ML20154C191

Insp Repts 50-327/85-45 & 50-328/85-45 on 851202-06. Violations Noted:Failure to Take Prompt Corrective Actions in Resolving Problems W/Upper Head Injection Level Switches & to Follow Instructions

ML20154C191
Person / Time
Site:	Sequoyah
Issue date:	01/21/1986
From:	Debs B, Mccoy F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20154C174	List: ML20154C170 ML20154C175 ML20154C191
References
RTR-NUREG-0588, RTR-NUREG-588 50-327-85-45, 50-328-85-45, NUDOCS 8603050030
Download: ML20154C191 (47)

See also: IR 05000327/1985045

Text

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UNITED STATES

. [A KE2, o NUCLEAR REGULATORY COMMISSION

[ n REGION 14

g ,, j

101 MARIETTA STREET, N.W.

• * ATLANTA, GEORGI A 30323

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Report Nos.: 50-327/85-45 and 50-328/85-45

Licensee: Tennessee Valley Authority

6N11 B Missionary Ridge Place

1101 Market Street

Chattanooga, TN 37402-2801

Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79

Facility Name: Sequoyah 1 and 2

Inspection Conducted: December 2-6, 1985

Team Leader: / 7

F. R. McCoy

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l 'Dat'e Signed

Team Members: D. P. Falconer

W. K. Poertner

. D. P. Loveless

J. A. Arildsen l

W. Ho' land

C. Coldsell

R. Pierson

J. Moorman

M. Scott

M. Runyan

D. Brinkma , E

Approved by:

B. T. Debs, Acting, Chief

/[7-/

Operational Programs Section ' D/tiSigned

Division of Reactor Safety

SUMMARY

Scope: This routine, announced inspection involved 494 inspector-hours on site

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in the area of maintenance activities.

Results: Two violations were identified: two examples of failure to take prompt

corrective actions in resolving problems with Upper Head Injection (UHI) level

switches (paragraph 13) and in resolving problems associated with review of

completed maintenance requests (MRs) (paragraph 6); and three examples of failure

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to follow procedures in the areas of motor operated valve modification

(paragraph 10), definition of preventative maintenance for auxiliary air

compressor ' dryers (paragraph 7), and housekeeping of contaminated work areas

(paragraph 14).

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REPORT DETAILS

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1. Persons Contacted

Licensee Employees

• H. L. Abrocrombie, Site Director

• P. R. Wallace, Plant Manager

• B. Patterson, Maintenance Superintendent

• G. B. Kirk, Compliance Supervisor

• R. W. Fortenberry, Engineering Section Supervisor

*C. R. Brimer, Manager, Site Services

i *H. D. Elkins, Group Supervisor, Instrument Maintenance

*D. L. Jeralds, Craft Section Supervisor, Instrument Maintenance

i *R. Schnur, Engineer, Instrument Maintenance

l *A. S. Lehr, General Foreman, Instrument Maintenance

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• T. Kontovich, Engineering Supervisor, Electrical Maintenance

1 *L. McEachern, Craft Section Supervisor, Electrical Maintenance ,

] *D. L. Love, Craft Section Supervisor, Mechanical Maintenance

• G. S. Boles, Outage Engineering Supervisor, Mechanical Maintenance '

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• L. S. Bryant, Engineering Supervisor, Mechanical Maintenance

• J. R. Robertson, General Foreman, Mechanical Maintenance

• M. R. Sedlauh, Electrical Modification Supervisor  :

, *L. O. Alexander, Mechanical Modification Supervisor

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• R. J. Griffin, Nuclear Safety Review Staff Site Representative < l

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• J. L. Hamilton, Quality Engineering / Quality Control Supervisor 1

• D. L. Cowart, Quality Surveillance Supervisor

• T. Burdette, Quality Assurance

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• R. L. Circhell, Compliance Engineer

Other licensee employees contacted included engineers, technicians,

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l operators, mechanics, and office personnel.

NRC Resident Inspectors +

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• K. Jenison

! *L. Watson '

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• Attended exit interview

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2. Exit Interview i

The inspection scope and findings were summarized on December 6, 1985, with

, those persons indicated in paragraph I above. The inspectors described -the '

areas inspected and discussed in detail the inspection findings. No

dissenting comments were received from the licensee. The licensee did not

! identify as proprietary any of the materials provided to or reviewed by the

j inspector during this inspection.

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3. Licensee Action on Previous Enforcement Matters

i (0 pen) Violation 328-85-24-02 - Corrective actions associated with failure

i to properly preplan and perform post maintenance testing of safety related ,

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equipment have not yet been completed. The licensee identified date for

implementation of these corrective actions is January 1,1986. This item  ;

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remains open.

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i (0 pen) Violation 328-85-24-03 - Corrective actions associated with

! operability of ice condenser intermediate deck doors have been determined to

i be adequately prescribed in surveillance instruction (SI)-108.1, Ice

1 Condenser Intermediate Deck Doors - Visual Inspection, Lif t Test, and Ice

! Removal, which is required to be performed weekly as required during

Modes 1-4. Sin:e SI-108.1 was issued on November 27, 1985, and since the

! units are currently in Mode 5, there is insufficient data to determine

adequacy of implementation of this SI. This item will remain open pending ,

evaluation of implementation.

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l (Closed) Unresolved Item 328-85-24-04 - With regard to missile hazard

concerns associated with feedwater hanger 2-FDH-282, the licensee has  :

redesigned and modified the hanger in accordance with Engineering Change l

Notice (ECN) L6263 in order to allow reloading of the hanger. This action l

should correct the initial inadequate anchoring of the hanger and does >

resolve the missile hazard concern. This item is closed. I

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, (0 pen) Violation 327-85-05-01, 328-85-05-01 - Corrective actions associated

with resolving deficiencies with measuring and test equipment (MTE) have

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been partially initiated and are not scheduled for full implementation until

, June 1, 1986. Pending completion of full implementation of MTE program

improvements, this violation remains open.

l 4. Unresolved Items

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Unresolved items are matters about which more information is required to

determine whether they are acceptable or may involve violations or

i deviations. Four unresolved items were identified during this inspection.

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These unresolved items involve determination of operability for UHI (see

paragraph 13), determination of seismic qualification for ASCO series 8316

, solenoid valves (see paragraph 11), determination of NUREG-0588

! environmental boundary qualification for ASCO series 8316 solenoid valves

i (see paragraph 11), and assessment of corrective actions associated with

I seismic and quality assurance documentation for three previously installed ,

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UHI level switches (see paragraph 13).  ;

5. General Conclusions Associated With the Maintenance Assessment and Actions

Requiring Completion Prior to Unit Restart ,

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. The inspection team considers that the actions committed in the Sequoyah

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Nuclear Performance Plan with regard to maintenance activities are being ,

, implemented and that, although some specific program weaknesses still exist,

the maintenance program, in general, appears adequate. Improvement with

regard to performance of maintenance work has been noted. The attitudes of

employees at the craft and first line supervisory level were observed to be

good. Direct observation of maintenance activities reflected adequate use

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of procedures. Reliance on skill of the craft for activities observed

appeared to be in line with that noted at other Region II facilities. Craft

personnel were observed to be knowledgeable of tasks they were performing

and foremen and general foremen were observed to be properly knowledgeable

of work being performed or planned under their cognizance.

In the area of planning and scheduling of maintenance work,, the inspection

team considers that the licensee's new programs show potential for proper

work management; however, additional implementation time is necessary to

properly assess effectiveness. The inspection team notes that the licensee

relies extensively on the expertise and knowledge of planners for all

aspects of maintenance program implementation. Because the role of the

planners is so integral and important to program implementation, the

licensee should consider improvement in written guidance, resource

allocation, and training in order to ensure that the planners are adequately

equipped to fulfill their responsibilities.

Weaknesses were noted in management assessments and actions associated with

repetitive failure of safety related equipment. In the case of UHI level

switch problems, initial implementation of short term corrective actions and

definition of long term corrective actions were considered to be adequate;

however, the timeliness associated with achieving full implementation of

long term actions and the lack of establishment of intermediate actions in

light of continued questionable system operability is considered inadequate.

The inspection team considers that the underlying cause for this weakness

may be that management is not fully considering the issue of operability of

safety related equipment and systems from a broad perspective based on

continued history of problems and performance. It is considered that the

licensee should review all outstanding MRs, design change requests (DCRs),

and engineering change notices (ECNs) to ensure outstanding work associated

with safety related equipment is reviewed in a manner which challenges

system operability; any work required to resolve problems associated with

questionable operability of safety related equipment should be completed

prior to restart of the affected unit. Additionally, cognizant engineers

should be interviewed to ensure that all issues which may involve

operability of safety related equipment have been formally identified with

an MR, DCR, or ECN. Resolution of these concerns should be completed prior

to unit restart and is identified as an inspector followup item

(327-85-45-01, 328-85-45-01).

In the area of preventative maintenance, weaknesses were noted in program

implementation. Of particular concern is the failure to establish a

preventative maintenance program for the aux.liary air compressor dryers

when the vendor manual for these components recommended 14 preventative

maintenance items. It is considered that the licensee should establish if

this failure to prescribe preventative maintenance represents an isolated

case or if this represents a generic problem requiring programmatic

corrective actions. Resolution of this concern should be addressed as a

part of the response to violation 327-85-45-09, 328-85-45-09 prior to unit

restart.

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Deficiencies were noted in the implementaion of equipment qualification

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modifications pursuant to 10 CFR 50.49. Specifically, a jumper was not I

removed from valve 2-FCV-70-134 during rewiring of the valve and

i modifications were accomplished on series 8316 ASCO solenoid valves which

may have resulted in degradation of seismic and boundary qualifications. In

the case of the valve rewiring problem, the licensee should determine if the

i; problem is isolated or a generic problem requiring programmatic corrective ,

i actions. In the case of the ASCO solenoid valve problems, the licensee i

should determine, and if necessary take corrective action to ensure,

adequate seismic and boundary qualifications for these valves. Resolution i

, of these concerns should be addressed in response to violation 327-85-45-09,

! 32S-85-45-09, Unresolved Item 327-85-45-11, 328-85-45-11, and Unresolved

j Item 327-85-45-12, 328-85-45-12, prior to unit restart. i

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, In addition to completing these actions delineated above, it is also

l considered that the following additional actions should be completed prior

to unit restart:

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complete replacement and post modification testing of UHI level

! switches on Unit 2 prior to unit restart. Resolution of this concern '

is identified as an inspector followup item (327-85-45-02,

328-85-45-02).

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resolve the question of UHI operability and address results of the

licensee review of this issue i n response to unresolved item

i 327-85-45-17, 328-85-45-17.

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complete work associated with those MRs identified as requiring

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completion in inspector followup item 327-85-45-05, 328-85-45-05.

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provide an assessment and status of actions taken to date in response

to Inspection and Enforcement Bulletin 85-03. Completion of this

action i s identified as an inspector followup item (327-85-45-03,

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328-85-45-03). '

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evaluate the results of M0 VATS testing and inspection over a larger

data base to determine the necessity for full completion, prior to unit ,

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! restart, of MOVATS testing and inspection on all motor operated valves

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which have been rewired pursuant to 10 CFR 50.49. Completion of this

action i s identified as an inspector followup item (327-85-45-04,

! 328-85-45-04).

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6. Review of Programmatic Aspects of Corrective Maintenance

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l The inspection team reviewed maintenance initiation, planning practices, i

i scheduling, execution, status reporting, tracking, post maintenance testing,

i and documentation of repair work and completion. Additionally, machinery

history and trend analysis was reviewed. The inspectors reviewed Sequoyah

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Standard Practice SQM-2, Maintenance Management System, and discussed the  ;

maintenance program with the appropriate license personnel responsible for

developing and implementing the maintenance program. The inspectors also

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discussed implementation of this procedure with the planning sections and

technicians of the various disciplines. The purpose of SQM-2, is to 1

establish the method and responsibilities for managing the initiation,

i planning, scheduling, execution, status, tracking, and documentation of ,

! corrective maintenance and repair work. The inspectors discussed the

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developmental aspects of this procedure and learned that the intent was to

give maintenance personnel a clear, concise program that would easily

identify equipment in need of repair, and allow for easier trending and

documentation of work. The work request (WR) is the document generated by

any individual to initiate corrective maintenance. The WR is suitable for

, non-critical system, structures, or components (CSSC) equipment; non-class

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IE equipment; non-environmentally qualified (10 CFR 50.49) equipment;

non-reportable; or non-material history type items. If the work affects

CSSC or similar type equipment or components then a MR is generated from the

WR. This method appears to be an effective means of controlling worF.

through different levels of planning and review suitable to the type

equipment and components involved.

A review was conducted of work authorization and return to service of

components under the WR and MR program. The inspectors noted that after the i

WR tag has been completed (including a description of work to be performed)

the originator's supervisor is required to initial the WR to concur that the

request is needed and that sufficient information has been given to allow

the appropriate maintenance section to locate and plan the work. The

planner then assigns a priority to the WR and details instructions on how

the work is-to be performed. The operations section is then notified prior

to and upon completion of work. If a MR is required, an MR form is I

initiated and additional reviews are conducted. These reviews are performed i

by the quality assurance (QA) staff, the safety staff, and the craft section

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supervisors if the component is CSSC. Prior to and after completion of the

work, the operations section shift engineer is notified and followup reviews

of the MR are performed by the OA staff. The inspectors found SQM-2 to be

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technically adequate with regard to delineating the responsibilities for

i maintenance activities and giving guidance to personnel on the preparation

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of WRs and MRs. The inspectors recognize that this program relies

extensively on the knowledge and experience of the planners. The planners

are individuals of various backgrounds and disciplines who are responsible

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for planning work to be performed by WRs or MRs. The planners are

responsible for gathering all necessary documentation and reference

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materials to prepare the WR or MR, for listing detailed instructions to

perform the work and for listing all post-maintenance test requirements,

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The inspectors noted that the planners are the focal point for proper

implementation of the maintenance program. The licensee has taken action to

increase the number of planners from 3 to 12 over the past year in order to

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ensure that there are sufficient numbers of personnel to fulfill this

critical role. Because the success of corrective maintenance implementation

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relies heavily on the planning effort and more specifically on planner

knowledge, the inspectors are concerned that all necessary information to

plan MRs may not be easily available to planners. An example of this is the

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availability of a document that delineates the specific post-maintenance

l test requirements for all QA components. Post-maintenance test requirements

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are currently assigned based on the knowledge and experience of the

individual planners. Presently, the planners have no specific written

guidance to assist them in deciding what post-maintenance test requirements

are applicable to CSSC equipment and components. If the planner is in doubt

about the post-maintenance test requirements for a particular maintenance

request, he can request assistance from the maintenance engineering

personnel. The licensee is presently developing guidelines to assist

maintenance planners in the determination of post-maintenance test

requirements. These guidelines are scheduled to be issued by January 1,

1986. In response to violation 328-85-24-02, the licensee committed to

provide personnel who plan MRs instruction in proper post maintenance test

requirements by January 1, 1986. As of this inspection, this trt.ining had

not been provided to the planners. Although a review of selected MRs did

not reveal inadequate post-maintenance test requirements for those specific

jobs reviewed, there is still concern that programmatically, more written

guidance and training for planners in the area of post-maintenance testing

may be necessary in order to properly equip the planners to fulfill their

responsibilities. This concern with regard to establishing written

guidelines and formal training for planners is not restricted to just

post-maintenance testing. Since the backgrounds and experience levels of

the individual maintenance planners vary, the inspectors are also concerned

that the lack of a formal training program or consistent guidelines for

maintenance planners in all aspects of planning could lead to inconsistency

in the implementation of the maintenance program, possibly resulting in

inconsistent work being performed on similar components. The inspectors

reviewed the manner in which the newly formed systems engineering group is

used in the implementation of maintenance activities. The group's

responsibilities are defined by Standard Practice SQA-168, Systems

Engineering, which at the time of this inspection, was in the review and

approval cycle. These responsibilities are designed to provide a single

point contact for history, status, and resolution of system problems, and

reliability and performance of systems under an engineer's cognizance.

Additionally, these responsibilities allow the systems engineer to

coordinate work activities across discipline lines. Discussions with system

engineers, maintenance engineers, and planners determined that system

engineers have little involvement in the work request process. If a problem

develops that cannot be resolved by the planners or maintenance engineers,

it will be referred to the systems engineers for resolution. The systems

engineering group is not used in the determination of post-maintenance

, testing requirements. A member of the systems engineering group has been

assigned to pro,ide input into the development of the post-maintenance test

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program but has not yet been asked to participate. The inspection team

considers that the systems engineering group could be an effective group for

establishing and consolidating maintenance planning information, such as

specific post-maintenance test requirements for all QA components, in order

to assist planners in accomplishing their responsibilities.

The inspectors reviewed the manner in which corrective maintenance is

scheduled and prioritized. Initial prioritization of each WR is

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accomplished by the initiator. Establishing the need for an MR and formal

prioritizing of WRs and MRs which were initiated during the previous

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24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is accomplished at a planning meeting conducted prior to the start

of day shif t. This meeting is attended by general foremen, planners, and

middle management representatives from each of the maintenance groups as

well as a QA representative and an operations coordinator. Work required to

be accomplished by MR is identified as such and a priority of immediate

action, or routine priority 1, 2, or 3 is established. Work on immediate

action MRs should be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, work on routine priority 1

MRs should be initiated within seven days. Routine priority 2 and 3 MR

initiation is indeterminate. The Maintenance Superintendent stated that, if

a priority which was initiated by the operations group is downgraded, the

operations group is notified by the operations coordinator in order to

ensure operations' agreement with thi action. Data is taken from this

meeting and loaded into a data bank for tracking purposes and MRs are

formally written by the maintenance scheduling unit. This process takes

place ir'a two to four hour period. The MRs are given to the planners who

complete the planning effort for each job and determine if resources are

available for each job to be worked. If resources are available, the job

goes on an available list. The available list is reviewed by general

foremer and foremen at another meeting where available MRs are selected for

work curing the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Additionally, MRs which have been field

comple-ted during the past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are identified during this meeting.

Ccmoleted work and scheduled work is then identified at an afternoon

plann:ng meeting attended by middle management, supervisors, and planners

from each maintenance discipline and the operations coordinator. This cycle

is continued on a daily basis. As indicated in the following paragraph, the

backlog of open MRs which have yet to be 'ield completed is not excessive

and is experiencing a decreasing trend. Th s is considered to be supportive

of an adequate program of scheduling.

A review of the backlog of corrective MRs indicates that the totai numbers

of outstanding corrective MRs which had no: been field completed at the time

of this inspection was 1169 items. This is considered to be a manageable

backlog. The inspectors were provided with data showing the number of

outstanding MRs for each week during 1985. This data showed that the number

of outstanding MRs increased significantly during the two month period

following plant shutdown on August 21, 1985. The number of outstanding MRs

reached a peak in mid-October and has subsequently been decreasing steadily.

This trend indicates that acceptable progress is being made in reducing the

number of outstanding MRs. Section 6.7.2 of the Sequoyah Nuclear

Performance Plan contains a commitment for the licensee's maintenance

department to review outstanding MRs on safety-related equipment to ensure

that no unworked item will degrade equipment or impede operator action

necessary for safe operations of the plant. To determine the licensee's

program for complying with this commitment, the inspectors obtained a list

of all active mechanical section MRs. The inspectors reviewed this list and

selected 25 MRs for evaluation. The inspectors evaluated the 25 selected

MRs and made a determination of those which, in their opinion, required

completion prior to plant startup and those for which completion was not

required prior to startup. The list of selected MRs was then given to the

licensee for an independent review and determination. The licensee's

determinations were then compared with the inspectors' previous

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determinations. This comparison showed that, within the selected sample of

MRs, the licensee had identified as requiring completion before plant

startup, all the MRs the inspectors had so identified plus two MRs the

inspectors had categorized as not necessarily requiring completion before

plant startup. Therefore, the inspectors concluded that the licensee is

apparently ccmplying with the commitment to complete all necessary work

prior to plant startup. Table 1, page 9, is a list of the MRs selected for

this sample as well as inspector and licensee notations regarding

requiren ents for completion prior to plant startup. Completion of work for

those MRs for which completion is identified as being required prior to

plant startup is identified as an inspector followup item (327-85-46-05,

328-85-45-05).

The inspectors noted that field completed MRs have potential for being

reported complete based on general knowledge of work rather than a review of

completed records due to the manner in which the information is compiled to

support the afternoon planning meeting. The inspectors consider that a

formal review of completed records is the proper vehicle for reporting

completion of work and considers that there are benefits in using an

independent group, such as the maintenance and scheduling section to

acccmplish this review.

The inspectors obtained and reviewed a printout of all MRs for which the

field work had been completed but which had not completed licensee review

and final closure. The printout showed 2466 MRs in this status. Licensee

Corrective Action Report (CAR) No. 4b-82-45 dated July 7,1982, noted that

MRs were not being maintained in accordance with SQM2 in that computer

records indicated that a large number (2,451) of CSSC MRs had been lost and

discarded. The CAR was closed on February 18, 1983, without addressing the

disposition of the missing CSSC MRs. A supplemental response to the CAR was

issued on March 7, 1985, to provide guidance on the disposition of these MRs

and to require completion of their disposition by April 12, 1985. The

inspectors' review of the printout disclosed numerous MRs with field

completion dates prior to February 18, 1983. In an interview with a

licensee representative on December 5,1985, it was determined that 670 MRs

which had been field completed prior to February 18, 1983, were still in

this status (had not been closed out) despite the requirements of the

March 7, 1985 supplemental response to CAR No. 4b-82-45 to do so by

April 12, 1985. A further review of the printout disclosed that an

additional 710 MRs had been field completed between February 19, 1983 and

September 30, 1985, but had not been closed out. This represents a review

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duration in excess of 60 days which is considered excessive. These failures

to complete corrective actions associated with CAR 4b-82-05 and associated

supplements and to properly manage the review process to prevent recurrence

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is an example of failure to take prompt corrective action and is a violation

(327-85-45-06,328-85-45-06).

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TABLE 1

MAINTENANCE REQUESTS REVIEWED BY INSPECTOR AND LICENSEE

Completion Required Before Plant Startup

MR Number NRC Inspector Determination Licensee Determination

Y102554 Not required Not required, but will be done

A536974 Yes Yes, before Mode 3

A536273 Yes Yes, Completed

A520434 Yes Yes, Completed

AS48375 Yes Yes

A548376 Yes Yes

A533760 Yes Yes

A285227 Yes Yes, Completed

A546226 Yes Yes

A237970 Not required Not required

A534592 Yes Yes

A561762 Yes Yes

A562888 Not required Not required

A522163 Yes Yes

A282103 Not required Not required

A244832 Not required Not required

A546281 Yes Yes, perform requested evaluation

A295578 Not required Not required, but will be done

A521756 Yes Yes

A520429 Yes Yes

AS48442 Yes Yes

A550462 Yes Yes

A523146 Not required Yes

A548426 Yes Yes

AS48431 Not required Yes

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The inspectors reviewed the licensee's program for machinery history and

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trend analysis and noted that actions are being initiated to implement a

trend analysis program. The provisions for this program are currently being

, drafted into Standard Practice procedure SQM-58. As presently i

) conceptualized, this trend analysis program will establish a history data

base through the TVA EQUIS program for NPRDS reportable maintenance items,

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! maintenance activities associated with 10 CFR 50.49 equipment, maintenance l

activities associated with CSSC equipment failures, and maintenance

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activities associated with some non-CSSC equipment failures. The program l

will ensure unique identification for each component entered into the

'.

history data base and will establish a trending threshold to determine

. repetitive equipment problems for a specific component and generic equipment l

1

problems for a particular type of component. The inspectors reviewed i

.

machinery history for main feedwater isolation valves and also for UHI level

! switch problems noted in paragraph 13 of this report with respect to this

! conceptualized trend analysis program and concluded that, as conceived, this

program is capable of providing for effective trend analysis. The

j inspectors consider that some potential problems could be encountered with

< assuring effective trend analysis and recommended that the licensee consider I

i the following items in development of their program to avoid potential

problem areas:

'

-

If the trending program is to work properly, functional categorization

l of data on the MR must be accurate and compatible with the EQUIS

program categories to ensure that trending program input data is

'

reliable. To this end, it is considered that written guidance and

training for planners in this area is necessary.

-

The trending threshold for repetitive failures looks at a specific

!.

component by unique identification and the trending threshold for

i generic failures looks at a particular model of equipment. Nothing

i really addresses groups of components with the same specific

il application (e.g. , all main feedwater isolation valves, all steam

generator blowdown valves, all UHI level switches). As indicated by

j review of the UHI level switch problem delineated in paragraph 13 of

j

this report, review of component data in this manner can effectively

provide repetitive failure information.

,

J -

Unless "out of calibration" conditions are reported as equipment

l failures, it is possible that problems such as the UHI level switch -

, problem delineated in paragraph 13 of this report would not be '

1

identified through the trend analysis program. Consideration should be

j given to resolving this issue. j

i

j -

Once the trend analysis program has been developed and implemented, a

! review, using an independent data system such as the potential

!

!

reportable occurrence data base, should be conducted to confirm program i

reliability.

,

i

I

!

! I

i  !

!

"M '++v.. - ,.wv

!

=

.

.

11

The inspectors consider that the overall program as specified in SQM-2

should be adequate to assure safe and proper completion of corrective

maintenance. However, since the program is relatively new, insufficient

data exists to properly assess the effectiveness of program implementation.

Additionally, efforts being initiated in the area of machinery history and

trend analysis show the potential for an adequate program, but can not be

effectively assessed until implemented. The inspection team considers that

additional review of the programmatic aspects of maintenance planning is

warranted af ter actual completion of committed improvements and after

sufficient implementation time under operating conditions has transpired.

Accomplishment of this additional inspection is identified as an inspector

followup item (327-85-45-07, 328-85-45-07).

During inspection of this area, the inspectors reviewed resolution of

inspector followup item 327-85-24-01, 328-85-24-01. All elements of this

item have yet to be fully resolved; however, the Maintenance Superintendent

indicated that it is intended that each element will be resolved in

conjunction with implementation of long range maintenance program

improvements. Inspector followup item 327-85-24-01, 328-85-24-01 remains

open.

The inspectors also reviewed implementation of commitments from the Sequoyah

Nuclear Performance Plan with respect to communic'ations from management to

craft workers. Section 6.3.1 of the Sequoyah Nuclear Performance Plan

states that in the past, performance of maintenance activities by craft

workers and control of craft worker activities at the foreman level had not

met the licensee's expected level of excellence The licensee identified

one of the root causes for this problem to be inadequate communication to

the working level by management of job requirements, performance

expectations, and feedback in instances of inadequate performance.

Therefore, the licensee committed in section 6.3.1 of the Sequoyah Nuclear

Performance Plan to improve such communications via the following three

routine meetings:

a. Weekly meetings among the maintenance group supervisor, craft section

supervisor, foreman, and general foreman for each of the three

maintenance sections with frequent attendance by the Maintenance

Superintendent. The stated purpose of tnese meatings is to discuss

current problems associated with regulatory perrormance, procedural

acherence, procedure adequacy, coordination, and scheduling and to make

assignments as appropriate for their resolution. The Sequoyah Nuclear

Performance Plan also states that plant policy, experience review

items, and administrative requirements will be reviewed and discussed

in these weekly meetings.

b. Monthly safety meetings in which the licensee has committed to

communicate plant policy and requirements to all maintenance section

employees.

c. Weekly crew safety meetings in which the foremen are to discuss plant

experience items such as recent violations, LERs, and personnel errors

with their crew members.

_- - .--. . . - - - . _ . - . _ . - - . --

.

'

.

12

l

,

To determine if these meetings are being conducted and if the meetings are

covering the subjects the licensee committed to cover, the inspector inter-

t

.

viewed 12 Maintenance Department employees (2 foremen, and 2 craft workers i

from each of the three sections; electrical, instrument and control, and

mechanical). The information obtained during these interviews indicates

4

that these meetings are aeing conducted at the specified frequencies and d

j

that the topics covered in these meetings include those committed to in the

Sequoyah Nuclear Performance Plan, i

7. Review of Pr eventative Maintenance, Instrument Calibration, and Measuring

7

and Test Equipment Programs

i

The inspectors conducted a review of the licensee's preventative maintenance The

(PM) program. The PM program 1.; governed by Standard Practice SQM-57.

I

l

objective of the program is to maintoin equipment to ensure quality at least

'

equivalent to that specified in the original design and material specifica-

tion. The requirements of SQM-57 apply to inspections, lubrication, adjust-

ments, parts replacement, or cther activities accomplished on a routine

basis to ensure reliable performance of mechanical, electrical, and

instrument and control equipment. The program requires the maintenance

groups to prepare PM requests based on vendor information or other require-

ments. The maintenance scheduling unit is responsible for scheduling of PMs ',

i

' and also assembles the work packages to perform the PMs. The maintenance

scheduling unit assigns a completion due date to each PM work package and

routes the packages to the maintenance groups. After completion, the

package is revieved by the appropriate group prior to filing in the e

,

'

l

'

appropriate history file. The inspectors reviewed scheduling of PMs with

the scheduling supervisor and determined that a complete schedule of PMs

f

'

with respect to due dates based on stated frequency is available. However, .

no scheduling consideration is provided with respect to manpower allocation

!

which would help group planners in manpower planning. Also, the scheduling

of PMs does not consider the operability requirements of the components.

l

This condition may require that a PM which would require a component to be

l

' taken out of service would not be able to be accomplished when required by

the master schedule if the equipment is required to be operable to support

I the mode that the unit is in. Additional discussions were held with

responsible personnel in each of the maintenance groups and the following

i

conclusions were reached.

>

- Planners do not receive a schedule of upcoming PMs other than receipt

l

i

of the PM packages just prior to required performance.

i ,

- Late or incomplete (cancelled) PM activities normally are only reviewed

! by the r;eneral foreman with regard to affect on the equipment. It

should be noted that administrative requirements make it easier to

! cancel a PM rather than defer it. Engineering evaluation of incomplete

i

i

or cancelled PMs normally is not accomplished. Also, higher management

i

reviews of late or incomplete PMs appeared to be minimal.

i

!

l

r

l

l

1 -_ .

. - _ - - - - -

- - - - -

- - _ - .- _ . _ _ . _ . . -- - . . - _ = - -

t

'

.

.

! 13

-

Equipment failure in general is not used as an input into the PM

4

preparation. The mechanical maintenance and electrical maintenance

i groups had not used any equipment failure (trending) data as source of

information during engineering review of PM instructions for revision.

The instrument maintenance group did provide for equipment failure

i

'

input into PM revision due to an internal requirement that engineers

maintain a notebook of maintenance problems associated with assigned

,

systems.

i

{

-

Procedures were prepared in advance for performance of most PMs. '

However, the detail required to insure that all required data was

4

recorded coupled with the degree of training provided to personnel

j performing PMs in order to insure that they understood the information

that was required to be recorded appeared to be inadequate. This

! conclusion was based on review of completed PMs which were only r

j

'

partially performed or had missing data in blanks that required data or

information. The inspectors also noticed that no procedure was in .

) place to allow for temporary changes to PM procedures and that changes  !

l were being done without appropriate technical review. '

!

' -

A lubrication control system had been incorporated into the prugram and

the instrument maintenance and mechanical maintenance groups had this

f

incorporated into their respective PMs. An electrical maintenance

group representative was not sure that all lubrication requirements ,

were being accomplished through the electrical maintenance PM program. '

! This is due to mechanical maintenance i nitially writing lubrication t

requirements for electrical motors which were part of a vendor supplied

i

motor and pump assembly into the mechanical maintenance PM program when

1 the lubrication program initially was assigned to the site. A

l mechanical maintenance representative stated that an internal memo had

been issued assigning electrical maintenance responsibility for ,

i lubrication requirements on electrical components; therefore,

mechanical maintenance no longer included lubrication requirements in

, their PMs for motors on pump and motor assemblies. the inspector

j requested that the electrical maintenance group review all PMs on i

i safety related components to assure that proper lubrication controls l

l are in place.

'

Resolution of concerns with PM program weaknesses as delineated herein is l;

identified as an Inspector Followup Item (327-85-45-08, 328-85-45-08).

i

The inspectors reviewed implementation of PM recommendations from vendor

manuals into the PM program. Six vendor manuals were reviewed to determine

if the vendor PM recommendation were incorporated into the PM program. Most

were inexplicit or did not delineate PM recommendations. However, Pall

'

Trinity Micro Corpoiot on had very specific preventive maintenance required

d

i for their model 101 HAl-6HD9810-331 air dryers. These dryers, which the

licensee uses in their auxiliary control air system, are required in order

j to supply clean, dry air to certain valves in the containment building

'

following an accident. The inspectors noted that the licensee's PM program

.

did not include these dryers. Furthermore, through interviews with the

t

i

4

i

t

_ _ = . - - - - ~ . . . . _ _ , _ _ _ _ _ - . . _ - - . - - . - , - - _ _ _ - - . .-.--~__.----,..m..--_-,,-- _,_m.-----

- _-- - - . _ _ - - . - - . - - . . - . . -

.

14

systems engineer, the inspectors determined that the dryers had not been

considered for inclusion in the program. The inspectors toured the spaces

containing the dryers. The inspectors noted the following items:

,

-

The calibration stickers for the dryers instrument panels were dated in

i 1978.

-

The optional package available from the vendor to easily check

desiccant quality was not installed.

-

Old paint on the dryers indicated that certain major parts had not been

opened in a long time (e.g. , pre- and after-filters, desiccant parts,

check valves, and pilot valves).

'

The inspectors noted that information related to air dryer maintenance was

previously provided in IE Circular 81-14 and IE Notice 81-38. In fact, IE

Notice 81-38 even stated selected preventive maintenance items which were

i also delineated in the Pall Trinity Micro Corporation manuals. During the

i

'

inspectors' review of SOM-57, it was noted that the document required that

'

the responsible performing group shall identify the type and frequency of

maintenance to be performed from vendor manuals, manufacturers' bulletins,

.

Technical Specification requirements, division procedures, standard

!

practices, 10 CFR 50.49 or other directives and documents. The Pall Trinity

,

Micro Corporation manual suggests 14 types of maintenance be performed in

l timeframes from monthly to annually. These requirements include checking

! outlet dewpoint, blowdown of relief valves, replacing filter cartridges,

l inspection of desiccant, and cleaning of valves. These recommendations were

not taken into consideration in developing the PM program. Consequently,

a

this is an example of failure to follow procedure SQM-57 and is a violation

i (327-85-45-09,328-85-45-09).

I

The inspectors reviewed the licensee's instrument calibration program by

,

evaluating the calibration history of three safety-related instruments.

l Instruments selected were:

1

1

IN No. Description

'

j PI-62-110 (Unit 1) Centrifugal Charging Pump Discharge

.

i

Pressure Instrument

l' TR-61-138 (Unit 2) Ice Condenser Ice Bay Temperature i

,

Monitor

I

l

l MIS-65-16 (Common) Emergency Gas Treatment System Train A

i

Moisture Level Hi  !

l For each instrument, calibration history was maintained current on calibra-  ;

i

tion cards which were maintained in fire-resistent files as quality records.

! In addition, administrative records associated with each calibration were

maintained in document control. The information contained in the local

!

i historical file included "as-found" and "as-left" data for each instrument

!

i

L

- _.

,

l

l

'

4

\

15

calibration range and was sufficient in whole to provide a basis for trend

analysis and for evaluation of the credibility of affected surveillance

tests when the instrument is found out of calibration. For each instrument,

documentation was maintained locally which certified that the instrument was

calibrated by TVA Central Laboratory Services and that the calibration was

traceable to nationally recognized standards. Each calibration card

3

contained initials of the individuals who performed the calibration. The

!

Materials Clerk who is assigned the primary responsibility for maintaining

the file was able to identify the persons who had performed the calibrations.

The use of initials on the calibration card was backed up by full signatures

i on the Instrument Maintenance Instruction forms filed in document control.

Although approved procedures were available to calibrate the above instru-

ments, detailed step-by-step instructions were not provided. The licensee

stated that these instruments, though safety related, were not CSSC and that

the calibration of non-CSSC (including safety-related and compliance related)

instruments is considered within the skill of the craf t. Calibration

instructions involving CSSC instruments provide step-by-step guidance. It

was beyond the scope of this inspection to evaluate the level of skill

within the instrument maintenance group. However, the inspector observed a

calibration of the feedwater control system (IMI-46) and determined that the

techr.icians were capable of performing this calibration without detailed

instructions.

The inspectors reviewed the implementation of corrective actions associated

with MTE concerns noted within the last Systematic Assessment of Licensee

Performance (SALP) reported for Sequoyah and delineated in NRC Inspection

.

Report 327/85-05, 328/85-05, dated February 22, 1985. Improvements in the

! MTE program are scheduled for implementation on June.1, 1986, and

consequently have yet to be completed. A review of a draf t TVA summary

report which addresses resolution of problems with MTE indicates that TVA

considers that some improvement has been made with regard to control of

MTE, as a result of actions taken to date, which include changes to control

and issue all MTE from a central site services location. The inspectors

consider that it is too premature to assess implementation of program

improvements at this stage of development and that actions requiring

completion prior to such assessment include:

-

assigning singular program responsibility to one organization to ensure

program consistency.

-

revising all applicable proceaures (including ancillary procedures) to

reflect all changes within the MTE program.

l

Until these actions are implemented and this implementation reviewed

violation 327-85-05-01, 328-85-05-01 remains open.

4

i

_ _ _ _ _ _ _ - - - - . _ . _ - - - - - _ - - - - - _ _ - _ - _ _ - - _ - _ _ _ _ _ _ . _ _ _ . _ _ _ . _ _ _ _ _ _ _ _

- = . --- - - . - - - - _ _ - _ - _ _ _ - . - - . - - _ . -- --

1

. .

-

i

,

16

1

i

i

i 8. Review of Implementation of Vendor Recommendations for 10 CFR 50.49

! Equipment Into Corrective and Preventative Maintenance Programs

!

The licensee recently revised Standard Practice Procedure SQM-62,

j Qualification Maintenance Data Sheets (QMDS) Implemeqtation, Environmental

Qualification Deviation' Report, and Category II Upgrade Control, to clarify

and upgrade the QMDS program. QMDS is a subset of the Equipment

!

Qualification (EQ) data packages which are now being revised at

TVA-Knoxville. At the time of the inspection, only preliminary EQ packages

i had been received at the site. The revised SQM-62 program will incorporate

the final updated QMDS packages as they are received at the site. The major

j thrust of the revised QMDS program will be to eliminate the practice of

l using MRs to disseminate QMDS requirements by instead incorporating them

, into approved plant procedures. QMDS recommendations may still appear in

'

MRs but a portion of them will also be incorporated in plant procedures.

. Scheduling of QMDS requirements will utilize the surveillance instruction

I

(SI) program whenever the SI frequency satisfies the QMDS required

I frequency. When the frequencies are not compatible or when replacement of

] whole devices qualified for less than 40 years is required, scheduling will

be accomplished with a new quality maintenance (QM) program. The entire  ;

QMDS program will be consolidated as Appendix C to SQM-62 after all revised

, QMDS packages are received. This appendix will list the unique  ;

] identification number of the equipment, the EQ binder in which it is L

j located, a description of each individual requirement, the frequency, the  ;

implementing instruction, and the responsible group. The inspectors -

-

questioned the licensee concerning restrictions involving maintenance

'

activities taking place in the vicinity of qualified equipment which could

l create environmental conditions contrary to QMDS requirements. Standard

Practice Procedure SQA-173, Sequoyan Nuclear Plant 10 CFR 50.49

) Environmental Qualification Program, Section 6.5.1, states that planners

should positively identify maintenance activities that may affect equipment

) within the scope of the SQN 10 CFR 50.59 program. Based on numerous

interviews with maintenance planners, this aspect of the QMDS program is not

,

l t

well established. The licensee stated that a detailed EQ training proqram

i

is scheduled to begin December 16, 1935, which should educate plannt.9 on

! these new requirements. The revised QMDS program appears to be adequate to

ensure that QMDS requirements and recommendations will be properly

,

i i

I

accomplished; however, the manner in which the program is implemented will

j be critical to its success. The implementation of this program is again

,

dependent upon the experience, guidance, and training provided to planne.'s, i

As in the case of other planning activities, this area also needs to be

following completion of training and after sufficient

,

reviewed

implementation time has transpired to allow for assessment of effectiveness.

i 9. Review of Maintenance Instructions

!

!

I

The inspectors reviewed several maintenance instructions (mis), spanning

each of the disciplines, in order to determine the instruction's L

l understandability, adequacy of reviews, and technical accuracy. The

!

instructions reviewed were MI-10.27, Diesel Generator Battery Maintenance

j and Inspections; MI-5.4, Blocking of Ice Condenser Lower Inlet Doors During

!

!

!

,

_ . . ~ _ _ _ - _ _ _ - .. _,_, _ _ _ - -

_ . _ _ _ _ _ - ,

.

.

17

Cold Shutdown; MI-10.38, ASCO Solenoid valves; MI-10.38.1 ASCO Solenoid

Valves 206-381-1R through 206-381-7R; MI-2.6, Disassembly, Inspection, and

Reassembly of Reactor Coolant Pump No.1 Seal and Runner - Units 1 and 2;

Instrument Maintenance Instruction (IMI)-99 cc 11.6 B, Reactor Protection

System, Offline Channel Calibration of AT/Tavg Channel II Rack 6, Unit 1;

IMI-46, Feedwater Control System, Units 1 and 2; MI-11.4, Maintenance of

CSSC Valves; MI-6.15. General Procedure, Tightening Bolted Joints; MI-6.20,

Configuration Control During Maintenance Activities; and MI-11.10, G. H.

Bettis Actuator Maintenance Guidelines, Units 1 and 2. Within the scope of

this inspection, the requirements of these procedures appeared to be clear,

technically adequate, and correctly incorporated into the observed

maintenance activities. In particular, it was noted that MI-10.38 and

MI-10.38.1 contained special requirements for the torquing of screws and

application of lubricants to seal: cf ASCO solenoids in accordance with

vendor recommendations. Suitable QC holdpoints were noted to be inserted in

the procedures to ensure adequacy of the maintenance activity and suitable

prerequisites were in place to ensure the activity would be performed in a

safe and controlled manner. The Sequoyah Nuclear Performance Plan committed

to a reduction in the tiering of procedures where possible such as to

directly implement regulatory documents without intermediate level manuals.

A schedule for the review and revision of surveillance instructions with

respect to reduction in tiering of procedures has been promulgated and a

similar schedule for maintenance instructions is in draft. Two recent

procedures (EQ-10.46 and EQ 10.37), were noted to have incorporated this

consideration in the drafting of their data sheets. The inspectors reviewed

implementation of maintenance instruction improvements delineated in the

Sequoyah Nuclear Performance Plan. The Sequoyah Nuclear Performance Plan

committed to limitorque valve operator maintenance procedure revisions in

order to incorporate appropriate measures addressing the limitorque valve

operator gear reversal problem identified at Browns Ferry. Maintenance

Instruction MI-11.2A, has been drafted to provide guidelines for the

maintenance of limitorque SB-00, SMB-000, and SMB-00 valve operators and the

adjustments of torque and limit switches. MI-11.2A incorporates measures

addressing the gear reversal problem and is in review for approval. Two

additional procedures are in draft to address the gear reversal problem for

the remaining CSSC and non-CSSC limitorque valve operators. The Sequoyah

Nuclear Performance Plan committed to the development of a checklist for

review of maintenance instructions. These maintenance instruction review

checklists were reviewed for MI-9.3.1 and MI-10.35, and demonstrated in

those areas implementation of this commitment. The Sequoyah Nuclear

Performance Plan committed to the November 15, 1985 interim implementation

of an instruction review sheet to obtain input from craftsmen to ensure

adequacy of existing maintenance instructions. The inspector reviewed

procedures in three maintenance shops and found maintenance instruction

review sheets being used on 22 of 23 procedures reviewed. The inspectors

consider that this demonstrates implementation of this commitment.

During a review of the maintenance program, the inspectors noticed that the

procedures which describe and control the maintenance program such as SQM-1,

Sequoyah Nuclear Plant Maintenance Program; and SQM-2, Maintenance Program,

were written as standard practices. The inspectors determined that standard

.

.

18

practices do not receive Plant Operations Review Committee (PORC) review.

The inspectors informed the licensee that they considered that the above

listed procedures are required by technical specifications paragraph 6.8.1.a.

and also require PORC review in addition to plant manager approval as

required by technical specification 6.8.1.b. The licensee then provided the

inspector with a copy of Division of Quality Assurance audit finding from

Audit Report No. QSQ-A-85-0010. The finding (Deviation QSQ-a-85-0010-D01) ,

stated that SQN Maintenance Program procedures are not being reviewed by

PORC as required by the technical specifications. The Sequoyah response

dated August 14, 1985, stated that a general procedure for the control of

maintenance, repair, and replacement work will be prepared. This procedure

will be issued by December 31, 1985. After learning that the issue had been

licensee identified, the inspectors reviewed the index of standard practices

and questioned whether other standard practices should also be PORC reviewed.

During the inspection exit. the licensee committed to PORC review the

maintenance program procedures (SQM-1, SQM-2, SQM-57, and SQM-58) and to

also review the other standard practices to determine if others require PORC

review. Additionally, the licensee committed to issue an LER on this

matter. Until all actions have been completed such that it can be verified

that the licensee actions satisfy all requirements of 10 CFR 2 Appendix C

for self-identification and correction of violations, this item will be

identified as an inspector followup item (327-85-45-10, 328-85-45-10).

10. Review of Sequoyah's Application of Lessons Learned From The Maintenance

Aspects of the Davis Besse Auxiliary Feedwater Event

The inspectors reviewed the licensee's evaluation of Generic Letter 85-13

which transmitted NUREG-1154 with respect to Auxiliary Feedwater (AFW)

containment isolation valves and other safety related valves and the

reliability of the AFW system. The inspectors noted that during the week

of this assessment, the licensee received Inspection and Enforcement (IE)

Bulletin 85-03 which requires completion of specific actions associated with

the Davis Besse AFW event. The inspectors noted that as part of the

licensee evaluation of NUREG-1154, the licensee stated a review of safety

related MOVs to assess the pertinent failure modes affect' valve

performance under design basis conditions would be consio;.ed. The

.

inspectors noted that IE Bulletin 85-03 requires review and documentation of

the design basis for operation of motor-operated valves in high pressure

coolant injection, core spray, and emergency feedwater systems. The

inspectors noted that as a result of concerns over AFW system reliability,

Sequoyah formed an AFW system task force to evaluate the reliability of the

AFW system. As a result of this task force evaluation, the licensee

identified 24 action items to improve the overall reliability of the AFW

system. These action items are tracked by the AFW system engineer. The AFW

system engineer also trends, on a monthly basis, the number of issued

potential reportable occurrences which affect the AFW system in order to

trend system performance. The inspectors reviewed the AFW system task team

report and determined the status of the 24 action items recommended by the

task force. All items were being tracked by the AFW system engineer and

most items had already been completed or were in the process of completion.

,

.

19

The inspectors reviewed the Motor Operated Valve (MOV) program which is

being initiated at Sequoyah as a result of Limitorque valve operator pinion

gear reversal problems experienced at TVA's Browns Ferry facility. Sequoyah

conducted an investigation to determine what maintenance had been performed

on CSSC Limitorque valve operators in which the pinion gear may have been

disturbed. This investigation identified five valves on which maintenance

had teen performed that may have effected the pinion gear. These five

valves have been inspected by the licensee for proper pinion gear

installation ana no problems were identified by the licensee. The licensee

is presently developing a comprehensive safety related MOV program. This

~

program will consist of visual inspection, lubrication and testing. As part

,

of the MOV program, the li.ensee has instituted a major rewrite of the

limitorque maintenance procedures. One aspect of the rewrite program is to

replace generic limitorque maintenance instruction with instructions

addressing specific type of limitorque valves. This rewrite is scheduled

for completion in January 1986. Sequoyah has instituted a composite crew to

perform maintenance and testing of MOVs. This crew consists of a foreman,

two mechanics, and four electricians. All personnel, with the exception of

two electricians, have attended the limitorque training program. The two

electricians that have not attanded the limitorque training are paired with

the two electricians that have attended the training. As part of the MOV

prcgram, Sequoyah has purchased Motor Operated Valve Test Systems (MOVATS)

equipment and has received training from the M0 VATS company on its use.

Sequoyah presently plans to utilize the composite crew and MOVATS testing on

241 limitorque valves on units 1 and 2 prior to startup if resources and

time permit. These 241 valves are undergoing modification to replace

internal wiring on the valve operators to meet NURFG-0588, 10 CFR 50.49

requirements prior to startup. As the modification group completes

modification and post modification testing on a specific limitorque valve,

the valve is turned over to the composite crew for MOVATS testing and

inspection. As of this inspection, M0 VATS testing and inspection had been

completed on six limitorque valves of which problems were identified on four

valves. The inspectors consider that the results of the MOVATS testing and

inspection should be evaluated as more valves are completed to determine the

extent of problems and the need to test all 241 valves prior to unit

startup. The inspector observed the MOVATS testing conducted on valve

2-FCV-70-134 per MI-10.43, Procedure for Testing of Motor Operated Valves

Using the MOVATS-2000 System. During the conduct of the fiOVATS testing, the

limitorque motor tripped on overload as opposed to the torque switch as

specified in the procedure. Investigation by the MOVATS personnel

determined that a jumper was installed across the torque switch which

prevented the torque switch from functioning. This jumper should have been

removed during the performance of work plan 11853, NUREG-0588, 10 CFR 50.49

Valve Rewiring, that was performed by the modifications group prior to

turning the valve over to the composite crew for MOVATS testing and

inspection. Under normal operation of valve 2-FCV-70-134, this jumper would

have no affect on the operation of the valve because the torque switch is

not electrically connected. However, when the torque switch was inserted in

! the circuitry to accomplish MOVATS testing, this jumper prevented t5e torque

switch from functioning and the 1imitorque motor tripped on overload.

Review of work plan 11853 determined that this jumper should have been

l

l

l _ - - _

.

9

.

20

removed during the valve rewiring modification performed on the valve.

Discussions with the modifications crew that performed the work indicated

that this was the first valve they had performed the modification on and

that not removing the installed jumper was an oversight, the torque switch

was electrically disconnected from the circuitry as required by the work

plan; however, the electrical leads were not removed as required per the

work plan. The licensee instituted MR-A-295497 to visually inspect all

valves that had already been functionally tested per the modifications

package. Fif teen valves were inspected and no similar occurrences were

discovered. The licensee also revised the procedure to visually inspect

wiring during functional testing to verify correct wiring on the valves that

have yet to be functionally tested per the work plan. Failure to remove

electrical wiring in valve 2FCV-70-134 as required per work plan 11853 is

another example of failure to follow procedure which has been identified as

violation 327-85-45-09, 328-85-45-09.

.

11. Review of Implementation of Watts Bar Experiences at Sequoyah

a. Followup of Watts Bar Nonconformance Reports

The inspectors selected several non-conformance reports (NCRs) from

Watts Bar files that were potentially generic to Sequoyah to determine

if the experience review and lessons learned program at Sequoyah was

delivering information, when required, to the responsible sections for

corrective action. The Watts Bar NCRs which were reviewed and their

dispositions at Sequoyah are as follows:

-

NCR W-312-P identified a problem with the 6900V breaker on 2A-A

shutdown board feeding ERCW pump 0-A in which the breaker failed

to open electrically by use of the handswitch in the main control

room. The problem occurred when the mechanical linkage to the

trip coil had a sheared pin preventing the trip. The pin failure

was due to lack of fusion of a fabrication weld. A further random

sampling of twenty breakers of similar make revealed six welds

that were identified as questionable. Discussions with Sequoyah

electrical maintenance section personnel indicated that they were

aware of this NCR through informal discussion with Watts Bar

electrical maintenance personnel. However, by the end of this

inspection period, December 6, 1985, the Sequoyah electrical

maintenance section had not received any formal documentation on

this problem. This is not considered to be a problem at this

point in time since this NCR was dated November 25, 1985, and a

generic review is required to be performed by the engineering

section in Knoxville. Office of Engineering Procedure (0EP)-17,

Corrective Action, is the controlling procedure for generic

reviews between sites and allows up to 30 days for analysis to be

performed and documentation to be routed to the site. The

- - - - -. . . _ . _ ._ . - _. . . - - .

.

4 -.

21

licensee- did perform an evaluation of this NCR for applicability

to Sequoyah based upon preliminary information and determined that

'

the breakers for the additional emergency. diesel generator are

manufactured by the same vendor and are of similar type. However,

i the licensee had not physically inspected the breakers for

mechanical linkage damage as of this inspection.

- NCR W-310-P dated November 20, 1985, identified a problem with the

additional diesel generator system in which the General Electric

,

model 12 CFD differential protection relay is not seismically

qualified per IE Notice 85-82. The licensee had not reviewed this

NCR from Watts Bar since this item was evaluated per the IE

I Notice. This evaluation determined that the identified conditions

) are not applicable to Sequoyah since Westinghouse differential

i

protection relays are used.

! -

Construction Deficiency Report (CDR) WBRD-50-390/85-52 was issued ,

This CDR identified

in accordance with 10 CFR 50.55(e).

i improperly installed ASCO solenoid valves at Watts Bar. As of the

i end of this inspection period, the licensee was not aware of this

l

CDR through the formal or informal process. However, at this

4 point in time, this can not be considered to be a problem since

i the CDR was issued November 19, 1985. Again, per OEP-17,

l engineering has 30 days to complete a generic review. The

j inspectors toured the plant and observed several series 8316 ASCO

) solenoid valves which were recently installed at Sequoyah as part

] of the NUREG 0588, 10 CFR 50.49 program. The specific valves

i inspected were 1-FSV-63-64, 1-FSV-68-305, 1-FSV-77-20, and

1-FSV-63-42 which are located in the unit 1690 foot elevation

The inspectors learned through discussions with the

pipe chase.

l licensee that these solenoids were provided from the vendor with

j mounting brackets installed on each end of the valve. This

) configuration was seismically and environmentally qualified by the i

vendor. However, the valves inspected had mounting configurations

that differed from that provided by the vendor. Valves

1-FSV-63-64 and 1-FSV-63-42 had only a bracket attached to one end

and valves 1-FSV-68-305 and 1-FSV-77-20 were mounted by the is inch

piping that connects to the inlet and outlet ports of the

! solenoids. In turn, the piping is supported by a unistrut hanger.

The inspectors questioned the original seismic qualification of

these solenoid valves and requested documentation that proved

i that mounting the solenoids by using unistrut piping supports was

-

'

a seismically analyzed and approved method. Since the licensee

was unable to provide this documentation by the end of this  !

inspection period, the seismic qualification verification of these r

!

'

,

m._ _ , ,_. _ , r,. __ _ _ _ , _ _ .,_ _,_ . _ -

__.,__..,.. .- _____, ,. --_. j,_ o ,_., _ ;. _ . m _ _ . __.

.

-. .. . . . . . . _.

> .

.

22

valves is identified as unresolved item (327-85-45-11,

328-85-45-11). With respect to the environmental qualification of

the four valves, the inspector reviewed engineering change notice

(ECN)-6487 which was issued in September 10, 1985, and work plan

(WP) 11806. The purpose of this ECN was to replace the existing

solenoid valves with qualified valves to meet NUREG 0588

requirements and the WP gave detailed instructions to implement

the actions required by the ECN for unit 1. The inspector noted

.

that neither the ECN nor the WP denoted any special requirements

i

for disassembly or reassembly of these valves to allow for

installation. In these cases, one or both of the mounting

brackets were removed in order for the valves to be installed to

conform to the existing mounting configuration. This required

removal and replacement of two of the four screws, at the end of

each valve body, that maintain the NUREG 0588 boundary. However,

no torque values or tightening patterns were specified in the ECN

nor the WP and discussions with the licensee indicated that no

special torquing of the screws was performed. The vendor bulletin

gives specific torque values for these. screws and requires that a

criss-cross tightening pattern be used to maintain the NUREG 0588 >

boundary. The inspectors requested that the licensee provide

documentation to show that the NUREG 0588 boundary was not

violated upon removal and reinstallation of the valve body screws.

Since the licensee was not able to provide this documentation by

the end of this inspection period, the verification of the

environmental qualification of these solenoid valves is identified

as unresolved item (327-85-45-12, 328-85-45-12).

-

Non-ASME Significant NCR W-295-P dated November 21, 1985,

identified a problem with the automatic to manual transfer switch

for the emergency diesel generator excitation system. The problem

involved the inability to select between the manual and the

automatic voltage regulators in the remote (main control room)

location due to improper wiring of the "K2" and "K3" relays which

allow for this transfer capability. Discussions with licensee

personnel indicated that they were aware of this NCR through the

formal process. However, as of the end of this inspection period,

a licensee determination for existence of similar problems at

j Sequoyah had not been completed.

1 -

Numerous NCRs have been generated at Watts Bar with regard *,o

cable pulling deficiencies. The inspectors held discussions with

the appropriate licensee management to review Sequoyah's

evaluation of these problems. The licensee indicated that they

were aware of cable pulling problems at Watts Bar and had received

I a Significant Condition Report from engineering in August 1985.

,

The licensee further indicated that a review for applicability at ,

!

Sequoyah was completed in September 1985, and work was '

• consequently stopped based upon the fact that Sequoyah was pulling

cable under the same specifications as Watts Bar. The general

specification for cable pulling, G-38, was subsequently revised l

l

l

l

l

l

l'

. . . . _ - . . . - - - -

,

.

'

,

23

J

1

.

'

and cable pulling operations were reinitiated, although pulling at

Watts Bar was only partially authorized under certain conditions.

At the beginning of November 1985, the licensee learned that a

l full stop work authority was again in effect at Watts Bar.

'

Consequently, the licensee stopped work prior to reviewing

. information through the formal experience review' process. At the

end of this inspection period, the licensee had not received any

formal documentation; however, informal communications have taken

,

place with Watts Bar.

As a result of inspection of these specific items, the inspectors

concluded that the licensee is aware of problems at Watts Bar that may

be generic to Sequoyah. The inspectors noted that the formal

experience review and lessons learned program takes a period of up to

<

four weeks for applicable documentation to get from one site to another

i once the generic review process has begun. However, a timely informal

communications process is in effect between the sites prior to that

time so that items of mutual interest may be discussed in a timely

manner. The inspectors will review the implementation of OEP-17 to

determine if all significant NCRs generated at Watts Bar (including

j construction generated NCRs) receive an adequate and timely review.

4

This item is identified as an Inspector followup item (327-85-45-13,

328-8f-45-13) and will be followed up by the Watts Bar resident

inspector.

l b. Nuclear Safety Review Staff Inspection Report Followup

The inspectors reviewed numerous discrepancies identified by TVA's

1 Nuclear Safety Review Staff (NSRS). These discrepancies had been

identified and documented in several NSRS inspection reports for

.

Sequoyah during 1985. The inspectors noted that NSRS had not conducted

i followup inspections at Sequoyah to determine if corrective action for

4

these discrepancies had been implemented. Therefore, the inspectors

i

selected several of these items to determine if the responsible

<

sections were aware of the NSRS concerns and if corrective action had

t been taken if necessary. The selected deficiencies, denoted by NSRS

item number, and resultant corrective actions are noted as follows:

.!

-

R-85-03-NPS-08, Surveillance of Maintenance Programs for All

Nuclear Plants. This NSRS concern identified that surveillances

of the maintenance activities by onsite QA groups have not been

adequately performed. The inspector discussed this concern with

i

the appropriate licensee personnel and learned that the Sequoyah

QA section prepared a response that specified that five QA

evaluators perform surveillance of maintenance activities for the

'

various licensee maintenance sections. In addition, the response

specified that these QA inspections include reviews of

documentation to ensure tests are required as appropriate,

observation of test performance, and verification that acceptance

criteria are met. Also, the response indicated that the quality

engineering section has performed and will continue to perform an

-- - _ - _ _ - _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ .

- - - - . - - _ . - . _ . - .. .

.

.

4- 24

e

after-the-fact review of MRs on CSSC equipment for documentation,

correction of problems encountered, and verification that

acceptance criteria are met. As of the response date, eight

surveys of maintenance activities had been performed for 1985.

The inspectors reviewed the survey checklists and verified that

'

they contained the requirements delineated in the response to the

i NSRS concern. Some of these requirements are as follows: check

, MR documentation, verify that a clearance has been established, i

verify that the MR has complete instructions and provisions for l

configuration control, verify that appropriate QC holdpoints and

l post-maintenance testing requirements are established, verify that .

the procedure does not violate Technical Specifications, and  !

verify that acceptance criteria are met.

'

-

R-85-02-SQN/WBN-02, Maintenance, Operating, and Test Instructions

at Watts Bar and Sequoyah. This NSRS concern specified that

Sequoyah instructions were not adequate to provide the level of

j confidence needed for tube fitting maintenance activities as a

j result of the thimble tube event at Sequoyah. The inspectors

discussed this item with the licensee and learned that revision 7

. to MI-1.9, Bottom Mounted Instrument Thimble Tube Retraction and

Rein

ertion, had been issued. The inspectors noted that the

revision incorporated: (1) a precaution to ensure that, except as

allowed in (2) below, no maintenance on the high pressure fittings

'

was to be performed while primary system pressure is above

atmospheric pressure; (2) a precaution that any maintenance on the

fittings above atmospheric pressure be performed by a unique PORC

approved procedure; (3) a requirement for the cognizant engineer

to be present during the tightening process; and (4) a requirement

for QA to complete and document a visible check for any evidence

of reactor coolant leakage during mode 3. l

j -

R-85-03-NPS-07, Common Mode Failure at all Plants. This NSRS

concern identified that the mechanical maintenance section did not

appear to have a method of avoiding common mode failures unlike

1 the electrical and instrument maintenance sections. The

1

inspectors discussed this item with the appropriate licensee

3 personnel and learned that the mechanical maintenance section has

issued a section letter and three subsequent revisions on this

subject. The inspectors reviewed mechanical maintenance section

4

letter (MMSL)-A36, Common-Mode Failures, Maintenance Initiated.

The purpose of this procedure is to delineate the responsibilities

of the mechanical maintenance section to identify and prevent I

maintenance initiated common-mode failures to CSSC equipment l

through proper training, proper procedure preparation, appropriate

supervisory review, assignment of various personnel to jobs, and

,

,

l adequate post-maintenance testing. However, as of this inspection l

.;

I

period, implementation of this section letter had not taken place.

l The inspectors consider that implementing precautions to prevent

.

'

l

j

!

!

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

J

.

,

25

'

i

common mode failure is required for safe operation of the plant.

Therefore, followup of the implementation of the requirements of

MMSL-A36, is identified as inspector followup item (327-85-45-14,

, 328-85-45-14).

!

-

R-85-02-SQN/WBN-01, Office-Wide Awareness Bulletin for Tube t

Fitting Maintenance Activities. This NSRS concern involved a

recommendation that an office-wide awareness bulletin be issued ,

relative to tube fitting practices as a result of recent industry

events with failures of pressurized tube fittings during

maintenance activities. The inspectors discussed this item with

.

i

the appropriate licensee personnel and learned that a safety

bulletin has been issued and that training has been conducted for

all mechanical maintenance employees with regard to tube fitting

awareness. This bulletin referenced IE notice 84-55 which

described seal table leaks at Zion and Sequoyah nuclear plants.

The safety bulletin addressed the Office of Nuclear Power's policy '

on compression fittings. The inspectors reviewed the bulletin and

i

noted that it contained a brief summary of problems associated

! with interchanging fittings with those of different manufacturers,

l problems associated with improper orientation of fittings,

i specific procedure requirements for disassembly and reassembly of

connections, and methods of inspection and use of "SWAGELOCK" gap

inspection gauges.

!

-

R-85-03-NPS-04. American Society of Mechanical Engineers (ASME)

l

' Section XI Post-Maintenance Valve Testing at Sequoyah. This NSRS

concern specified that the instrumentation maintenance section did

not identify the need for ASME Section XI valve tasting when they

performed work on Section XI valves. Discussions with appropriate

l licensee personnel indicated that the instrument maintenance

i

planners are aware of the requirements for ASME Section XI valve

testing as delineated in surveillance instruction (SI)-114.1, ASME

' Section XI Interview Inspection Program, and SI-114.2, Inservice

Inspection Program for TVA Sequoyah Nuclear Plant (Unit 2). The

licensee also indicated that training on the requirements for

, valve stroke testing is being prepared for all instrument

1 maintenance personnel (including planners) in addition to general

ASME Sectton XI training. The inspectors' concern about the  ;

importance of a formal training process for planners has been

3 previously addressed in paragraph 6 of this report.

4

1 As a result of inspec. tion of these specific items, the inspectors have

!

concluded that the licensee is aware of the NSRS concerns and is

implementing appropriate corrective actions as required.

12. Review of Maintenance Training

The inspectors reviewed maintenance training referenced by the licensee in  !

the Sequoyah Nuclear Performance Plan. The review included training on '

administrative requirements, instrument maintenance training, mechanical

l 1

.

.

26

maintenance training, electrical maintenance training, unresolved safety

question determination training for engineers, and maintenance request

training. Within these areas, the inspectors made the following

observations:

a. Training on Administrative Requirements (paragraph 6.3 of the Sequoyah

Nuclear Performance Plan)

This course is provided by the Power Operations Training Center (P0TC)

and gives maintenance craft personnel 16 instructional contact hours in

quality assurance requirements, the maintenance work control system,

clearance procedures, temporary alterations and procedural adherence.

A review of the student manual indicates that the course is well

structured and provides instruction to the detail necessary to achieve

the indicated learning objectives. In addition, course administration

includes controlled instructor lesson plans, attendance control,

examination standards and remedial training. Approximately 86 percent,

90 percent, and 100 percent of plant mechanical electrical and

instrument maintenance personnel respectively have completed this

training. Additional training has been scheduled for completion in

administrative requirements for all maintenance craft personnel;

however, the training schedule is not based upon unit restart. The

inspectors consider that this training in administrative requirements

meets the elements stated in the Sequoyah Nuclear Performance Plan and

is adequate.

'

,

b. Instrument Maintenance (paragraph 6.6.1 cf the Sequoyah Nuclear

Performance Plan)

The instrument maintenance apprentice training program is INP0 accredited

and provides extensive training. The program is approximately 3.5

years (7000 hours0.081 days <br />1.944 hours <br />0.0116 weeks <br />0.00266 months <br />) in duration of which 17 months (2640 hours0.0306 days <br />0.733 hours <br />0.00437 weeks <br />0.001 months <br />) of this

time is formal classroom and laboratory instruction with the balance of

time consisting of formalized on-the-job training (0JT) at the plant.

All phases of the program contain student evaluations in the form of

written examinations, oral boards and plant craf t or POTC subcommittee

progress review. Overall, the program appeared to contain the elements

and management oversite necessary to provide technically qualified

replacement instrument maintenance personnel.

I c. Mechanical Maintenance Training (paragraph 6.6.2.(a) of the Sequoyah

Nuclear Performance Plan)

The mechanical training program has not received INPO accreditation.

The self evaluation report is scheduled for submittal to INPO in

January 1986, with INPO accreditation team visit anticipated in the

Spring of 1986. Mechanical maintenance training consists of three

general areas, plant systems familiarization, mechanical update

training and mechanical specialized training and is administered by the

POTC. Three full-time mechanical instructors are assigned to conduct

the courses in each of these areas. Allocation of additional space at

.

.

27

the POTC is being developed into instructor offices, classrooms and

laboratories. A review of this program indicates that adequate

resources and management attention are being allocated in order to

ensure that mechanical maintenance personnel are well trained in the

technical elements necessary to accomplish their job function. The

inspectors noted that the training is not a certification process;

therefore, the control of job function in the plant is not based on

completion of any segment of the training program. Determination of

whether a mechanic is qualified to accomplish a job task is performed

at the foreman level and is not administratively related to current

training status. The plant systems familiarization course consists of

80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> of formally administered an? controlled instruction in the

following areas:

Mechanical Print Reading

Reactor Familiarization

Condensate and Feedwater

Main Steam, Turbine and Generator

Reactor Coolant

Chemical and Volume Control

Raactor Core Cooling

-

Shutdown Cooling

Residual Heat Removal

-

Emergency Core Cooling

High-Pressure Coolant Injection

Low-pressure Coolant Injection

Containment

-

Ice Condenser

-

Containment Spray

-

Containment Isolation

Cooling Water System

-

Component Cooling Water

-

Essential Raw Cooling Water

-

Spent Fuel Pool Cooling

In addition, periodic retraining is provided on additional systems

and areas as designated by formal and informal feedback and

program evaluation.

Current estimates of the status of completion of training are as

follows:

Craft Training Completed Retraining Completed

Boilermakers 63% 100%

Machinist 65% 60%

Steamfitters 86% 74%

Asbestos Workers 57% 100%

_ _ _ _ - _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ~

.

.

28

,

Craft Training Completed Retraining Completed

(Continued)

Carpenters 79% 75%

Sheetmetal Workers 100% 60%

The update training consists of the following courses and hours of

instruction. Courses are provided only to applicable crafts

(e.g., only carpenters get Rigging Fundamentals).

Course Title Training Hours

Air Compressors 1 8

Air Compressors 2 8

,

'

Basic Bearings 12

Centrifugal Pumps 1 8

Centrifugal Pumps 2 8

i

Coupling and Shaft Alignment 12

Heat Exchangers 1 8

Heat Exchangers 2 8

Piping Auxiliaries 8

Positive Displacement Pumps 1 8

Positive Displacement Pumps 2 8

Safety Valves 1 8

Safety Valves 2 8

i Steam Traps 8

Riggino Fundamentals 16

Estimates of the status of completion of update training are as

i follows:

Craft Training Hours

Boilermakers 45%

Machinist 21%

Steamfitters 29%

The specialized training consists of the following courses and

hours of instruction which are provided to applicable crafts.

Cours_e Title Training Hours

Limitorque Actuator Maintenance 24

Valve Maintenance 1 8

Valve Maintenance 2 32

Emergency Diesel Generators 24

Refrigeration and Air Conditioning 40

Reactor Coolant Pump Seals 8

Initial Tube Fitting . 4

Crane Operator Screening Approx. 1-1/2

Procedures 16 I

i

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.

.

29

d. Electrical Maintenance (paragraph 6.6.2(b) of the Sequoyah Nuclear

Performance Plan)

The electrical maintenance training program has not received INPO

accreditation. The self evaluation report is scheduled for submittal

to INPO in January 1986 with INPO accreditation team visit anticipated

in the Spring of 1986. Electrical maintenance training is administered

by the POTC and consists of plant systems familiarization, electrical

update training and electrical specialized training. Three full time

electrical maintenance instructors conduct the courses in the above

areas. Allocation of additional space at the POTC is being developed

into instructor offices, classrooms and laboratories. A review of this

program indicates that adequate resources and management attention have

been allocated in order to ensure that electrical maintenance personnel

4 are well trained in the technical elements necessary to accomplish

l their job function. The inspectors noted, as in the mechanical

'

maintenance program, that the electrical maintenance training program

is not a certification process. Determination of whether an

electrician is qualified to accomplish a job task is performed at the

foreman level and does not administratively require completion of the

electrical maintenance training program. Topics covered in plant

systems familiarization consists of 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> of classroom instruction.

In addition, retraining is provided as determined by plant feedback and

program evaluation. the following topics are contained in this

curriculum:

i Plant Systems Familiarization (80 Hrs) Systems Retraining (24 Hrs)

Mechanical Print Reading Electrical Print Reading

Electrical Print Reading Review

Reactor Familiarization -

Single Line Diagrams

Condensate and Feedwater -

Schematics

Main Steam, Turbine and Generator -

Logic Diagrams

Reactor Coolant -

Connection Prints

,

Chemical and Volume Control -

Conduit and

Reactor Core Cooling Grounding Drawings

-

Shutdown Cooling Power Distribution Systems

Residual Heat Removal -

Offsite Power

-

Emergency Core Cooling -

Onsite Power

High-Pressure Coolant -

Unit Boards

Injection -

Diesel Generators

Low-Pressure Coolant -

Vital DC Power ,

Injection -

Vital Inverters '

Containment -

Preferred Inverters

-

Ice Condensor

-

Containment Spray

-

Containment Isolation

Cooling Water Systems

-

Component Cooling Water

-

Essential Rcw Cooling Water

-

Spent Fuel Pool Cooling

_ _ _ _ .- . _ - . _ _.

.

.

30

i

,

r An estimated of the status of plant system familiarization training

completed is as follows:

Training Completed Retraining Completed

,

80*4 95*4

Update training consists of the folicwing topics and hours of t

instruction:

[

Course Title Training Hours

DC Motors, Control Circuits and Troubleshooting 20

AC Motors, Control Circuits and Troubleshooting 28

AC and AC Generators 8

Transformer Maintenance 12

Battery Maintenance 12

Measuring and Test Equipment 16

EMT-21a Wheatstone Bridge

EMT-21b The Megohmmeter

'

EMT-21c Biddle Digital Low Resistance Ohmmeter

EMT-21d Hypot

J

Approximately 21 percent of plant electricians have completed this

entire curriculum.

Specialized training consists of the following topics and instructional

hours.

Course Title Training Hours

Annunciator Maintenance & Troubleshooting 40

i

Circuit Breaker Maintenance 40

Limitorque Actuator Maintenance 24

i

Elevator Maintenance 64

Basic Oscilloscope Operation 24

Solid State Electronics 40

Emergency Diesel Generators 24 ,

Refrigeration and Air Conditioning 40

Crane Operator Screening Approximately 1-1/2

, Procedures 16

e. Unresolved Safety Question Determination (USQD) Training for Engineers

(paragraph 4.13 of the Sequoyah Nuclear Performance Plan)

USQD training for engineers is conducted by the plant compliance staff

, and provides training in procedure SQA 119, Unresolved Safety Question

'

Determination, for plant engineers. These courses were provided at

various times and consisted of approximately one instructional contact

hour in changes to, philosophy of, and implementation of SQA 119.

During the review of this training, the inspectors noted that the

_ _ - _ _ _ _ _ - .

.

s

31

training was not provided in a controlled manner. mandatory attendance

was not established and attendance sheets were not utilized; therefore,

accountability and auditability of course attendance was not possible.

Course instructors did not utilize approved and reviewed lesson plans

with stated learning objectives; therefore, course consistency could

not be assured. In addition, no form of student evaluation was

utilized to ensure that a minimum level of knowledge was retained.

Since the USQD material was administered in an uncontrolled,

nonauditable manner, the inspectors do not consider that the

instruction which was presented constitutes training. Additionally,

the inspectors can not confirm that all applicable engineers have

received the training committed to in the Sequoyah Nuclear Performance

Plan, paragraph 4.13. The licensee should ensure that training

provided by organizations other than the POTC is administered in a

controlled and auditable manner. Additionally, the licensee should

review that training designated in the Sequoyah Nuclear Performance

Plan, paragraph 4.13 to ensure that all applicable personnel have

received requisite training as stated. Resolution of this concern is

identified as an inspector followup item (327-85-45-15, 328-85-45-15).

f. MR Training

In response to the thimble tube cleaning event, the licensee provided

MR training to personnel authorized to review MRs in the QA

organization. The inspector reviewed course attendance records dated

September 21 and 28, 1984, and December 20, 1984, and verified that the

training was conducted as required.

13. Review of Past Maintenance Related Events and Repetitive Failures

During the course of this inspection, the inspectors reviewed four events

dealing with maintenance activities and evaluated licensee corrective

actions on three types of components that have experienced repetitive type

problems. The results of these reviews are delineated below.

a. Review of LER 327-85-27 (Loss of Residual Heat Removal (RHR) Suction)

On May 14, 1985, while in Mode 5 at 140'F and 10 psig, both trains of

Unit 1 RHR were isolated by a false high pressure signal from Reactor

Coolant System (RCS) pressure transmitter PT-68-66. Unit I had been in

cold shutdown for approximately one month prior to the event. The PCS

temperature increased from 140 F to 149 F during the event. The

train B RCS transmitter was on a common sensing line with the train B

Reactor Vessel Level Indication System (RVLIS), which was undergoing a

high pressure test to assure adequate fill of the RVLIS sensing lines.

The transmitter sensed the high pressure in the RVLIS and isolated

FCV-74-2, the RHR suction line isolation valve, at 500 psig, as

designed. Operators promptly responded to indication of FCV-74-2

closing and secured the operating RHR pump. The RHR system was

isolated for 16 minutes while operators diagnosed the problem and

depressurized the RVLIS. The inspectors reviewed the maintenance

- . ._

.

.

32

activities associated with this event to determine if they were

conducted in accordance with administrative procedures governing the

control and accomplishme nt of plant maintenance. Corrective actions

were evaluated to determine if they were promptly implemented and

corrected the root cause of this event. The event was caused by an

inadequacy in SI-484, Periodic Calibration of RVLIS and RCS Wide Range

Pressure Channels (p-403, P-406) (Refueling Outage), which prescribed

the configuration of the RVLIS for the for the test. The test was

performed in accordance with Special Maintenance Instruction (SMI)

0-68-26, Partial Fill of RVLIS System - Upper Plenum Sense Lines

(trains A and B). Steps to preclude this event, such as isolation of

the RCS transmitter from RVLIS or disabling the pressure signal to the

RHR suction isolation valve, were not included in either procedure

SI-484 or SMI-0-68-26. The licensee stopped work on the RVLIS test

after the system was depressurized. The procedures were reviewed in

detail by the licensee, revised as needed, and were *eviewed and

approved by PORC. In addition, the licensee conducted a review of

other procedures being utilized to perform outage work to assure that

no other conflicts existed. Failure to provide an adequate procedure

for testing of the RVLIS was previously cited as an example of

violation 327-85-17-04, 328-85-17-03. A review of licensee revisions

to SI-484 and SMI-0-68-26 to correct the identified deficiency

indicates adequate resolution of this example of the above violation.

b. Review of LER 327-85-21 (14ain Control Room Ventilation Isolation)

The inspectors reviewed the subject LER and determined that the

licensee identified that the main control room isolation signal was

i

generated due to a spike on radiation monitor RM-90-125. After the

event, a maintenance request was written to investigate the cause of

the problem. During the investigation, it was determined that the

monitor had a defective power supply. The power supply was replaced

and the radiation monitor was returned to service. The inspectors

reviewed the completed MR, A-528889, and associated work documents and

determined that the troubleshooting and repair of RM-90-125 was

I accomplished by approved procedure IMI-134. The cause of the failure

,

appeared to be properly evaluated and appropriate corrective action was

taken to resolve the problem. The inspectors' review also determined

that required administrative approvals were obtained before initiating

work. 0A control and review was accomplished as required, and

corrective action records were being stored as part of the package.

The inspectors reviewed IMI-134 and determined that the PORC approved

procedJre conformed to administrative requirements including format,

approval, control, and necessary detailing of work instructions. '

c. Review of LER 328-85-009, (Reactor Trip from Turbine Trip from Loss of

Stator Cooling) 1

j

LER 328-85-009 was reviewed to assess the cause of the failure and to

determine if adequate corrective action was taken to reduce the

probability of reoccurrence. It was determined that the event

l

i

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

.

.

33

chronology was essentially as delineated within LER 328-85-009. The

inspectors censider that the failure of 2A stator cooling water pump

was not precipitated by licensee maintenance inadequacies.

Additionally, it is considered that adequate corrective action has been

implemented as a result of this event.

d. Review of LER 327-85-30 (Two Inadvertent AFW Starts Due to a Failed

Condensate Pump Valve and Leaking Feedwater Regulator Valve)

LER 327-85-30 discusses two events in which the AFW pumps started

inadvertently. The first event was caused by the condensate dump back

valve from the hotwell failing open. This fluctuation caused the main

feed pumps ( o r, their turning gears) to trip, causing automatic

initistion of the turbine driven AFW pump. The inspectors reviewed

documentation associated with the repair and re-calibration of the

affected valve and its associated controller. This documentation

appeared complete and gave confirmation that work associated with this

event was performed in accordance with requisite administrative

controls and procedures. The second event occurred due to inadequate

calibration which resulted in the valve being improperly seated. This

caused the steam generator to flood up to 75% level thereby tripping

the main feedwater system and starting AFW pumps. As a result of this

event, the licensee has developed new instructions for ensuring proper

seating of this type of valve during calibration.

e. Assessment of Repeated Ice Condenser Door Problems Since May 1985

Since May 1985, several unit 2 ice condenser intermediate deck doors

have b'an repeatedly covered by an accumulation of ice severe enough to

caus. a limiting condition for operation as defined by Section 3.6 of

the Technical Specification. On several occasions, the minimum torque

racessary to open the doors has exceeded the Technical Specification

limit. In all cases, ice was removed and the doors returned to

operable status prior to reaching the time limit of the action

statement. It was initially considered that the ice buildup was caused

by inleakage of humid air through torn insulating tape on the overhead

upper ice condenser doors. However, TVA evaluated this condition and

cetermined that the torn insulating tape was not a major cause of the

ice buildup. Rather, the problem has apparently been caused by ice

condenser inleakage through the existing vents blankets in conjunction

with high humidity conditions resulting from steam leakage through the

steam generators manway. A power plant maintenance specialist who was

interviewed considered that the steam leaks were the major factors for

the problem, and that once these leaks were repaired, the icing problem

would most likely be solved. The steam leaks were repaired during the

current outage. Additional corrective" action has been scheduled prior

to startup to limit the vented airflow space and to provide extra

insulation to minimize condensation above the intermediate deck doors.

Workplan No.11872 was PORC approved on November 27, 1985, and this

modification will be completed prior to startup. Included in the scope

of work is to install insulation behind the upper deck vent curtain and

i

-- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

.

.

34

seal the bottom of the curtain above all ice condenser bays which do

not contain vents. Vents are to be located at every third bay.

Westinghouse assured TVA in a letter dated April 6, 1984, that the

minimum vented area of 120 cubic feet could be adequately provided by

the installation of a vent every third ice condenser bay. This

modificatien will therefore not inhibit the design vent capacity which

is based on the analysis of a small break loss of coolant accident.

Another part of the modification to install insulation around radial

beams located in the upper plenum. Water has been observed to condense

on the radial beams and to drip on the intermediate deck doors below

and freeze. Most of the icing in the past has occurred under the

radial beams. T ie repair of the steam leaks and the installation of

the modification described above should solve the recurrent ice

condenser problems. However, until unit 2 is restarted and brought to

full power for several weeks, the effectiveness of the corrective

action cannot be determined. The licensee should closely monitor the

situation after startup. The inspectors toured the ice condenser

intermediate plenum and observed that several intermediate deck doors

were severely iced over. Since the unit is below mode 4, ice condenser

operability is not required. The current icing problem is apparently

due to piping leaks from several air handling units and is not related

to the general recurring situation. The inspectors were told that the

problems with the air handling units would be resolved prior to

startup. The inspector reviewed corrective actions taken in response

to NRC violation 328-85-24-03, Failure to Monitor Ice Condenser Bed

Temperatures at the Required Frequency. The principal NRC concern

resulted from performance of ice removal activities without formal

procedures needed for work on safety-related equipment. SI-108.1, Ice

Condenser Intermediate Deck Doors - Visual Inspection, Lif t Test and

Ice Removal, was PORC approved and issued on November 27, 1985. This

procedure which is scheduled to be performed weekly, formally controls

pull test and ice removal activities and appears to satisfactorily

resolve concerns regarding procedural controls on safety-related

equipment. However, there is insufficient data to review

implementation of this instruction and consequently violation

328-85-24-03 remains open. -

f. Masoneilan Valve Failures

Steam generator blowdown valves, their paired isolation valves, and a

safety injection system test isolation valve have had repeated repairs

on their limit switch actuator arms and stem nuts. The valve vendor is

Masoneilan for all three valve types. These valves are FCV-1-7, -14

-25, and -32; FCV-1-181 thru 184; and FCV-63-84, respectively. These

valves have not been permanently fixed or replaced to prevent cyclic

repairs; preventive maintenance and attempted repairs have been

unsuccessful in correcting these failures. The mode of actuator arm or

stem nut failure is generic to all three valve groups. The valves are

air operated with stem nuts attaching the stem to the air diaphram.

The limit switch actuator arms are attached to the stem by screws. The

arms ride between limit switches, which when contacted by the arms,

.

.

35

provide indication of valve position in the control room. Due to

vibration or flow through the valves two events can occur; one, the

stem nut loosens and the actuator arm swings clear of the limit switch

and two, the retaining screws loosen on the actuator arm and the arm

ceases to rigidly contact a limit switch. This mode of actuator arm or

stem nut malfunction causes a loss of valve position indication. Site

personnel had been evaluating and repairing steam generator blowdown

valves and tneir paired isolation valves. Site actions on these valves

have been as follows:

-

In the valve repair procedure, a check was made of stem nut

tightness.

-

In accordance with a valve vendor suggestion, lock-tight was used,

without success, to lock the stem nut to the diaphram and stem.

-

In accordance with a valve vendor recommendation, the diaphrams on

1-FCV-1-7, 14, 25, and 32 valves were replaced with a diaphram

which could withstand higher ambient temperatures since the space

which housed the unit 1 isolation valves experienced elevated

temperatures. A PM procedure was written in response to IE

Bulletin 78-04 to address the NAMCO limit switches on the valves.

-

In recognizing the stem rotation problem, a DCR, SQ-DCR-1978 dated

July 1985, was initiated on this problem. However, discussions

with licensee staff indicates that SQ-D:R-1978 was lost in typing

and was never rerouted.

Prior to this inspection, the licensee initiated a revision to SQM 58,

Maintenance Hirtary and Trending in order to establish a trend analysis

program as discussed in paragraph 6 of this report. The inspectors

consider that implementation of this trend analysis program would have

detected thete repetitive problems and could have prompted correctiva

action. Tis date, the corrective measures taken by the licensee have

not satisfactorily resolved these problems and until such resolution is

completed, this concern is identified as an inspector followup item

(327-85-45-16, 328-85-45-16).

g. UHI Level Switches

The UHI lines are provided with four accumulator isolation valves, two

in each line, which function to isolate the UHI accumulator to prevent

the injection of nitrogen gas (driving force) into the RCS following

the blowdown of UHI water. Actuation of UHI accumulator isolation is

controlled by UHI level switches (LS-87-21, LS-87-22, LS-87-23, and

LS-87-24). Each switch functions to close one of the four UHI

accumulator isolation valves on low UHI water level. On November 22,

1982, three of four Unit 1 UHI level switches and three of four Unit 2

UHI level switches were found outside the setpoint tolerance of

103.4 2 0.5 inches allowed by Technical Specification surveillance

requirement 4.5.1.2.c during the performance of their required 18-month

-- .. .- -. _ . -. - - - - - - - - . _ - _ _ _ - - - - . - . - - _ - -

i

.

-

'

36

i  !

!

I

calibration. In addition, the fourth unit 2 UHI level switch was found

to be inoperable due to a broken microswitch. The inoperability of UHI  !

level switches was subsequently reported to the NRC pursuant to

i Technical Specification 6.9.1.13.b onl December 21, 1982, via LERs

j 50-327/82-35 and 50-328/82-37. In a supplemental response to these *

LERs, the licensee committed to check the calibration of the UHI level  !

! switches on or before February 1,1983, and to recheck it every 30 days [

i

'

if they were found out of tolerance and, if not, every 90 days. On  ;

January 15, 1983, the licensee discovered two of four unit I level i

i switches out of tolerance (LER 50-327/83002) and on January 28,' 1983,

j discovered four of four unit 2 level switches out of tolerance (LER

50-328/83013). In response to these' findings, the licensee committed

f' to continue checking the calibration of the level switches once per '

l

'

month. In addition, . engineering assistance was' requested from the TVA

downtown office. The results of the once per month checks of the level

i switches are summarized in Table 3 on page 42. The licensee continued

to find the level switches out of the Technical Specification tolerance

j throughout the spring of 1983. In response to this unsatisfactory

!

I trend, corrective actions continued including contacting Duke Power <

Company. Plan _t McGuire was also having problems with these switches '

i and extensive interactions with the vendor representative (Barton) and

i with Westinghouse, both onsite and offsite, were directed towards  !

j improving calibration techniques and determining the root cause of the

j setpoint drift. On March 22, 1983, Westinghouse provided a Nuclear [

Safety Evaluation demonstrating that UHI water delivery limits of 900 '

cubic foot (minimum) and 1105 cubic foot (maximum) were acceptable for i

Sequoyah based on available LOCA' analysis. This increased the maximum ,

l UHI volumetric delivery envelope from 1055 cubic feet which was

i utilized in establishing the Technical Specification level switch i

i setpoint tolerance. Based on . Westinghouse's reanalysis, the licensee i

j submitted a Technical Specification change request -to change the ,

i setpoint to 82.1 2 5.6 inches above the tank vendor working line on  !

i

March 28, 1985. On April 12, 1983, the licensee began investigating

the availability of a qualified replacement for the UHI level switches.  ;

At that time, no other available replacement level switch was

qualified. The licensee considered utilization of a " Static-0-Ring"

(50R) switch as a possible replacement switch and initiated

implementation of qualification tests for this switch by Wylie

,

i '

, Laboratories in conjunction with an inplant reliability test of the "

i switch. By letter dated May 3,1983, the NRC granted the previously

j requested Technical Specification change. On May 5, 1985, the licensee

i performed the last calibration check on unit 2 UHI level switch .

l utilizing the 103.4 0.5 inch setpoint. Four of four level switches '

j were discovered to be out of tolerance and were subsequently

-

recalibrated to the new setpoint (LER 50-328/83062). On May 6, 1985,

I

the licensee performed the last calibration check on unit 1 UHI level

switches utilizing the 103.4 1 0.5 inch setpoint. Three of four level

j switches were found to be out of tolerance and were subsequently i

l recalibrated to the new setpoint (LER 50-328/83066). The UHI level

i

switches are Barton Model 288A. The ! licensee suspected that the l

{ observed setpoint drift was the result of a combination of inherent

, .

I

!'

!

_ _ - . __ . . _ .

_

- - - ._ __ . _ . . -

e

.

37

i

instrument drift, calibration technique, and environmental conditions

(vibration). On June 28, 1983, the calibration procedure was revised

to incorporate all vendor recommended improvements in the calibration

of the Barton 288A level switch.

As a result of repeated problems with these Barton 288A level switches,

the licensee instituted corrective actions as delineated in Table 2,

page 41. These actions included:

(1) Contacted the vendor (Barton) and had a vendor representative

onsite to investigate the problem and recommend improvements in

calibration techniques.

l (2) Contacted Westinghouse about calibration problems and requested

reanalysis of UHI volumetric delivery envelope to justify a

Technical Specification change to increase the allowed setpont

.

tolerance.

,

(3) Contacted other plants (McGuire) with similar Bartons.

l (4) Decreased the surveillance interval from the Technical

Specification required 18 months to one month.

(5) Initiated efforts to determine a replacement level switch (SOR).

(6) Replaced installed Barton 288A level switches which showed

excessive unreliability with other Barton 238A level switches from

plant replacement inventory.

On August 24, 1983, the licensee initiated special test procedure

SQ-STEAR-INST-83-13, Reliability Test of Static-0-Ring (SOR) Level

Switch for UHI Water Accumulator. This procedure installed a SOR

i

level switch in parallel with a ur.;. 2 Barton 268A switch. The SOR

!' switch calibration was checked mcnthly for a period of seven months to

determine reliability. The last data point was taken on March 20,

1984, and on June 29, 1984, the Director of Nuclear Services

recommended to the Site Director that the SOR calibration data and the

I simple construction and operation of the SOR switch indicated that it

would be a reliable replacement and that final approval was pending

resolution of Class 1E environmental qualification concerns' which were

being addressed by the vendor and the Division of Engineering Design.

I On June 1,1984, the licensee prepared DCR 2111 to replace the Barton

Model 288A UHI level switch with a more reliable one. This DCR was

subsequently approved for transmittal to Engineering Design on

January 27, 1985. Calibration data on the Barton 288A level switch

remained good from June 1983 (implementation of the above corrective

,'

actions) until July 1984 on unit 1, and May 1984 on Unit 2. During the

14 month period on unit 1, Barton 288A level switches were found to be

outside the allowed setpoint tolerance only five times, two switches in

!

i

-_-. _ _ _ . - _ _ _ _ - - - - _ _ _ _ - _ - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ - - - - _ _ - _ _ _ _ _ _ -

_ -_ .. __ _ _ - __ _ - . _ _ . - _ . _

'

,

.

38

,

June 1983 (LER 50-327/83084), one switch in November 1983 (LER 50-327/

, 83156), one switch in January 1984 (PRO-1-84-038)+, and one switch in

April 1984 (PRO-1-84-157)+. During the 12 month period on unit 2, no

Barton level switches were found to be outside the tolerance.

From August 1984 on unit 1 and June 1984 on unit 2, Barton 288A level

switch calibration data began a deteriorating trend of being outside

the Technical Specification allowed setpoint tolerance as delineated in

Table 3, page 42. Between August 1984 and August 1985, unit 1

Barton 288A UHI level switches were found outside the Technical

Specification allowable setpoint tolerance on 10 occasions during

monthly calibration checks. Between June 1984 and June 1985, unit 2

Barton 288A switches were found outside the Technical Specification

tolerance on five occasions during monthly calibration checks. The

only apparent licensee response to this out of tolerance trend was to

recalibrate the out of tolerance Barton 288A level switches or to

change out selected level switches with replacement Barton 288A level

switches from plant stores. The inspectors consider that during this

>

period of time there was indication that short term corrective actions

established in June 1983 were not providing continued assurance of UHI

'

level switch operability. Although long term corrective actions were

still being pursued, additional short term corrective actions were not

I established to analyze the increased unreliability of level switches i

i

subsequent to June 1984. On March 28, 1985, Engineering Change Notice '

(ECN) L6359 was issued by the Division of Engineering Design to replace '

the unit 1 and unit 2 Barton 288A UHI level switches with a more

,

reliable level switch (50R). Work Plan 11751 was authorized on

i August 23, 1985, to replace the level switches on unit 1. Switch

J' replacement has been completed; however, post-maintenance testing has

not been completed due to the need to revise the calibration procedure,

SI-196 for use on the SOR switch. At the time of this inspection,

unit 2 replacement was not planned to be accomplished prior to unit

restart; instead, it was scheduled to be accomplished during the next

refueling outage following restart. The inspectors consider that the

operability of UHI is questionable in light of continued problems with

j the Barton 288A level switchs and consequently consider that replace-

ment and post-modification testing should complete prior to unit 2

restart. The licensee committed that this action would be completed

prior to unit restart. This concern has been previously identified in

paragraph 5 of this report as inspector followup item 327-85-45-02,

328-85-45-02.

1

i

+0n January 1,1984, 10 CFR 50.73 removed reporting requirement for these fail-

ures; therefore, only Potential Reportable Occurrence (PRO) reports were written

by the licensee.

i

.

.

.-

39

10 CFR 50, Appendix B, Criterion XVI requires that measures shall be

established to assure that conditions adverse to quality are promptly

identified and corrected. Contrary to the above, measures established

by the licensee and placed in effect on June 1983 were not sufficient

to assure continued operability of Barton 288A UHI level switches until

the installation of a suitable replacement level switch, in that the

Barton 288A level switches displayed a deteriorating out of Technical

Specification allowed setpoint tolerance trend from August 1984 on

unit I and June 1984 on unit 2 during monthly calibration checks.

Additionally, long term corrective actions which were scheduled for

unit 2 were not being promptly implemented in that level switch

replacement was not considered prior to unit 2 restart. This is

another example of failure to take prompt corrective action identified

as violation 327-85-45-06, 328-85-45-06.

Technical Specification 3.5.1.2 requires that each upper head injection

accumulator system shall be operable in Modes 1, 2, and 3 when above

1900 psig. Until the licensee can demonstrate that the multiple

failures of the Barton 288A UHI level switches to meet allowed setpoint

tolerances during a decreased surveillance interval of one month did

not constitute UHI system inoperability, this item will be identified

as an unresolved item (327-85-45-17, 328-84-45-17).

During the review of the UHI Barton 288A issue, the inspectors noted

that the licensee has not performed a formal evaluation of all plant

components to determine if other plant applications of Barton 288A

switches are adver ,ely af fected by setpoint drift. However, it was

noted that the licensee had identified and initiated action to resolve

one other Barton 288A application in which setpoint drif t had caused

calibration problems. The reactor coolant loop resistance temperature

detection (RTO) bypass line utilizes Barton 288A instruments as flow

switches to indicate low bypass flow. The instruments do not serve a

control function, but do actuate an alarm in the main control room to

indicate low bypass f low to the RTDs which supply RCS temperature

inputs to the reactor protection system. ECN L6380 was issued on

April 29, 1985, to replace the RCS bypass line Barton 288A flow switch.

At the time of this inspection, installation was planned for cycle 3

refueling outages on both units which is subsequent to scheduled unit

restart. The inspectors consider that this particular Barton

application should be considered in conjunction with the reviews and

evaluations to be conducted in resolution of inspector followup item

327-85-45-01, 328-85-45-01.

Also, during the inspection team's review of the UHI Barton 228A issue,

a problem concerning documentation of seismic qualification and QA

level designation was identified. On June 12, 1985, the licensee

identified (PRO-2-85-008) that UHI level switch 2-LS-87-23 did not have

the proper documentation of seismic qualification and QA level

designation. An evaluation of the other installed switches by the

licensee identified that 1-LS-87-21 and 1-LS-87-24 had the same

deficiency. All switches were promptly replaced with components having

I

-

..

40

proper qualification documentation. Discussions with Barton

representatives and a review of procurement records indicated that

these switches were of a type seismically qualified; however, seismic

certification was not requested in the procurement process and

therefore appropriate documentation was not provided as part of the

contract. The switches were correctly ordered as QA Level II

replacement parts; however, since the switches were upgraded to

Class IE components after receipt of the switches QA level designation

of replacement components in stores should have been upgraded to QA

Level I. A review of the licensee's investigation into the incident

revealed a thorough evaluation of the circumstances and resolution of

discrepancies. A review of the licensee's corrective actions could not

be completed during this inspection to verify that all the requirements

of 10 CFR 2 Appendix C for self idertification and correction of

violations were met. Until the licensee provides a complete

description of corrective actions to pru?ude the problems described

above for evaluation, this item will be identified as unresolved

(327-85-45-18, 328-85-45-18).

_

.

_ -_. . _ . _. . _ -

.

.

41

TABLE 2

CHRON0 LOGY OF CORRECTIVE ACTIONS

Date

t

January 1983 Began 30 day calibration checks

.

February 1983 Contacted TVA downtown office for engineering support.

March 1983 Contacted Westinghouse for ensite support. Contacted Duke

Power Company, McGuire plant about similar problems.

Contacted Barton vendor. Contacted Westinghouse concerning

increasing tolerance. Requested Technical Specification

change to increase tolerance based on Westinghouse analysis.

April 1983 Purchase request submitted for onsite Barton services.

May 1983 Barton representative on site to provide vendor support.

Technical Specification change request granted.

, June 1983 Calibration procedures revised to include improvements in

calibration technique.

August 1923 Began STEAR-1NST-83-13 to test SOR ' replacement switch.

March 1984 Completed STEAR-INST-83-13 with favorable results.

June 1984 Director, Nuclear Services recommends SOR replacement switch

pending resolution of 1E environment qualification concerns.

March 1985 DCR 2111 submitted to replace Barton 288A switches.

August 1985 ECN 6359 issued to replace Barton 288A switches with SOR

switches.

i

NOTE: Change out of install Barton 288A level switches "th replacement

' Bartons f rom plant stores' inventory and recalibration of out-of-

calibration level switches are not shown in above chronology.

.

- . _ _ - _ _ _ _ _ _ - . . - - _ . - _ . - _ - _ . __ . - _ . - . . . _ _ -

.

.'

42

TABLE 3

Date Out of Tolerance Number Out of Tolerance

I l l l

Month l Year l Unit 1 l Unit 2 l

l 1 I l

November l 1982 l 3 l 3 l

l

l January l 1983 1 2 l 4 l

) February l 1983 2 3

l l l

March l 1983 l 3 l 4 l

j April l 1983 l 2 l 3 l

May l 1983 l 3 l 4 l

1 *

l

--

l TS Change l TS Change l

June l 1983 l 2 l

-

l ,

j November l 1983 l 1 l

-

l

l Janua ry l 1984 l 1 l

-

l

April l 1984 l 1 -

l l

June i 1984 l

-

l 1 l

July i 1984 l

-

l 1 l

t

August i 1984 l 2 l

-

l

1 October l 1984 l 1 l 1 l

l Feb"uary l 1985 l 1 l 1 l

March l 1985 l 2 l

-

l

May l 1985 l 1 1

l l

July l 1985 l 2 l

-

l

August i 1985 l 1 l

-

l

i

j NOTE: Months during which no switches were found to be out of the Technical

.

I

Specification tolerance or when the calibration was not required  !

1' (shutdowns) are not shown.

1

I

i

,

_ . _ . _ . _ __. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _

l

,

!

l *

.

i

43

4

14. Observations of Maintenance Activities

, The inspection team observed the performance of various maintenance work

items spanning each of the disciplines, i

The performance of work controlled by WP 11853 to perform a functional test

for valve 2-FCV-63-175, Safety Injection Pump 2B-B Discharge to Refueling i

. Water Storage Tank Shutof f Valve, was observed. The inspectors reviewed

] this WP and noted that a control form with appropriate signatures was

included. In addition, the inspectors discussed the scope of this WP with

I

the responsible engineer stationed in the control room and maintenance

personnel stationed at Motor Operated Valve (MOV) Board 28-B. The

inspectors found that the responsible engineer was knowledgeable of the

procedure and that the technician at the MOV Board was aware of his duties.

The inspectors noted that the cognizant engineer completed all steps as

i required by the instruction and documented discrepancies that were

encountered. One problem occurred during performance of this functional i

test in which the closing contacts at the local control panel would not

operate to give local control. However, the closing contacts at the remote

station (main control room) did operate properly. The inspector discussed

with the cognizant engineer the method for handling this discrepancy. The

engineer stated that he would write a work request for electrical '

maintenance to check the local close contacts to clean and/or repair as

i

necessary. A second problem encountered was vibratory movement of the valve

handwheel during valve stroking. The cognizant engineer stated that the

work request would also address this discrepancy. The inspector noted that '

j the responsible engineer was in control of the test and that the control t

-

room operator performed actual valve manipulations in the control room. In

, addition, the shift engineer was consulted as to the required position of

j the valve upon completion of the test. The inspector considers that this

functional test was conducted in a safe and professional manner.

a

l The inspectors observed the performance of main feed pump turbine special

i control loop calibration in accordance with selected portions of IMI-46. No

!

significant procedural or performance inadequacies were noted. Prior to

performance of this procedure, a preliminary review by the IM technician led

I to the implementation of a temporary change to the procedure which clarified '

4

'

the signal cable connection points required for the dynamic response

verification, and corrected a page numbering error. During the performance

of the observed portions of IMI-46, the technicians displayed familiarity

j with the procedure and exhibited proficiency in its performance.

I The rebuilding of a Bettis actuator for containment isolation va've

2-FCV-31C-229, in accordance with MR A302455 was observed. This maintenance

request incorporated portions of MI-6.15, General Procedure for Tightening

,

Bolted Joints, MI-6.20, Configuration Control During Maintenance Activities,

{ MI-11.4, Maintenance of CSSC Valves, and MI-11.10 G. H. Bettis Actuator

Maintenance Guidelines. Applicable portions of these procedures were

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followed and QC hold points were adhered to. As used, the procedures were ,

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technically adequate and the technicians performing the procedure performed l

the procedure as written.

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44

The inspectors observed Motor Operated Valve Test System (MOVATS) testing

conducted on Valve 2-FCV-70-134 per Maintenance Instruction 10.43, Procedure

for Testing of Motor Operated Valves Using the MOVATS-2000 System. The

inspectors' assessment of this work was previously delineated in

paragraph 10 of this report.

The inspectors observed preven .tive maintenance being performed by

instrument maintenance technicians on unit 1 strip chart recorders on the

1-M-5 panel in accordance with preventative maintenance procedure

PM 0765-068. The inspectors reviewed the work copy of the procedure and

noted that required information was being recorded as work on the different

instruments was progressing. Also, the instrument history cards were being

used and updated as required. The inspectors questioned the instrument

technicians assigned to the job and determined that the personnel understood

the scope of the job and were properly qualified to perform the tasks. The

inspectors asked the lead technician to indicate what actions would be taken

for a problem encountered beyond the scope of the work. The lead technician

stated that the supervisor would be informed of the problem and added that

if additional repair beyond the scope of the procedures were required, the

technician would prepare a MR after consultation with the supervisor. The

inspectors also determined that the appropriate controlled technical manuals

were available to assist in performing the work and that appropriate

supervision was available to assist in evaluating problems and provide for

appropriate evaluation of work progress.

The inspectors observed partial performance MR A549627, Component Cooling >

Water Heat Exchanger A Sleeve and Plug Tubes. This included observation of

the removal of the heat exchanger's end bells. Written procedures were

followed at the work site, the technicians displayed familiarity with the

procedures, and adequate technical knowledge of the system. No significant

procedural or performance inadequacies were noted.

Additional observations were conducted by the inspection team with regard to

plant housekeeping. The inspectors reviewed Standard Practice Procedure

SQA-66, Plant Housekeeping. The purpose of this instruction is to implement

the requirements of the Orerations Quality Assurance Manual (N-00AM) Part II

Section 1.2, Housekeep ing in Nuclear Power Plants. This procedure specifies

that each supervisor responsible for work activities within the plant shall

ensure that the work area is cleaned up upon completion of maintenance or

modification work, or the end of the working shifts whichever occurs first.

In addition, appendix A of this procedure specifies that the normal

hcasekeeping assignment of the auxiliary building belongs to the Operations

Suparvisor. Attachment 1 of SOA-66 specifies items that shall be considered

in pse formance of housekeeping checks. Some of those items are the

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following:

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floors are cleared of accumulation of litter, dirt, water, oil, etc.;

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expendable items, loose unused tools, and spare parts have been stored

and trash disposed of in predesignated locations;

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scaffolding in the area is actually being used; and

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