ML20140B407

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Insp Repts 50-424/97-04 & 50-425/97-04 on 970316-0426. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering & Plant Support & Emergency Preparedness Area
ML20140B407
Person / Time
Site: Vogtle  Southern Nuclear icon.png
Issue date: 05/21/1997
From:
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20140B393 List:
References
50-424-97-04, 50-424-97-4, 50-425-97-04, 50-425-97-4, NUDOCS 9706060204
Download: ML20140B407 (35)


See also: IR 05000424/1997004

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U. S. NUCLEAR REGULATORY COMMISSION (NRC)

REGION II

Docket Nos.

50-424 and 50-425

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License Nos.

NPF-68 and NPF-81

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Report Nos:

50-424/97-04, 50-425/97-04

Licensee:

Southern Nuclear Operating Company. Inc.

Facility:

Vogtle Electric Generating Plant (VEGP) Units 1 and 2

Location:

7821 River Road

Waynesboro. GA 30830

Dates:

March 16 through April 26, 1997

Inspectors:

C. Ogle. Senior Resident Inspector

M. Widmann. Resident Inspector

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

P. Kellogg, Reactor Inspector (Sections M1.5. E8.1. and'

E8.2)

E. Girard. Reactor Inspector (Section E1.3)

R. Cain. Consultant (Section E1.3)

T. Scarbrough, NRR (Section E1.3)

J. Kreh. Radiation Specialist. (Sections P2.1. P2.2. P3.1.

P3.2. PS.I. P6.1, and P7 1)

Approved by:

P. Skinner Chief

Reactor Projects Branch 2

Division of Reactor Projects

Enclosure 2

DOK0500k24

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(D

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EXECUTIVE SUMMARY

Vogtle Electric Generating Plant Units 1 and 2

NRC Inspection Report 50-424/97-04. 50-425/97-04

This integrated inspection included aspects of licensee operations,

engineering, maintenance, and plant support.

The report covers a six-week

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period of resident inspection.

It also includes the results of announced

inspections by a regional inspector in the engineering and a regional

inspector in the Emergency Preparedness area.

Additionally, an assessment of

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the safety related MOV program was made by a regional inspector, an NRR

inspector and a consultant.

Ooerations

In general, the conduct of operations was professional and

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safety-conscious.

However, some isolated instances of control room

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operator performance which represented a minor degradation in control

room demeanor were observed by the inspectors (Section 01.1).

The licensee was successful in controlling debris generated as a result

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of work during the Unit 1 First Planned Outage (IP1).

However, a

violation was identified for debris removed from the Unit 1 containment

with the unit in Mode 4 (Section 01.2).

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An unresolved item was identified for an unplanned negative reactivity

addition that occurred as a result of placing a demineralizer in

service.

Operator recognition of the resultant change in plant

parameters was good (Section 01.3).

The shutdown for IP1 was controlled and in accordance with licensee

procedures. However, distractions resulting from two annunciators

resulted in a level of control room activity greater than that observed

during similar evolutions (Section 01.4).

Maintenance

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Maintenance activities were generally completed satisfactorily (Section

M1.1).

A poor practice regarding a valve removed from a system with a hold tag

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attached was documented (Section M1.3).

A non-cited violation was identified for the licensee procedure for

maintenance on an air damper actuator for the 1A diesel generator

(Section M1.4).

The use of an equivalency determination (ED) to replace handswitch light

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fixtures appeared to be a poor practice as an exception to the

construction specification was required to successfully complete the

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changeout (Section M1.5).

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Enclosure 2

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A non-cited violation was identified for licensee-identified

shortcomings in the testing of the P-4 interlock feature. The actions

of the Assistant Team Leader to identify and resolve this issue were

proactive and represented good attention to detail (Section M8.1).

An unresolved item was documented related to the adequacy of the

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licensee's testing of the P-4 interlock feature for the reactor trip

bypass breakers (Section M8.1).

Enaineerina

The ED package developed to implement a modification to an atmospheric

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relief valve was adequate and addressed the appropriate safety issues

(Section E1.2).

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The licensee had met the intent of Generic Letter (GL) 89-10 in

verifying the design-basis capabilities of their notor-operated valves

(MOVs), with limited exceptions. These exceptions included a failure to

document their consideration of an NRC safety evaluation applicable to

their EPRI PPM calculations and dynamic test results which did not fully

support certain calculation variables or methods used in establishing

valve settings and capabilities. Additionally, the ins)ectors were

concerned that several valves had little margin (less tlan 5%) available

to provide for uncertainties or long-term degradation.

In a letter to

the NRC dated May 5. 1997, the licensee stated actions that would be

performed to resolve the above issues.

An inspector followup item (IFI)

was identified to track the completion of these actions.

Strengths were

identified which included:

Use of the Electric Power Research Institute

Performance Prediction Model (EPRI PPM) to establish thrust requirements

for several groups of MOVs and licensee personnel who were very

knowledgeable of the MOV industry issues.

(Section E1.3)

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Issues were raised regarding the licensee's evaluations of 24 valves for

pressure locking and/or thermal binding.

The licensee agreed to provide

a supplemental-response to GL 95-07 to address these issues.

The NRC

staff will address these issues in their safety evaluation of the

licensee's response to GL 95 07. (Section El.3)

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The extended work hours of two reactor engineers immediately prior to a

reactor startup was identified as a poor practice (Section E4.1).

Plant Support

Strengths were noted in the licensee's pre-evolution brief and procedure

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for transfer of the Unit 1 spray additive tank contents.

However an

uriresolved item was issued to identify additional review by the

inspectors associated with the safety evaluation performed for this

procedure (Section R2.1).

Enclosure 2

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Emergency response facilities were well equipped and were maintained at

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a suitable level of operational readiness (Section P2.1).

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The operational status of the siren system exceeded the minimum

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requirements established by the Federal Emergency Management Agency

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(Section P2.2).

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Changes to the Emergency Plan via Revisions 24 and 25 were made in

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accordance with 10 CFR 50.54(q).

Emergency declarations by the licensee

on October 25 and November 15, 1996 were made in accordance with the

Emergency Plan Implementing Procedures (EPIPs) (Section P3.1).

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The EPIPs were determined to be generally thorough in terms of detail

needed to implement the various recuirements and commitments in the

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Emergency Plan. A violation was icentified for failure to maintain

copies of EPIPs up to date in the Operations Support Center

(Section P3.2).

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The training program for the Emergency Response Organization was being

conducted in accordance with Emergency Plan training commitments

(Section PS.1).

No degradation had occurred in the organization or management of the

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emergency preparedness program, nor is any expected to occur with the

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reassignment of the Emergency Preparedness Coordinator position

(Section P6.1).

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The audits conducted by the licensee fully satisfied the 10 CFR 50.54(t)

requirement for an annual inde)endent audit of the emergency

preparedness program (Section 37.1).

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Enclosure 2

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Report Details

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Summary of Plant Status

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Unit 1

On March 28, 1997, the unit was shutdown from full power to correct a hydrogen

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seal leak on the main turbine generator.

The unit entered Modes 2, 3. and 4

on March 29.

Following the completion of maintenance on April 4, 1997,

transition to Mode 3 and startup activities were initiated.

Criticality was

achieved on April 5. with nominal full power attained on April 7.

On A]ril

18. the unit was shutdown to resolve an electrical grounding issue on t1e main

turbine generator. At the end of the inspection period, the unit remained in

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Mode 3 with turbine generator reassembly in progress.

Unit 2

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The unit operated at full power throughout the inspection period.

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Doerations

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Conduct of Operations

01.1 General Comments (71707)

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Using Inspection Procedure 71707. the inspectors conducted frequent

reviews of ongoing plant operations.

In general, the reviews indicated

that the conduct of operations was satisfactory. The inspectors

observed some isolated instances of control room operator performance

which represented a minor degradation in control room demeanor.

These

observations were discussed with licensee management.

01.2 Unit 1 Containment Debris

a.

Insoection Scope (71707)

In preparation for reactor startup, the inspectors conducted walkdowns

of the Unit I containment on April 3, 1997.

At the time of these

walkdowns, the unit was in Mode 4.

The inspectors reviewed deficiency cards (DCs) documenting debris

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identified within the Unit I containment during the Unit 1 First Planned

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Outage. (IP1).

Additionally. the inspectors reviewed the licensee's

engineering evaluation, conducted after the discovery of the debris, of

its impact on sump performance.

Procedures 14900-C " Containment Exit

Inspection," Revision 2 and 00303-C. " Containment Entry." Revision 18,

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were also reviewed,

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Enclosure 2

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b.

Observations and Findinas

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Approximately 32 items were documented on Dcs between March 29. 1997 and

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April 4.1997. as debris or loose material discovered within the Unit 1

containment during the Unit 1 planned generator seal repair outage

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(IP1). These items ranged from a set of anti-contamination overalls to

small pieces of paper and tape. Of the 32 items, nine were identified

by the inspectors during their entries into containment.

The most

significant of these was a pair of anit-contamination overalls found

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beneath accumulator number one.

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The licensee's evaluation concluded that this material would not have

caused a malfunction of the containment saray or residual heat removal

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systems.

This conclusion appears reasona)le based on the nature and

amount of material documented.

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Further, from their walkdowns. the inspectors noted that the licensee

was successful in controlling debris generated as a result of ongoing

maintenance in containment.

Though the scope of work was limited, the

inspecto s did not identify debris at active worksites during IPl.

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part. this may have been as a result of the emphasis that the licensee

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placed on material control within containment during IPl.

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c.

Conclusions

The failure to remove or properly control the material identified in the

Unit I containment'during IP1 was contrary to the requirements of

Procedure 00303-C. This is identified as Violation (VIO) 50-424/97-04-

01. Containment Debris Identified During IPl.

01.3 Unit 1 Unclanned Necative Reactivity Addition

a.

Insoection Scone (71707)

The inspectors reviewed the circumstances surrounding a Unit I unplanned

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negative reactivity addition on April 10. 1997, that occurred following

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placing a demineralizer cation resin bed in service.

The inspectors

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reviewed available plant computer data: control room logs: the Unit 1

demineralizer logbook; and Procedure 13006-1

" Chemical Volume and

Control System (CVCS)" Revision 36.

The inspectors also interviewed

'ersonnel involved in the event including the reactor operator (RO).

alance of plant operator, and the Shift Superintendent (SS).

The

inspectors also discussed this issue with licensee management.

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Enclosure 2

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b.

Observations and Findinas

On April 10. the Unit 1 R0 at the request of chemistry personnel.

placed the CVCS cation bed.1-1208-D6-001. in service for approximately

25 minutes.

Immediately after the demineralizer cation bed was removed

from service, the RO noticed a reduction in reactor coolant system (RCS)

average temperature of approximately 0.5 F. as well as, a minor power

reduction to approximately 3553 Megawatts Thermal (Mwt).

After

recognizing these as effects of a negative reactivity addition

associated with placing the cation bed in service, the R0 diluted the

RCS to restore plant conditions.

This negative reactivity addition was the result of placing a cation bed

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in service which had last been used at a boron concentration well in

excess of that for the existing RCS boron concentration. After the

fact, it was determined by the on-shift crew, that the cation bed was in

service from March 28 to March 31, 1997.

This was during the recent

Unit 1 planned shutdown, during which. RCS boron concentration was

approximately 1396 Jarts per million (ppm).

As a result, residual water

in the CVCS cation ]ed contained this concentration of boron.

This fact was not appropriately documented in the demineralizer logbook

maintained in the control room. Specifically, the most recent entry in

this logbook, showed the cation bed being placed in service on March 28.

1996.

No entry was made for removal of the bed from service three days

later. Also, the year was in error. As an additional complication, the

next most recent entry in the logbook. for approximately four hours of

CVCS cation bed service, also on March 28. 1997, was in error in that

the year was also listed as 1996.

On April 10. 1997, when the operators reviewed the demineralizer logbook

in preparation for placing the CVCS cation bed in service, they

discounted the two most recent entries.

Instead they relied on a March

14. 1997, loabook entry. That entry indicated that the cation bed was

last removed from service on March 14. 1997, at a RCS boron

concentration of approximately 803 ppm. Accordingly, the R0 believed

that the cation bed met the boron concentration criteria of Procedure

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13006-1 (being within 200 ppm of existing RCS boron concentration)

required prior to aligning the bed for service.

The RCS boron

concentration on April 10, was a) proximately 671 ppm.

(Procedure 13006-

1 provides guidance that if the acron concentration has changed more

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than 200 ppm since the last time the bed was placed in service, then

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approximately 200 gallons of the initial CVCS cation bed effluent be

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diverted to the recycle holdup tank prior to it being aligned to the

RCS.

Cation bed flushing did not occur on April 10.)

Enclosure 2

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c.

Conclusions

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The inspectors concluded that the lack of an entry for tile removal of

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the cation bed on March 31 was contrary to the requirements of Procedure

13006-1.

Each time the cation demineralizer beds are placed in or out

of service. the date, time. and boron concentration are required to be

documented by the procedure.

In addition, the administrative errors

made in the demineralizer log book entries (i.e.. March 28, 1996 versus

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1997) also contributed to the event.

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As part of a comprehensive review of the event, the licensee stated

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their intention to evaluate their methods and procedures used to control

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activities that may affect reactivity. Therefore, pending review of

licensee actions in this area, this procedure noncompliance was

identified as Unresolved Item (URI) 50-424/97-04-02. Unit 1 Unplanned

Negative Reactivity Addition.

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The inspectors also concluded, although there was an unplanned

reactivity change, the R0 quickly recognized the RCS temperature

deviation and responded appropriately.

This is a positive example of

operator awareness and attention to detail.

01.4 Unit 1 Shutdown Observations

a.

Inspection Scone (71707)

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The inspectors observed portions of the Unit 1 shutdown on March 28 and

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29, 1997. This shutdown was coriducted from full power to Mode 4 to

perform repairs on the main turbine generator.

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b.

Observations and Findinas

The initial portion of the shutdown was well controlled.

In particular.

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the inspectors noted good communications between the personnel on shift

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and appropriate references to annunciator response procedures.

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However, later in the shutdown, the inspectors observed a level of

control room operator activity that was higher than that observed by the

inspectors during previous control room observations for similar )lant

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evolutions.

This primarily stemmed from distractions introduced

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control room annunciators.

Specifically, during control rod

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manipulations, the R0 at the controls was repeatedly interrupted by

annunciators. ALB06-F01. CSFST (Critical Safety Function Status Tree)

TROUBLE, and ALB10-D06. R0D DEV (DEVIATION)

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The inspectors estimated that every two to three minutes, the RO was

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interrupted to acknowledge the CSFST alarm.

This alarm came in

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consistently for several hours during shutdown activities. The

inspectors were informed that the CSFST alarm was the result of the

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reactor vessel level instrumentation system indicating just below the

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Enclosure 2

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setpoint of 100 percent vessel level.

The inspectors were informed that

this was not an actual condition but an erroneous indication due to the

method that vessel level dynamic head is calculated with four reactor

coolant pumps in operation.

Eventually, the control staff was augmented with a licensed senior

reactor operator assigned the responsibility to acknowledge this alarm.

The licensee was unable to explain the cause for the rod deviation alarm

at the time of the shutdown.

The alarm was received and cleared within

seconds at least four times during rod manipulations.

c.

Conclusions

The shutdown was conducted in a controlled fashion in accordance with

licensee procedures. The observations discussed above did not impact

plant safety.

However, they resulted in a level of control room

activity greater than that observed by the inspectors during previous

control room observations for similar evolutions.

The licensee also informed the inspectors as to the basis for their

conclusion that the conditions described above represented nuisance

alarms and their strategy for correcting these alarms. The inspectors

were informed that operations personnel had also raised similar concerns

with these same alarms.

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02

Operational Status of Facilities and Equipment

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02.1 Safety-Related Walkdowns

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a.

Inspection Stone (71707)

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The inspectors walked down the following engineered safety feature (ESF)

systems as part of the routine inspection effort to verify availability

and overall condition of the systems:

Unit 1 and 2 Auxiliary Feedwater (AFW) Systems

b.

Observations and Findinos

The ins)ectors verified proper system configurations both electrically

and meclanically for the above ESF systems through accessible portions

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in the plant, a walkdown of main control room boards, and a review of

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system drawings.

The inspectors also observed overall raaterial

condition of system components during the walkdowns.

A minor labeling

issue was identified regarding the handswitch for Unit 2 AFW pump house

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dampers 2-HV-12010 and 2-HV-12010A. This issue was forwarded to the

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licensee for resolution.

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Enclosure 2

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c.

Conclusions

The inspectors concluded that the systems reviewed were available to

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perform their function and that systems were properly aligned.

No

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significant items or discrepancies were noted during these inspections.

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Operations Procedures and Documentation

03.1 Walkdown of Clearances (71707)

During the inspection period, the inspectors walked down the following

clearances:

19700029

Residual heat removal pump room coolers

19700032

Safety injection system pump room coolers

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b.

Observations anc' Findinas

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The inspectors did not identify any problems during these walkdowns.

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Miscellaneous Operations Issues (71707)

08.1 (Closed) Escalated Enforcement Item (EED 50-424. 425/96-14-03:

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Configuration Control Deficiencies Involving Mispositioned Components

and Improper Independent Verification

An Enforcement Conference (EA 97-045) was held in the Region II office

on March 10. 1997. to discuss the issues identified in EEI 50-424,

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425/96-14-03, Configuration Control Deficiencies Involving Mispositioned

Components and Improper Independent Verification.

(Refer to Sections

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02.3. 02.4. and 02.5 of Ins)ection Report (IR) 50-424. 425/96-14.) As a

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result of the conference, t1e EEI was closed and two violations (VIO)

were identified: VIO 50-424, 425/97-045-01014, Failure to Implement

Procedures and Failure to Perform Adequate Independent Verification, and

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VIO 50-424/97-045-02014. Failure to Maintain Two Independent Emergency

Core Cooling System (ECCS) Flow Paths Operable.

The Notices of

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Violation were issued as Enclosure 1 to the NRC letter of March 25,

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1997, summarizing the proceedings of the meeting.

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Enclosure 2

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II.

Maintenance

M1

Conduct of Maintenance

M1.1 Maintenance Work Order Observations

a.

Insoection Scope (62707)

The inspectors observed portions of maintenance activities involving the

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following work orders:

A9700316

Replace control circuit board on radiation monitor ARE-2533

19700230

Intermediate range nuclear instrumentation NI-35 and NI-36

compensating voltage adjustment

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19700852

Reactor water storage tank (RWST) sludge mixing pump:

re3 lace oil seals and bearings (1-1204-P4-001)

19701160

1 3V-3000, atmospheric relief valve loop 1. will not

actuate: replace conax cable and raychem electrical splices

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29700062

Containment spray (CS) pump train B: change oil

29700094

Electrical preventive maintenance (PM) on 2-HV-9001B, CS

Jump train B discharge valve

29700507

Replace tachometer relay speed switch on diesel generator

(DG) train B

b.

Observations and Findinas

The observed maintenance activities were performed satisfactorily.

M1.2 Surveillance Observation

a.

Insoection Scone (61726)

The inspectors observed the performance or reviewed the following

surveillances and plant procedures:

14005-1

Shutdown margin and Keff calculations

14030-2

Power range calorimetric channel calibration

14400-1

Control room emergency filtration actuation logic test

14423-1

Source range nuclear instrumentation system (NIS) analog

channel calibration: NI-31 and NI-32

14450-1

1-HV-8809A reactor coolant system (RCS) pressure isolation

valve and 1-HV-8890A check valve inservice test (IST)

14485-1

CS system flowpath verification

14495-1

Auxiliary feedwater (AFW) flowpath verification

14546-1

Turbine driven AFW pump operability test

14804-2

Safety injection pump train B and discharge check valve IST

14806-1

CS pump B train IST

14900-C

Containment exit inspection

14980-2

DG train B operability test

24698-1

NIS intermediate range channel calibration (1-1602-05-NIR)

Enclosure 2

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b.

Observations and Findinas

The observed surveillance a'ctivities were performed satisfactorily.

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M1.3 Hold Tao On Valve Removed From System (62707)

On April 17, 1997, the inspectors observed a drain valve, with a hold

tag attached, on the short piece of piping lying in the corner of the

Unit 1 train A spent fuel pool heat exchanger room.

Following questions

on the appropriateness of this condition, a deficiency card (DC) was

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generated.

Subsequently. the inspectors were informed that the valve was

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inappropriately removed from the system by contractor personnel with the

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hold tag attached as part of an ongoing design change. The licensee

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described to the inspectors the corrective actions they have taken in

response to this issue.

As described, these actions vere adequate.

The inspectors noted from their review of Procedure 00304-C. " Equipment

Clearance and Tagging," Revision 33. that this practice is not

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procedurally prohibited.

In this case, the safety consequences were

minimal.

The inspectors identified to licensee management that this was

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a poor practice and could result in undesirable safety consequences.

M1.4 DG Air Damoer Maintenrra

a.

Insoection Scoce (62707)

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The inspectors reviewed maintenance performed on DG 1A damper and

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actuator ITV-12096 on April 9.1997.

This included witnessing a portion

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of the maintenance, reviewing maintenance work order (MWO) 19602862 and

associated checklists, and a review of request for engineering review

(RER) 93-0026. The inspectors also reviewed this issue with members of

the maintenance and operations departments,

b.

Observations and Findinas

The work observed consisted of inspection and lubrication of the DG 1A

actuator and damper ITV-12096.

These components serve as one of six air

exhausts during DG operation provided on the east wall of the DG 1A

building.

At the time of the maintenance, motive air for this damper

was isolated and the damper was failed open.

Three other dampers were

also failed open since motive air was isolated through the common air

supply valve.

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During the evolution, the inspectors observed the maintenance

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technicians attach an air line and supply air to the common motive air

line.

This attachment was immediately downstream of the isolation

valve. When questioned. the technicians indicated that the air was used

in an effort to partially shut the damper thereby facilitating actuator

Enclosure 2

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reassembly. This effort failed, however, since the air was supplied

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immediately upstream of a solenoid valve in the air sup)1y line which

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was shut as a result of the DG running concurrently wit 1 this

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maintenance.

The mechanics then attacF.ed the temporary motive air

downstream of the solenoid valve to d point which was common to all four

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dampers.

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The inspectors noted that RER 93-0026 indicated two exhaust dampers can

be shut without impacting DG operability.

Further, the cognizant Unit

Shift Supervisor (USS) informed the inspectors that he provided

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directions to the mechanics that only one damper at a time be cycled.

The mechanics indicated to the inspectors that they were aware of the

)otential impact of their attachment point for the tenporary air

urther, they clearly indicated that they only intended to partially

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stroke the damper.

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The inspectors identified two potential concerns in the maintenance

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procedure:

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The attachment point for motive air to cycle the dampers was not

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specified nor, alternatively, was a precaution or note provided to

warn against attaching to a point common to more than one damper.

2)

Nothing in the MWO authorized or suggested that partially shutting

the dampers to reinstall the actuator covers was authorized or

appropriate.

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As corrective action to the first concern, the licensee modified the

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maintenance instructions to provide precautions for locally stroking the

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dampers.

The inspectors reviewed these precautions and consider them

adequate to prevent recurrence.

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The inspectors discussed the second concern with the licensee.

The

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licensee stated their intention to investigate this practice.

c.

Conclusion

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The inspectors concluded that the maintenance procedure was improperly

established in that it did not provide adequate instructions for locally

stroking the dampers.

This is contrary to the requirements of Technical Specification 5.4.1.

However, consistent with Section IV of the NRC

Enforcement Policy this was identified as Non-Cited Violation (NCV)'50-

424/97-04-03. Inadequate Maintenance Instructions For DG Air Damper

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Stroking.

Enclosure 2

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M1.5 Modification of Licht Fixtures On Handswitch.1HS-12585A

,

a.

Insoection Scooe (62703)

l

The inspectors observed the modification of the light fixtures in

[

handswitch 1HS-12585A under MWO 19700947 and later followed up on the

[

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post-modification testing of the handswitch,

t

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b.

Observations and Findinas

[

i

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,

On April 15. 1997, the inspectors observed Instrument and Control

,

l

Technicians changing the light fixtures ir, handswitch 1HS-12585A. The

existing Korry Series 114 indicating lights u;ere being replaced with

'

Dialight 101 light fixtures with an external dropping resistors. This

change was being made to extend the life of the indication lights by

removing the dropping resistor from the back of the lamp fixture and

!

mounting it externally in the switch case. This removed the heat source

!

from the lamps which was shortening the bulb life.

MWO 19700947

1

contained the instructions for the changeout of the light fixtures

including the mounting of the new external dropping resistors and the

rewiring of the lamp sockets. An equivalency determination (ED) 96-VAD-

045 had been generated to document the acceptability of the Dialight 101

l

as a replacement for the Korry Series 114.

The inspectors reviewed the ED and the MWO for the replacement. The MWO

l

invoked a Construction Specification X3AR01, for the replacement.

Engineering Procedure 50020-C. " Equivalency Determinations of

Replacement Parts or Materials." Revision 6. stated in part that an ED

i

may not be used to effect a change in parts or materials involving a

,

non-compliance to a specification.

The inspectors noted in the ED

'

package that an exce)tio,1 to the construction specification had been

l

generated to allow t1e landing of three ring terminal lugs to a switch

,

terminal point. The specification allows only two. While the exception

i

!

to the specification avoided non-compliance with the specification. the

inspectors indicated to licensee management that it appeared to be a

poor practice.

Post-modification testing was observed by the inspectors

and was successfully completed on the handswitch.

c.

Conclusions

The inspectors determined that the replacement was carried out in

accordance with the work order and applicable procedures. The taking of

!

an exception to a construction specification to allow the change out was

'

!

noted by the inspectors to be a poor practice. While the actual

rewiring of the light fixtures would not require a drawing modification,

the inspectors noted that the wiring internal to the handswitch was

significantly different than that of the original manufacture. The

ins)ectors noted that discussions between the technician performing the

.

worc and the independent reviewer were necessary for the reviewer to

understand what had actually been accomplished.

i

Enclosure 2

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.

11

M8

Miscellaneous Maintenance Issues (62707)

M8.1

(Closed) Licensee Event Reoort (LER) 50-424/97-002:

P-4/ Turbine Trip

Circuit Not Surveillance Tested, and

(Closed) Unresolved Item (URI) 50-424. 425/96-14-06:

Potentially

,

Inadequate Surveillance Testing of P-4 Circuitry

a.

Insoection Scoce (61726,1

This LER documented inadequate surveillance testing of the reactor trip

breaker P-4 circuitry. This issue was previously documented by the

inspectors as URI 50-424. 425/96-14-06.

i

The inspectors reviewed the LER. reactor trip breaker wiring diagrams.

)

and surveillances which test the P-4 circuitry.

In addition. the

inspectors witnessed Sortions of the surveillance testing conducted on

i

the reactor trip brea(ers and reviewed this issue with cognizant

licensee personnel.

i

b.

Observation and Findinas

Previous inspection of this issue was documented in Inspection Report

50-424. 425/96-14 (Sections 03.1 and M3.1).

.

The inspectors determined that the licensee has modified procedures and

conducted surveillance testing to address the shortcomings identified in

the LER.

l

The inspectors also noted that the licensee does not test the P-4

interlock feature of the bypass breaker prior to placing them in

'

service.

Further. the P-4 signal generated by the bypass breakers and

supplied to the EHC system is also not verified by licensee

surveillances.

Pending further review of this issue by the NRC, this is

identified as URI 50-424. 425/97-04-04. P-4 Interlock Testing of Reactor

Trip Bypass Breakers.

c.

Conclusion

The inspectors concluded that the licensee failed to conduct adequate

testing of the P-4 circuit as a result of inadequate surveillances and

post-maintenance functional testing.

This was contrary to the

requirements of Technical S)ecifications Table 4.3-2. Item 9.b (Improved

Technical Specifications Ta)le 3.3.2-1. Item 8.a).

However consistent

with Section VII of the NRC Enforcement Policy this was identified as

NCV 50-424, 425/97-04-05. Inadequate P-4 Circuit Testing.

LER 50-424/97-002 and URI 50-424. 425/96-14-06 are closed.

The inspectors also concluded that the actions of Assistant Team Leader

Enclosure 2

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_

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.

.

12

to identify and resolve these items were proactive and demonstrated good

attention to detail.

M8.2 (Closed) Violation (VIO) 50-424. 425/96-12-02:

Failure To Take

Effective Corrective Actions To Assure MCC Door Latches Are Properly

Secured, and

,

(Closed) LER 50-424/97-003:

Unlatched Doors On Motor Control Centers

'

Changes Seismic Qualifications

The inspectors reviewed the licensee's corrective actions for these

i

,

l

items and concluded they are adequate.

These items are closed.

'

l

III.

Enoineerino

El

Conduct of Engineering

E1.1 General Comments (37551)

During the inspection period, the inspectors assessed the effectiveness

of onsite engineering processes by reviewing engineering evaluations,

modifications, and engineering testing.

The inspectors also reviewed

i

deficiency cards (DC)s to determine whether the licensee was

appropriately documenting problems and implementing corrective actions.

E1.2 Unit 1 Atmospheric Relief Valve Modification

a.

Insoection Scope (37751)

The licensee performed a modification to steam generator loo) 1

l

atmospheric relief valve (ARV).1-PV-3000, in accordance wita

equivalency determination (ED) 95-VAD-043.

The inspectors reviewed ED

95-VAD-043, the safety evaluation, and the drawings for the valve

modification.

In addition, the inspectors observed portions of the

field modification work on the relief valve.

b.

Observations and Findings

This modification was developed to change the relief valve plug and seat

l

angles to address seat leakage and to increase the seating reliability

of the valvos.

The ED considered and addressed the impact that the modification would

i

have on the safety function of the comoonent.

The safety evaluation was

adequate and identified no unreviewed ' safety questions.

New components

were purchased to the proper safety classification.

The inspectors *s field observations did not identify any discrepancies

between the ED package and actual work performed.

However, the licensee

Enclosure 2

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13

,

did identify improper raychem splices installed on wiring for two ARVs.

1-PV-3000 and 1-PV-3030.

These discrepancies were appropriately

documented in deficiency cards and are the subject of Licensee Event

j

Report (LER) 50-424/97-004. Additional followup will be conducted

, during the inspectors' review of this LER.

c.

Conclusions

The inspectors concluded that the ED package developed to implement the

relief valve modification was adequate and addressed the appropriate

safety issues.

E1.3 Generic Letter 89-10 Proaram Imolementation

l

a.

Insoection Scooe (Temocrary Instrnetion 2515/109)

!

This inspection provided an assessment of the licensee's implementation

of Generic Letter (GL) 89-10. Safety-Related Motor-Operated Valve

l

Testing and Surveillance. The licensee notified the NRC that they had

l

completed implementation of GL 89-10 in a letter dated July 28, 1995.

I

Subsecuently, in a submittal dated January.31,1996, the licensee

'

proviced information to facilitate the NRC's closure of its review of

the licensee's GL 89-10 program.

The assessment conducted during this inspection included the scope of

,

l

Motor Operated Valves (MOV)s in the licensee's program and their

l

determinations of MOV settings and verifications of MOV capabilities.

l

periodic verification of MOV capabilities. MOV corrective actions and

trending. MOV post maintenance and post modification testing, and

actions to address pressure locking and thermal binding. The NRC

inspectors conducted the assessment through a review of the licensee's

l-

GL 89-10 implementing documentation and through interviews with licensee

l

personnel.

The documents reviewed included: Generic Letter 89-10 Close-

,

l

Out Submittal, dated January 1996: Calculation X4C1000U02, Revision 11;

l

and the calculations, test records, etc., referred to in the following

paragraphs.

In addition, the inspectors reviewed summary tabulations of

MOV information and calculation results prepared by the licensee.

Prominent among the tabulations was a list of "available valve factors"

(AVFs) for the licensee's GL 89-10 gate and globe valves. The licensee

'

prepared this list at the inspectors' request to aid them in assessing

the capabilities of the licensee's MOVs.

The AVFs were calculated using

i

,

i

formulas described in previous NRC inspection reports (e. g.. Inspection

Report 50-338. 339/97-01, dated March 21. 1997).

The inspectors

compared the AVFs for the licensee's valves to valve factor requirements

established in industry testing which the NRC had )reviously reviewed.

]

These comparisons were performed to determine if tie AVFs were

'

conservatively higher.

b.

Observations and Findinas

'

Enclosure 2

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14

1.

Scone of MOVs Included in the Proaram

)

The sco e of valves included in the licensee's GL 89-10 program was

origina ly reviewed and detenained acceptable by the NRC during

!

Inspection 50-424, 425/92-01. . At that time, the scope consisted of 280

j

MOVs.

In the current inspection the inspectors found that the licensee

I

had subsequently removed 26 MOVs.

The inspectors selected 18 of the

l

valves removed and reviewed the bases for their removal, which were

j

documented in a letter dated October 21. 1991 (Log SG-10616).

The

{

!

inspectors found that the bases given were satisfactory. Although not

!

l

reviewed in detail by the ins)ectors, similar bases had been prepared by

the licensee for removal of tie other 8 valves.

The current program

scope included 126 gate valves 58 globe valves, and 70 butterfly valves

for a total of 254 valves.

l

2.

Determinations of Settinas and Verifications of Caoabilities for

Gate and Globe Valves

The inspectors selected and reviewed calculations, test data, and

f

evaluations for the. following sample of valves in order to assess the

'

licensee *s validation of calculation assumptions and their

determinations of MOV settings and capabilities:

1HV5106

Auxiliary Feed Pump Turbine Isolation

2HV5120

Auxiliary Feed Pump Discharge

1HV8508B

Charging Pump Mini-Flow Isolation

'

!

1HV8835

Safety Injection System Cold Leg Loop Header Isolation

l

2HV8716A

Residual Heat Removal Hot Leg Isolation

l

The licensee's gate valves were manufactured by Anchor-Darling and by

i

Westinghouse.

These valves were divided into 17 groups, each group

l

consisting of valves of the same manufacturer, size. pressure class, and

i

disc type.

The Electric Power Research Institute (EPRI) Performance

l

Prediction Model (PPM) ads used to calculate the minimum required

i

l

thrusts for all of the Anchor-Darling gate valves except those in Group

l

i

AD-3.

For Grou) AD-3. the licensee calculated the minimum required

thrusts using tie standard industry equation and an assumed valve factor

of 0.50.

An EPRI variation of the standard industry equation was used

to calculate required thrusts for Westinghouse gate valves. This

equation employed assumed " friction factors" in calculating the required

thrusts. A friction factor of 0.55 was assumed for operation in steam

and 0.60 for operation in water, based on EPRI stellite on stellite

l

friction measurements.

~

The licensee's globe valves were manufactured by Velan and Fisher. As

in the case of gate valves, the globe valves were divided into groups

consisting of valves of the same manufacturer, size pressure class, and

disc type. The EPRI PPM was used to calculate the minimum required

i

thrusts for all of the Velan globe valves.

The minimum required thrusts

for the Fisher globe valves were calculated using Fisher's metbdology.

,

Enclosure 2

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.

15

Standard industry relations and component limitations were used to

i

,

determine the capabilities and maximum allowable thrusts for the gate

!

and globe MOVs.

Assumed stem friction coefficients (discussed in a

subsequent paragraph) were used in relating motor-operator torque to

i

,

thrust.

l

The licensee adjusted the minimum required thrusts for gate and globe

i

valves for load sensitive behavior, torque switch repeatability, and

i

diagnostic equipment uncertainties.

The maximum allowable thrusts were

!

adjusted for torque switch repeatability and diagnostic equipment

uncertainties.

l

l

The inspectors' findings were as follows:

l

!

MOV Sizino and Switch Settinos

The licensee generally used methods of determining required thrusts that

were validated through dynamic testing.

The licensee dynamically tested

83 of the 254 MOVs in their 3rogram.

From their review of the bases for

the licensee's methods and t1e variables employed in each method, the

inspectors found that the licensee had satisfactorily established the

minimum thrust requirements and verified adequate capabilities for their

i

gate and globe MOVs with several exceptions.

These exceptions and

!

actions which the licensee proposed to assure each was adequately

addressed are described below:

l

The closing thrust settings (adjusted for diagnostic equipment

.

uncertainty, torque switch repeatability, and load sensitive

behavior) of three Velan globe valves exceeded the minimum

'

1

requirements predicted by the EPRI PPM by less than 5%.

The

inspectors considered that this small margin might be inadequate

to account for long-term degradation in MOV capabilities.

'

Subsequent to the inspection, in a May 5. 1997 letter to the NRC.

the licensee indicated they would address this by including an

additional 5% bias uncertainty in the target thrust settings of

all torcue switch controlled rising stem valves.

The 5% would be

includec as a " good practice" but would not be used in determining

'

l

operability.

l

.

The licensee's Anchor-Darling and Velan valve thrust calculations

.

which employed the EPRI PPM methodology did not document

l

consideration of the NRC safety evaluation of the EPRI PPM.

This

NRC safety evaluation (transmitted from the NRC to the Nuclear

l

Energy Institute in a letter dated March 15, 1996) described the

i

conditions and limitations under which the NRC considered the EPRI

PPM an acceptable methodology.

Subsequent to the inspection, in

the May 5, 1997 letter referred to above, the licensee indicated

.

they would review the NRC safety evaluation in detail for

applicability to their calculations and that a summary of the

Enclosure 2

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)

16

i

i

review would be included in Calculatiori X4C1000U02.

The licensee did not have justification for the valve factor

i

l

assumed in calculating the minimum required thrusts for valve

Group AD-3 with the standard industry equation.

This valve group

consisted of four 4-inch Anchor-Darling 150 pound flex wedge gate

!

valves whose safety function was to open to provide air to purge

the containment.

The licensee had assumed a valve factor of 0.50

but had no air-operation dynamic test data from similar valves to

'

I

support this value. The available valve factor calculated for

l

these MOVs was 0.56.

As these valves were statically tested and

their service conditions were mild (air at an opening design-basis

differential pressure of 132 psid) the inspectors had no

i

l

immediate concern for their operability.

However, based on the

'

available valve factor, they considered the long-term capabilities

of these valves marginal.

Subsequent to the inspection, in the

,

May 5. 1997 letter referred to above. the licensee indicated they

,

would modify the valve operators to increase their thrust output

at degraded voltage.

The licensee also indicated the valves would

l

be re-evaluated utilizing a 0.7 friction coefficient and the

'

Nuclear Maintenance Application Center Guide (1990) thrust

equation to provide a more conservative prediction of thrust

requirements.

j

The closing thrust capabilities of the two 0.5-inch Fisher globe

valves in Group FG-1 were marginal at design-basis conditions.

The calculated closing thrust ca] abilities of the valves exceeded

the minimum required thrusts wit 1 margins of 0% and 4%.

This

closing thrust margin was limited by the valve weak link analysis.

The inspectors were concerned that these margins might be too low

l

to account for uncertainties.

Subsequent to the inspection, in

1

the May 5. 1997 letter referred to previously above the licensee

'

indicated they would substantially increase the as-left capability

margins of these valves by reducing their design packing loads

from 1000 to 500 lbs.

The results of dynamic tests performed on Westinghouse gate valve

.

groups W-2A W-28. and W-8 did not fully support the valve design

methodology employed in determining the minimum thrust

requirements for these valves.

Further, the licensee had no

dynamic test results to support the valve design friction factors

employed in calculating the minimum thrust requirements for

Westinghouse gate valve groups W-9. W-11. and W-12.

The current

set-ups of the valves in all six of these groups provided them

,

with available valve factors that were adequate to ensure their

l

current operability, based on general industry experience reviewed

by the NRC.

Subsequent to the inspection, in the May 5.1997,

letter referred to previously above, the licensee indicated they

would re-review the dynamic test results for the valves in groups

,

W-2A, W-28. and W-8 and that they would revise their methodology

Enclosure 2

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17

i

to bound all credible test data

For groups U-9. W-11. and W-12.

they stated that they would either identify industry test data to

justify their methodology or replace the current methodology with

l

EPRI PPM methodology.

l

The inspectors considered that the licensee's satisfactory completion of

'

the actions stated in the May 5.1997 letter (referred to above)

l

necessary and a)propriate to provide assurance of the long-term

capability of t1e MOVs discussed above.

The licensee's completion of

the actions was identified as part of an inspector followup item, as

discussed in E1.3.c below.

,

.

Load Sensitive Behavior

The licensee's close-out submittal documented the licensee's evaluation

of the load sensitive behavior exhibited in their testing of MOVs under

torque switch control. The licensee statistically analyzed 50 data

points and determined a mean of -2.3% and a standard deviation of 8.58%.

The licensee elected to apply this wholly as a 20% random uncertainty

that was combined with instrument error and torque switch repeatability.

'

Although more precise to apply the mean separately as a bias with two

standard deviations applied as random uncertainty the inspectors found

that the licensee's calculation methods yielded equivalent results

because the mean value was small.

The inspectors considered the

licensee's methodology adequate to account for the load sensitive

behavior experienced by MOVs under torque switch control.

The licensee

did not apply load sensitive behavior values in establishing settings

for MOVs in which opening and/or closing were controlled by limit

switch.

They informed the inspectors that they accounted for this

phenomena through stem friction coefficient changes between static and

dynamic conditions for limit controlled MOV positioning.

This is

discussed in the following paragraph.

Stem Friction Coefficient

The valve stems on the licensee's Anchor-Darling valves had stub ACME

threads while their Velan. Fisher, and Westinghouse valves had standard

ACME threads.

In calculations, the licensee assumed a stem friction

coefficient of 0.20 for the stub ACME threaded stems and 0.15 for the

standard ACME threaded stems. The inspectors reviewed statistical

analyses which the licensee performed on their test data and found that

the analyses supported the 0.20 assumed for stub ACME threaded stems but

not the 0.15 value assumed for the standard ACME threaded stems. Their

review indicated that a value of 0.18 would be more appropriate for the

standard ACME threaded stems (based on the mean plus two standard

deviationU. The inspectors found that the load sensitive behavior

which the licensee applied in calculations for torque switch seating was

adequate to make up for the difference between 0.15 and 0.18.

However,

the licensee did not apply load sensitive behavior in determining thrust

for limit switch controlled seating or opening.

The licensee evaluated

Enclosure 2

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.

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- . - -_.

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4

I

18

'

a)p11 cation of the 0.18 stem friction coefficient in relating torque to

!

t1 rust for limit switch controlled valve o)ening and closing and

)

l

provided the results to the inspectors.

T1e ins)ectors reviewed these

'

results and did not identify any immediate opera)111ty concerns.

Subsequent to the inspection in their May 5.1997 letter to the NRC.

the licensee indicated they would use the 0.18 stem friction coefficient

'

for all limit switch controlled positioning of MOVs with standard ACME

l

threaded stems.

The inspectors considered the licensee's satisfactory

com)letion of this action necessary to support the capabilities of MOVs

wit 1 standard ACME threaded stems.

The licensee's completion of the

action was identified as part of an inspector followup item. as

discussed in E1.3.c below.

i

l

Coenina Diaanostic Eauioment Uncertainties

The inspectors found that the licensee had appropriately evaluated the

valve opening diagnostic equipment uncertainties described by their

l

equiament supplier in Liberty Technology Customer Service Bulletin 31.

i

Furtier, they had revised their. diagnostic arocedures to obtain tension

,

l

in the calibration range (when needed) whic1 reduces the applicable

l

diagnostic error in the open direction.

The inspectors considered this

.

diagnostic equipment uncertainty adequately resolved by the-licensee.

_

Desian-Basis Capability

The static and dynamic tests which the licensee 3erformed in

demonstrating the design-basis capabilities of t1eir MOVs were

satisfactory.

I

3.

Determinations of Torcue Reauirements and Verifications of the

1

Capabilities of Butterfly Valves

The licensee's butterfly valves were 4 . 8 . 10 . 18 . and 24-inches in

'

size and all were manufactured by Fisher.

The torque switches for the

MOVs were either bypassed or scheduled to be bypassed.

The greatest

'

design-basis differential pressures were experienced by the 18-inch

valves (173 psid o)ening) and the lowest were experienced by the 24-inch

valves (having eitler 0 psid opening and closing or 31 psid opening and

closing).

Static diagnostic tests had been 3erformed on all of the

butterfly MOVs but only the 8-inch size had 3een dynamically diagnostic

tested.

l

The licensee had initially calculated torcue requirements for the

l

butterfly MOVs using an equation developed by the manufacturer.

However, the dynamic diagnostic testing which the licensee performed on

four 8-inch valves indicated that the packing loads determined with the

manufacturer's equation were too low.

ine licensee modified the

equation to provide packing loads more consistent with the test results

,

l

and a) plied the modified equation in determining torque requirements for

all t1eir butterfly MOVs.

Enclosure 2

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_ _ . _ _ _ . _ _ _ _ ._

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19

From a review of the licensee's calculations. dynamic test results. and

!

static test results for the 8-inch butterfly MOVs. the inspectors found

that the modified calculation provided an adequate determination of

'

torque requirements for these valves. While the dynamic torque

i

component was sometimes underpredicted by a small amount (about 50 . the

static component was predicted conservatively and the overall result was

satisfactory.

However, the inspectors were concerned that the licensee

had performed no dynamic tests to demonstrate the validity of their

modified equation to the larger sizes of butterfly valves, especially

the 18-inch valves which experience the highest differential pressures

of the butterfly valve groups.

The larger 24-inch valves were of less

_

concern because of their low design-basis differential pressures.

No

'

current o)erability concerns were identified for the 18-inch valves,

i

because t1ey were routinely operated at conditions approaching design-

basis and they had significant calculated capability margins.

The

inspectors raised questions regarding the long-term capabilities of the

18-inch butterfly valves and the validity of the licensee torque

i

l

calculation method for valves of this size, as margins might be reduced

in future o)eration.

Subsequent to the ins?ection. in their May 5.1997

'

letter to t1e NRC. the licensee indicated t1ey would perform

instrumented dynamic torque testing of two of the 18-inch butterfly

valves to demonstrate that the 18-inch valves have adequate long-term

'

!

capabilities at design-basis conditions.

While the licensee will not be

!

able to obtain accurate measurements of differential

3ressure during

these tests. they stated that they will ensure that t1e test

l

configuration is representative of the conditions postulated in

'

determining the design-basis differential pressure. Additionally, they

i

stated that they will monitor test pressures, utilizing local

i

instrumentation to the extent practical, to assess actual system

,

conditions and provide a basis for evaluating the test data.

The

'

inspectors considered that the licensee's satisfactory completion of the

testing and evaluation of the test data against the calculation

l

methodology would provide adequate assurance of the capabilities of the

18-inch valves and increased confidence in the calculation methodology.

The licensee's completion of the action was identified as part of an

inspector followup item, as discussed in E1.3.c below.

J

4.

Periodic Verification

l

The licensee's guidelines for periodically testing MOVs in accordance

with GL 89-10 were described in Motor Operated Valve Program Manual GEN-

34. Revision 3.

GEN-34 prescribed statically testing each MOV once

'

every five years or three refueling cycles.

The inspectors reviewed

l

printouts for a sample of MOVs in the licensee's planning database and

l

verified that the periodic static diagnostic testing was specified.

For

I

each MOV the database identified the date of the last test and the due

date for the next test.

The licensee's periodic verification actions

were found to be adequate for closure of GL 89-10. The NRC may re-

i

assess the licensee's long-term periodic verification program as part of

its review for GL 96-05. Periodic Verification of Design-Basis

!

Enclosure 2

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20

Capability of Safety-Related Motor-0perated Valves dated September 18.

1996.

5.

Post Modification and Post Maintenance Testina

The licensee's post modification test requirements were determined by

engineers using post maintenance testing requirements as guidance.

The

inspectors reviewed the licensee's post maintenance test guidance, which

,

was provided in Motor Operated Valve Program Manual GEN-34. Revision 3.

'

Additionally, the inspectors reviewed the post modification and post

maintenance testing recorded for maintenance work orders 29302176.

19501792. 29600325. 19501753. 29600250, 19501789. 29600274. 19500812.

,

19501909. and 29601931. These maintenance work orders involved

j

correction of packing leaks, correction of through valve leaks. changes

from torque to limit switch controlled seating, actuator modifications.

'

verifications of valve internal dimensions, and replacement of a valve

stem and stem nut.

The inspectors found that the licensee generally

performed full diagnostic testing following the maintenance and

modifications.

Based on the licensee's post maintenance test guidance,

dynamic testing was considered after maintenance.

The inspectors

concluded that the licensee had implemented acceptable post modification

and post maintenance testing.

'

6.

MOV Corrective Actions and Trendina

The licensee's guidance for correction and trending of MOV failures and

!

degradation was described in Motor Operated Valve Program Manual GEN-34

Revision 3.

This manual provided specific guidance on the investigation

of typical failures and on the corrective actions. Additionally, it

1

prescribed trending of test failures, reviews of test data for trends.

and preparation of an annual trend report.

Based on a review of the

GEN-34 guidance. corrective maintenance documented in the maintenance

work orders referred to in the previous paragraph, and the description

of trends documented in the licensee's latest annual trend report (Log

,

'

NOM-02169. dated March 20. 1997), the inspectors concluded that the

licensee's MOV corrective actions and trending were satisfactory.

)

7.

Pressure Lockina and Thermal Bindina

The inspectors reviewed the licensee's GL 95-07. Pressure Locking and

Thermal Binding of Safety-Related Power-0perated Gate Valves, submittal

!

dated February 8. June 28 and July 26, 1996.

During this review the

!

inspectors noted that the licensee's pressure locking analysis for

i

residual heat removal (RHR) hot leg injection valves 1/2 HV-8840 assumed

!

that bonnet leakage over an eleven hour period would reduce bonnet

'

pressure and the valves could overcome potential pressure locking.

The

licensee referenced a Westinghouse analysis of bonnet depressurization

.

rates for gate valves tested by Commonwealth Edison.

The inspectors

'

found that the licensee could not demonstrate that the Westinghouse

4

Enclosure 2

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21

,

l

analysis of bonnet depressurization was generically applicable to all

{

flexible wedge gate valves.

Further. the licensee's pressure locking

l

analysis did not appropriately address the effect of increased ambient

1

room temperature on bonnet pressure.

i

The licensee prepared a safety evaluation that concluded that the

ability of the emergency core cooling system to meet its design

function. including full redundancy, is met with 1/2 HV-8840 in the

l

closed position.

This safety evaluation was prepared to support a

change to the Final Safety Analysis Report (FS97-031), to describe the

redundant hot leg injection flow paths. The inspectors reviewed the

,

!

safety evaluation and considered that it satisfactorily resolved the

l

valves 1/2 HV-8840 pressure locking concern.

The licensee's GL 95-07 submittal stated that boron injection tank

,

discharge valves 1/2 HV-8801A.B and containment saray pump discharge

isolation valves 1/2 HV-9001A.B were not susceptiale to pressure

locking.

The licensee indicated that the valves might initially

pressure lock when attem) ting to open, such that the motors would be

incapable of unseating t1e valves and would undergo locked rotor

!

conditions.

However, the licensee concluded that the' respective safety

'

injection and containment spray pump would start and the discharge

)ressure applied to the upstream side of each valve would equalize

)onnet pressure allowing the valves to o)en.

The licensee's actuator

capability calculations indicated that t1e actuators could develop

adequate thrust following operation at a locked rotor condition but the

margin between required valve thrust and actuator capability was low.

The inspectors concluded that operation at a locked rotor condition was

not an acceptable p" essure locking solution because not all of the

licensee's assumptions for determining actuator capability following a

locked rotor condition had been validated by testing.

!

The licensee's pressure locking analysis for RHR pump shutdown cooling

l

suction valves 1/2 HV-8701A.B and HV 8702A.B concluded that the valves

were not susceptible to pressure locking because bonnet leakage would

i

reduce the amount of thrust required to overcome pressure locking.

The

inspectors did not agree, as they found that the licensee could not

satisfactorily demonstrate that there would be sufficient leakage to

'

3reclude pressure locking.

However, during operation. the valves have

)een routinely opened without experiencing any problems and the

i

inspectors considered this an acceptable short term pressure locking

'

solution. The inspectors did not consider this an acceptable long-term

.

pressure locking solution because valve characteristics could

significantly change following maintenance.

The licensee's GL 95-07 submittal stated that RHR pump miniflow valves

'

!

1/2 FV-0610 and FV-0611 would be modified to prevent thermal binding and

pressure locking by revising the control scheme to utilize the limit

'

switch closure to minimize disc wedging.

The inspectors found that the

Unit 2 valves had been modified and the Unit 1 modification was

,

,

.

Enclosure 2

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22

scheduled to be completed in the Fall of 1997.

During the inspection

the licensee was still evaluating the closing force required to ensure a

small amount of leakage past the seat of each valve would occur.

The

inspectors concluded that minimizing wedging force was an acceptable

pressure locking and thermal binding corrective action.

The licensee's GL 95-07 submittal stated that pressurizer block valves

1/2 HV-8000A.B and RHR pump shutdown cooling suction valves 1/2 HV-

8701A,B and HV-8702A B were not susceptible to thermal binding because

the valves had been closed numerous times and reopened at a lower

temperature without experiencing any problems.

However, the licensee

i

did not provide any historical data to support this conclusion.

Therefore, the inspectors were unable to determine if these valves were

susceptible to thermal binding under the current actuator setup

conditions.

The adequacy of the licensee's actions to address pressure locking and

thermal binding remain under NRC evaluation.

During the current

inspection, the inspectors raised issues regarding bonnet

depressurization and actuator locked rotor assumptions.

The licensee's

pressure locking evaluations of valves 1/2 HV-8701A,B, 1/2 HV-8702A,B,

1/2 HV-8801A/B, and 1/< HV-9001A/B, were insufficient to meet the intent

o '" 95-07.

Ope et'onal history demonstrating that valves 1/2 HV-

8000A,o, ' " HV C .1A,B and 1/2 HV-8702A.B. are not susceptible to

i

thermal iinalng .nd the licensee's evaluation of valves 1/2 FV-0610 and

'

FV-0611 we@~; forces will be evaluated by the NRC staff to determine

if the intent of GL 95-07 is met. The licensee agreed to provide a

supplemental response to GL 95-07 to address these issues.

The NRC

staff will address these issues in their safety evaluation of the

licensee's response to GL 95-07.

7.

Strenaths

The inspectors observed the following strengths in the licensee's

implementation of GL 89-10:

Use of the EPRI PPM.

.

Personnel who were very knowledgeable of the MOV industry issues.

c.

Conclusions

The inspectors determined that the licensee had generally met the intent

of GL 89-10 in verifying the design-basis capabilities of their MOVs.

l

with limited exceptions.

These exceptions include a failure to document

!

their consideration of an NRC safety evaluation applicable to their EPRI

PPM calculations and dynamic test results which do not fully support

,

certain calculation variables or methods used in establishing valve

settings and capabilities. Additionally, the inspectors were concerned

that several valves had little margin (less than 50 available to

Enclosure 2

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4

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4

23

3rovide for uncertainties or long-term degradation.

In a letter to the

4RC dated May 5. 1997, the licensee stated actions that would be

,

performed to resolve the above issues.

It stated that the actions.

"

except fcr the modification of two valves per unit, would be completed

in 1997. The modifications of the two valves (1/2HV-9380A.8) are to be

performed in 1998 and 1999. The letter also indicated that the NRC

staff would be notified of the results and status of each issue by the

!

end of 1997.

Based on the results of this inspection and the actions

i

l

stated in the licensee's letter, the NRC concluded that their review of

i

the licensee's im)lementation of GL 89-10 could be closed.

NRC

verification of t1e licensee's completion of the actions stated in the

licensee's letter of May 5. 1997 we, identified as an Inspector Follow

up Item (IFI) 50-424. 425/97-04-06.

!

The inspectors noted several licensee strengths, which are described in

Section E1.3.b.7.

i

,

The adequacy of the licensee's actions to address pressure locking and

thermal binding remain under NRC evaluation.

Issues were raised

regarding the licensee's evaluations of 24 valves for pressure locking

and/or thermal binding.

Previously addressed by the NRC through GL 89-

10. the NRC staff will now address these issues in their safety

evaluation of the licensee's response to GL 95-07.

The licensee agreed

to provide a supplaiental response to GL 95-07 to address these issues.

E4

Engineering Staff Knowledge and Performance

E4.1 Enaineerina Personnel Work Hours

q

.

a.

Insoection Scope (37551)

The inspectors observed portions of the Unit 1 startup activities on

April 4 and 5. 1997. The inspectors also observed portions of the

reactor engineering activities associated with the startup.

b.

Observations and Findinos

Overall. preparations for startup were well planned by the onshift crew

and reactor engineering personnel.

Startu) activities were successfully

completed and appropriately supported by t1e engineering staff.

However, the inspectors questioned the amount of time the reactor

engineering staff spent onsite to su) port the startup activities.

Two

reactor engineers were assigned by t7e licensee to support the Unit 1

startup.

Both engineers re)orted to work on the morning of April 4 and

stayed through startup on tie morning of April 5.1997.

Each engineer

spent a total time of approximately 21 to 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> onsite.

Enclosure 2

. _ _ . . _ _ _ . . _ . _ . _ _ _ . _ _ _ . _ _ _ _ _

._.-.._._.__.____.m.

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v

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,

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. E

i

l

a

24

.

-(

.

c. ' Conclusions

!

The startup activities were conducted safely and in accordance with

[

' licensee procedures.

However, the ins)ectors were concerned with the

i

.

extended period of time spent on-site )y the reactor engineers prior to

i.

and during the reactor startup.

While no actual negative impact was

observed,- the inspectors were concerned that this practice could degrade

l

E

the. effectiveness of the reactor engineers as a barrier to difficulties

'

during a startup.

The inspectors noted that this practice by reactor

engineers is not prohibited by the licensee's procedures.

The

.

inspectors concluded that this was a poor practice.

1

i

l

This observation was brought to the attention of the reactor engineering

i

supervisor and licensee management.

'

.

'

E8-

Miscellaneous Engineering Issues (37551)

!

E8.1

(Closed) Violation 50-424/96-09-02:

Mispositioned Unit 1 Fire

i

Protection Header Containment Isolation Valve.

T

'-

While performing a slave relay test on July 16, 1996, operators

F

discovered the fire header containment isolation valve 1-HV-27901 was

i-

open.

This fire protection isolation valve is' normally closed in all.

!

modes and. opened only if required to combat a fire inside containment.

'

Investigations indicated that the last time the valve was cycled was

during a slave relay test on June 7.1996.

At that time. all

. restoration steps were signed off and independently verified indicating

the valve was restored to its normally closed position following the

i

. slave relay test.

'

Corrective actions for this violation included shift. briefings,

procedural revisions and partial performance of some system alignments.

The inspector reviewed Operation Procedure 10000-C, " Conduct of

Operations," Revision 36. dated March 12, 1997.

This procedure had been

revised to clarify expectations for periodic, methodical observations of

control board indications-and system alignments. The ins)ector also

reviewed Operations Procedure 14228-1/2. " Operations Mont11y

Surveillance." Revision 19. dated November 13. 1997.

This procedure had

i

been revised to include additional position checks of safety-related

i

valves and dampers.

The inspector verified by discussion with operators

that the interim measure of partial system alignments had been

i

accomplished. However, additional configuration control problems were

identified in subsequent inspections. The effectiveness of this

corrective action will be verified during closecut of the items

a

identified subsequent to this inspection.

This item is closed.

,

Enclosure 2

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25

E8.2 (Closed) Violation 50-424/96-02-04:

Pressurizer Safety Valve Testing

Inadequate Corrective Action

Corrective actions for this violation included rework of valve 1-PSV-

8010C. The rework included replacement of a worn bellows / disc holder

assembly.

Following rework, the valve was retested and exhibited good

re)eatability of lift set)oint.

The inspectors reviewed the test data

tacen following the rewort and concluded that the rework effort had been

successful in improving the repeatability of the valve lift setpoint.

,

Additional corrective actions included performing an engineering

analysis to determine the possibility of an increase in setpoint

tolerance.

The inspectors reviewed 'an interoffice correspondence dated

January 31. 1997, which indicated that Westinghouse had performed an

evaluation with respect to an increase in the setpoint tolerance. The

evaluation concluded that the setpoint tolerance could be revised from

2485 ! 1% to 2460

2%.

The inspectors determined from discussions with

the licensee's staff that a proposed change to Technical Specifications

was being generated to allow the setpoint and tolerance change.

This item is closed.

IV.

Plant Support

'

.

R1

. Conduct of Plant Support Activities

R1.1 General Comments (71750)

Plant support activities were observed and reviewed to ensure that

!

licensee programs were implemented in conformance with facility policies

and procedures and in compliance with regulatory requirements.

Activities reviewed included radiological controls, physical security,

emergency preparedness, and fire protection.

R2

Status of Radiological Protection and Chemistry Facilities and Equipment

i

R2.1 Unit 1 Soray Additive Tank Contents Transfer

a.

Inspection Scope (71750)

The inspectors reviewed the licensee's preparations and actions

associated with removal of sodium hydroxide from the Unit 1 spray

'

additive tank.

This included attending the pre-evolution brief:

review

of Temporary Procedure T-CHEM-97-01. " Transfer. Neutralization and

Disposal of the Spray Additive Tank Contents"; and review of the

associated safety evaluation.

The inspectors also conducted a walkdown

I

of the equipment used in this evolution.

Enclosure 2

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26

b.

Observations and Findinas

On April 24, 1997, the licensee transferred the liquid sodium hydroxide

contained in the Unit 1 spray additive tank to the south neutralization

tank adjacent to the water treatment plant.

The Unit 1 spray additive

tank was removed from service: the contents were transfer 7d to allow

neutralization prior to final waste discharge.

The transfer was

accomplished with a portable pump through a hose. The hose was routed

'

from the spray additive tank room in Level D of the auxiliary building,

up an auxiliary building stairwell, and across a portion of the

protected area to the neutralization sump.

-

.

The pre-evolution brief was well done.

Representatives from appropriate

l

work groups participated. The brief was detailed and clearly laid out

the expected conduct of the evolution.

Contingency measures for

potential problems were also discussed.

Likewise, the procedure was

well done.

The inspectors noted detailed precautions and limitations as

well as appropriate steps for accomplishment,

j

Following the 3re-evolution brief, the inspectors questioned operations

personnel on t1e potential impact that the open doors for this evolution

would have on-the piping penetration area fiItration and exhaust system.

Specifically, the inspectors were concerned that opening auxiliary

'

building doors to route the hose could degrade the capability of the

system to maintain a negative pressure in the penetration areas.

These

-

individuals could not identify any such impact.

However, they did note

that a contingency measure discussed at the pre-evolution brief was to

close the doors in the event of a radiological incident.

During the walkdown, the inspectors observed that open auxiliary

building doors, used to route the transfer hose, established a flowpath

between the atmosphere and two rooms served by the piping penetration

area filtration and exhaust system.

Later the same day the cognizant engineering manager informed the

inspectors that based on his own concerns he had determined that a

hazards review was not conducted as part of the develo) ment of T-CHEM-

97-01.

A deficiency card and hazards analysis were suasequently

generated.

c.

Conclusion

Strengths were noted in the licensee's pre-evolution brief and procedure

for transfer of the Unit 1 spray additive tank contents.

However,

pending .further inspector review of the hazards analysis and the safety

evaluation this issue is identified as an Unresolved Item (URI) 50-

424/97-04-07. Adequacy of Licensee's Safety Evaluation For Sodium

Hydroxide Transfer.

4

Enclosure 2

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27

P2

Status of Emergency Preparedness (EP) Facilities, Equipment, and

Resources

P2.1 Facility Inspection

a.

Jn_spection Scono (82701)

The inspectors examined the licensee's emergency response facilities

(ERFs) and equipment to assess their adequacy and to determine whether

they were maintained in a state of operational readiness.

,

b.

Observations and Findinos

The inspectors toured the Main Control Room. Technical Support Center

(TSC). Operations Support Center (OSC). and Emergency Operations

Facility (EOF).

Selected equipment and supplies within these facilities

were inspected. All tested equipment was found to be in operable

condition. Miscellaneous instruments and supplies in the various

facilities were selectively examined.

With one exception involving

outdated procedures (discussed in detail in Section 3.2. below). no

significant discrepancies were identified.

Records of surveillances and periodic tests of emergency supplies and

equipment governed by the following procedures were inspected for the

period October 1. 1995 to March 31. 1997:

91204-C. " Emergency Response Communications"

91702-C, " Emergency Equipment and Supplies"

>

91705-C. " Inventory and Testing of Emergency Preparedness

>

Material / Equipment Which Are Not Part of the Emergency Kits"

14400-1. " Control Room Emergency Filtration Actuation Logic Test"

>

54031-C. " Technical Support Center HVAC [ Heating. Ventilation, and

>

Air Conditioning] System Test"

54039-C " EOF Filtration System HEPA [High-Efficiency Particulate

Air] Filters Test"

Surveillances and tests as specified by the above procedures were

performed at the required frequencies.

No discrepancies were noted by

'

the inspectors.

Licensee documentation indicated that deficiencies

identified during the surveillances were expeditiously corrected.

c.

Conclusions

ERFs were well equipped and were maintained at a suitable level of

operational readiness.

Enclosure 2

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.,

P2.2 Public Alert And Notification System

a.

Insoection Scone (82701)

The inspectors reviewed the licensee's methodology for notifying the

public in the event of an emergency, and the results of system testing

during 1995 and 1996.

b.

Observations and Findinas

,

The licensee maintained a public alert and notification system

consisting of 47 sirens and approximately 1100 tone-alert radios within

the 10-mile Emergency Planning Zone (EPZ) around the Vogtle Plant. The

inspectors reviewed the licensee's siren maintenance program and the

summary data, as provided to the Federal Emergency Management Agency

(FEMA). for 1995 and 1996 testing of the siren warning system.

For the

47 sirens. the aggregate success rates of the weekly silent tests and

annual full-cycle test were 99% for 1995 and 97% for 1996.

The

applicable acceptance criterion used by FEMA for such test results is

90 percent,

c.

Conclusions

The operational status of the siren system exceeded the minimum

requirements established by FEMA.

P3

EP Procedures and Documentation

P3.1 Emeraency Resoonse Plan

a.

Insoection Scone (82701)

The inspectors reviewed the licensee's maintenance of the Emergency Plan

f

(Plan) and selected commitments therein, and reviewed recent revisions

to the Plan to determine whether changes were mede in accordance with

10 CFR 50.54(q).

b.

Observations and Findinos

The version of the Plan in effect at the time of the current inspection

was Revision 25. approved by the General Manager on April 15. 1997. The

last Plan revision formally reviewed by the NRC was Revision 23. dated

April 1.1996.

Revision 24 contained administrative modifications

exclusively, addressing the recent change in assignment of the facility

i

operating license from Georgia Power Company to Southern Nuclear

Operating Company.

Revision 25 included a variety of minor editorial

and substantive modifications resulting from the licenseets annual

l

review of the Plan.

Enclosure 2

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29

Between the previous inspection of the licensee's EP program (in

i

l

September 1995) and the ending date of the current inspection, emergency

declarations were made by the licensee on October 25 and November 15,

1996, both at the Notification of Unusual Event (NOVE) level.

These

declarations occurred as a result of the loss of a significant portion

of the Control Room annunciators. The inspectors examined documentation

for these two NOUE declarations, and concluded that each was correctly

classified based on the -licensee's emergency action levels (EALs), and

that. notifications to cognizant offsite authorities were made in

accordance with requirements regarding timeliness and content.

l

Documental review confirmed the licensee's conduct of the required

i

annual review of EALs with State and local governmental authorities for

!

1995 and 1996.

lhis review was accomplished annually by means of a

'

formal presentation to cognizant officials.

No dissenting observations

or comments were received from those agencies, according to the

l

licensee.

l

c.

Conclusions

Changes to the Plan via Revisions 24 and 25 were made in accordance with

i

10 CFR 50.54(q).

Emergency declarations by the licensee on October 25

and November 15. 1996 were made in accordance with the Emergency Plan

Implementing Procedures (EPIPs).

l

P3.2 Plant Emeraency Procedures

a.

Insoection Scope (82701)

The inspectors reviewed the licensee's administration of selected Plan

requirements through evaluation of the adequacy of the implementing

details contained in the EPIPs.

b.

Observations and Findinas

The inspectors reviewed the primary and alternate means used by the

licensee to notify its Emergency Response Organization (ERO) personnel

if an emergency is declared during off-hours.

These processes were

described in EPIP 91204-C " Emergency Response Communications"

The

automated calling system, activated by Security used a comparatively

advanced software program to methodically fill ERO positions as

personnel called in response to the notification by the system.

In the

event of this system's unavailability, the alternate methodology was a

straightforward manual call-out by Security personnel via individual

'

telephone contacts and/or a group page.

The backup system was described

in Section 5.9.2.5 of EPIP 91204-C only in general terms: no details

were specified in this or other EPIPs.

Since the alternate system

discussed here was not addressed in the Plan. implementing details were

l

not required to be provided in the EPIPs.

The ' inspectors verified that

l

appropriate implementing documents / procedures were available (outside

l

Enclosure 2

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30

the framework of the EPIPs) to Security personnel by means of a walk-

through interview with a Security Shift Captain.

However, the

inspectors learned that the licensee had never conducted a test or drill

of the manual backup system for ERO call-out.

This system had been

<

instituted because the licensee considered it prudent to have a backup

to the automated system.

The inspectors discussed the desirability of

'

conducting a test of the manual system at some reasonable frequency in

order to identify any procedural deficiencies and to provide training to

'

potential users.

Licensee management agreed with this view, and

informed the inspectors that they planned to conduct a test of the

t

backup system for off-hour ERO notification by December 31, 1997.

L

Selected copies of the Plan and EPIPs which were available for use at

l

the Control Room. TSC OSC. and EOF were checked and found to be current

revisions, with one significant exception.

In the OSC Manager's office,

i

there was one copy of the EPIPs (manual set No. 55).

The ins)ectors'

l

review of this manual determined that the following eight EPI)s were

outdated by one revision level: 91001-C. 91105-C. 91107-C. 91110-C.

'

91702-C. 91705-C. 91706-C. and 91801-C.

(An apparently unrelated

discrepancy was that EPIP 91306-C was missing from the procedure

manual.) The licensee issued Deficiency Card No. 1-97-197. and took

prompt corrective action to bring the EPIP manual up to date.

Preliminary review of this matter indicated that, in approximately

November 1996. Document Control personnel had discontinued the updating

of EPIP manuals in the ERFs.

This occurred as a result of a

misunderstanding or miscommunication between the Document Control and EP

staffs.

The EP Coordinator, whose office was adjacent to the E0F.

quickly identified the discre]ancy at the EOF because he was not

receiving copies of revised E3IPs.

Subsequently the same problem for

the TSC was independently identified and corrected by a member of the

Document Control staff, but was not reported to the EP Coordinator.

The

generic nature of the EPIP distribution problem was thus not d". closed

because the licensee did not conduct an adequate root-cause

investigation.

This issue represented a failure to follow the Plan as

implemented by the requirements of EPIP 91701-C. " Preparation and

Control of Emergency Preparedness Documents". Revision 7. dated

08/04/95. which stated in Section 2.3 that "The DOCUMENT CONTROL

SUPERVISOR is responsible for:

.. Maintaining all documents in all ERFs

up to date." Table 1 of this procedure listed the applicable documents,

among which was the "VEGP Emergency Plan Implementing Procedures" in the

OSC.

c.

Conclusions

Based upon selective review, the licensee's EPIPs were determined to be

generally thorough in terms of detail needed to implement the various

requirements and commitments in the Plan.

The document control

discrepancy in the OSC is identified as Violation 50-424,

50-425/97-04-08.

Failure to Maintain Copies of EPIPs Up to Date in all

Required Storage Locations.

Enclosure 2

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31

P5

Staff Training and Qualification in EP

,

P5.1 Trainina of Emeroency Response Personnel

a.

Insoection Scooe (82701)

The inspectors conducted a broad-pers)ective review of the training

i

program for the ERO to determine whetler Plan requirements and the

intent of regulatory requirements were being met.

'

b.

Observations and Findinas

The inspectors reviewed Emergency Plan Section 0, addressing training of

emergency response personnel, and the associated implementing

procedures, and interviewed Training Department managers.

The Plan

included the requirement for general overview and specialized training

for all ERO 3ersonnel (clearly delineated by position in the detailed

matrix of Taale 0-2).

Integrated response drills were conducted

regularly (3-4 times per year) to provide drill experience for ERO

,

l

personnel, although no systematic tracking of personnel participation

l

was used to ensure optimal utilization of this component of the training

j

l

program.

c.

Conclusions

i

The licensee's ERO training program was being conducted in accordance

with Plan training commitments.

P6

EP Organization and Administration

P6.1 Proaram Manaaement Chanaes

j

a.

Insoection Scope (82701)

The inspectors reviewed this area to determine if any changes in

management or personnel had occurred which could negatively affect the

,

management and implementation of the EP program.

b.

Observations and Findinas

l

The organization and management of the EP program were reviewed and

.

!

discussed with licensee representatives. The organizational

l

relationship between the EP Coordinator and upper plant management had

l

'

not changed since the September 1995 inspection.

The current EP

Coordinator was planning to retire as of May 1. 1997. The individual

selected as his replacement had been an assistant to the EP Coordinator

for the past 11 years, and was knowledgeable and experienced in the

field of emergency preparedness.

Enclosure 2

i

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.

.

32

-c.

Conclusions

No degradation had occurred in the organization or management of the EP

,

3rogram, nor is any expected to occur with the reassignment of the EP

!

Coordinator position.

P7

Quality Assurance in EP Activities

P7.1 10 CFR 50.54(t) Audit of Emeroency Preoaredness Procram

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a.

Insoection Scooe (82701)

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The inspectors reviewed this area to assess the quality of the required

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annual audit and to verify that the audit met the requirements of

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10 CFR 50.54(t).

b.

' Observations and Findinas

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The licensee's Safety. Audit and Engineering Review (SAER) Department

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conducted the required annual independent audits of the EP program in

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1996 and 1997.

The February 1996 audit, documented as Audit

No. OP12-96/08 . identified no " unacceptable areas", but provided

" comments" on five minor deficiencies. The January 1997 audit,

documented as Audit No. OP12-97/02. identified no " audit findings". but

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included two comments and one recommendation.

Based upon review of the.

audit reports and the auditors' checklists, these audits were judged to

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be thorough and appropriately detailed.

c.

Conclusions

The SAER audits fully satisfied the 10 CFR 50.54(t) requirement for an

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annual independent audit of the EP program.

V.

Manaaement Meetinas and Other Areas

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Review of Updated Final Safety Analysis Report (UFSAR)

A recent discovery of a licensee o)erating its facility in a manner

contrary to the UFSAR description lighlighted the need for a special

focused review that compares plant practices. procedures and/or

parameters to the UFSAR descriptions. While performing the inspections

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discussed in this re) ort. 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.

Enclosure 2

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X1

Exit Meeting Summary

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The inspectors ) resented the inspection results to members of licensee

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management at tie conclusion of the inspection on April 29, 1997.

The

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licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during

the inspection should be considered proprietary.

No proprietary

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information was identified.

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X2

Pre Decisional Enforcement Conference Summary

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On April 18. 1997, a pre-decisional enforcement conference was held at

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the NRC Region II office to discuss a potential enforcement issue

identified in Inspection Report 50-424, 425/97-02. The issue related to

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an improperly surveyed and shipped package.

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PARTIAL LIST OF PERSONS CONTACTED

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Licensee

J. Beasley Nuclear Plant General Manager

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R. Brown. Manager. Training and Emergency Preparedness

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W. Burmeister Manager Engineering Support

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D. Carter. Su>ervisor. SAER

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S. Fields. Supervisor. Nuclear Steam Supply System Design Team

S. Chestnut. Manager Operations

J. Gasser. Plant Operations Assistant General Manager

P. Grissom Senior Engineer

K. Holmes. Manager Maintenance

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D. Midlik. Senior Engineer

J. Roberts. Emergency Preparedness Coordinator

R. Robinson. Nuclear Specialist

P. Rushton. Plant Support Assistant General Manager

M. Sheibani. Nuclear Safety and Compliance Supervisor

C. Stinespring. Manager. Plant Administration

E. Talton. Project Engineer

C. Tippins, Jr.

Nuclear Specialist I

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INSPECTION PROCEDURES USED

IP 37551:

Onsite Engineering

IP 61726:

Surveillance Observation

IP 62703:

Maintenance Observation

Enclosure 2

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IP 62707:

Maintenance Observation

IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

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IP 82701:

Operational Status of the Emergency Preparedness Program

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TI 2515/109:

Inspection Requirements for Generic Letter 89-10

ITEMS OPENED AND CLOSED

Ooened

50-424/97-04-01

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Containment Debris Identified During 1P1

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(Section 01.2)

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50-424/97-04-02

URI

Unit 1 Unplanned Negative Reactivity Addition

(Section 01.3)

50-424/97-04-03

NCV

Inadequate Maintenance Instructions For DG Air

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Damper Stroking (Section M1.4)

50-424. 425/97-04-04

URI

P-4 Interlock Testing of Reactor Trip Bypass

Breakers (Section M8.1)

50-424. 425/97-04-05

NCV

Inadequate P-4 Circuit Testing (Section M8.1)

50-424.425/97-04-06

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Actions to Address GL 89-10 Inspection Issues

(Section E1.3.c)

50-424/97-04-07

URI

Adequacy of Licensee's Safety Evaluation For

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Sodium Hydroxide Transfer (Section R2.1)

50-424. 425/97-04-08

VIO

Failure to Maintain Copies of EPIPs Up to Date

in all Storage locations (Section P3.2)

Closed

50-424, 425/96-14-03

EEI

Configuration Control Deficiencies Involving

Mispositioned Components and Improper

Independent Verification (Section 08.1)

50-424/97-04-03

NCV

Inadequate Maintenance Instructions For DG Air

Damper Stroking (Section M1.4)

50-424, 425/97-04-05

NCV

Inadequate P-4 Circuit Testing (Section M8.1)

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50-424. 425/96-14-06

URI

Potentially Inadequate Surveillance Testing of

P-4 Circuitry (Section M8.1)

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50-424/97-002

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P-4/ Turbine Trip Circuit Not Surveillance Tested

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(Section M8.1)

Enclosure 2

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50-424. 425/96-12-02

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Failure to Take Effective Corrective Actions To

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Assure MCC Door Latches Are Properly Secured and

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(Section MB.2)

50-424/97-003

LER

Unlatched Doors On Motor Control Centers Changes

Seismic Qualifications (Section M8.2)

50-424/96-09-02

VIO

Mispositioned Unit 1 Fire Protection Header

Containment Isolation Valve (Section E8.1)

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50-424/96-02-04

VIO

Pressurizer Safety Valve Testing Inadequate

Corrective Action (Section E8.2)

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Enclosure 2

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