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Insp Repts 50-424/89-27 & 50-425/89-31 on 890916-1027. Violations Noted But Not Cited.Major Areas Inspected:Plant Operations,Radiological Controls,Maint Surveillance, Security & Administrative Controls Affecting Quality
	ML19332E617
Person / Time
Site:	Vogtle
Issue date:	11/22/1989
From:	Aiello R, Brockman K, Rogge J; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML19332E616	List: IR 05000424/1989027; ML19332E615;
References
	50-424-89-27, 50-425-89-31, NUDOCS 8912080082
	Download: ML19332E617 (29)
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UNITE 3 STATES

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Report Nos.:

50-424/89-27 and 50-425/89-31 Licensee:

Georgia Power Company

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P.O. Box 1295 l

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Birmingham, AL 35201

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' Docket Nos.:

50-424 and'50-425 License Nos.: NpF-68 and NPF-81

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Facility Name: Vogtle Units 1 and 2 P

Inspection Conducted:

September 16 - October 27, 1989 l

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/dE2 M Inspectors: 0 nc

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i J.~ FAogge, Senior Residentynspector Date Signed

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Ri'T A ello, Resident Inspettor

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Accompanied by:

Robert D. Starkey I'

' Approved By:

N# M N - 2 2-e c)

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. Broi:kmin, h etion Chief Date Signed O vision of Reactor Projects

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SUMMARY Scope:

This routine inspection entailed resident inspection in the following areas:

plant operations, radiological controls, maintenance, i

surveillance, security.. and quality programs and administrative controls affecting quality.

Results:.In the areas inspected, one non-cited violation pursuant to the discretionary provisions of the NRC Enforcement Policy, four i

inspector follow-up items, and three unresolved items were identified. The non-cited violation involved a failure to c6nduct a

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monthly visual inspection on containment fire extinguishers as required by Section 4.3.1 ~ of NFPA-10 (paragraph 3.b(1)(f)).

The four IFIs identified involved the verification of complete installation of canvas tool bags on chain hoists located over safety-related equipment (paragraph 1.b(2)), review of the improvement program for

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the control of scaffolding (paragraph 1.b(2)), the review of revisions to procedures 00255-C and 81090-C regarding 10 CFR Part 21

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(paragraph 5), and the review of a report regarding the analysis of the aluminum content in containment with respect to hydrogen generation during adverse conditions (paragraph 3.b(1)(f)).

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8912090092 891122 PDR ADOCK 05000424

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The three unresolved items, which may become violations, involve

minipurge operation in 1988 (paragraph 2.a), the improper liunsee u

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interpretation of high energy line break protection requirements l

(paragraph 3.b(2)), and ISEG having a membership of less-than five

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(paragraph 6).

Weaknesses were 'identifie'd in plant operations, maintenance, and

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quality programs.

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The weakness identified in the area of maintenance was with regards j

U to housekeeping practices.

In particular, the use of "in process"

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tags to track material was failing to ensure the removal of material

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when expiration dates were exceeded. Secondly, scaffolding was left j

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in place long after work was complete (paragraphs 2.b(1) and 2.b(2)).

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The weakness -in plant operations involved the verification of

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L-operator qualification prior to assuming control.

No procedure or practice exists where the off-going operator or shift supervisor

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verifies 'that the on-coming watchstander is in a qualified status

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(paragraph 4).

The weakness in quality programs was in the area of ISEG membership

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F and PRB action tracking.

The fact that the ISEG staff was below

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minimum staff level, combined with the lack of a priority replacement-i plan, directly challenged the functionality of the group.

The PRB

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weakness involved the failure to approve or document a reason for

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L not approving an extension of assigned action item due dates j

(paragraph 6).

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Strengths were also noted in the plant operations, maintenance, and

quality programs areas.

In the plant operations area, the performance and knowledge of the

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-operators in moving spent fuel from the Unit 1 to the Unit 2 spent

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fuel pool was noteworthy (paragraph 2.b(8)).

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S In maintenance, the control, planning, and execution of the Unit 2 L

snubber outage was a strength.

In addition, this strength in minor outage planning has been previously noted (paragraph 2.b(7)).

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In the quality programs area, the membership of the PRB has been

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changed to Department. Managers, in lieu of. Supervisors of b

Departments.

While this has always been allowed by technical

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specifications, the phnt previously held membership at the minimum managerial level allowed (paragraph 6).

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DETAILS 1.

Persons Contacted i

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Licensee Employees

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J. Aufdenkampe, Plant Engineering Supervisor l-O '

G. Bockhold, Jr., General Manager Nuclear Plant

C. Coursey.. Maintenance Superintendent

G. Frederick, Safety Audit and Engineering Group Supervisor

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H. Handfinger, Manager Maintenance

W. Kitchens, Assistant General Manager Plant Operations

R. Legrand, Manager Chemistry and Health physics

G. McCarley, Independent Safety Engineering Group Supervisor C. McCoy, Vice President-Nuclear

A. Mosbaugh, Plant Support Manager W. Mundy, Quality Assurance Audit Supervisor

R. Odom, Nuclear Safety and Compliance Manager J. Swartzwelder, Manager Opere.tions

C. Stinespring, Manager Plant Administration Other licensee employees contacted included technicians, supervisors, engineers, operators, maintenance personnel, quality control inspectors, and office personnel.

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Attended Exit Interview

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An alphabetical list of acronyms and initialisms is located in the last

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paragraph of the inspection report, 2.

Operational Safety Verification - (71707)(93702)

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The facility began this inspection period with both units at 100% full

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power.

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Unit 1:

On. September 30, 1989, reactor power was reduced to 75% to conduct an outage on the "A" MFPT. On October 2, with power ascension in progress at 87% power, the reactor tripped on Low Low level in the #1 steam generator.

This occurred as a result of MSIV 3006A shutting due to a blown fuse. The unit subsequently entered Hot Standby (Mode 3).

On October 3, the unit conducted a cooldown to facilitate repairs to Source Range NI-31.

On October 5, with repairs on MSIV 3006A and NI-31 completed, the unit entered Startup (Mode 2), went critical, and entered Power Operation (Mode 1). On October 6, the unit was synchronized to the grid and resumed full power operations.

It remained there, with the exception of minor reductions for maintenance, through the end of this inspection period.

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Unit 2:

On October 6, 'the unit was shutdown to facilitate the completion of the

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first visual snubber inspection outage.

On October 8, the unit entered Hot Shutdown (Mode 4) to facilitate containment entry.

On October 10, following completion of the snubber inspections, the unit entered Mode 2 t

and went critical. On October 11, the unit entered Mode 1 and tied to the L

grid.

Later that same day, an automatic reactor trip occurred as a result

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of a dropped control rod.

On October' 12, with control rod repairs and f

testing completed, the unit re-entered Mode 2, went critical, re-entered

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Mode 1, synchronized to the grid, and resumed full power operations. The

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unit remained at full power, with the exception of minor power reductions for maintenance, through the end of this inspection period.

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On October 16, a CVI occurred due to an inadvertent data processing module on radiation monitor 2RE-2656 de-energizing and reenergizing during t

surveillance, a.

Control Room Activities Control Room tours and observations were performed to verify that facility operations were being safely conducted within regulatory requirements.

These inspections included one or more of the following attributes, as appropriate at the time of the inspection:

- Proper Control Room staffing

- Control Room access and operator beha>ior

- Adherence to approved procedures for activities in progress

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- Adherence to technical specification limiting conditions for operation

- Observance of instruments and recorder traces of safety-related and important-to-safety systems for abnormalities

- Review of alarmed annunciators and actions in progress to correct them

- Control Board walkdowns

- Safety parameter display and the plant safety monitoring system

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operability status

- Discussions and_ interviews with the On-Shift Operations Supervisor, Shif t Supervisor, Reactor Operators, and the Shif t Technical Advisor (when stationed) to determine the plant status, plans, and to assess operator knowledge

- Review of the operator logs, unit logs, and shift turnover sheets On October 1,1989, during a deep backshift, the inspector observed the Unit 1 operators vent pressure from containment.

During this

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evolution, the inspector noted that Unit 2 had been purging i

containment since 1:50 a.m.

Discussion with the Shift Supervisor indicated that Unit 2 had vented containment prior to this evolution (September 30 from 7:17 p.m. to 8:32 p.m.) and had reduced pressure from.877 psig to

.015.

During the Unit 2 venting operation, a humidity alarm was received.

The purging was being performed to reduce the humidity.

On October 2, after reviewing Technical

Specification 3.6.1.7, the inspector raised the concern that l

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humidity control was not a valid reason for opening the 14-inch

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containment purge supply and exhaust valves, h

i Licensee management reviewed the evolution and informed the inspector L

that they were allowed to open these valves for pressure control, as l

had been checked on the Release Permit.

In addition, continuous purging was a method to control pressure.

This practice had been

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h utilized by Unit I since its licensing until the beginning of 1989.

F In response to comments from other outside parties, they elected to L

use the venting method.

When venting, containment pressure is reduced to.3 psig and then exhaust vans are used.

During the

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F process, prior to starting the exhaust fans, humidity alarms may be

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received in the charcoal HEPA filtration system.

This is due to a

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design where the moisture control heaters are interlocked with the fan. Upon starting the fan, heaters are energized and moisture is normally removed within five minutes.

During the Unit 2 venting on September 30,- the alarm failed to clear and the operator determined

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that purging, as described in the procedure, was necessary.

Purging was performed from 1:50 a.m. until 3:45 p.m. when a Maintenance Work

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Order was issued to investigate the problem.

Maintenar.ce determined that both the control and alarm were set at 60%.

The alarm should have been. set at 70%.

c Inspector review of procedures 13125-1, Rev. 9, and 13125-2, Rev. 4, F

noted that each procedure describes that an alarm may be received in step 2.2.8 and directs purging by step 4.1.2 until the alarm clears after pressure relief is complete.

The procedure is inadequate in that it does not provide guidance on an expected time for accomplishment. Engineering informed the inspector that five minutes r

should be sufficient and normally the alarm would clear before the venting process was completed.

The inspector also reviewed alarm response procedures 17052-1,

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Rev. 4, and 17052-2, Rev. 2, for alarm window B07.

The listed probable cause did not include the venting of containment.

The procedure does identify that a malfunction could exist and maintenance should investigate.

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Datawasprovidedtotheinspectorasfoklows:

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Time No. of Curies Exposure Dates (br)/%

Releases

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(mrem /yr]

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152.48/3.49 129 18.9 7 E-03 June 30, 1989 July 1, 1988 -

3632.35/83.16

24.69

.89 December 31, 1988 January 1, 1988 -

4200.22/96.16

28.37 1.8 June 30, 1988

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L The above data for Unit I was not annotated with when the unit was in Modes 1, 2, 3, or 4.

However, the data illustrates the effect that reduced venting has on lowering potential dosos to the public.

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The technical specification compliance is not based on limiting these releases but is based on reducing the probability that the valves would be challenged in an actual event.

By maintaining the valves closed to the maximum extent practicable, with openings made only for safety-related reasons, the likelihood of a challenge is reduced.

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(Note the obvious decline from 96.16% to 3.49%. )

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misunderstood this concept and determined that the mini purge valves

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may be opened continuously for pressure control.

The Assistant General Manager for plant operation's committed to establish a policy to define what " maximum extent practicable" would mean and revise procedures 17052 and 13125 to incorporate guidance.

While a minor violation occurred with regard to the excessive purging conducted to clear the humidity alarm where procedures were inadequate, the issue of technical specification compliance prior to 1989 is under review by NRC.

This item is identified as an

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unresolved item and is tracked as:

URI 50-424/89-27-01 and 50-425/89-31-01, " Resolve Issue Of TS 3.6.1.7 Mini-Purge Valve Operation During 1988."

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Facility Activities Facility tours and observations were performed to assess the effectiveness of the administrative controls established by direct u

observation of plant activities, interviews and discussions with licensee personnel, independent verification of safety systems status and LCOs, observation of licensee meetings, and review of f acility records.

During these inspections, the following objectives were achieved:

(1) Safety System Status - Confirmation of system operability was obtained by verification that flowpath valve alignment, control and power supply alignments, component conditions, and support systems for the accessible portions of the ESF trains were proper.

The inaccessible portions were confirmed as availability permitted.

During a routine walkdown of both control buildings, the inspector observed a wide range of nitrogen pressures on containment electrical penetrations.

The inspector identified that, except for required LLRTs which are conducted at intervals of no greater than 24 months, the licensee hac neither a program for periodically monitoring the nitrogen pressure on these penetrations nor had a standard pressure been established.

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l The licensee. agreed to begin monitoring, on a quarterly basis,

the nitrogen pressures of containment electrical penetrations.

l This monitoring has been incorporated into the operations " Daily Schedule Control Sheet" for non-technical specifications

activities. When any of these electrical penetrations indicates less that 10 psig or greater than 35 psig of nitrogen pressure an MWO will be initiated to either recharge or depressurize the unit.

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The licensee has a program, defined by procedure 00352-C, Rev.1, " Control Of In-Process Materials," to control those

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materials which have been removed from permanent storage or

' installed locations for the purpose of rework, repair, modification, calibration, testing or cleaning.

"In-Process"

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tags are issued by Supervisors / Foremen with an assigned

expiration date based upon the estimate as to when the r

associated work will be completed and/or the equipment will no longer be needed.

In process status also applies to bulk material or consumables which are being temporarily stored. The

inspectors observed numerous "In-Process" tags throughout the I

plant which exceeded their expiration dates.

In several instances, the expiration date was exceeded by weeks or months, and the associated material was still in service.

Procedure 00352-C provides guidance as to how expiration dates may be extended.

Due to the large volume of expired

"In-Process" tags, it is apparent that the licensee has failed r

to maintain adequate control of the "In-Process Material"

' tagging system. This lack of control over "In-Process Material" g

is identified as a program weakness.

l (2) Plant Housekeeppg Conditions Storage of material and

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components and cleanliness conditions of various areas throughout the facility were observed to determine whether safety and/or fire hazards existed.

The-insnector reviewed the licensee's method of requesting, reviewing, approving and constructing scaffolding.

Procedure 20003-C, Rev. 3. "Scaf folding Construction And Control" was developed from RER 87-0921 which established generic criteria for requirements on scaffolding to address the "two over one" concern.

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While procedure 20003-C adequately addresses the actual mechanics of scaffolding installation, the inspector noted

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through plant walkdowns and interviews that the procedure is

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deficient in other areas.

First, the procedure does not emphasize prompt installation and removal of scaffolding which is erected near safety-related equipment.

The inspectors noted examples of such scaffolding which had been installed for weeks.

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the scaffolding coordinator.

Second, there is no requirement

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k to notify the control room prior to the installation or removal of scaffolding near safety-related equipment. In practice, the

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control room is often notified.

There is also no required

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documentation on the MWO form to indicate scaffolding

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installation or removal, which was one of the original recommendations of RER 87-0921. Finally, the procedure does not

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clearly state who is responsible for communicating to the scaffolding coordinator that work has been completed and scaffolding.should be removed.

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The licensee plans to develop a computer program to track scaffolding installation and to refererce scaffolding installation to a specific MWO, where appropriate. The licensee s

foresees having such a program in service early in 1990.

To review the licensee improvement action, the following tracking item is established.

Until evidence of control is noted, the

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current program is considered to be a weakness.

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IFI 50-424/89-27-02 and 50-425/89-31-02, " Review Improvement

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Program For Control Of Scaffolding."

A second concern was identified when the inspector observed

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'several examples of chain hoists in safety-related pump rooms

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I which had chains suspended directly above or resting against the safety related pump, motor, or piping. The licensee agreed that

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a more secure and safe location could be derived for the chains.

The licensee's solution was to attach a canvas tool bag to each chain, place the chain inside the bag, and move the chain from directly above the pump.

The licensee has taken steps to insta11' the bags in all chain hoist locations above safety related pumps and to review the possibility of installing them on chain hoists located above non-safety related equipment.

Additionally, the engineering staff will determine the preferred storage location for the chain hoist on the monorail and indicate that preferred location by the placement of signs or by painting the railing.

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.Since complete implementation of this item is ongoing, it is identified as:

IFI 50-424/89-27-03 and 50-425/89-31-03, " Verify Complete Implementation Of Canvas Bags Over Equipment."

(3)

Fire protection - Fire protection activities, staffing, and equipment were observed to verify that fire brigade staffing was appropriate and that fire alarms, extinguishing equipment, actuating controls, fire fighting equipment, emergency equipment, and fire barriers were operabl S'

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One problem regarding surveillance of fire extingusihers in containment was identified.

(See DC 2-89-1446, paragraph

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3.b(1)(f)).

(4) Radiation Protection Radiation protection activities,

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staffing, and equipment were observed to verify proper program implementation. The inspection included a review of the plant L

program effectiveness.

Radiation work permits and personnel compliance were reviewed during the daily plant tours.

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Radiation Control Areas were observed to verify proper identification and implementation.

(5) Security - Security controls were observed to verify that security barriers were intact, guard forces were on duty, and (

access to the Protected Area was controlled in accordance with i

the facility Security Plan.

Personnel were observed to verify L

the proper display of badges and that personnel requiring escort l

were properly escorted.

Personnel within Vital Areas were

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observed to ensure they had proper authorization for the area.

Equipment operability or proper compensatory activities were verified on a periodic basis.

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(6) Surveillance (61726)

Surveillance tests were observed to

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i verify that approved procedures were being used, qualified personnel were conducting the tests, tests were adequate to verify equipment operability, calibrated equipment was utilized, and technical specification requirements were followed.

The inspectors observed portions of the following surveillances and/or reviewed completed data against acceptance criteria:

Surveillance No.

Title 14423-1, Rev. 6 Source Range Analog Channel Operability Test 14495-1, Rev. 3 AFW System Flow path Verification 14545-1, Rev. 5 MDAFW pump Monthly Operability Test 14803-2. Rev. 2 CCW Pumps And Discharge Check Valve Inservice Test 14808-2, Rev. 3

"B" CCP And Check Valve Inservice Test 14980-1, Rev. 15 Diesel Generator Operability Test l

(7) Maintenance Activities (62703)

The inspector observed

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maintenance activities to verify that correct equipment clearances were in effect, work requests and fire prevention work permits, as required, were issued and being followed,

quality control personnel were available for inspection

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activities as required, retesting and return of systems to j

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service was prompt and correct, and technical specification reauirements were being followed.

Maintenance Work Order backlog was reviewed.

Maintenance was observed and/or work packages were reviewed for the following maintenance activities:

MWO No.

Work Description-28903845 Repair Leaking Valve Bonnet Gasket On CVCS System 28904212 Replace Yarway Weldbond Globe Valve Packing On Feedwater System b

28904429-Repair Inside Housing Leak On SGBD Flow Transmitters 28905578 Repair RCS Fitting Leak

"p The planning and execution of the Unit 2 snubber outage was a strength. One snubber failure occurred when a load cell pin failed to' remain intact.

This failure was resolved.

(8) Spent Fuel Activities (86700) - The inspector witnessed portions t

of three shifts of spent fuel handling operations. Verification was made to ensure that correct procedures with their appropriate revisions' were being used and that the operators were satisfactorily knowledgeable regarding actions to be taken if abnormal. indications were received during fuel handling operations.

On Octcber 20, 1989, fuel assembly 5A32, was lif ted out of SFP #1, position A7, and hoisted.

The bridge crane failed to translate due to a faulty geared limit switch on the hoist motor.

The assembly was reinserted into position A7 to

' facilitate troubleshooting.

Following repair, fuel transfer operations were reinitiated.

On October 23 and 25, the inspectors again observed fuel transfer operations.

The transfers were conducted in an orderly and professional manner which, overall, was considered a strength.

During this -inspection, one URI and two IFIs were identified in this area.

No violations or deviations were identified.

3.

Review of Licensee Reports (90712)(90713)(92700)

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In-Office Review of Periodic and Special Reports This inspection consisted of reviewing the below listed reports to determine whether the information reported by the licensee was

technically adequate and consistent.

Selected material within the report was questioned randomly to verify its accuracy and to provide a reasonable assurance that other NRC personnel have an appropriate document for their activities.

Monthly Operating Report - Reports dated September 14 and October 11, 1989, were reviewed. The inspector had no comments.

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(Closed) Special Report 50-425/89-03, " Area Maximum Normal

Temperature Exceeded."

On September 2,1989, while performing shift surveillance, the room temperature for Auxiliary Building room A107 was logged as - 104 degrees Fahrenheit by the evening shif t.

Subsequently, the night shift PE0 logged the room temperature as 124 degrees Fahrenheit and

,F the following day shift PE0 logged room temperature as 112 degrees L

Fahrenheit. On review of this data, no plant conditions could be identified which could have contributed to this apparent temperature excursion. Technical Specification Table 3.7-3 indicates that the n ximum normal temperature for the room is 115 degrees Fahrenheit and the maximum abnormal temperature is 126 degrees Fahrenheit. Based on the above estimate, the maximum normal temperature for this room may have been exceeded for 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months and 4 minutes.

The environmental qualification master list and a walkdown of the room identified the

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Loop 1 and Loop 4 Main.Feedwater Regulating Valves and the Loop 1 and Loop 4 Main Feedwater Bypass Regulating Valves as the only L

safety-related equipment located in this room. ASCO solenoid valves and NAMCO limit switches are appurtenances of these components and

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are located in this room.

Licensee review of the equipment qualification temperatures for this eauipment determined that this

equipment is qualified for at least 126 degrees Fahrenheit.

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qualified life specified for this equipment is based on the temperature at which it was qualified, not on the maximum normal temperature limit of 115 degrees Fahrenheit. Therefore, the apparent i-temperature excursion which occurred in this event had no adverse affect on the qualified life currently specified for the safety-related equipment in this room. The inspector has no further questions.

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Deficiency Cards and Licensee Event Reports Deficiency Cards. and. Licensee Event Reports were reviewed for potential generic impact, to detect trends, and to determine whether

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corrective actions appeared appropriate. Events which were reported pursuant to 10 CFR 50.72, were reviewed following occurrence to determine if the technical specifications and other regulatory requirements were satisfied.

In-office review of LERs may result in further followup to verify that the stated corrective actions have been completed, or to identify violations in addition to those described in the LER. Each LER was reviewed for enforcement action in accordance with 10 CFR Part 2, Appendix C, and where the violation

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was not cited, the criteria specified in Section V.G of the

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Enforcement Policy were satisfied.

Review of DCs was performed to maintain a realtime status of deficiencies, determine regulatory compliance, follow the licensee corrective actions, and assist as a basis for closure of the LER when reviewed. Due to the numerous DCs processed, only those OCs which resulted in enforcement action or further inspector followup with the licensee at the end of the inspection are listed below.

The DCs and LERs denoted with an asterisk indicate that reactive inspection occurred following the event and prior to receipt of the written report.

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(1) The following_ Deficiency Cards were reviewed:

(a) *DC 1-89-1444, " Automatic Reactor Trip On SG #1 Lo Lo Level Due To MSIV Shutting."

On October 2,1989, an automatic reactor trip occurred on SG #1 Lo Lo level due to MSIV 3006A shutting as a result of a blown fuse, The unit was in power ascension at 87' rated

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power, whtn the trip occurred. _ The unit was stabilized in Mode - 3 and. repairs were made. The post trip corrective action was reviewed.

This event will be further followed up when submitted as a LER.

(b) DC 1-89-1496

" Error In Procedure Leads To Technical Specification 3.0.3 Entry."

On June 14, 1989, while at 100*4 power, handswitches for manual actuation of Containment Isolation - Phase "A" and Containment Ventilation Isolation were tested.

Each handswitch was taken out of service, tested, and returned to-service. On October 13, 1989, while preparing for the re-test, a system engineer identified an error in the procedure which resulted in simultaneously disabling both handswitches.

This condition is in conflict with the requirements of Technical Specification Table 3.3-2 which requires both handswitches to be operable in Modes 1,2,3,4 (and at specific times in Mode 6).

Although during the previous test, LCO entries had been made for each handswitch being out of service, it was not recognized that both handswitches had been out of service. This condition should have resulted in an entry into TS 3.0.3.

This event will be further followed up when submitted as a LER.

-(c) 'DC 1-89-1505, " Loose Parts Monitor Channel Calibration Not Performed Per FSAR 16.3.3."

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The operability of the loose parts monitoring system was not-demonstrated as required in the surveillance requirements of FSAR, Section 16.3.

A channel calibration was not performed during the Unit I first cycle refueling.

This will be further followed up when submitted as a special report.-

(d) DC 1-89-1516, " Potential Pressurizer Safety Valve Set Pressure Deviation."

Westinghouse letter GP-14629 identified a potential pressurizer safety valve set pressure deviation where the test conditions differ from the as-installed conditions, I

subsequently resulting in a potential unreviewed safety

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The FSAR licensing basis analyses were

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evaluated, since pressurizer safety valve setpoints above the nominal 2500 psia +1% value could have a potential

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adverse impact on the FIAR licensing basis criteria, where

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credit is taken f or safety valve relief, specifically in the loss of Load / Turbine Trip, Feed 11ne Break, Locked Rotor z

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and RCCA Ejection analyses. Typically, in each of these analyses, the pressurizer safety valves are actuated and

provide sufficient relief capacity to limit the peak

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pressure in the RCS to an acceptable value, Should the PSV set pressure be increased, the margin to the maximum

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allowed pressure for each of these events would be reduced.

Westinghouse performed sensitivity studies on the impact of

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increased.PSV set pressures. Based on the results of these sensitivity studies, the calculated pressure spikes for

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these transient do not challenge the pressure integrity of the primary system compcnents. Similarly, the effect of a lost loop seal during normal plant operation and

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pressurizer safety relief transients conditions has been reviewed for the case in which a pressurizer safety relief

. valve has been set and is installed in a loop seal configuration.

If the loop seal is lost as a result of a

transient lifting the PSV, the PSV is exposed to steam at

the valve seat.

This causes a-reduction in set pressure.

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The reduction of the valve's set pressure from the nominal i

value of 2500 psia to the PORV set pressure. and actuating at that point, does not affect the licensing basis criteria since no credit is taken for the PORVs-in the licensing

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basis analysis. A further set pressure reduction to the maximum 8% below 2500 psia is not expected to violate the

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licensing criteria, however, confirmation would require plant. specific analysis or evaluation. If the loop seal is lost during normal plant operation, the PSV is exposed to

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steam at the valve seat and experiences a reduction of the I

valve's set pressure from the nominal value of 2500 psia to

a level which opens during normal plant operation. It is bounded for one PSV as defined by the current analysis of an inadvertent opening of a PSV. The safety applicability to this unit is under reyiew by the licensee and will be

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further followed by the Test Program Section.

(e) DC 2-89-1419, " Loss Of Primary Offsite Communication Line."

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On October 5,1989, a construction crew inadvertently cut the ENS telephone line while installing a water line on the plant site.

Southern Bell was dispatched to make repairs.

Service was returned in approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months .

The necessary 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months report was made to the NRC in a timely manner pursuant to 10 CFR 50.72 (b)(1)(v).

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(f) *DC 2-89-1446, " Failure To Conduct Monthly Visual Inspection On Containment Fire Extinguishers."

A Unit 2 containment building walkdown was conducted by the.

resident inspectors during the snubber inspection outage.

The inspectors noted that the fire extinguishers had not had a monthly visual inspection since _ January 1989. This inspection is required by Section 4.3.1 of NFPA-10, the standard for portable fire extinguishers.

The licensee stated that these fire extinguishers are not inspected due to ALARA and habitability reasons, until the unit enters Mode 5.

This exception should have been included in Table 9,5.1.9 of the FSAR. To correct this deficiency, the following commitments were made and completed as documented

.in an engineering and technical support interoffice correspondence dated October 12, 1989:

DC 2-89-1446, which identified the non-compliance with

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NFPA-10, was dispositioned by Engineering Support.

A LDCR was generated to Chapter 9 of the FSAR to take

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exception to the inspection requirements of NFPA-10 for fire extinguishers in containment, based on ALARA considerations.

The containment fire extinguishers will be inspected whenever the plant is in Mode 5 for greater than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months unless they have been inspected

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within-the past 31 days.

This LOCR was PRB approved.

Plant Maintenance Procedures for surveillance of fire

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extinguishers were revised to incorporate the LDCR.

Since 'the above represents a violation of the Fire Protection Program and meets the criteria for non-citation, the following item is identified as:

NCV 50-424/89-27-04 and 50-425/89-31-04,

" Failure To Conduct A Monthly Visual Inspection Surveillance On Containment Fire Extinguishers As Required By Section 4.3.1 Of NFPA-10."

Further investigation has shown that the existence of these fire extinguishers in containment during adverse ccnditions had not been analyzed to account for the amount of hydrogen that may accumulate as a result of the aluminum that is part of the extinguishers.

It has also been determined

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that if temperatures exceed 200 degrees Fahrenheit, enough degradation will occur to cause actuation of the extinguishers. However, it has been determined that if all of the fire extinguishers' chemicals mixed with containment spray that no adverse effects will occur.

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The inspector asked for a report regarding the analysis of the aluminum content with respect to hydrogen generation during adverse conditions in containment. Followup of this

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item ~will be tracked as:

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IFI 50-424/89-27-05 and 50-425/89-31-05, " Review The Report Regarding The Analysis Of The Aluminum Content With Respect To Hydrogen Generation During Adverse Conditions In Containment."

(g) "DC 2-89-1450, " Automatic Reactor Trip On High Neutron Flux Rate."

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On October 11, 1989, a Unit 2 automatic reactor trip occurred on high neutron flux rate. The high neutron flux

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rate trip was induced by dropped control rod K2 due to a

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blown fuse.

The root cause has been isolated to a faulty diode in the control rods stationtry gripper coil.

This i

. event will be further followed up when submitted as an LER, t

l (h) *DC.2-89-1457, " Inadvertent Containment Ventilation L

Isolation During Radiation Monitor Surveillance."

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'On October 16',-1989, an Instruments and Control technician

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was preparing to replace a faulty Analog-to-Digital citcuit

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L board in the Data Processing Module of the Containment L

building area radiation monitor, 2RE-2565.

This process b

' involved setting the DPM in bypass and lifting the ESF t'

actuation leads in order to avoid an inadvertent ESF L

actuation while work was in progress. As he began to lift P

the leads inside the DPM panel, the technician contacted c

other wires inside the panel and noticed arcing at one of h

the terminals to which the power cable connected.

He F.

tightened the loose terminal' leads but found that the DPM was internally cycling in and out of' bypass.

The technician then called to advise the control room of the

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i situation and was told that a CVI had occurred. Train "A" valves and dampers moved to their proper positions. Train r

."B" valves and dampers had to be manually actuated due to a

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fault in the

"B" train portion of the radiation monitor circuitry. The operators verified that the radiation level

in the Containment atmosphere was normal.

The valves and dampers were then returned to their normal positions and sk the CVI signal reset. This item will be further followed

up when submitted as a LER.

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(2) The following LER was reviewed and is ready for closure pending verification that the licensee's stated corrective actions are completed.

50-425/89-26, Rev.

O,

" Incomplete Communications Lead To Missed ASME Section XI Valve testing."

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On September 3, 1989, the Shift Supervisor noticed that a high-energy line break' valve for steam generator blowdown i

isolation had not been tested per ASME Section XI within the

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specified time interval. Testing was immediately initiated and

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successfully completed. The cause of this event was cognitive

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- personnel error resulting from incomplete communications. _The Shift Supervisor responsible for completing the testing noted on r

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the test completion documentation that the valve was not tested l

when originally scheduled. However, the Surveillance Tracking

Coordinator did not fully understand the note and did not

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. reschedule the test prior to its due date.

In addition, the

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Shif t Supervisor did not eppropriately notify the necessary p

personnel.

This emphasizes the need to follow procedural

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requirements when testing is not completed.

This report was e

submitted as a voluntary report, j

L The inspector reviewed with the General Manager the criteria i

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utilized to arrive at the conclusion that a missed surveillance

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- of a. required component had not occurred. Technical Specifi-

cation 3.3.3.11 requires that the high energy line break

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instrumentation listed in Table 3.3-11 shall be " operable "

The Table lists eight temperature elements and four flow transmitters as instrumentation for achievement of the isolation

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function " Steam Generator Blowdown Line Isolation." Each of the

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four blowdown lines are designed with two, train separated L

valves (HV-15212, HV-15216). Automatic closure occurs when any one of the four temperature, or the one flow transmitter, for L

each respective valve reaches the high setpoint. The valves are subject to Technical Specification 4.0.5 surveillance require-

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ments for testing of ASME Code Class 2 components. Technical l

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Specification 4.0.5d stipulates that performance of the above

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inservice inspection and testing activities shall be in addition t o'

other specified surveillance requirements.

Technical Specification 4.0.5c stipulates that the provisions of Technical

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Sper'fication 4.0.2 are applicable. Generic letter 87-09 states

that failure to perform a surveillance within the allowable surveillance interval defined by Technical Specification 4.0.2 constitutes a reportable event under 10 CFR 50.73(a)(2)(1)(B)

because it is a condition prohibited by the plant's technical specifications.

The inspector raised the concern that the licensee views Technical Specification 3.3.3.11 as requiring only one valve to be operable and not two, therefore, concluding that a reportable condition could not exist.

The licensee determined that since

no action statement was provided for a single lost component that no requirement to have two existed. Action is required when below the Technical Specification Table 3.3-11 minimum operable requirement of one. This action stipulates that the instruments be returned to operable status within seven days.

The lack of singularity suggests that two or more are required.

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The licensee utilized a second example of where the technical

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specification appears to require two containment high range

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monitors but action requirements address action only when less -

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than a~ minimum of one channel (Technical Specification 3.3.3.6,

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Table 3.3-8, i tem.14).

The inspector noted that the action stipulates " restore inoperable channel (s)" and implies that more e

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than one should be restored.

The. inspector further noted that

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L this action statement also applies to steamline radiation

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monitors (Technical Specification 3.3.3.6, Table 3.3-8,

item 15).

For this instrument, both the total channels and

minimum channels operable are listed as one per steamline. In

applying.the action statement the word channel, not channels, is correct. The inspector determined that the wording of the

' i action statement discusses the correct level of instruments.

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The inspector requested that an evaluation be performed to

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determine what is required.

The paper dated October 24, 1989, reviewed FSAR Sections 7.6.6.7 and 10.4.8.3.2, P& ids for r, team i

generator - blowdown (1X4DB159-1 - and IX4DB159-3), and Standard

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Review Plan 3.6.1 and 10.4.8.

The review was discussed with the originator and the. inspector was informed that two were m

L required.

Since additional discussion of the evaluation with i

B the~ General Manager was deemed appropriate, the inspector l

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' determined that this would remain unresolved for another

L inspection period and informed the General Manager of this

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course of action. Instead of further discussion, the inspector

L received a letter dated October 26, 1989, from the General

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Manager to the Vice President-Nuclear which stated the intent to b

deny any violation.

The inspector considers this to be the

final ' informal.' position. of the licensee, and due to the

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sensitivity of the position, determination of a violation will e

be made by.NRC management.

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This item is considered to be unresolved by the inspector

pending' final determination by NRC of the actual requirements and is identified as:

VRI 50-424/89-27-06 and 50-425/89-31-06, " Resolve Licensee Use Of Action Statements To Determine - Requirements Of Limiting Condition Of Operation - LER 2-89-26."

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.(3) The following LERs were reviewed and closed.

(a)

50-424/87-72, Rev. 2

" Inadequate Training Causes A Surveillance To Be Improperly Performed."

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On December 9, 1987, the licensee identified that on November 21, 1987, an Auxiliary Plant Operator had

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improperly performed a surveillance on the Reactor Vessel Level Indication System.

The cause was attributed to the fact that the operator was not familiar with the console

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computer display.

Surveillances performed prior to and

.following the events were performed satisfactorily,

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indicating that the system was operable. A second cause

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was that the reviewer failed to detect the error.

Corrective actions included counseling the involved personnel, placing the LER in required reading, and r

providing additional training on the displays.

In

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addition, a console was procured and incorporated into the simulator. This item resulted in a violation in NRC Report

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50-424/88-09,

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(b) 50-424/87-82, Rev.

1,"

Failure To Perform Response Time Test Results In Technical Specification Violation."

On June 20, 1989, plant personnel were reviewing the

maintenance history associated with the Unit I reactor trip breakers when it was discovered that an RTB had been swapped-out without performing a response time test for the breaker being installed.

This swap-out occurred on October 17, 1987, with the replacement of breaker No.

02YN0728-4, which was installed in the main RTB

"B" cubicle; for breaker 860.759-1.

From October 17, 1987, until the replacement of breaker 860.759-1 on March 6, 1988, the minimum channels operable requirements of TS3.3.1 were-not met, as far as response time testing was concerned. The root cause of this event was considered to be a procedural inadequacy, in that Procedure 27765-C,

" Westinghouse Type DS-416 Circuit Breaker Maintenance", did not contain instructions for performing a response time bench test.

Procedure 27765-C implements the RTB PM program, and this procedure has been changed to address response time testing requirements.

The inspector has no further comments.

(c) 50-424/88-39, Rev.

O, " Radiation Monitor Loss Of' Power Leads To Fuel Handling Building Isolation."

On November 21, 1988, a Fuel Handling Building isolation occurred due to a momentary loss of power to radiation monitor ARE-2532.

The building post-accident filtration i

units started and the appropriate valves and dampers actuated. Control room operators verified that no abnormal

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radiation condition existed by checking other monitors.

The normal building supply and exhaust units were restarted and the post-accident filtration units were secured and reset.

An investigation found no cause for the momentary loss of power. Various wiring, connections and parts were checked for faults with no malfunctions found. Although

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personnel were working on. a data processing module and a power distribution panel _ (from which momentary losses of

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power could have been generated), interviews concluded that

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actions from these groups were not the cause of the loss of

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power.

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-(d) -50-424/89-03.. Rev. O, " Inadvertent Removal Of Train "B" ESF Chiller From Service Results In Entry Into TS 3.0.3."

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On January 18, 1989, a Limiting Condition for Operation

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action statement was entered for maintenance of the Train in

"A" ESF ' chiller. On January 19, 1989, the ESF Train

"B"

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chiller was inadvertently removed from service for calibration.

This - resulted in both trains being out of

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service, which is a condition not allowed by Technical Specification 3.7.11; thus, the plant entered Technical

' Specification 3.0.3.

Calibration of Train

"B" was performed under a Maintenance Work Order.

The technician

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retrieved data from a previous maintenance work order and noticed a difference in tag numbers.

The technician then realized he was working on the wrong train and informed the Shif t Supervisor.

Necessary steps of the procedure were completed and Train "B" was returned to service.

At the time of the error, the unit was in the process of

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conducting a shutdown and achieved Hot Standby within one hour and thirty-five minutes of the allowable seven hours.

The cause of this event was personnel error.

The technician prepared -paperwork, which was subsequently approved by the Shif t Supervisor, for calibration of the wrong train. A contributing cause was a procedure which only gave the loop number and did not specify the train.

Corrective actions included immediate restoration of Train

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'"B" to an operable status, creating a separate preventative maintenance task for Loop B and adding a train indicator to the procedure loop information sheets.

This item resulted-in a violation in NRC Report 50-424/89-07.

'(e) 50-424/89-06, Rev. O, " Inadequate Functional Test Leads To Improper Termination Of Limiting Condition For Operation."

On January 30, 1989, the Gaseous Waste Processing System's Outlet Analyzer, IARC-1119, failed to pass the surveillance requirements of Technical Specification 4.3.3.10.

The TS required ~ grab samples to be taken and analyzed at least

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once.per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A micro fuel cell in the analyzer was replaced and tested on February 7,1989. On February 23

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1989, a review of the work order discovered that the equipment had been placed in service, even though a complete surveillance test of the analyzer had not been

_ performed to verify that the surveillance requirements were s

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The surveillance test was then performed

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satisfactorily.

This event was caused by personnel error.

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Procedural inadequacies contributed to this event.

The

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appropriate procedure was. revised and the appropriate

- personnel were counseled.

Proper checks now exist _ to ensure all required testing is performed prior to exiting an LCO.

This item resulted in a violation in NRC Report 50-424/89-14.

(f) 50-424/89-10, Rev. O, " Valved Out Radiation Monitor Leads To Unmonitored Liquid Waste Release."

On March 14, 1989, a plant operator was preparing to perform ' a liquid waste release per procedure 13216-1,

" Liquid Waste Release".

The operator verified that radiation monitor 1-RE-0018 was registering normal background levels and that isolation release valve 1-RE-0018 would close on a -high radiation signal.

The release began and the operator checked the signal from 1-RE-0018 and found it was not registering above background levels.

A brief search found that the inlet valve to 1-RE-0018 was closed.

This valve, 1-1901-X4-144, was opened, 1-RE-0018 registered the proper activity level, and the liquid waste release continued to completion.

The closure of the inlet valve resulted iri liquid waste being released unmonitored, which is a condition prohibited by Technical Specification 3.3.3.9.

The operator omitted the performance of a pre-release line flush which would have ensured that the inlet valve - was opened.

Corrective actions included counseling the operator and changing procedure 13216-1 to require independent verification of the inlet valve being open.

This item resulted in a violation in NRC Report 50-424/89-14.

(g) 50-424/89-15, Rev.

1,

" Personnel Error Leads To Inadequately Performed Surveillance."

On July 2,1989, plant operators discovered a failure to adequately perform the requirements of Technical Specification 4.2.1.1.b, which requires monitoring and logging of the Axial Flux Oifference for each operable excore channel at least once per 30 minutes following the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the alarm becomes inoperable.

Instead, the surveillance was performed at one-hour intervals for the first 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

This condition existed

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for approximately 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months until discovered during shift turnover by an oncoming licensed operator. The root cause of this event was personnel error. Plant operators failed to change the frequency of monitoring and logging from one hour to 30 minutes.

The corrective actions included increasing the frequency for monitoring, counseling of L

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This item resulted in a violation

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in NRC Report 50-424/89-22.

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(h) 50-425/89-09, Rev. O, " Procedure Misinterpretation Leads To

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Late Surveillance Testing."

l On. March _ 20, 1989, a diesel fuel oil shipment arrived

onsite for offloading into the diesel fuel oil storage

tanks.

A technician obtained and analyzed a sample.

The

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technician and. his foreman interpreted a note in the C

analyses scheduling procedure to mean that the i

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neutralization number and mercaptan were not required to be l

performed.

In. fact, only the mercaptan was exempt from the

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F analysis and the neutralization number was required to be

performed.

After the analysis found the other fuel

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properties to be satisfactory, the shipment was unloaded

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into the diesel fuel oil storage tanks.

Meanwhile, a

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second diesel fuel oil shipment arrived onsite, was sampled and analyzed as the first, and was unloaded into the tanks.

-A laboratory supervisor reviewed the data sheets and i

questioned the omission of the neutralization number.

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After the requirement was clarified, the technician

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obtained the original samples from each shipment and

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determined that the neutralization number of each was

within Technical Specification requirements.

The cause of i

this event was the misleading nature of the procedure note.

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The procedure note was rewritten and clarified. This item resulted in a violation in NRC Report 50-425/89-15.

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(i) 50-425/89-10, Rev. O, " Radioactive Discharge Without Permit Leads To Technical Specification Violation."

Technical Specification 3/4.11.1 requires that releases of radioactive materials to unrestricted areas be sampled and

- analyzed for appropriate alpha, beta and gamma emitters.

l On March 8,1989, the contents of the Unit 2 turbine

building drain tank were sampled for gamma emitters to l

determine if a release permit was required. On March 9, a

plant operator released the _ tank contents to the Unit 2

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Waste Water Retention Basin without a permit. On Mcrch 14, during a review of releases, it was found that no permit had been issued for the March 9 release.

The permit ensures that required samples have been taken, analyzed and i

are within allowable limits for releases.

Procedure

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13211-2, '! Turbine Building Drain System"' required that sample analysis be used to determine how drain tank contents are to be processed, but did not specify that a release permit may be required.

The cause of this event was that the operator did not obtain a radioactive release permit prior to releasing.

Procedure 13211-2 was revised

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to provide specific instructions that a radioactive release

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permit may be required for releasing the contents of a i

turbine building drain tank.

Also, at shif t briefings, l

operators were reminded that waste permits are required prior to. release of all radioactively. contaminated tank contents.

This item resulted in a violation in NRC Report 50-425/89-15.

One non-cited violation, one IFI, and one VRI were identified during this

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L inspection period.

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Followup on a Regional Request - (92701)

t Reactor Operator License Verification - The inspectors continued a review,

begun during hlRC Inspection Report Nos. 50-424/89-25, 50-425/89-29, 50-424/89-19 and 50-425/89-23, of the methods used by the licensee to l

disseminate-the current qualification status of licensed operators.

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L When a licensed operator is determined to be unqualified to assume shif t

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E duties, he receives both a phone call and a letter from the Manager-Operations. informing him of the disqualification.

The individual's immediate supervisor also receives a copy of the disqualification letter

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and -the qualification list in the control room is updated.

These

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i-notifications and list updates generally occur on the same day. Since the control room qualification list is updated only when changes occur in l

personnel qualification status, it is difficult to determine, on a daily

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basis, whether or not the list is current. The list could be several days

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old, as indicated by its date, and yet be correct since no changes have

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been made to the personnel qualification status since that date.

The maintenance of the control room qualification list is considered to be a weakness because it is not verified periodically to be correct.

Procedure-10004-C, " Shift Relief", Rev. 6, requires that an operator p

assuming the shif t be alert, coherent, and fully capable of performing

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assigned duties, but makes no requirement to verify that the relieving

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operator meets the requirements of his license.

The inspectors consider

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the lack of qualification verification at the time of shift relief to be a weakness,

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i In summary, the primary responsibility to keep operations management informed of operator disqualification rests most heavily on the licensed i

i-operator himself. Immediate supervisors and shift schedulers are notified

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and a qualified list is available, but the individual operator is usually

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the one most aware of his qualification status and license restrictions.

The person being relieved is not likely to have such complete information.

At present, _ procedures do not require that there be verification or

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certification prior to a licensed operator standing watch.

The licensee

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.has, however,. modified the qualification list to include individual licensee conditions such as the requirement to wear corrective lens.

No violations or deviations were identified.

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c 5.-

Reporting of Defects And Nancompliance - (36100)(90714)

This inspection was to determine whether organizations and individuals subject to 10_ CFR Part _ 21 regulations have established and are imp 1_ementing proceduret and controls to ensure the reporting of defects and non-compliances.

This. inspection utilized NUREG-0302, Rev. 1

" Remarks Presented (Questions / Answers - Discussed) At-Public Regional Meetings To Discuss Regulations (10 CFR Part 21) For Reporting Of Defects And Noncompliance" dated July-12-26, 1977.

The following measures were established:

Procedure 00255-C.

" Document Posting Responsibilities," which

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establishes the responsibilities for posting.

The inspector noted that section 3.1 requires that posting shall be conspicuous and in a sufficient number of places to permit personnel engaged in licensed activities to observe the posting on their way to or from any licensed activity location to which the document applies.

The procedure does not amplify how or when this is to be accomplished. A

' listing of the current postings locations was. provided.

The inspector discussed with the Plant Administration Superintendent that while ali major structures were listed, no listings were present for

~ temporary structures, such as trailers, or old construction buildings o

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now utilized as permanent buildings, such as security offices or the CIMCO building.- In addition, the Control Building was not posted. A clear definition by the licensee was not present. NUREG 302 simply states on page 216-1:

"Every premise where activities subject to Part 21 are conducted,_must be posted in a conspicuous location. The number of posting locations that is adequate should be judged on the normal access of the individuals to the premises."

To comply with this regulation and the similar, but dif ferent, requirements of 10 CFR Part 19, the inspector determined that the

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' minimum acceptable postings should be the:

1.

main entrance lobby of the training building, 2.

main entrance lobby of the administration building, 3.

both entrance lobbies of the Plant Entrance Security Building, m

4.

main entrance lobby of the service building,

5.

main entrance of the maintenance building, 6.

health Physics Control Point entrance, 7.

health Physics Dosimetry, 8.

field Support and Radwaste Building, 9.- warehouse area, and 10.

any temporaty or other structures outside the protected area.

In; reviewing the postings, the inspector noted that the utility has

. postings in numerous locations in excess of the inspector determined minimu,-

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b To resolve the difference between the licensee and inspector, the licensee' reviewed the posting requirements.

The inspector found

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theiri identified areas to be ' acceptable.

While examining the postings, the-inspector identified that Section 206 of the Energy Reorganization Act of 1974 contained wording which could confuse a

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_ person. In addition, the list of procedures which had been adopted

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was _ incomplete.

10 CFR 21.6 requires, in part, the posting of

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Section 206 of the Energy Reorgenization Act of 1974 and-the

. procedure adopted pursuant to the regulations (10 CFR 21).

10 CFR 21'.21(a)'further requires the adoption of appropriate procedures for evaluating deviations-and assumes that a director or responsible of ficer.will be. informed.

Site and corporate procedures for

' evaluation weae not listed on the posting.

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Procedure 70515, Rev. 3T, " Requisition Review For Technical And

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Quality Requirements." This procedure defines the criteria and

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process for reviewing procurement documents for technical

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adequacy - and specifies quality reautrements.

By utilizing standard typing paragraphs the licensee informs suppliers of 10 CFR 21 applicability.

Procedure-VNS-AP-06,

" Licensing Related Activities" and

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VNS-AP-10, " Procedures for Corrective Action." These procedures

. delineate the responsibilities for review, evaluation and final notification- - to the responsible corporate official, These-procedures were newly established to replace the GPC procedures.

The inspector' review included comparison between the old and new procedures.

The new procedures have climinated the checklist type speci_ticity' and provide only general requirements, such as the statement that the Manager-Licensing will ensure that any non-compliance determined to be potentially reportable pursuant-to 10 CFR 21 is evaluated to determine if a substantial safety hazard exists. The removal of specificity for accomplishment-is considered.to be a weakness.

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Procedure 81010-C " Reviewing And Reporting Potential Defects And Non-compliance."

This procedure describes the method for reviewing documentation for potential defects or non-compliance.

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The procedure does not determine reportability, but screens and performs a review for-potential reportability.

Actual

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reportability is a determination made at the corporate level.

The inspector reviewed the log which was being maintained to

track the process.

Four packages were reviewed for completeness.

The inspector's review indicated that forwarding

was being conducted to coporete. However, the inspector noted that very few items forwarded by the site were being determined

,

reportable at the corporate level. The site log indicated that 44 issues had identified to date.

The definition of " Basic Component" was substantially different. The inspector also identified that the terms " defect" and " deviation" were used inter-changeably and without regard to 10 CFR part 21 definitions.

Under 10 CFR part 21, a " deviation" is to be evaluated, determined to be a defect or not, and then promptly

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reported.- The licensee procedure in step 4.1.1, for example, wrongly states _in part:

"A defect or non-compliance which falls into any of the

below criteria-is potentially reportable and must be evaluated."

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As a. result of the above inspection, the licensee committed to review and revise procedure 00255-C to clarify posting locations and 81010-C

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to correct. terminology. This item is identified as:

IFI; 50-424/89-27-07 and 50-425/89-31-07, " Review Procedure 00255-C and 81090-C Regarding 10 CFR Part 21."

During thi~s inspection, one IFI was identified.

No violations or deviations were identified.

6.

Evaluation of Licensee Self-Assessment Capability - (40500)

'

-The objective of this review was to evaluate the effectiveness of the licensee's. self-assessment programs.

Specifically, the licensee's Plant Review. Board 4nd Independent Safety Engineering Group were assessed to

. determine their effectiveness in monitoring and evaluating plant performance c and - providing assessments and findings to prevent plant-problems.-

This_ review consisted of _ attendance at two PRB meetings, review of PRB minutes for?the last 9 months, and review of the licensee's administrative

,.y procedure. 00002-C, Rev.

10,

" Plant Review Board Duties and

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N Responsibilities,". The inspector determined that the PRB is properly performing'its intended function and responsibilities as described in LTechnical Specification 6.4.1.

"

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Two discrepancies _ were noted by the inspector. _First, procedure 00002-C does not discuss non-voting PRB members and their alternates and yet those designated-individuals routinely attend and participate in PRB meetings.

The licensee-will revise the procedure to include a description of duties of non-voting members..Secona, PRB assigned action items routinely exceed their stated response due dates.

In all cases, the open action items were

'

accurately tracked in' the PRB minutes, but in several examples, the action items exceeded their due dates by 4-6 weeks with no explanation given in the minutes nor extension of due dates granted by the PRB.

Failure to control action items due dates was identified as a program weaknes3.

On July 31, 1989, the membership of the PRB was upgraded such that department managers replaced supervisors as tt e PRB members.

The

,i Assistant General Manager-Plant Operations was appointed as chairman of

the.PRB. The upgrading of the PRB membership is considered a strength of the licensee's self-assessment.

In reviewing ISEG, the inspector interviewed the members, reviewed the reports covering 1989 activities, and reviewed corporate procedures concerning their operation. Items discussed with the members included the review process for LERs and SOERs, event criteria, tracking, and

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b implementation of corrective action recommendations, and other day-to-day L

functions.

Also discussed was the experience level of each member.

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Overall, the ISEG was accomplishing its intended function. In the area of

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ISEG staffing, however, a discrepancy was noted.

Technical Specification , 6.2.3.2 requires that ISEG shall be composed of at least five, dedicated, full-time engineers, Since mid-July 1989, there have been only four members. On: September ;1,1989, membership decreased to three, due to a-r l

medical disability. The inspector alevated the membership concern to the licensee, c

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.On October 4,'1989, the Vice President-Nuclear Vogtle Project stated that

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the. corporate position was that this requirement us to have these positions in the staffing plans.

Upon loss of an individual, the normal i

process for selection was adequate for ensuring replacement. This process

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is identical _ to how a replacement would occur for any posted vacancy.-

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Temporary assignment of_ engineers to ISEG was not considered necestery

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,

I since the licensee considered themselves ir compliance by having the l

positions in the staffing-. plans.

At the request of the Vice

s President-Nuclear,- the inspector notified the regional manage,nent of the L

licensee-position and agreed to have him promptly informed upon final

determination.

Should the NRC determination be contrary to the licensee,

!

o then temporary assignments _would be made. The licensee filled one of the F

L two. positions effective _ October 16, 1989 and the second vacant position on October 22, 1989.

Pending the resolution by NRC regional management of ISEG minimum membership-requirements, this item is identified as:

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L URI item 50-424/89-27-08; and 50-425/89-31-08, " Resolve ISEG Membership

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Replacement Requirements When Less Than Five ISEG Members."

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During 'this inspection, one URI was ' identified in this area.

No violations or deviations were identified.

7.

' Exit Interviews - (30703)

l The -inspection scope and findings were summarized on October 27, 1989, zwith those persons indicated in paragraph 1 aboves The inspectors described the areat inspected and-discussed in detail the inspection j

results.

No -dissenting comments were received from the licenses.

The i-licensee did not identify a pecpM etary any of the materials provided to or reviewed by the inspector during this inspection.

Region based NRC

exit interviews were attended during the inspection period by a resident inspector, This inspection closed nine Licensee Event Reports. The items

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_ identified during this inspcction were:

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i NCV 50-424/89-27-04 and 50-425/89-31-04, " Failure To Conduct A

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Monthly Visual Inspection Surveillance On Containment Fire

Extinguishers As Required ;y Section 4.3.1 Of NFPA-10" - (paragraph 3.b(1)( f)).

URI 50-424/89-27-01 and 50-425/89-31-01, " Resolve Issue Of TS 3.6.1.7 Mini-Purge Valve Operation During 1988" - (paragraph 2.a).

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URI -50-424/89-27-06 and 50-425/89-31-06, " Resolve Licensee Use Of

- Action Statements To Determine Requirements Of Limiting Condition Of

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Operation - LER'2-89-26" - (paragraph 3.b(2)).

- URI 50-424/890-27-08 and 50-425/89-31-08, " Resolve ISEG Membership Replacement Requirements When Less Than. Five ISEG Members"

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_,

(paragraph 6).

IFI 50-424/89-27-02 and 50-425/89-31-02, " Review Improvement Program

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For Control Of Scaffolding" - (paragraph 2.b(2)).

-IFI '50-424/89-27-03 and-50-425/89-31-03,

" Verify Complete Irnplementation Of Canvas Bags Over Equipment" - (paragraph 2.b(2)).

.~~

IFI 50-424/89-27-05 and 50-425/89-31-05, " Review The Report Regarding

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The_ Analysis Of The Aluminum Content With Respect To Hydrogen

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. Generation _ During Adverse ' Conditions In Containment" - (paragraph n

3.b(1)(f)).

IFI 50-424/89-27-07 and 50-425/89-31-07, " Review Procedure 00255-C

and 81090-C Rega-ding 10 CFR Part 21" - (paragraph 5).

'

The following: strengths and weaknesses were discussed:

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Weaknesses were -identified in plant operations, maintenance and j

quality programs.

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-The' weakness identified in the area of maintenance regarded housekeeping practices.

In particular, the use of in process tags to track material was failing to ensure the removal of material when expiration dates were exceeded.

Secondly, scaffolding was left in

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place long after work was complete (paragraphs 2.b(1) and 2.b(2)).

The weakness in plant operations involved the verification of-operator qualification prior to assuming control.

No procedure or practice exists where the off going operator or shift supervisor

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verifies that the on-coming watchstander is in a qualified status

_

(paragraph 4).

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The weakness in-quality programs was in the area of ISEG membership and PRB action tracking.

The fact that the ISEG staff was below minimum staff level, combined with a lack of a priority replacement plan, directly challenged the functionality of the group. The PRB weakness involved the failure to document a reason for or approve _an extension of assigned item due dates (paragraph 6).

Strengths were also noted in the quality programs, plant operations and maintenance areas.

In the plant operations area, the performance and knowledge of the operators in moving spent fuel from the Unit 1 to the Unit 2 pool was noteworthy (paragraph 2.b(8)).

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.In maintenance, the control, planning, and execution of the Unit 2

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snubber outage was a strength.

In addition, this strength in minor

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outage planning had been previously noted (paragraph 2.b(7)).

-.In. the quality programs area, the membership of the PRB has been t-changed to Department Managers'in lieu of Supervisors of Departments.

t While this'has always been allowed.by technical specifications, the plant' previously held membership to the minimum managerial level.

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allowed (paragraph 6).

During this inspection period, the resident inspectors toured the local Public-Document Room - and located the licensee's backup Emergency Operations Facility in Waynesboro, GA.

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8.

Acronyms ~And Initialisms AFW Auxiliary Feedwater System

'ALARA-As Low As Reasonably Achievable ASCO (trade'name)

S ASME American Society of Mechanical Engineers b

CCP Coolant Charging Pump CCW Component Cooling Water System CFR Code of Federal Regulations CIMCO-(trade name)

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CVCS Chemical & Volume Control System i

CVI-Containment Ventilation Isolation

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- DC-Deficiency Cards DPM Data Process Module

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ENS Emergency Notification System

'. - -

ESF-Engineered Safety Features FSAR Final Safety Analysis Report GPC Georgia Power Company HEPA High Efficency Particulate Air-

.i HV High Voltage IFI Inspector Followup Item ISEG Independent Safety Engineering Group LCO'

Limiting Conditions for Operations LDCR License Document Change Request

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LER Licensee Event. Reports LLRT Local Leak Rate Test MDAFW Motor Driven AFW Pump MFPTL Main Feedpump Turbine MSIV Main Steam Isolation Valve MW0'

Maintenance Work Order NAMCO-(trade name)

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NCV Non-cited Violation NFPA National Fire Protection Association NI Nuclear Instrument NPF Nuclear Power Facility NRC Nuclear Regulatory Commission PDR Public Document Room 4 g_

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PE0 Plant Equipment Operator F

PM-Planned Maintenance

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.PORV-Power Operated Relief Valve t

PRBL Plant Review Board

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PSIA Pounds Per Square Inch Absolute PSIG Pounds Per Square Inch Gauge

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PSV Pressurizer Safety Valve RCCA Rod Control Cluster Assembly h-RCS Reactor Coolant System RER Request for Engineering Review Rev

~ Revision RTB Reactor Trip Breaker F

SFP-

' Spent Fuel Pool

SG Steam Generator

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SGBD Steam Generator Blowdown

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SOER Significant Operations Evaluation Report E

TS LTechnical Specification URI Un-Resolved Item I

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v t e Inspection Report - Vogtle - 1989027
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \|
1989 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 32(0) 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 18(0) 20(0) 21(0) 22(0) 23(0) 24(0) 25(0) 26(0) 27(0) 28(0) 29(0) 30(0) 31(0) 32(0) 33(0) 35(0) 8(0) 9(0) 12(0) 16(0) 22(0) 37(0) Security Operator Exams Emergency Planning Other

IR 05000424/1989027

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