This was identified as an example of an apparent violation

EEI 50-424.425/96-14-03. Configuration Control Deficiencies Involving

Mispositioned Components and Improper Independent Verification.

02.4 Misoositioned Jumoer For Thermal Overload Device

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a. Insoection Scooe (71707)

The inspectors conducted walkdowns of the accessible portions of the

Units 1 and 2 SI systems. This included in-plant and control room

verification of component positioning and operability; a review of the

UFSAR: comparison of selected technical specification (TS) requirements

and their associated surveillance procedures: and verification of

licensee lineup procedures against system drawings.

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Observations and Findinas

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housekeeping were good. quipment operability, material condition and

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The inspectors noted several minor administrative differences between

lock status as specified in Procedures 11105-1 and 11105-2. Safety

Injection System Alignments, and the system drawings. These did not

impact system operability and in all cases the components were found to

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be in the correct position.

These were identified to the licensee for

resolution.

On January 9, 1997, during a walkdown of the 480-Volt breaker enclosures

of four Unit 1 SI system valves, the inspectors identified that a jumper

installed in the control circuit of valve 1-HV-8802A, SI Pump A to Hot

Leg 1 and 4 Isolation Valve, was improperly positioned.

Thejumperwas

installed between breaker terminal points "14" and "W1."

This jumper is

provided as the thermal overload protection bypass device required by

TS 3.8.4.2 and should have been installed between breaker terminal

points "15" and "W1." As a result of this mis-wiring, the thermal

overload protection device for the breaker was not by>assed.

TS 3.8.4.2

requires that the thermal overload protective device 3e bypassed

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whenever the valve is required to be operable.

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accomplished, the action statement requires that the valve be declared

inoperable and the appropriate action statement for the valve be

entered.

TS 3.5.2 ap) lies to this valve as part of the SI system and

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specifies actions witlin 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if the valve is inoperable.

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Enclosure

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Following confirmation of this observation, the licensee declared the

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valve inoperable and restored the jumper to the correct position later

that day.

The following day, operators conducted a walkdown of a

portion of the Unit 1 breakers specified in TS 3.8.4.2 and found no

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other configuration problems.

On January 13. the licensee commenced

Surveillance Procedure 28905-C. Motor Operated Valve Thermal Overload

Bypass 18 Month Verification, to verify the jumper positions for

breakers specified in TS 3.8.4.2.

Based on a review of MWO 19600079 and interviews of the appropriate

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maintenance personnel, the inspectors determined that maintenance on the

breaker, requiring lifting and restoring the jumper, was last performed

on March 28, 1996.

The lifting and restoration of the jumper were

accomplished in accordance with Procedure 20429-C. Short Term

Documentation of Temporary Jumpers and Lifted Wires.

This included an

independent verification of the restoration of the jumper to the

recuired terminal location.

Both the initial positioner and the

incependent verifier annotated on a lifted lead form that the wire had

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been properly restored.

When interviewed by the inspectors. neither

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technician could describe anything particularly noteworthy about the

restoration of this particular jumper that would have prevented landing

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it in the correct location.

They did indicate that the terminal block

cover which had the terminal labelling annotated on it, had to be

removed to connect the jumper.

However, the inspectors were informed

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that the cover would only reattach in'the correct position.

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indicated that they were surprised by the discovery of the mispositioned

jumper.

Their descriptions of their implementation of the lifted lead

procedure were consistent with inspector observations of this practice

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in the past.

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The effect of the mispositioned jumper was to restore the thermal

overload device into the breaker control circuit. A review of the

wiring diagram and examination of the breaker cubicle by the ins)ectors

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indicated that there were no other implications as a result of tie

improper jumper installation.

The licensee informed the inspectors that

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the valve was satisfactorily dynamically tested with the thermal

overload in the circuit in May 1993 and statically tested with the

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thermal over!oad in the breaker control circuit in March 1996, again

without incident. At the time of discovery, the inspectors verified

that the thermal overload device was set at the setpoint specified by

the licensee's procedure.

The inspectors noted from their review of the emergency o)erating

procedures (E0Ps) that valve 1-HV-8802A is used when esta)lishing hot

leg recirculation following a loss of coolant accident. The other SI

pump is provided with its own hot leg injection valve.

Additionally,

the E0P for hot leg recirculation provides actions which are to be taken

if the SI train A hot leg recirculation flow path cannot be established.

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Enclosure

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c.

Conclusion

This mis-positioning represents another example of a configuration

control deficiency identified by the inspectors as well as a failure of

the two-party verification system.

This also represents another

instance involving the improper implementation of the lifted lead form

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documented by the inspectors in the last 18 months. The inspectors

concluded that the failure to proaerly install the thermal overload

protection by) ass device between iarch 28, 1996 and January 9. 1997 was

contrary to t1e requirements of TS 3.8.4.2 and 3.5.2.

This was

identified as an example of an apparent violation EEI

50-424.425/96-14-03. Configuration Control Deficiencies Involving

Mispositioned Components and Improper Independent Verification.

02.5 480-Volt MCC Soare Breakers Miscositioned

a.

Insoection Scooe (71707)

The inspectors compared actual breaker positions on motor control

centers-(MCCs) 1BBE and 2BBE with the required positions s)ecified in

Procedures 11429-1 and 11429-2, 480-Volt AC 1E Electrical )istribution

System Alignments,

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Observations and Findinos

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On January 19, 1997, the inspectors conducted a walkdown of the 480-Volt

breakers on MCCs 1BBE and 2BBE.

All load equipped breakers were

]roperly positioned.

However, the inspectors noted that between the two

iCCs. fifteen breakers labelled as spares were improperly positioned.

Specifically Procedures 11429-1 and 11429-2 require that spare breakers

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be shut unless tagged.

In fact. the inspectors observed that these

fifteen spare breakers were open and untagged.

The inspectors confirmed from a review of the one-line diagrams for the

two MCCs. that the open breakers were in fact spares and not connected

to loads. Additionally. the inspectors reviewed the clearance database

and determined that the spare breakcrs were not under clearance when the

lineups were last completed.

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The last performances of the 1E system alignments were reviewed (Unit 1

- April 1996 and Unit 2 - February 1995). The Unit 2 alignment clearly

indicated that all spare breakers were closed at that time. The Unit 1

breaker alignment is less clear in that no initials are contained in the

procedure blanks for the "ALL OTHER BREAKERS" entry.

However, the two

clearance exceptions provided in these blanks do not relate to spare

breaker clearances.

The licensee informed the inspectors that their subsequent review of the

breaker alignments of other 1E MCCs yielded similar inconsistencies in

the alignment of spare breakers.

Enclosure

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c.

Conclusion

The inspectors concluded that while the safety consequence of the

fifteen spare breakers being open on 1BBE and 2BBE was minimal, it

represented another example of an NRC identified configuration control

deficiency. Accordingly. the failure to properly position the spare

breakers on MCCs 1BBE and 2BBE in accordance with the requirements of

Procedure 11429-1 and 11429-2 is identified as an apparent violation

EEI 50-424.425/96-14-03. Configuration Control Deficiencies Involving

Mispositioned Components and Improper Independent Verification.

03

Operations Procedures and Documentation

03.1 Identification Of Potentially Inadeouate Surveillance Testina Of Turbine

Trio From Reactor Trio (P-4 Interlock)

a.

Insoection Scooe (71707)

The inspectors reviewed the circumstances regarding the licensee's

identification of potentially inadequate testing of the turbine tiip

from reactor trip circuit (P-4 interlock).

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The ins)ectors reviewed operator log entries regarding this issue.

a) plica)le TSs. and the associated DC. The review by the inspectors of

t1e surveillance procedures subsequently used to test the affected

circuits is documented in Section M3.1 of this report.

b.

Observations and Findinos

At 5:00 p.m. on January 22, 1997, the licensee entered TS 3.0.3 on both

units in response to their identification of potentially inadequate

surveillance testing used to demonstrate the operability of the turbine

trip from reactor trip circuit.

This testing is used to demonstrate

operability of this P-4 circuitry in accordance with the requirements of

TS 3.3.2 Functional Units 5.b.2 and 9.b. Reactor Trip. P-4.

The licensee invoked the provisions of TS 4.0.3.

This allows delay of

action requirements, with a duration of less than one day. for up to 24

hours to permit completion of a surveillance which has not been

performed within the allowed surveillance interval.

The following day, after comaletion of the surveillance of the A train

)ortion of these circuits, t7e licensee exited TS 3.0.3 at 8:29 a.m. on

Jnit 1 and at 9:47 a.m. on Unit 2.

Testing of the respective B trains.

and exiting the remaining TS 3.3.2. was completed at 11:43 a.m. on

Unit 2 and 2:43 p.m. on Unit 1 on January 23, 1997.

Enclosure

~ _ . _ . _ _ _ _ _ _ _ _ _ _ _

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_ _ _ _ _ . - .

,

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4

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10

)

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c.

Conclusion

l

!

The review of this issue by the inspectors was ongoing at the end of the

j

report period.

Pending additional review, this is identified as

j

Unresolved Item (URI) 50-424.425/96-14-06. Potentially Inadequate

Surveillance Testing of P-4 Circuitry.

03.2 Walkdown of Clearances (71707)

The inspectors walked down the following clearances:

29600433

Chemical and volume control system (CVCS) positive

!

displacement pump (PDP): repair stuffing box leak

i

29600437

CVCS Centrifugal Charging Pump (CCP) train A; repair

oil leak and speed increaser

.

29700049

Post accident sampling system backflush waste to fuel

handling building drains: repair valve 2-1212-U4-125

b.

Observations and Findinaq

The inspectors did not identify any problems or concerns with the

clearances.

j

08

Miscellaneous Operations Issues (71707)

08.1

(Closed) Insnector Follow-uo Item (IFI) 50-424/96-03-03: Mispositioned

l.

Auxiliary Building Drain Valve

This item documents an improperly positioned Unit 1 auxiliary building

drain valve discovered by the 1acensee following inspector questions on

,

the positioning of the same val >e in Unit 2.

l

,

The inspectors reviewed the acticas taken by the licensee in response to

this finding identified by SAER. The ins)ectors have not identified any

I

other mispositioned drain valves during t1eir routine inspection.

This

i

valve is not safety-related.

Bssed on this review, this item is closed.

II.

Maintenantg

M1

Conduct of Maintenance

M1.1 Maintenance Work Order (MWO) Observations

a.

Insoection Scope (62707)

,

i

!

The inspectors observed portions of maintenance activities involving the

i

following work orders:

!

Enclosure

-.

.

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.-

-.-

--

. - -

..

.

_-

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11

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19700027

Reactor trip breaker train A springs would not charge

l

after being tripped open

29600433

Chemical and Volume Control System (CVCS) Positive

Displacement Pump (PDP) repair stuffing box leakage

1

29600437

CVCS Centrifugal Charging Pump (CCP) investigate /

'

repair oil leak

29603144

Unit 2 CCP train A speed increaser gearing and bearing

change out

b.

Observations and Findinas

The observed maintenance activities were performed satisfactorily.

M1. 2 Surveillance Observation

i

a.

Insoection Scoce (61726)

The inspectors observed the performance of or reviewed the following

surveillances and plant procedures:

14420-1

Solid state protection system (SSPS) and reactor trip

breaker train A operability test

14421-2

SSPS and reactor trip breaker train B operability test

!

14475-1

Containment integrity verification - valves outside

containment

14485-2

Containment spray system flow path verification

i

14546-1

Turbine driven auxiliary feedwater pump operability

test

,

'

b.

Observations and Findinas

The observed surveillance activities were performed satisfactorily.

1

M2

Maintenance and Material Condition of Facilities and Equipment

M2.1 CCP ?A Soeed Increaser Bearina Failure

a.

Insoection Scope (62707)

!

l

The inspectors reviewed maintenance on the Unit 2 train A CCP speed

increaser following the licensee's entry into a 72-hour limiting

condition for operation (LCO) on the pump on December 27. 1996.

This

review included MWO 29603144. Unit 2 CCP Train A Speed Increaser Gearing

,

Enclosure

.

. _ _ _ _

_ _ _ _

_ _ _ .

. . __.

_

12

l

and Bearing Change Out, and MWO 29700025. Thrust Head Socket Plate

'

l

Torquing: Vendor Manual 2X6AH02-85. Charging / Safety Injection Manual:

l

Procedure 27115-C. Westinghouse SU-1023-8X5 Speed Increaser: and

l

Deficiency Card (DC) 2-97-003.

l

b.

D.bservations and Findinas

On December 27, 1996, the Unit 2 train A CCP experienced a journal

l

bearing failure on the pump end of the high speed shaft of the speed

increaser.

Subsequently, a high speed gear seal failed that resulted in

a loss of lubricating oil. This allowed lubricating oil to spray into

'

the pump room causing smoke when the oil came in contact with the hot

metal of the speed increaser.

At approximately 5:55 a.m. a fire alarm

was received in the main control room for the CCP train A pump room.

l

Operators stopped the train A pump at approximately 6:00 a.m. and

i

swapped operation to the CCP train B pump without incident. At

6:00 a.m. operations entered a 72-hour LC0 to disassemble and repair the

!

inoperable CCP.

Maintenance replaced all speed increaser rotating

components, bearings, and oil seals including the main oil pump. At

3:28 a.m.. on December 30,1996, the LC0 was exited following com)letion

l

of maintenance activities and restoration of the pump to an opera)le

'

status.

1

,

On January 6,1997, during the MWO 29603144 closure review, a quality

control inspector identified that the thrust plate cap screws were not

installed as required per the vendor manual.

Vendor manual 2X6AH02-85

was included as an attachment to MWO 29603144 work instructions and

!

!

contained a drawing of the s

General Assembly SU-1023-8. peed increaser. On that drawing. 1930012.

a note provided instructions to install the

thrust plate cap screws with a locking compound and to torque the cap

screws to 50-60 foot-pounds.

During the performance of the MWO. a

locking com

reassembly. pound was not used nor were the cap screws torqued during

The CCP 2A's speed increaser was reworked under MWO 29700025. The MWO

i

required work description addressed the proper installation of the cap

'

screws. including torquing and locking compound requirements.

During

review of the MWO instructions, maintenance personnel ide~ified an

l

additional requirement on the speed increaser drawing for the use of

lockwire during the spray nozzle hardware installation. This also had

,

not been performed prior to returning the pump to an operable condition.

!

On January 7. the rework activity was completed and the CCP 2A was

declared operable after a successful functional test.

U)on identification of the inadequately torqued thrust plate cap screws

tie licensee initiated DC 2-97-003 and performed an engineering

evaluation.

Results of engineering evaluation REA-VE-3100 & X6AH02.

Thrust Plate Screw Torque Evaluation, indicated that based on the

,

as-found condition of the pump speed increaser. CCP 2A may have

eventually failed if required to provide long term cooling. The

Enclosure

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13

engineering evaluation concluded that the pump was operable, but in a

degraded condition.

c.

Conclusions

Based on this review, the inspectors concluded that the corrective

actions taken by the licensee to address the identified deficient

conditions were adequate and performed in a timely manner.

In addition,

the licensee has submitted a revision to Procedure 27115-C to include

the torquing and lockwire issues discussed above.

The inspectors

concluded that these actions were adequate to prevent recurrence.

The inspectors concluded that the improper installation of the thrust

plate cap screws was the result of a failure to properly follow MWO and

vendor manual instructions.

Failure to properly follow instructions

during performance of MWO 29603144 was contrary to the requirements of

Technical Specification (TS) 6.7. Procedures and Programs.

However,

consistent with Section VII of the NRC Enforcement Policy this was

identified as non-cited violation NCV 50-425/96-14-04. Failure to

Implement Work Instructions For Unit 2 CCP 2A Speed Increaser.

The inspectors also concluded that the identification of the missed

4

'

steps in the reassembly of the speed changer were examples of good

attention to detail.

M3

Maintenance Procedures and Documentation

'

M3.1 Testina of Reactor Trio Inout to Turbine Trio Loaic

l

a.

Insoection Scope (61726)

The inspectors reviewed the procedures used to test the reactor trip

input to the turbine trip logic (P-4 interlock).

Specifically, the

inspectors reviewed the following:

Procedure 14420-1

SSPS and Reactor Trip Breaker Train A

Operability Test

Procedure 14420-2

SSPS and Reactor Trip Breaker Train A

Operability Test

Procedure 14421-1

SSPS and Reactor Trip Breaker Train B

Operability Test

Procedure 14421-2

SSPS and Reactor Trip Breaker Train B

Operability Test

The inspectors also witnessed performance of Procedure 14421-2.

Enclosure

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14

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b.

Observations and Findinas

The conduct of the' testing witnessed by the inspectors was satisfactory.

Step 3.9 of Procedures 14420-1, 14420-2, 14421-1 and 14421-2 originally

l

contained a precaution and limitation that stated:

"This procedure

i

shall be performed by licensed personnel only." However. Procedures

j

14421-1 and 14421-2 were changed on January 23, 1997. using )en and ink,

to modify this step to:

"This procedure shall be performed )y or under

the direction of licensed personnel only."

When questioned, the approving authority for the change, the Shift

i

Superintendent (SS). described three basic reasons behind his changing

!

this precaution and limitation. These were:

-

Only 4 reactor operators (R0s) were available on shift that

day. Given the critical nature of the surveillance and the

l

possibility of a plant trip, he stated his desire to

l

maintain 2 R0s on each unit.

i

He stated his desire to involve Plant Equipment Operators

-

(PE0s) in the manipulation of plant equipment. He described

his intention that the participation of the PE0 be directly

supervised by a senior reactor operator (SR0).

-

The SS also indicated that his review revealed that there

!

were no commitments or bases behind the requirement to use

only licensed personnel to perform these procedures.

The inspectors observed from their review of the completed Procedure

14420-2. that a PE0 had initialled for completing several steps.

.Primarily, these ste)s-involved manipulation of the reactor trip bypass

breaker.

However, t1e Step 3.9 precaution and limitation had not been

changed in 14420-2 to allow performance of the surveillance by other

than licensed personnel.

When questioned on this apparent discrepancy, the SS stressed to the

inspectors that the PE0 was under the direct supervision of an SR0

during his work on the surveillance.

Likewise, similar comments,

stressing the involvement of an SRO in overseeing and directing the

actions of the PEO. were made by other members of the operations

management organization during the inspection of this issue. The

Operations Manager informed the inspectors that a PE0 accomplishing the

procedure under the supervision of an SRO was an acceptable combination

and more than met the intent of the procedure.

He further stated that

this exceeded the standard of a having a licensed operator perform the

procedure.

The licensee also pointed out that the testing was

successfully accomplished using the PE0 with SR0 supervision.

Notwithstanding arguments to the contrary, the inspectors concluded that

i

j

Enclosure

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.

.

15

the PE0 who' accomplished the actions of the statement and initialed the

procedure was performing the steps.

?

The inspectors also observed that the changes to Step 3.9 in

i

Procedures 14421-1 and 14421-2 were initialled by the approving

j

authority for the change, the SS.

The inspectors were concerned that

the approving authority making changes during his review could bypass

,

the required reviews.

When questioned on this, the SS acknowledged

making the changes prior to implementation of the procedures.

He stated

j

that the procedures were subsequently reviewed by the respective Unit

!

Shift Supervisors (USSs).

Both USSs stated to the inspectors that they

!

reviewed Step 3.9 in the procedure following the change by the SS.

j

However, neither the quality reviewer nor the change originator reviewed

the change to Step 3.9 after the SS made his change to the procedure.

The inspectors identified that the reviews performed by the USSs. were

not documented in accordance with the licensee *s administrative process

for procedure changes. Procedure 00051-C. Procedure Review and Approval.

i

The inspectors identified from a review of the USS logs, that plant

staffing exceeded TS requirements on the day these surveillances were

s

performed.-

c.

Conclusions

The inspectors concluded that having a PEG perform steps within

!

Procedure 14420-2. was contrary to the requirements of Step 3.9 of that

!

procedure.

In addition, the failure to document the reviews of changes

!

made to Step 3.9 of Procedures 14421-1 and 14421-2 was not in accordance

with the requirements of Procedure 00051-C. Procedures Review and

i

Approval. These are identified as two exam)les of a minor violation for

i

failure to properly im)1ement procedures.

iowever consistent with

l

.

Section IV of the NRC Enforcement Policy this was identified as

!

NCV 50-424.425/96-14-05. Failure to Implement Procedures During P-4

l

Testing. Two Examples.

!

III.

Enaineerina

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E7

Quality Assurance in Engineering Activities

l

E7.1 Failure Analysis of the Unit 2 Charaina Pumo Soeed Increaser Bearinas

,

a.

Insoection Scooe (37551)

i

!

The inspectors followed the licensee's engineering event review team

!

efforts involving the Unit 2 train A Centrifugal Charging Pump (CCP)

speed increaser bearing failure that occurred December 27. 1996. The

)

inspectors observed portions of the event review team's root cause and

{

corrective action determination: reviewed event report 2-96-06. Bearing

l

Failures in Speed Increaser for Centrifugal Charging Pump 2A: the

l

Enclosure

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+

_ _ ..._. _ _

_ __._ _ _ _ __ _ _ . _ _ _ .. _ _ _ .

(

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16

I

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Deficiency Card (DC) generated in response to the event: personnel

statements; and auxiliary building rounds sheets (that monitor lube oil

)

temperatures). The inspectors also had discussions with engineering and

maintenance management. in addition to corporate engineering vibration

i

experts. as to their investigation and findings based on the

i

circumstances surrounding this event.

b.

Observations and Findinas

A detailed event description is provided in section M2.1 of this report.

i

Based on the facts and evidence as a result of this event. the licensee

l

theorized that the CCP 2A speed increaser bearing failure occurred due

to metal fatigue as a result of one of two causes. The first failure

i

theory was a shortened service life resulting from harsher than expected

i

conditions (i.e.. higher dynamic loading, and number of unlubricated

l

starts) which ultimately resulted in the failure of the journal bearing.

,

The second proposed theory was that the failure was due to misalignment

i

between the motor and the speed increaser. This latter theory was

supported by the need to realign the motor to the speed increaser during

'

repair activities.

The event review team also determined that the quarterly Preventive

Maintenance (PM) program performed was lacking, in that the program was

unable to provide warning of the bearing's imminert failure >rior to the

,

event.

The current PM performed on the CCP requires pump vi) ration

'

measurements and a lubricating oil analysis.

The PM was last performed

on December 17, 1996.

PM results indicated normal (acceptable)

measurements.

Corrective actions recommendations developed and adopted by plant-

!

management included:

further analysis of the damaged high speed gear to

!

determine its failure mode mechanism: installation of temperature

sensors on the speed increaser gear box and proximity vibration sensors

on gear box shafts to improve vibration data collection: and to perform

i

a gear box bearing and gear inspection after additional data collection

-has been performed.

r

c.

Conclusions

-

The ins)ectors concluded that the engineering event review team did a

thorougl job in exploring possible contributors to the event. The

planned examination of the damaged CCP 2A s)eed increaser should assist

in conclusively determining the failure meclanism.

The event review

team appropriately consulted outside personnel (i.e.. pump vendor and

vibration experts) in an effort to determine the root cause(s).

The

inspectors also concluded that the licensee's )lanned corrective actions

'

to address the deficiencies identified in the )M program were

appropriate.

t

Enclosure

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17

The team's effort to determine the root cause of the event is identified

as a strength.

E8

Hiscellaneous Engineering Issues (37551)

E8.1 (Closed) Licensee Event Report (LER) 50-424/96-001 Revision 1: Pipe

Fatigue Leads To Nuclear Service Cooling Water System Inoperability.

This issue was documented in Inspection Report 96-01 (paragraph 2.4) and

Inspection Report 96-02 (paragraph 4.5).

The original LER was closed in

4

Inspection Report 96-03 (paragra>h 4.2).

This revision to the LER

updates information related to tie licensee's corrective action.

No new

issues were revealed by this revision to the LER.

This item is closed.

E8.2 NRC Notification For Condition Outside The Desian Basis

a.

Insoection Scoce (37551. 90712)

At 5:39 p.m. on January 21, 1997, the licensee made a one-hour

'

non-emergency notification to the NRC in accordance with the

requirements of 10 CFR Part 50.72 (b)(1)(ii)(B). condition outside the

design basis of the plant.

The licensee's notification stated that

portions of the Nuclear Service Cooling Water (NSCW) system and several

containment penetrations had been determined to be outside their design

basis,

b.

Observations and Findinas

When advised of the pending notification. the inspectors responded to

the site and reviewed the basis for the licensee's notification. The

inspectors also reviewed the issue with the Manager of Engineering

Support and one of his direct reports. Additionally. the inspectors

'

discussed the licensee's planned strategy for compensatory actions with

the Shift Supervisor (SS).

The licensee's notification was based on the results of reviews

conducted in response to NRC Generic Letter 96-06. Assurance of

Equipment Operability and Containment Integrity During Design Basis

Accident Conditions. As a result of their review, the licensee

preliminarily determined that portions of the NSCW system may be

susceptible to water hammer during certain design basis events. The

inspectors were informed that a hydraulic transient analysis indicated

that during the potential water hammer, some postulated stresses in the

system exceeded American Society of Mechanical Engineering (ASME) code

values.

However, the licensee informed the inspectors that the NSCW

system would stay intact and capable of performing its intended safety

function.

Enclosure

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.

.

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18

During the same review, the licensee also postulated that thirty

containment penetrations, fifteen in each unit. could be susceptible to

thermally induced over)ressurization of water filled, isolated piping

inside containment.

T1e inspectors were informed that subsequent

analysis indicated that twenty-six penetrations would either relieve any

overpressurization through an isolation valve, due to the isolation

valve designs or would remain capable of performing their intended

safety function.

For the four remaining penetrations. the licensee

added caution tags to ensure that the system was operated so as to

prevent any overpressurization of the penetrations during a design basis

event.

On February 14, 1997, this one-hour emergency notification

report was withdrawn.

IV.

Plant Sucoort

R8

Miscellaneous Radiological Protection and Chemistry (RP&C) Issues

(71750)

R8.1

(Closed) Licensee Event Report (LER) 50-425/96-004: Water Sample Not

Taken For Isotopic Analysis Following Power Change.

This issue was previously documented as non-cited violation (NCV)

50-425/96-09-04 in paragraph R2.3 of Inspection Report 96-09.

The

inspectors reviewed the corrective actions identified in the LER and

concluded they are sufficient.

No new issues were raised in the LER.

This LER is closed.

51

Conduct of Security and Safeguards Activities (71750)

S1.1 Routine Observations of Plant Security Measures

During routine inspection activities the inspectors verified that

portions of site security plan were being pro)erly implemented. This

was evidenced by:

proper display of picture Jadges by plant personnel:

l

appropriate key carding of vital area doors: proper searching of

,

packages / personnel at the Protected Area (PA) entrance; and adequacy of

'

compensatory measures (i.e. . posting of guards) during disablement of

vital area Parriers.

Security activities observed during the inspection

i

period were well performed and appeared adequate to ensure physical

protection of the plant. Guards were observed to be alert and

attentive.

Enclosure

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]

S2

Status of Security Facilities and Equipment

}

S2.1 Walkdown of PA Barriers

a.

Insoection ScoDe (71750)

3

Using Procedure 71750. Plant Support, the inspectors walked down the PA

i

barriers to observe the general condition and verify that the integrity

[

of the fencing and isolation zones around the barriers was maintained.

b.

Observations and Findinas

,

4

i

On January 30 and 31. 1997, the inspectors reviewed the integrity of the

PA barrier.

In general, the fence fabric and barbed wire were in

satisfactory condition.

The isolation zones were well maintained and

clearly posted.

However, during these walkdowns the inspectors

j

identified several minor discrepancies in the material condition of the

i

PA boundary. These items were identified'to security management' for

j

resolution.

i

c.

Conclusions

.

i

The inspectors concluded that for the most 3 art, the general condition

'

of the fencing and isolation zones around t1e PA was being properly

maintained except as noted above.

The inspectors noted that although

minor discrepancies were identified, none of the items represented a

regulatory non-compliance.

V.

Manaaement Meetinas

X

Review of Final Safety Analysis Report

A recent discovery of a licensee operating its facility in a manner

i

contrary to the Updated Final Safety Analysis Report (UFSAR) description

i

highlighted the need for a special focused review that compares plant

practices, procedures and/or parameters to the UFSAR descriptions.

While performing the inspections discussed in this report. the

inspectors reviewed the applicable portions of the UFSAR that related to

the areas inspected. The inspectors verified that the UFSAR wording was

'

consistent with the observed plant practices, procedures and/or

parameters.

X1

Exit Meeting Summary

The inspectors ) resented the inspection results to members of licensee

management at tie conclusion of the inspection on February 6.1997. The

licensee acknowledged the findings presented.

l

Enclosure

_ _ _

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____.m.

.

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.

20

The inspectors asked the licensee whether any materials examined during

the inspection should be considered proprietary.

No proprietary

information was identified.

PARTIAL LIST OF PERSONS CONTACTED

i

Licensee

J. Beasley. Nuclear Plant General Manager

P. Rushton. Plant Support Assistant General Manager

W. Burmeister Manager Engineering Support

M. Griffis. Manager Plant Maintenance and Modifications

K. Holmes. Manager Maintenance

J

C. Stinespring. Manager Plant Administration

D. Huyck Manager Nuclear Security

M. Slivka. Independent Safety Evaluation Group (ISEG) Supervisor

C. Tippins, Jr., Nuclear Specialist I

INSPECTION PROCEDURES (IPs) USED

'

i

IP 37551:

Onsite Engineering

IP 61726:

Surveillance Observations

i

IP 62707:

Maintenance Observations

IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

!

IP 90712:

In-Office Review of Written Reports of Nonroutine. Events at Power

.

Reactor Facilities

l

REFERENCED PROCEDURES AND DRAWINGS

Procedures 11429-1. Rev. 7. and 11429-2. Rev. 11, 480-Volt AC IE

'

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Electrical Distribution System Alignments (Units 1 and 2)

1

Procedure 13150-1 Rev. 18. and 13150-2. Rev. 17. Nuclear Service

!

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Cooling Water System (Units 1 and 2)

Procedure 25021-C. Rev. 14. Coating

1

-

Procedure 11888-C. Rev. 8. Safety Related Locked Valve Manipulation Log

-

Sheet

-

Procedure 11867-2. Rev. 20. Safety Related Locked Valve Verification

)

Checklist

Procedures 11105-1 Rev. 16. and 11105-2 Rev. 8. Safety Injection

-

System Alignment (Units 1 and 2)

1

-

Procedure 28905-C. Rev. 12. Motor Operated Valve Thermal Over Load

l

Bypass 18 Month Verification

-

Procedure 20429-C. Rev. 14. Short Term Documentation of Temporary

Jumpers and Lifted Wires

-

Procedure 27115-C. Rev. 7. Westinghouse SU-1023-8X5 Speed Increaser

Enclosure

I

.

.

.

.

21

-

Procedure 14420-1. Rev. 23T. and 14420-2. Rev. 15T. SSPS and Reactor

Trip Breaker Train A Operability Test (Units 1 and 2)

Procedure 14421-1. Rev. 4T. and 14421-2. Rev. 3. SSPS and Reactor Trip

-

Breaker Train B 0)erability Test (Units 1 and 2)

Procedure 00051-C. Rev. 21. Procedure Review and Approval

-

Vendor Manual 2X6AH02-85. 3810-SU-1978. Charging / Safety Injection Manual

-

Drawing 1X3D-AA-F25A Rev. 16. One Line Diagram 480 V Motor Control

-

Center 1BBE

Drawing 2X3D-AA-F25A, Rev. 15. One Line Diagram 480 V Motor Control

-

Center 2BBE

-

Drawing 1X4DB121. Rev. 27. and 2X4DB121. Rev. 32. Safety Injection

System (Unit 1 and 2)

-

Drawing 1X4DB122. Rev. 37. and 2X4DB122. Rev. 35. Residual Heat Removal

System (Units 1 and 2)

l

-

Drawing 1X4DB116-2. Rev. 21. and 2X4DB116-2. Rev. 20. Chemical and

!

Volume Control System (Units 1 and 2)

-

Drawing 1X3AC03-295. Rev.1. Wiring Diagram for Valve 1-HV-8802A

.

l

t

ITEMS OPENED AND CLOSED

j

Ooened

50-425/96-14-01

NCV

NSCW Motor Cooler Not Vented Prior To Being

Returned To Service (Section 02.1).

50-425/96-14-02

NCV

Inadequate Procedure Results in Loss of One

.

Train of Starting Air for the Unit 2 DG Train A

'

(Section 02.2).

50-424, 425/96-14-03

EEI

Configuration Control Deficiencies Involving

Mispositioned Components and Improper

j

Independent Verification (Sections 02.3. 02.4.

and 02.5).

50-425/96-14-04

NCV

Failure to Implement Work Instructions for

Unit 2 CCP 2A Speed Increaser (Section M2.1).

50-424. 425/96-14-05

NCV

Failure to Im)lement Procedures During P-4

Testing. Two Examples (Section M3.1).

50-424. 425/96-14-06

URI

Potentially Inadequate Surveillance Testing of

P-4 Circuitry (Section 03.1).

Enclosure

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.

4

22

Closed

50-425/96-14-01

NCV

NSCW Motor Cooler Not Vented Prior To Being

Returned To Service (Section 02.1).

50-425/96-14-02-

NCV

Inadequate Procedure Results in Loss of One

Train of Starting Air for the Unit 2 DG Train A

(Section 02.2).

50-425/96-14-04

NCV

Failure to Implement Work Instructions for

Unit 2 CCP 2A Speed Increaser (Section M2.1).

50-424. 425/96-14-05

NCV

Failure to Implement Procedures During P-4

Testing. Two Examples (Section M3.1).

50-425/96-004

LER

Water Sample Not Taken For Isoto)ic Analysis

Following Power Change (Section R8.1).

50-424/96-03-03

IFI

Mispositioned Auxiliary Building Drain Valve

(Section 08.1).

50-424/96-001. Rev. 1

LER

Pipe Fatigue Leads to Nuclear Service Cooling

Water System Inoperability (Section E8.1).

LIST OF ACRONYMS USED

AC

- Alternating Current

ASME

--American Society of Mechanical Engineering

CCP

- Centrifugal Charging Pump

CFR

- Code of Federal Regulations

CRF

- Coatings Recuest Form

CVCS

- Chemical anc Volume Control System

DC

- Deficiency Card

DG

- Diesel Generator

EEI

- Escalated Enforcement Item

E0P

- Emergency Operating Procedure

I&C

- Instrumentation and Controls

IFI

- Inspector Followup Item

IP

- Inspection Procedure

LCO

- Limiting Condition for Operation

LER

- Licensee Event Report

'

MCC

- Motor Control Center

MWO

- Maintenance Work Order

NCV

- Non-Cited Violation

NOV

- Notice of Violation

NPF

- Nuclear Power Facility

NRC

- Nuclear Regulatory Commission

NRR

- Nuclear Reactor Regulation

NSCW

- Nuclear Service Cooling Water

NUREG

- Nuclear Regulations

Enclosure

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A

23

PA

- Protected Area

PDP

- Positive Displacement Pump

PDR

- Public Document Room

PE0

- Plant Equipment Operator

PM

- Preventive Maintenance

)sig

- Pounds Per Square Inch Gauge

RG

- Regulatory Guide

RO

- Reactor Operator

RP&C

- Radiological Protection and Chemistry

i

SI

- Safety Injection

SR0

- Senior Reactor Operator

SS

- Shift Superintendert

SSPS

- Solid State Protection System

TS

- Technical Specifications

UFSAR

- Updated Final Safety Analysis Report

URI

- Unresolved Item

USS

- Unit Shift Supervisor

VIO

- Violation

l

l

,

l

Enclosure

_