ML20245B717

SALP Repts 50-327/89-01 & 50-328/89-01 for 880204 - 890203

ML20245B717
Person / Time
Site:	Sequoyah
Issue date:	02/03/1989
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20245B703	List: ML20245B702 ML20245B717
References
50-327-89-01, 50-327-89-1, 50-328-89-01, 50-328-89-1, NUDOCS 8904260238
Download: ML20245B717 (68)

See also: IR 05000327/1989001

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ENCLOSURE 1

INTERIM SALP REPORT

U. S. NUCLEAR REGULATORY COMMISSION

OFFICE OF NUCLEAR REACTOR REGULATION

SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE

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NRC INSPECTION REPORT NUMBER i

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50-327/89-01 AND 50-328/89-01

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TENNESSEE VALLEY AUTHORITY (TVA)

SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2

FEBRUARY 4, 1988 - FEBRUARY 3, 1989

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TABLE OF CONTENTS

PAGE

I. INTRODUCTION.................................................. -1

A. Licensee Activities..................................... 2

B. Direct inspection and Review Activities................. 5

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II. SUMMARY OF RESULTS........................................... 7

A. Basis Period Summary.................................... 7

! B. Assessment Period Summary.............................. 17

C. 0verview............................................... 18

Ill. CRITERIA.................................................... 19

IV. PERFORMANCE ANALYSIS........................................ 20 .

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A. Plant 0perations....................................... .

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B. Radiological Controls.................................. 27

C. Maintenance / Surveillance............................... 30

D. Emergency Preparedness................................. 39

E. Security............................................... 40

F. Engi.neering/ Technical. Support.......................... 42

G.- Safety Assessment /Quali ty Verification. . . . . . . . . . . . . . . . . ., 48

V. SUPPORTING DATA AND SUMMARIES............................... 54

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A. Investigation Review................................... 54

B. Escalated Enforcement Action........................... 55

C. Management Conferences................................. 55

D. Confirmation of Action Letters......................... 56

E. Review of Licensee Event Reports....................... 57

F. Licensing Activities................................... 57

G. Enforcement Activity................................... 63

H. Re a c t o r T r i p s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

I. E f fl u e nt R el e a s e S umm a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

J. Acronyms............................................... 64

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I. INTRODUCTION

The Systematic Assessment of Licensee Performance (SALP) program is an

integrated NRC staff effort to collect available observations and data on

a periodic basis and to evaluate licensee performance on the basis of this

information. The program is supplemental to normal regulatory prococses

used to ensure compliance with Nuclear Regulatory Commission rules and

regulations. It is intended to be sufficiently diagnostic to provide a

rational basis for allocating Nuclear Regulatory Commission (NRC)

resources and to provide meaningful feedback to the licensee's management

regarding the NRC's assessment of their facility's performance in each

functional area. l

)

The last SALP appraisal period for Sequoyah was for the period l

March 1,1984 through May 31, 1985 with the SALP report being issued on

September 17, 1985. In August 1985, both units were shutdown for Environ-  ;

mental Qualification (EQ) verification. In the September 17, 1985 letter j

transmitting the TVA SALP reports, the NRC communicated that significant

programmatic and management deficiencies existed in TVA's nuclear program

and pursuant to 10 CFR 50.54(f), TVA was requested to address these de-

ficiencies prior to the s'tartup of any nuclear unit. TVA responded by

issuing and implementing the Corporate and Sequoyah Nuclear Performance

Plans. NRC evaluation of the performance plan implementation is docu-

mented in NUREG-1232, Volumes 1 and 2, respectively, and NRC inspection

reports. Furtier SALP review was deferred pending restart of Unit 2. By

letter dated May 26, 1988, TVA was notified that the normal SALP evalua-

tion process had recommenced as of February 4,1988.

An NRC SALP Board, composed of the staff member s listed below, met on

flarch 28, 1989, to review the observations and data on performance, and

to assess licensee performance in accordance with Chapter NRC-0516,

" Systematic Assessment of Licensee Performance." The guidance and evalo-

ation criteria are summarized in Section III of this report. The Board's

findings and recommendations were forwarded to the Associate Director for

Special Projects, Office of Nuclear Reactor Regulation, for approval and

issuance.

This report is the NRC's assessment of the licensce's safety performance

at Sequoyah for the period February 4,1988 through February 3,1989.

The SALP Board for Sequoyah was composed of:

B. D. Liaw, Director, TVA Projects Division (TVAPD), Office of

fluclear Reactor Regulation (NRR) (Chairman)

L. J. Watson, Acting Assistant Director for Inspection Programs,

TVAPD, NRR

S. C. Black, Assistant Director for Projects, TVAPD, flRR

R. C. Pierson, Assistant Director for Technical Programs, TVAPD, NRR

D. M. Collins, Chief, Radiological Protection and Emergency

Preparedness Branch, Region II (RII)

A. F. Gibson, Director, Division of Reactor Safety, RII

J. N. Donohew, Senior Project Manager, TVAPD, NRR

K. M. Jenison, Senior Resident Inspector, TVAPD, NRR

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The following staff also attended the Sequoyah SALP Board meeting:  ;

J. Brady, TVF D, NRR

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P. Harmon, TVAPD, NRR

G. Hubbard, TVAPD, NRP,

S. Weiss, TVAPD, NRR

B. Zalcman, Technical Assistant, NRR

E. Goodwin, TVAPD, NRR

B. Desai, TVAPD, NRR

K. Landis, RII

R. Borchardt, RII Coordinator, ED0

T. Rotella, TVAPD, NRR

A. Licensee Activities

Both units began the assessment period in shutdown from an extended

outage that began in August 1985. TVA agreed, in 1985, not to

restart the units without receiving NRC approval.

On February 4,1988, Unit 2 received NRC permission to enter Modes 4 I

and 3 (hot shutdown and hot standby) and began the heatup process.

The plant was heated up using reactor coolant pump heat and entered l

Mode 4 on February 6,1988. While in Mode 4, approximately nine i

personnel errors occurred which included inadvertent Main Steam

Isolation Valve (MSIV) closures and feedwater isolations, generation

of a reactor trip signal, and a loss of Volume Control Tank (VCT)

level. None of the events resulting from those personnel errors

represented significant safety concerns of their own accord and

collectively appeared to be typical of what one would expect of a

near term operating plant going through the same evolution.

On February 27,1988, Unit 2 entered Mode 3. While in Mode 3, a

number of events occurred including inadvertent closure of all four

MSIVs, exceeding Technical Specification (TS) surveillance limits for

Reactor Coolant System (RCS) leakage, exceeding RCS cold leg accumu-

lator boron concentration, and two events involving auxilicry

feedwater pump operability and charging pump operability of which the

later involved escalated enforcement. The majority of these events

were personnel related and were responded to by the licensee in an

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adequate manner.

On March 22, 1988, the NRC Commissioners voted to allow Unit 2 to

restart. On March 30, the NRC approved entry into Mode 2 (Startup).

On March s1, prior to actually beginning dilution, the licensee

determined that modifications would be required on one of the three

pressurizer safety valve loop seals, and the restart was delayed.

During resolution of problems with pressurizer loop seals, a tube

leak was identified in the #3 steam generator. On April 7, Unit 2

began a cooldown to Mode 5 (cold shoutdown) to repair the steam

generator tube leak and complete pressurizer loop seal modifications.

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On May' 7', Unit 2 began the heatup process again and entered Mode. 4.

On May 11, Unit 2 entered Mode 3 and on May 12, Unit 2 entered Mode 2.

Control rods were withdrawn and dilution to criticality Began. On

May 13, the reactor achieved criticality, entered Mode 1 (power

operation), and the generator was synchronized with the grid. On May

15, the NRC granted permission to allow operation above 30% power and

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power escalation was resumed. During the power escalation process

several minor events occurred which included the discovery of an

unqualified splice in the circuitry for one of the steam generator

water level indicators.

On May 19, Uni 2 tripped from 73% power due to steam flow / feed flow

mismatch coincident with low-low steam generator level. This situa-

tion occurred due to maintenance being performed concurrently cn two

pieces of equipment which together could cause a reactor trip (one

channel of steam generator level indication to replace the

unqualified splice and the #3 heater drain tank level controller

which resulted in plant oscillations). On May 20, efter corrective

actions for the trip were completed, NRC permission was given to

restart Unit 2.

On May 21,' Unit 2 achieved criticality. entered Mode 1, and was

synchronized with the grid. .

On May 23, Unit 2 tripped from 70% power on low fbs in RCS Loop #4.

This occurred due to a personnel error while performing a surveil-

lance instruction on the loop #4 flow transmitters. Or, May 24, Unit

2 achieved criticality, synchronized with the grid and began power  ;

escalation.

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On May 24, while Unit I was in partial drain to plug steam generator

tubes, a loss of decay heat removal occurred due to an cperatcr error ,

in positioning valves while changing the residual heat removal (RHR)

system alignment.

On May 29, 1988, Unit-2 achieved 100% reactor power.

On June 6,1988, Unit 2 tripped from 98% power on stean flow / feed

flow mismatch coincident with low level in #4 steam generator. The .

trip occurred while performing a surveillance on the feedwater l

regulating valves and resulted because a diode was missing in the

block circuit.

On June 8,1988, Unit 2 tripped from T2% power on low-low level in #2

steam generator. The trip was caused by operator error when placing

the feed pump contro'.ler in the automatic position which resulted in i

steam generator level oscillations.

On June 9, 1988, Unit 2 tripped from 20% power on low-low level in 72

steam generator. The trip was caused by transients in feed flow and

steam generator level which were initiated by feedwater heater

isolations.

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'On June 13, 1988, TVA mec with the NRC staff to discuss the root

causes _ for the five reactor trips which had occurred since Unit 2

restarted on May 18, 1988. Corrective actions identified included

l reducing the number of outstanding secondary plant work requests

which could contribute to balance of plant induced reactor trips.

On June.19, 1988, the NRC granted permission t'o restart Unit 2. On

June 30,1988, Unit 2 reached 70% reactor power (holding for core

life extension).

On September 27, 1988, the NRC granted permission ~for Unit I to enter

Mode 4. While in Mode 4, several unanticipated reactor trip signals

were gener M due to personnel errors while performing

surveillance.

On October 20, 1983, Unit 1 entered Mode 3. While in Mode 3, the UHI

membrane was ruptared while putting the system in service due to.

improperly labeleo valves. Equipment problems such as steam

generator safety valve at leakage, pressurizer safety valve seat

, leakage, reactor vessel inner seal leakage, and steam dump packing

leakage were encountered and properly resolved.

On ' November. 6,1988, Unit 1 entered Mode 2 and went critical . On

November 10, 1988, Unit 1 entered Mode 1, the generator was

synchronized with the grid, and power escalation began. Several

personnel errors related to equipment surveillance caused ESF

actuations while in Modes 2 and 1.

On November 18, 1988, Unit 1 tripped from 72% power due to an

electrical ground in the main generator stator. During the forced

outage to repair the generator stator, repairs to leaking steam

generator safety valves and a pressurizer safety valve were also

accomplished. ,

On December 25,1988, Unit 1 achieved criticality, entered Mode 1,

the generator was synchronized with the grid, and power escalation

began.

On December 26,1988, Unit 1 tripped on low-low level in #4 steam

generator. The trip was caused by a series of events that started

with a manual trip of the turbine due to generator seal rubbing.

After the turbine trip, steam generator level was controlled using

manual feedwater control which resulted in a feerwater isolation from

high-high level in #2 steam generator followed by the reactor trip on

low-low level in #4 steam generator.

On December 27,1988, Unit 1 achieved criticality and began power

escalation. On December 30, 1988, Unit I achieved 98% reactor power.

On January 19, 1989, Unit 2 was shutdown to begin the s heduled cycle

3 refueling outage after 210 continuous days of operation.

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B. Direct-Inspection and Review Activities

During the assessment period, routine inspections were performed at

the Sequoyah facility by the NRC. staff. Special inspections were

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conducted as follows.:

- February 4~- June 25, 1988; a series of special inspections.cf

the Unit 2 heatup and restart effort were conducted by the NRC

Sequoyah Restart Task Force. These inspections included control

room observation and reviews of activities associated with the

restart effort. (88-02,88-17,88-20,88-22,88-26,88-28,88-34)

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- February 1-19, 1988; a special inspection was performed to

assess the corrective actions performed by TVA in response to

the findings of the Integrated Design Inspection. (88-13)

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February 8-12, 1988; a special inspection was conducted to

assure that the licensee's corrective action program implementa-

tion adequately dispositioned adverse conditions, including

generic issues. (88-15)

- February 15-19, 1988; a special inspection of the open restart

issues' in the civil engineering area was conducted to determine

that adequate corrective action and resolution had occurred to

support the restart of Unit 2. (88-12)

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- February 29 - March 4, 1988; a special operational readiness

inspection was conducted to assess the adequacy of the

licensee's preparations for Unit 2 restart. (88-16)

- March 14-23, 1988; a special fire protection inspection was

conducted for Unit 2 restart in the area of implementation of

the' requirements of 10 CFR 50 Appendix R, Sections III.G, III.J. l

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III.L, and 111.0 including safe shutdown logic. (88-24)

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June 20 - July 8, 1988; a special Safety System Quality

Evaluation vertical slice review was conducted on the j

Containment Spray System to assess the licensee's Nuclear

Performance Plan implementation for Unit I restart. (88-29)

- July 11-15 and August 23-24, 1988; a special inspection was

conducted to assess the effect of excessive cooldowns following

reactor trips on end-of-life shutdown margin. (88-35)

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' July 25-28, 1988; a special fire protection inspection was

conducted for Unit 1 restart in the area of implementation of

the requirements of 10 CFR 50 Appendix R, Sections III.G, III.J,

III.L, and 111.0 including safe shutdown logic. (88-37)

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August 29 - September 2,1908; a special operational readiness

inspection was conducted to assess the adequacy of the

licensee's preparations for Unit 1 restart. (88-42)

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- September 6-9, 1988; a special inspection was conducted to

assess the licensee's unreviewed safety question determination

program and implementation. (88-43)

- September 25 - November 21, 1988; a series of special inspec-

tions of the Unit I heatup and restart effort were conducted by

the NRC Sequoyah Restart Task Force. These inspections included

control room observation and reviews of activities associated

with the restart effo-t. (88-40,88-46,88-47,88-48,88-49,88-51,

88-52,88-55)

- December 12, 1988 - January 26, 1989; a special ' quality

verification inspection was conducted in the areas of

maintenance, modifications, operations, radwaste processing, and

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correctiveactions.(88-50)

The staff spent more effort on Sequoyah than on any other operating

plant and also expended more effort than 'during the basis period.

Reviews by the staff included TVA's Corporate and Sequoyah Nuclear

Performance Plan (NPP) programs; the Employee Concern Task Group

(ECTG) element reports; sixty-five amendments to the Unit 1 and 2

Technical Specifications including an exigent amendment, an emergency

amendment, and a waiver of compliance; and four exemptions. The NPP

reviews were documented in the NRC Safety Evaluation Report

NUREG-1232 Volume 1 and 2 and its supplement, and included reviews in

the major areas of adequacy of design, special programs, restart

readiness, employee concerns, and allegations. The areas of adecuacy

of design, special programs, and restart readiness were further

. broken down as follows:

Adequacy of Design

1. Plant Modification and Design Control

2. Design Baseline Verification Program

3. Design Calculations Program

4. Alternately Analyzed Piping and Supports

5. Cable Tray Supports

6. Concrete Quality

7. Miscellaneous Civil Engineering Calculations

Special Programs

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1. Fire Protection i

2. Environmental Qualification of Electrical Equipment

Important to Safety

3. Piece Part Qualification (Procurement)

4. Sensing Line Issues

5. Welding .

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6. Containment Isolation

7. Contair, ment Coatings l

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'8. Moderate-Energy Line Breaks

9.- ECCS Water Loss Outside Crane Wall / Air Return Fan

0perability

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10. Platform Thermal Growth

11. Pipe Wall Thinning Assessment

12. Cable Installation

13. Fuse Replacement

Restart Readiness

1. Operational Readiness

2. Management

3. Quality Assurance

4. Operating Experience Improvement

5. Post-Modification Testing

6. Surveillance Instruction Review

7. Operability "Look Back"

8. Maintenance

Restart Test Program  !

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10. Training

11. Security

1~2 . Emergency Preparedness

13. Radiological Controls

14. Restart Activities List

II. . SUMMARY OF RESULTS- ,

' A' comparison of the present SALP ratings to the previous SALP ratings cf 4

years ago (1984 to 1985) would be of little benefit in determining the

current trend of the licensee. In order to evaluate the current trend cf

the licensee from the reassessment period to the assessment period, an

additional summary is provided below of the NRC staff evaluation for the

period from January 1,1987 until the start of the assessment period

(February 4,1988) to be used as a basis for comparison.

The' NRC established an Office of Special Projects (0SP) in February 1987

to address the particularly complex regulatory problems of TVA and one other

utility. Part of the OSP goal was to assess whether identified problems

to the licensee were on a path to an acceptable solution, and where not,

to identify acceptable solutions necessary to enable the staff to complete

its licensing reviews of these facilities, consistent with the NRC's

statutory mandate to protect the health and safety of the public.

A. Basis Period Summary (January 1,1987 - February 3,1988)

1. Plant Operations

During the entire basis period both units were in the shutdown

mode. Weaknesses were identified in the adequacy of Abnormal

and Emergency Operating procedures, emergency contingency action

procedures, compensatory operator actions, configuration

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control, the clearance process, investigation and resolution of i

event related issues, . involvement of first line and upper level j

management in the day-to-day operation of the plant, and control j

and authority over plant activiMes impacting schedule. Some  !

deportability / operability determinatices were classified as

unknown while awaiting Division of Nut ear

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review which was not always t;mely or responsive. In addition,

there was a reluctance by the licensee to report items that they

felt were minor. As a result, several events were nct properly

classified and repneted. Material condition, drawing adequacy

and configuration management training were acceptable.

These issues indicated a lack of management attention to and

involvement in the operational aspects of the plant. Control

room operators were burdened with the work control management

function. Their decisions in controlling these activities were

often reversed by management. This resulted in limiting the

amount of time senior reactor operators spent in the plant, a

reduction in the amount of time reactor operators spent

observing control panel indications, and a feeling that

management did not respect their ability to make decisions.

Several management changes occurred during the basis period

which contributed to major improvements.in plant activities. The

new managers included the Deputy Site Director, Plant Manager,

Operations Superintendent, and Corporate Outage / Maintenance

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Managers.

The operations section was adequately staffed to suppnrt piant

operations. ' Control room and plant shif t rotation was increased

to a six shift rotation late in the basis period. Overtime wcs

routinely used to augment normal shift staffing with several

occasions identified where administrative limits were exceeded

without receiving prior plant manager approval. The 1987 i;RC

replacement examinations for licensed operators indicated

satisfactory results (5 out of 5 passed).

Measures were implemented to revise and control primary drawings

in the control room. These drawings were redrawn and

maintained by computer-aided drafting systems which resulted in

improved accuracy and a more timely revision process. System

logic drawings.were removed from the primary drawing list during

1986 because they were not routinely updated and revised as

plant systems were modified.

Procedural compliance by Operations personnel was judged to be

marginally better than the plant staff as a whole. Instances of

procedure deviations and non-compliances occurred at an

unacceptable frequency, and resulted in several reportable

events.

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.The licensee made considerable progress in resolving the several

hundred technical issues encountered after the 1985 shutdown of

both units. Issues that remained to be resolved at the end of

the basis period included the evaluation of containment sump

level transmitters, lower containment coolers, and Senior

Operator manning.

2. Radiological Controls

Inspections conducted during the basis period of the Sequoyah

radiation protection program, indicated that the actions taken

by the licensee, including correction of previous weaknesses in

its program for maintaining exposure as-low-as-reasonably-

achievable (ALARA), were sufficient to support plant restart.

One significant event involved an exothermic reaction during a

radwaste solidification process which caused personnel

contaminations and higher than expected radiation levels.

Considerable organizational changes had taken place in the

Chemistry Group during the period. These revisions assured

close management involvement in maintenance of quality, storage

of radioactive waste, and effluent releases. Close coordination

with the Corporate Chemistry group resulted in resolution of

. technical issues in a timely manner.

The organizations were responsive to NRC initiatives in that

,, open items were being . closed out as the organization prepared

for Unit 2 startup. Staffing had been reviewed, and several new

management personnel were added to the Chemistry Group.

3. Maintenance / Surveillance

During the SALP basis period the Sequoyah maintenance program

experienced numerous weaknesses. These weaknesses were in

procedural compliance, corporate maintenance guidcnce,

maintenance trending, root cause analysis, first line manage-

ment involvement, training for maintenance planners, work

control, maintenance coordination, equipment classification

(Q-list), maintenance history tracking and trending, mainten-

ance procedure adequacy, plant drawing use, the preventive

maintenance program, accountability of maintenance tools and

equipment, post modification testing, quality assurance

involvement with maintenance activities, temporary alterations,

and corrective action. In addition, there were significant

backlogs .in the modifications, temporary modifications, and

maintenance areas. There was significant overlap between those

issues identified by ,the NRC and those issues identified by

TVA's Nuclea.r Manager's Review Group maintenance inspections.

Tracking, trending and scheduling were improved and craft

reviews were implemented which improved the quality of mainten-

ance activities. Areas that did not demonstrate active direction

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during the basis period were the maintenance instruction

enhancement project which was resolved during the SALP

assessment period,' and composite maintenance crews which were

identified by the Nuclear Maintenance Review Grcup (NMRG) as

having implementation problems but were not acted upon by TVA

. management. Institute for Nuclear Power Operations (INP0)

accreditation of the training for nine previously selected

maintenance craft areas was received during the SALP basis

period.

The NRC identified significant problems in the area of procure-

ment of safety-related parts and equipment at Sequoyah and was '

considering escalated enforcement action. Based on the NRC

findings, TVA in general and Sequoyah in particular initiated an

extensive Replacement Items Program (RIP) to ensure that

appropriate parts and equipment were installed in the plant for

EQ and seismic qualification of equipment prior to the restart

of the Sequoyah units. This included training in repair part

and procurement control which was considered one of the causes .

of the problem. Based on the shutdown plant enforcement policy I

and successful implementation prior to unit restart, these

issues were given discretionary enforcement. The program also

established controls to ensure that future procurement of

safety-related equipment met the appropriate requirements.

Sequoyah was completing the documentation and field work for ,

their EQ program. Sequoyah was found to have an excellent EQ

program which had proper management attention ard proposed sound

technical resolutions as problems arose. TVA management was

found to be knowledgeable of NRC and industry standards and

requirements in this area.

Licensee management recognized that storage of equipment did not

-meet the requirements of American National Standard Institute

(ANSI) 45.2.2 and initiated an improvement program to correct

this problem. The' equipment storage upgrade program initiated

by licensee management was adequate and well implemented. The

implementation included a computerized tracking system to ,

identify the exact location of each part, and well organized, i

clearly marked storage areas that met the ANSI 45.2.2 storage

class requirements, even at remote on-site locations. At the

close of the SALP tasis period safety related component storage

was in excellent condition, as a result of several energetic

knowledgeable managers who were personally involved in the

resolution of this industry wide issue.

As a resul t of significant NRC concerns with surveillance

instruction inadequacies which were under consideration for

escalated enforcement, the licensee established a surveillance

instruction review team to compare existing surveillance i

instructions to TS surveillance requirements. This review 1

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effort identified.a significant number of additiona! issues that

resulted in approximately 15 Licensee Event Reports (LERs) being

written. A number of significant revisions and management

changes were inade to' the surveillance instruction review and

update program to achieve technically adequate surveillance

instructions that met the surveillance requirements. Management

involvement in the final effort was aggressive and included an

independent validation process which wcs particularly well

l managed and ensured that the surveillance instructions produced

were of high quality and technically adequate. Based on the

shutdown plant enforcement policy and implementation of an

acceptable surveillance program prior to restart, these issues

were given discretionary enforcement. i

The licensee established a Nuclear Performance Plan Restart Test

Program in order to ensure the operability of scfety related ,

equipment which had been modified. A review matrix of component. i

functions and previous",y performed surveillance was established '

to ensure the testing of functions that had not been tested.

This program was considered adequately staffed with trained

individuals and was determined to be acceptable. Only the

closure of Mode 3 and 2 related items was deferred into the SALP

period.

A problem was identified in the Inservice Test (IST) valve test

program in that essentially all category A and B valves were

~ included in one Surveillance Instruction (SI) and scheduling was

. based on the issue date for the SI package, not the test date

for individual valves in the package. The test dates for

individual valves were not controlled resulting in a number of

valves exceeding their. test frequency. ,

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Procedural adherence was a weakness which contributed to several  !'

events and enforcement actions and indicated a lack of manage-

ment involvement in and attention to this area. In addition,

corrective actions were not effective in reducing the results of

this weakness until well into the SALP assessment period.

Conduct of testing was identified as an area of weakness during  !

the activities leading up to the restart of Unit 2. The

licensee took strong corrective action with the issuance of

special conduct of testing administrative controls which

resulted in a significant improvement in plant operations.

The effectiveness of the short term layup of the steam and power

conversion system (the secondary water system) was adversely

affected due to uncertainties in the startup schedule. The

uncertainties were directly related, to the inability of

management to control restart activity schedules. Continuous

maintenance and modifications of systems created a condition

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where the desired controls did not in some cases maintain the

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parameters for minimizing corrosion and degradation of the

car1 steel systems. The licensee was responsive to NRC

cor ms expressed during inspections and to NRC information

not a. Actions were taken to enhance the pro,tection of

systems .during the extended short term layup.

Organizational changes in the water chemistry program were a

strengthening factor for water chemistry control. Qualifica-

tions of the chemistry management and staff were adequate with a

sufficient number of chemists and analysts to maintain chemistry

control. Other elements of the water chemistry progran

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(procedures, training, and equipment) were maintained at a

sufficient level to achieve chemistry control during plant

startup.

During the basis period the licensee made progress in changing

its maintenance philosophy from reactive to preventive and was

trying to reinforce procedural compliance.

4. Emeroency Preparedness

The Emergency Preparedness program was adequately maintained

during the basis period. Two routine inspections and an

emergency exercise indicated the. licensee was maintaining an

effective emergency preparedness program. Licensee management

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attention to the program was adequate The two violations

identified during the rcutine inspections oddressed an

inadequacy in the training for licensed operators and a failure

to conduct required monthly concunications checks fcr three

months.

5. Security

Four routine' security inspections, one material control

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inspection and two special inspections relative to Fitness for

Duty and pre-employment screening were conducted. Two

violations were tited for failure to adequately post a

compensatory officer, and for failure to maintain a bullet-

resistant barrier. The Fitness for Duty program was judged

adequate with both a few noteable strengths and one significant

weakness. The NRC exercised discretionary enforcement in not

issuing a violation regarding numerous pre-employment screening

errors due to the significant corrective action initiated and

that the program was examined and determined acceptable prior to

plant startup. During this period the licensee, although

non-operational, did not reduce its security program nor did it

"de\ italize" any of its security areas. The NRC inspection

proc, ram also included various allegations, Employee Concerns and

the licensee's Regulatory Improvement Plan.

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A licensee Quality Assurance -Audit (QSS-A87-0010) was

performed and no regulatory issues were raised. With respect to

Safeguards Event Reports, there were four relative to expired  !

7_

badges not being voided and various visitor / escort deficiencies.

n

Of the 225 security incident reports per 10 CFR 73.71

requirements, the vast majority (nearly 95%) resulted from the

failure of equipment (hardware and systems) and not human

errors.

Midway through this period, the licensee reorganized its

security organization which resulted in security officers

working for and being accountable to ,the Corporate Nuclear

Security Support Branch, as oppose to the previous multi-

management-level structure criticized in prior SALP Reports. A

new site Security Manager was assigned to the site in July 1987.

L The extended' use of numerous compensatory iaeasures neeGd  !

because of failed equipment remained the. most significant l

regulatory issue throughout this period. ticwever, the licensee

was judged as adequately meeting requirements and providing

security for the facility. -

6. Engineering / Technical Support

The licensee's performance in the engineering / technical support

area was greatly affected by the many changes which were being

experienced by the engineering / technical support staff. Early

in the baseline perind, the licensee was trying to obtain a

clear definition of the scope of effort required to resolve many

technical and design issues which had been identified through

licensee sponsored evaluations and audits and NRC inspections;

however, the engineering and technical support staff was

hampered by changes in organization structures and changes in

key personnel as well as major changes to the internal

engineering procedures.

While the above changes hampered early baseline period

performance in engineering / technical support, the licensee had

- established many special programs to address and resolve

previously identified issues as well as new issues identified

durug the baseline period (e.g. discrepancies identified during

the NRC integrated design inspectn (IDI)). Some of the issues

for which special programs had two established included EQ of

safety-related electrical equipt ~t; design and configuration

control (design baseline verification program); design

calculations review - electrical, mechanical, nuclear, and

civil; electrical issues; instrument sense line issues;

component and piece part qualification; Appendix R; and restart

testing.

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The licensee performance in the - engineering / technical support

area was satisfactory for some of the programs; however, other

programs. were satisfactory only after corrections were made

based on NRC input. Examples of programs where the licensee's

. performance was satisfactory and the program implementation was

considered acceptable were: EQ; civil calculations; cable tray

supports; technical drawings; Design Baseline and Verification

Program (DBVP); and heat code traceability.

Examples of programs where program implementation was initially

considered inadequate included: component and piece part

qualification (inadequate seismic qualification and dedication

of commerciti grade parts for use in safety .c ted equipment);

pipe hangers and supports (inacecuate ~ caic id tions and

documentation to demonstrate that installed pipe hangers and

supports met plant design criteria); and instrument sense lines

and instrumentation accuracy calculations (lack of sufficient

conservatism). While the licensee's implemen :ation of some

programs was initially judged to be unsatisfact'ry or inadequate

relative to engineering / technical support, once problems or

concerns were identified, the licensee satisfactorily resolved

the problems and completed the programs.

7. Safety Assessment /Qu'ality Verification

For the basis period, there was an extensive review effort on

Sequoyah. The review effort included the following significant

items: .

1. review of the Corporate Nuclear Performance Plan was

completed and NUREG-1232, Volume 1 was issued;

2. most of the review of the Sequoyah Nuclear Performance Plan

was completed;

3. most of the Employee Concerns Task Group (ECTG) element

reports on Sequoyah were reviewed;

4. thirty amendments to the Units 1 and 2 TS were issued; and

5. twenty-one meetings were held with TVA on various technical

issues.

Overall, the work submitted by TVA was reasonably good. The

submittals generally showed evidence of prior planning by

management. An understanding of the technical issues was

generally !pparent. The resolutions of issues were generally

viable, timely, sound and well thought out with conservatism

exhibited by the licensee's approach. This was generally true

in the basis period except for the issues of cable testing and  ;

the transition of senior nuclear power management from contract

employees to permanent employees.

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-TheLissue of. cable testing which included the issue of-test ing

10'CFR 50.49 silicone rubber insulated cable which was inside

!" containment ; was protracted and- drawn out. .The issue' was -

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discussed tnroughout the basis period and was not resolved for

'1 Unit 1 until the! staff letter of- May 25,.1988 in the . rating

period. ' Die resolution of this issue was not timely and -the

technical issues were not well thought out.

2 .

E The TVA response to the staff's concer.:s on the transition of

,

TVA senior nuclear management was acceptable and the_ safety

- evaluation on the TVA's Corporate Nuclear Performance Plen was

issued on July 28, 1987; but, TVA was not responsive to the

issues raised ~ by the staff pertaining to the transition from

l Jcontract managers to.TVA permanent managers. As a result, the-

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staff was compelled to request TVA to notify the staff 30 days-

in advance 'of any permanent changes of the senior nuclear

,

managers.

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6 . In Janaery 1987, the NRC approved (for a period of two years)

.TVA's Quality Assurance Topical Report', TVA-TR75-1A, Revision 9,

which was; developed to resolve past problems relating to the

inability of management. to take prompt effective corrective

action to. prevent recurrence of problems. The past problems

were under consideration for escalated enforcement at the start

of the basis period. During the basis period, Sequoyah began

implementing the.new topical requirements which involved hiring

c the additional- staff required,' training them to appropriately

implement 1the program, and then monitoring the implementation to

ensure thatithe desired results were achieved. During this

transition period Sequoyah experienced significant implementa-

tion problems especially with the conditions adverse to quality

'(CAQR) program which was the subject of several TVA audits and

.NRC inspections. The TVA audits concluded taat the root cause

of the failure.of theLprogram to not fully process any signif-

icant CAQRs'was due to a lack of line management and Quality

Assurance (QA) management involvement and attention. This was

the same reason the previous corrective action program hadn't

been effective. Sequoyah responded by deeply involving upper

level managers in the corrective action program implementation.

While . problems still existed in the QA program implementation,

the staff concluded that the program began moving in a positive

direction toward the end of the basis period after upper level  ;

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management involvement had significantly increased. Based on '

the shutdown plant enforcement policy and implementation of an

acceptable corrective action program prior to restart, the past

problems were given' discretionary enforcement.

.

The three ' safety committees which functioned during the basis f

period [ Plant Operations Review Committee (PORC), Nuclear Safety l

Review Board (NSRB), Independent Safety Engineering Group {

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(ISEG)] went through a change process due to TS changes and >

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charter reviews, which were for the most part a result of NRC

initiatives. PORC was initially ineffective, however, improve-

ment-was observed near the end of the basis. period due to both

the qualified reviewer TS change and a new plant manager. The

NSRB and ISEG did not independently identify issues which

produced substantive changes to the site.

During the basis period, 88 LERs were issued of which 26 were

classi fied as significant. These resulted primarily from the

design reviews which TVA had initiated. Some LERs were unclear

with respect to the root cause determination of events or

differed from the staff determinations. The licensee esta-

blished an ISEG audit, identified similar concerns, and was

implementing ISEG and NRC recommendations at the end of the

basis period. j

Both the Special Employee Concerns Task Group (ECTG) and the new  !

Employee Concerns Program (ECP) were in existence during the

basis period. The ECTG was working on resolution of the

concerns which it received in the 1985 to early 1986 time frame. q

Numerous revisions to the ECTG reports and their corrective l

actions occurred as a result of NRC review. All employee {

concerns received during the basis period were processed through

the ECP. The NRC identified weaknesses relating to resolution

of generic Lconcerns, administrative issues, and restart

determinations which were.promptly addressed and corrected by

the ECP management. NRC reviews of both programs indicated that

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concerns were being adequately addressed at the end of the basis

period. j

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TVA Nuclear Power corporate management was usually involved in

Sequoyah site activities in an effective manner during the basis

period. There were several management changes at the site which

contributed to major improvements in operation, security and

radiological controls during this period. There were corporate

audits made in the radiological controls and maintenance areas

where actions were taken by corporate management to strengthen

these programs. Although many significant problems in programs

at the site were not being identified by TVA prior to NRC

inspections, usually strong corrective actions from the corporate '

level were taken when it was needed to correct the identified

problems.

For the basis period, corporate management was generally

responsive to NRC initiatives. Responses to NRC were generally

timely and generally sound and thorough. This is shown in the

significant amount of work completed by the staff and TVA in the

basis period.

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The staff conducted an inspection of management effectiveness 1

related to licensing _ activities in the basis period. The

inspection was conducted in key areas of responsibility at both

the plant site and corporate offices. The staff concluded that

corporate management processes in the areas inspected were

functioning adequately.

B. Assessment Period Summary (February 4,1988 - February 3,1989)

Sequoyah has been operated in an overall safe manner during the

assessment period. Management involvement in and attention to the

operations and support of the plant has significantly improved as a

result of the strong leadership exhibited by the new plant a.anager

and new site director.

The plant operations area matured during the assessment period. After

starting the assessment period with five reactor trips, Unit 2 was on

line for 210 continuous days which established a TVA single unit

record. Unit 1 experienced two reactor trips during startup with

full availability for the rest of the assessment period. Strengths

included the procedures upgrade programs, the emphasis on procedural

compliance, and the ownership concept for the operators. Corrective

activs for problems once the root cause was identified were consider-

ed a strength. Weaknesses included operation of the radwaste system;

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root cause analysis in relation to the post-trip cooldown shutdown

margin issues; and the performance of fire watches. Control of plant

activities by the control room operators improved during the latter

half of the assessment period.

The overall. quality and experience level of the health physics staff

is _a program strength, and the licensee's health physics, radwaste,

and chemistry staffing levels are adequate and compare well with

other utilities having facilities of similar s,ize. Management

provides adequate support and is involved in matters related to

radiation protection.

The maintenance / surveillance area also matured during the assessment

period. Strengths included the leadership exhibited by the new main-

tenance superintendent. the establishment of the work control group,

the establishment of a preventive maintenance upgrade program,

implementation of the system and train outage concept for scheduling

maintenance, and implementation of the system of the month review

program. Weaknesses included the large number of personnel errors or

inadequate procedures which resulted in Engineered Safety Feature or

reactor protection system actuations; the inability to produce  ;

realistic schedules; and the inability to correct problems associated

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with the feedwater control system. ,

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During a full' participation exercise, the licensee demonstrated  :'

that they could satisfactorily respond to an emergency at the

facility. However, weaknesses were noted in that the licensee had on

two' occasions failed to promptly report a Notice of Unusual Event

(NOVE) and also failed to recognize an explosion as requiring entry

into the emergency classification logic during the emergency j

exercise.

In the security area, a high number of hardware equipment inade-

quacies exist. These inadequacies, which are a result of the

security equipment being obsolete, have lead to a continuous depen-

dence on compensatory measures. Corporate support was weak because

of a high turnover rate; however, the licensee has finalized a

reorganization of its Corporate Nuclear Security Service Branch which

has resulted in some improvements. The site management has been

instrumental in dedicating site support to help the security branch

reduce the number of security compensatory measures.

The Engineering / Technical Support ac'tivities did not significantly i

exceed minimum regulatory requirements. While numerous issues were

resolved - during the assessment period, many of the issues were  ;

resolved only after considerable NRC input. Support for operations I

of the plant was initially viewed as a weakness but improved late in

the assessment period.

4 ~

In .the Safety Assessment / Quality Verification area, the most

important improvement was in the corrective action program which made

. significant strides during the assessment period. Strengths included

the significant management attention to and involvement in the

corrective action process, the strong leadership provided by the

plant manager and new site director in getting employees to accept 'j

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responsibility for doing quality work, the quality monitoring and

audit program, and the employee concerns program. Weaknesses in-

cluded the 10 CFR 50.59 safety evaluation program and the slipping of

the dates and scope changes for commitments made to the NRC. 3

C. Overview

February 4,1988 - February 3,1989

Functional Area Rating Trend ,

Plant Operations.................... 2 None

Radiological Controls............... 2 None

Maintenance / Surveillance............ 2 .None

Emergency Preparedness.............. 2 None

Security............................ 2 None

Engineering / Technical Support....... 3 Improving

Safety Assessment / '

Quality Veri fica ti on. . . . . . . . . . . . . . 2 None

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III. CRITERIA

Licensee performance is assessed in selected functional areas, depending

on whether the facility is in a construction or operational phase.

Functional areas normally represent areas significant to nuclear safety

and the environment. Some functional areas may not be assessed because of

little or no licensee activities or lack of meaningful observations.

Special areas may be added to highlight significant observations.

The following evaluation criteria were used, as applicable, to assess each

functional area:

1. Assurance of quality, including management involvement and control;

2. Approach to the resolution of technical issues from a safety

standpoint;

3. Responsiveness to NRC initiatives;

4. Enforcement history;

5. Operational and construction events (including response to, analyses

of, reporting of, and corrective actions for);

. 6. Staffing (including management); and

7. Effectiveness of the training and qualification program.

Nowever, the NRC is not limited to these criteria and others may have been

used where appropriate.

On the basis ~ of the NRC assessment, each functional area evaluated is

rated according to three performance categories. The definitions of these

performance categories are as follows:

1. Category 1. Licensee management attention and involvenient are

readily evident and place emphasis on superior performance of nuclear

safety or safeguards activities, with the resulting performance

,

i substantially exceeding regulatory requirements. Licensee resources

are ample and. effectively used so that a high level of plant and i

personnel performance is being achieved. Reduced NRC attention may l

be appropriate.

2. Category 2. Licensee management attention to and involvement i r.

the performance of nuclear safety or safeguards activities is good.

The licensee has attained a level of performance above that needed to ,

meet regulatory requirements. Licensee resources are adequate and j

reasonably allocated so that good plant and personnel performance is 1

being achieved. NRC attention may be maintained at normal levels.

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3. Category 3. Licensee management attention to and involvement in

the performance of nuclear safety or safeguards activities are not

sufficient. The licensee's performance does not significantly exceed

that needed to meet minimal regulatory requirements. Licensee

resources appear to be strained or not effectively used. NRC atten-

tion should be increased above normal levels.

The SALP Board may also include an appraisal of the performance trend

of a functional area. This performance trend will only be used when

both a definite ' trend of performance within the evaluation period is

discernable and the Board believes that continuation- of the trend may

result in a change of performance level. The trend, if used, is defined

as:

Improving: Licensee performance was determined to be improving near

the close of the assessment period.

Declining: Licensee performance was determined to be declining near

the close of the assessment period and the licensee had not taken

meaningful steps to address this pattern.

1

IV. PERFORMANCE ANALYSIS

A. Plant Operations

1. Analysis .

The quality of operations at Sequoyah improved during the SALP

assessment period based on the results of routine and special

inspections. During the first half of the assessment period,

several plant -trips and operational events occurred which

demonstrated that the operations area required further improve-

ment. Following an NRC/TVA management meeting to discuss the

root causes of the poor performance which caused the trips, the i

Sequoyah plant staff exhibited increased responsiveness to NRC l

issues, attention to detail, and commitment to quality.

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Increased management attention to and involvement in the opera-

tion of the plant contributed to a Unit 2 record power run

following the management conference. Management initiatives

included revisions to the root cause assessment procedures,

establishment of a requirement for PORC approval of post trip

reviews prior to restart, increased attention to control of

plant activities, and a conscientious effort to reduce the

number of inoperable or out of service components.

i

Management attention to and involvement in the upgrading of

. operating procedures were focused both by results from NRC  !

inspections, which occurred near the end of the basis period and ,

during the assessment period, and by licensee initiatives. l

Operating procedures were included in the licensee's ongoing

procedure enhancement program. Standardizing the procedure

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format and clarifying instruction steps as part of the

enhancement program were elements of the program initiated

during the latter part of the assessment period. This is a

long-term program and is not expected to be complete during the

next SALP rating period. System Operating Instruction (S01)

checklists were reviewed and revised by the licensee after NRC

inspections during the basis period revealed prcblems with the

system alignment processes. After the licensee completed these

revisions, system operating instructions were workable and

adequate. However, the procedure change process was difficult

and cumbersome. The use of night orders to circumvent the need

to revise operating procedures was stopped. TS' interpretations

were upgraded and now require specific approval prior to their

entry into the TS Interpretations log. The Emergency Operating

Procedures (EOPs) were determined to be adequate and the

corrective actions initiated by the licensee from a basis period

inspection were determined to be appropriate. The

Administrative Instruction for controlling Hold Orders was

revised to require more control by the Operations staff and more

responsibility by the persons performing the work resulting in

an improved hold order process. Upgrading cf the system logic  ;

drawings for those systems. described by the Design Baseline and  ;

Verification Program (DBVP) boundary was completed during the

assessment period and the drawings were returned to the control

room for use by the operators. Also, drawings essential for

safe plant operations were available in the control room. At

the end of the assessment period, a lcrg-term effort was in

progress to restore other system logics to the prinary drawirg

list and return them to the control room.

The licensee's approach to the resolution of technical issues

from an operational safety standpoint was technically sound. An

understanding of the safety aspects was apparent, and censerva-

tism was usually exhibited when responding to scfety-significant

events and issues. Notable exceptions to this generalization

were the poor planning and management ineffectiveness in dealing

with the system alignment and operability determination in

support of UHI valve repair, and in the resin transfer opera-

tions which occurred near the end of the assessment period.

Several operational plant events that occurred during the

restart of both Units 2 and 1-identified that a poor feedwater

control system design and operating philosophy existed. Changes

to procedures and specifi'c operator training to eliminate trips

and transients in this area were not initially effective. Rect

cause determinations did not involve sufficient first line

operations management efforts which resulted in a protracted

resolution process.

Improvements in the area of communications were instituted

following an incident involving manipulation of the wrong valve

by an auxiliary unit operator which resulted in a loss of RHR

suction. Control room professionalism was adequate and showed

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continued improvement during the assessment period. The

control room was upgraded through extensive cosmetic

improvements such as new carpeting, painting, and repair of

deficiencies such as roof leaks. However, several functional

deficiencies exist which affect operator performance and

effectiveness. Nuisance alarms, long-sta.nding hold orders and

Temporary Alterations (TACFs), and human factors problems

associated with steam generator level controls continued to

cause an unwarranted number of problems for the operators.

Management was aware of these problems and is addressing them in

the form of a System Engineering concept and a detailed control

room design review.

Problems continued in the configuration control area (system

alignment) through the startup of Unit 2 particularly in the

area of waste water systems. The program for controlling the

configuration and operations of the waste water systems was

changed to provide the same level of control for these systems

as was. applied to other plant systems that are under the

., authority of operations. This proved to be a positive step in

reducing configuration control errors associated with the waste

water systems. Additional changes made in the configuration

control program consisted of repeat back communication, and

separating the first and second verification by time and distance.

The latter change had been previously recommended during the

basis period by the licensee's Unit 2 operational readiness

review team, but had not yet been implemented by managcment.  ;

Once implemented, these changes significantly reduced configu- l

ration control problems.

The licensee performed evaluations to confirm that compensatory

measures which had previously been established for disabled

safety functions were properly documented and were collectively

and individually capable of being performed with normal staffing

levels. Operator awareness and control of long standing TACFs

in relation to their effect on plant configuration was a matter

of concern to the NRC during the basis period and continued to

be an issue during the assessment period. The licensee took

action to reduce the number of TACFs to approximately 80, which

was 50% of the level at the beginning of the period, with a goal

of having no more than approximately 30 TACFs.

Operators were well informed in the use of emergency operating

procedures. Because of the long duration shutdown period

(approximately 21 years), the number of reactor operators

experienced in power operations was low and additional support

personnel were made available in preparation for Unit 2 restart.

These included additional management presence in the control

room, additional control room Senior Reactor Operators, and

temporary Operating Shift Advisors. Operator actions for most

events that occurred during the Unit 2 startup were appropriate.

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Licensed operators responded effectively to plant transients on

most occasions during Unit 1 startup including a reactor trip

of Unit'l caused by' feedwater control problems, a turbine trip

of Unit 1, a reactor trip of Unit 1 caused by a generator

ground, and a lightning strike of a switchyard transfonner

during a thunderstorm. .

Operators were observed to be disciplined professionals with

adequate communication skills. However, occasional lapses which

were exemplified by one instance of inadequate action by an

operator during routine plant activities occurred. This example

involved the placement of a centrifugal charging pump in the

pull to lock position which resulted in a failure to comply with a

technical specification action statement,

Control room activities were generally conducted in an effective

and professional manner. Formal communications were observed in

most cases. Operators were attentive, aware of plant conditions

and responsive to changes in plant conditions. Senior plant

management actively supported the above operator activities and i

was deeply involved in the day-to-day operation of the plant.

In addition senior plant management maintained a detailed

account of and tracked the status of known equipment

deficiencies, CAQRs, and plant parameters in daily plant

meetings. Active involvement by plant management and support of

ti.e ownership concept by the operations department had a -

positive' effect on plant operations and morale. This was

exhibited by the absence of significant- events or operating

problems during the extended power run of Unit 2. Facility

operations reflected improvements in planning and assignment of

priorities during the period. The forced outage rate for both

units during the period was extremely high as a result of the

extended shutdown. However, following the five Unit 2 trips

which occurred early in the Unit 2 startup process, Unit 2 had

no forced outages for a period of approximately 210 days.

Unit 1 experienced two reactor trips during its startup period,

followed by full availability for the remainder of the

assessment period.

Management support and insistence on the ownership concept has

strengthened the authority and role of the Operations group in

general and the control room shift supervisor in particular.

Operations personnel have demonstrated on many occasions their

willingness to suspend or delay surveillance, maintenance ard

other schedule impacting activities until they were satisfied

that the plant was in a safe stable condition and that other

plant activities in progress would not interact with the

scheduled activities to produce safety system actuations. The

absolute authority of the operations staff in these matters has

been fully supported by plant management.

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During the assessment period the licensee administered i

requalification examinations. The results from the examinations

indicated a large percentage success rate (approximately 69 cut

of 70). Nonlicensed operators were judged to be extensively

trained receiving both detailed classroom training and thorough {

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in plant on the job training. The percentage success rate for

new operating license candidates was determined to be

below average (7 out of 11 passed).

Operations shift training for newly installed plant modifica- ,

tions and for correction of operating deficiencies or events was i

adequate.- However, occasional lapses were exemplif.ied by the

shutdown margin / excessive cooldown events and rod control demand

counter problems.

During the assessment period Operating shift manning was l

adequate and maintained at the levels established during the

basis period. Several management positions were eliminated to

streamline the Operations organization which resulted in a more

effective organization.

Management stressed procedural compliance by operations per-

sonnel throughout the assessment period. This had a side effect

of improving procedures by forcing operators to have inadequate

procedures revised before they could be used. However,

instances of procedural non-compliance and deviation continued

during Unit 2 startup, such as the MSIV closures, configuration

control deviations, and Upper Head Injection (UHI) accumu'lator

venting events. Management was very aggressive in responding to

the above issues and by the middle of the assessment period

procedural adherence was adequate and improving.

In an event involving the discharge of highly-radioactive spent

resin that occurred during the lctter portion of the SALP

assessment period, it was determined that the intense management

attention given to power operations had not been applied to the

waste processing portion of the power plant and the attendant

operations support staff. This event highlighted, in that area

alerte, inadequate procedures, a casual attitude toward following

procedures, inadequate drawing control, and failure to aggres-

sively correct design problems that make cperations awkward or

could create personnel or radiological hazards. In addition,

plant management in this specific area appeared to be poorly

trained and very weak with respect to the operating and physical

characteristics of their assigned system. Finally, interactions

between the waste and water management group and other plant

management that were observed following this event did not

demonstrate a cooperative, quality-oriented approach to the

resolution of technical issues within the waste and water

management group. Plant management is currently taking strong

corrective action to improve the waste water processing area.

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L Logkeeping by licensed operators continued to exhibit weaknesses

particularly -in the areas of detailed entries, entry and exit

from Limiting Condition for Operation (LCOs), and descriptive

explanations and rationales for decisions made and actions

conducted by the operators and SR0s. During the last' two moriths- l

'

of the assessment period, Operations management implemented

corrective actions in these areas by having' Operations super-

visors review logs for completeness, stand-alone entries and

supportable explanations for LC0 entries, exits and changes to

plant and equipment status. The NRC identified during the

latter portion of the assessment period a significant

improvement in the level of detail supporting log entries. The

corrective actions were effective.

Operational events in general were promptly and accurately

'

identified. Exceptions were the failure of the operations staff

to recognize problems with the excessive post-trip cooldowns,

and having a centrifugal charging pump in pull-to-lock while the

other pump was inoperable, both of which resulted in escalated

enforcement.

Emergency Notification System (ENS) reports occurred at a high

rate as a result of the special outage conditions and system

configurations. Notifications were generally conservatively

made 'and technically correct. ENS notification was not made

-

initi, ally for the centrifugal charging purp in pull-to-lock

event,. and for an unidentified RCS leakage above allowable

'

incident. DNE support of Operations in making Operability

determinations improved during the assessn.ent period. This

improvement was the result of management initiatives and

personnel changes.

As a result of the change in licensee management that occurred

at the'end of the basis period, PORC reviews became aggressive

and technically involved in the resolution of issues affecting

the safe operation of the unit. Changes in PORC activities

which resulted in improved performance included consistency in

personnel staffing and the high expectations established by the

new plant manager. The elevated expectations were also strongly

supported by the new site director and upper TVA management. As

a result of the TVA management initiatives, the Plant Operations

Review Staff was established as a part time support group for

PORC. P0RS employed specialized training and skills to perform

root cause evaluations and determine corrective action plans

associated with plant events, which were then submitted cs

completed projects to PORC. The use of the Plant Operations

Review Staff has involved the PORC deeply in day-to-day plant

operations.

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[ eat the close of the:SALP assessment period Sequoyah upper line

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management was found to .be strongly comnitted to obtaining  ;

quality'in plant operations. .There was also a general increase- .

.in management attention toward the ccnduct of operations and- l

. management awareness of plant conditions. These, coupled with  !

organizational changes to reduce both. management resistance to i

change; and the number of management levels, resulted in _ _ l

'

continuing improvement'in the performance of the operating staff l

-

and the resolution of technically diverse and complex issues  !

$ throughout the year.  ;

p i, During this assessment period the entire fire protection staff  ;

at Sequoyah was reorganized into a Fire Operaticns Unit. The l

Fire Operations Unit consists of a dedicated fire brigade which  :

'is responsible for fire suppression and fire prevention ,

inactivities. The dedicated fire brigade replaced the preexisting ]

system of_ a fire brigede composed of unit operations personnel. 1

Fire: brigade' training at TVA's Nickajack Fire Training Center j

was fourd to be excellent and brigade manning was determined to i

be adequate. Reorganization of the fire protection staff j

. greatly improved fire brigade effectiveness and fire prevention  !

activities during this assessment period. Organizational i

planning and assignment of- priorities was demonstrated in the l

fire ' brigade reorganization. In general, policies and pro- ,

~Under the reorganized

'

cedures were well stated and understood.  !

fire operations unit, decision making was usually at a level  !

" that ensured adequate management review. Involvement by  ;

corporate management in the fire protection area was evident.

Two . Fire' Protection QA Audits were performed during the SALP j

i

'

assessment period, one of which was by the licensee's insurer,

. American , Nuclear Insurers ( ANI). These audits icentified a i

number of unsatisfactory conditions and findings and reccarended i

several program improvements. The licensee either implemented i

E the - corrective actions associated with these findings or

evaluatcd the issues to develop a schedule date for completion  ;

of the corrective' actions. The NRC identified weaknesses in

~

the areas of procedural implementation of fire penetration ,

barrier requirements and control of combustibles. The new fire i

protection management was aggressive in the resolution of these i

issues and appeared to take appropriate corrective actions.  !

!

^

. The condition of Fire 4arriers, surveillance of fire protection l

syst' ems and components, emergency lighting, manual equipment and l

QA audits were satisfactory in terms of the low number of l

deficiencies noted. Housekeeping practices and conditions  ;

relative to fire. protection wera found to be adequate. l

l

During the SALP assessment period inadequacies in the perfor-

mance of fire watches were noted. The inadequacies consisted of  ;

inadequate inanagement oversight in regar d to fire watch per-

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sonnel and failure. of management to provide concise guidance on

how fire watch individuals must perform their duties. This

issue occurred at the time that the new organization was being

put into place and was aggressively pursued by the new fire

organization management.

Five violations and one deviation were identified: j

a. Severity Level III violation for failure to comply with TS  !

3.0.3 involving loss of safety functions and for failure to

notify the NRC in a timely manner. (88-20-03 & 88-20-04)

b. Severity Level IV violation for failure to implement

configuration controls. (88-26-01)

c. Severity Level IV violation for failure to meet require-

ments of TS 3.3.1 and 3.3.2 to place OTDT and OPDT in trip.

(88-39-02)

d.- Severity Level IV violation for failure to perform fire

watch patrols. (88-46-01)

e. Severity Level IV violation for performing a test of the

TDAFW pump without a written procedure. (88-48-02)

f. Deviation for failure to comply with a commitment made

concerning the control of combustibles (wood) in safety-

related areas. (88-54-01)

.

2. Performance Rating:

Category 2

3. Recommendations:

The Board recognized that significant experience was gained

through the plant events and activities which occur ed ,

during the assessment period and resulted in an improvement

in the plant operations area.

Radiological Controls  !

B.

1. Analysis

During the assessment period, inspections were performed by the

resident and Regional office staff in the areas of ram *+'on

protection, radiologi, cal effluent, and confirmatory meure-

ments. Included in the inspection program was a special team

inspection for restart of Unit 1 and a special team inspection

to assess the performance of health physics, chemistry, and

radioactive waste processing during the recent outage.

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The' qualifications of the new Superintendent of Radiological

Controls posi* ion were determined to have met the requirements

- discussed _ in Regulatory Guide 1.8, Qualification and Training of-

Personnel for Nuclear Power Plants.

The licensee's health physics, radwaste,. and chemistry staffing

levels were adequate and compared well with other utilities -

having' facilities of'similar size. An adequate number of ANSI

qualified licensee health physics (HP) technicians were

available to support . routine operations. During outage

operations, additional contract health physics technicians were

used to supplement the permanent health physics staff. The

overall quality and experience level of the health physics staff

is-viewed as a program strength. Radiation protection training

was considered good. The licensee's general employee training

(GET) in radiation protection was well' defined. The GET

training / retraining program not only included standard topics as

outlined in 10 CFR 19, but findings of licensee audits and NRC

inspections were factored into the training. Management support

of and commitment to training was evident in that sufficient-

time was allowed for training and employees were encouraged to

attend.

Management support and involvement in matters related to

radiation protection were demonstrated by: (1) purchasing an

automated laundry monitor to control the potential for " hot -

particles" in order to reduce exposure to personnel;

(2) installir.g seven sensitive portal monitors at the exit to

the . radiation controlled area (RCA) to be more effective in

detecting personnel contaminations; (3) establishing an ALARA

incentive program; and (4) providing corporate support in

resolving technical isst'es as related to the radiation protec-

-tion program.

Resolution of technica: issues was generally adequate; however,

a special team inspection observed, during the Unit 2 refueling

outage at the end of the assessment period, that the licensee

experienced problems in containment such as high iodine airborne

radioactivity, an unexpected increase of beta radiation levels in

steam generators, and heat stress to personnel while wearing

supplieu oar noods. These problems appeared to be caused by a

failure of licensee management to communicate and evaluate these

problems adequately. Early identification and technical resolu-

tion of the root causes were not performed in a timely manner,

which created the need for increased radiological attention,

resources, and demand for support from the radiological controls

program.

During the assessment period, a special NRC inspection team

revievied the licensee's controls for high radiation areas and

determined tw tnese controls were generally adequate.

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However, one violation was identified pertaining to two -

. Assistant Unit Operators (AU0s) who were unknowingly working in ;I

-a high. radiation area in the Unit 1 Auxiliary 8uilding created l

by an inadvertent introduction of-reactor coolant and resin into j

the CVCS demineralized resin transfer piping. The AU0s received  !

doses of between 400 and 500 mrem and did 'not exceed .any l

administrative or NRC exposure limits. . It was determined that  ;

~ the area was posted as a radiation area 'instead of 'a high l

radiation area 'and that the workers had neither an integrating l

dose . rate monitoring device nor an individual present with a

dose rate' monitoring device to provide radiological protection

job coverage. The licensee's immediate corrective action was to

post and lock the concerned high radiation area and to reconfirm

that other radiation and high radiation areas were adequatelv i

controlled. i

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~The respiratory protection program was reviewed by

the NRC during the assessment period and it was determined to t

the program was well defined and implemented in accordance with

appropriate regulations.

The 1987 collective radiation dose was 206 person-rem which was I

'

approximately 56% of the national average of 368 person-rem pe'r

pressurized water reactor (PWR). In 1988, the - station's

collective radiation dose was 382 person-rem, compared to 345  ;

person-rem per unit national average, which when combined with 1

the 1986 and ~ 1987 collective radiation dose ' averaged 284

person-rem for three years. However, since the unit has been

inoperative for an extended period the three ~ year average is

not necessarily comparable to similar intervals for other units.

At the end of 1987, the area of the plant controlled as

radioactively contaminated was approximately 15% of the total

area which potentially cruld become contaminated. At the end of

1988, the area contaminated was still approximately 15% and

slightly above other facilities similar in design, however, this

did not create a significant personnel exposure or personnel

contamination problem.

The licensee experienced 130 personnel contaminations in 1987.

The number of personnel contaminations in 1987 was among the

lowest in Region II. However, in 1988, the number of personnel

l contaminations increased to 409 and 155 of these were skin

l' contaminations. The increase in personnel contaminations was

due in part to startup activity at the plant, increasing

radiation levels and the increased detection sensitivity of the

new, more sensitive, portal monitors at the exit of the RCA.

Effluent summary data for 1985, IS86, and 1987, are contained

under Supporting Data and Summaries,Section I of this report.

These releases are consistent with the plant being shut down

from mid-1985_through 1987, and consequently no basis exists to

establish any trends during the assessment period.

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During the' assessment period, the licensee's program for

l' packaging, shipping, and storage of icw level radioactive waste

was - determined to be adequate. The licensee demonstrated good

w radioanalytical trend capability by' showing close agreement with

NRC results for both beta-emitting and gamma-emitting samples.

'

However, weaknesses were identified in the radiological waste

. water processing area as described in the operations section.of

g

this assessment.

Two violations were identified:

- a. 'Ssverity. Level IV violation for failure to adhere to or '

establish' procedures for performing breathing: zcne air

samples and for exposure control during steam generator

work. (08-31-02)

b. Severity Level IV violation for failure to evaluate

the radiation hazards present in the 690 foot eleva-

tion Pipe Chase in the Auxiliary Buildine. (89-05-04)

2.. Performance Rating:

Category 2

3. Recommendations:

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C. Maintenance / Surveillance

.1. Analysis

During the assessment period, the technical quality of main-

tenance and surveillance at Sequoyah was good as a result of the

many technical and programmatic upgrades which occurred. These l

programs experienced substantial organizational and~ perscnnel

changes resulting in a large number of licensee initiatives.

The addition of a new maintenance superintendent at the

beginning of the assessment period . resulted in licensee

initiatives in the maintenance area which included; increasing

the use of system engineers, the use of.new vibration monitoring

equipment techniques, maintenance procedure enhancement,

extensive Motor Operated Valve Actuators (M0 VATS) testing of

primary and balance-of-plant valves, establishment of a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

Outage Manager to coordinate maintenance and triodification work,

and the organization of maintenance and modification activities l

into train and system outages. Management of the Maintenance

Program was very effective as demonstrated by positive trends in

industry indicatcrs such as maintenance backlog, tagging,

overtime use, CAQR and LER generation, QA document rejection,

Post Modification Testing (PMT) rejection requiring maintenance

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rework, personnel contamination, industrial safety practices,

and delinquent safety-related preventive maintenance. Line

management increased its presence in the operating and work

spaces, became more aware of plant status and technical issues

and demonstrated a. commitment to the program and associated

improvements implemented during the assessment period.

l

The licensee developed a detailed program for completed

L maintenance record review, which is quite thorough and effective

l in identifying and correcting deficiencies. The use of

procedures in accomplishing maintenance activities was adequate

and improving. The quality of procedures and work requests, and

their associated review, steadily increased as a result of

Maintenance Section upper and middle level management

involvement in the licensee's program for removal, repair and

restoration of safety-related equipment. The licensee initiated

a system / train outage concept which was coordinated with unique

site electrical distribution and TS requirements. In addition,

the licensee instituted a standard maintenance practice which

established the niethod for managing, tracking, planning,

scheduling, post work evaluation of and documentation of main-

tenance work activities. This establishment of administrative

control over maintenance work activities reduced open-ended

" Troubleshoot and Repair" type work orders and provided clearer

direction to the personnel performing work in the field.

Operability determination was also added to the administrative

control process prior to closing out work orders.

The licensee's action with regard to NRC maintenance related

initiatives was generally good. The response varied depending

on the organizations involved and the time during the assess-

ment peciod when the NRC initiatives occurred. Licensee

response improved in all areas throughout the assessment

period. Responses from onsite maintenance and modifications

organizations were usually quick, professional and technically

accurate. During the initial portion of the SALP assessment

period, support for onsite maintenance related issues from the

TVA DNE organization took long periods of time. This caused

issue resolution and operability determination to lag.

However, by the middle of the assessment period DNE support

for maintenance and modification activities was much improved.

Licensee resolution of maintenance related technical issues

usually indicated technical understanding of the issues,

operational conservatism, and was generally well thought out.

Examples of well thought out maintenance activities were;

RCP trip bus troubleshooting and repair, and steam generator

tube leak resolution and preventive plugging. Those main-

tenance activities that were less professionally addressed

by the licensee included pressurizer safety valve trip

setpoint calibrations which occurred at the beginning of

the assessment period.

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The maintenance staff is generally well qualified and trained.

Special training was given to maintenance personnel following 4

issues related to the maintenance management system, EQ, conduct {

of testing, and configuration control. Trrining also included j

management training for all levels of liaintenance Department i

management and specific technical training for first and second

line managers to increase in-craft and cross-craft supervisory

expertise. The experience levels of maintenance department

first line supervisors averaged approximately 10 years of craft

related experience, which included several hundred hours of

craft and engineering training. The site maintained the INPO

training accreditation reccived during the basii period for

maintenance training.

During the assessment period, outage and work control

processes were established and implemented. Performance

immediately improved due to planning and assignment of

priorities. Procedures for control of these processes were well

defined, and appeared to be understood by the personnel involved

in their implementation. The technical background and level of

plant systems knowledge of the planners, coordinators and

managers in the work control / outage organization was excellent.

These positions were filled with operators, engineers, and

managers that were deeply involved in the day-to-day operations

of the plant and demonstrated excellent communications and

organizational skills.

'

' While maintenance tracking and planning was considered a

strength, maintenance outage stheduling was considered to be a

weakness. The licensee demonstrated it was capable of drafting

detailed correct 1<e and diagnostic niaintenance plans, and 1

implementing those plans in the field. However, outage and

maintenance schedules rarely had any realistic relation to the

actual work being performed in the plant and exhibited continual

and predictable schedule slips.

The licensee used the composite maintenance crew concept for

NOVATS testing, refrigeration, and general maintenance. An NRC

review of the implementation of the composite crew process at

the begining of the assessement period revealed that no

procedures addressed the training and qualifications require- j

ments for foremen supervising personnel in other crafts, for

'

craftsmen performing work outside of their craft, or for

craftsmen performing independent verification outside of their

craft. Although no plant events were attributable to composite

crews during the assessment period, composite maintenance crews

existed in, contradiction to the training and qualification

requirements for maintenance foremen and craftsmen. This

indicated insufficient management attention to and involvement

with the composite crew concept and represented a failure by

management to recognize that minimum regulatory requirements

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

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were not being met. Once management attention was focused on-the

~

problem, a comprehensive procedure was developed to address the

composite maintenance crew concept. Corrective actions that

were initiated appeared to have resolved problems with the

composite crew concept.

The. control and use of calibrated equipment met regulatory

requirements and purchase receipt inspection and traceability of

installed materials was found to be acceptable. Additionally,

Lpost maintenance testing was found to be satisfactorily

accomplished.

During the assessment period the material condition of

. plant components steadily improved. A review of system failures

did not indicate any adverse management or maintenance

practices. Several conditions that did not constitute failures

but did affect plant operations were: leaking pressurizer safety

valves on both units, a leaking reactor vessel flange 0-ring on-

Unit 1, and unstable feedwater automatic controls for both

units. In the case of the Unit 1 pressurizer safeties and the

Unit 1 vessel flange ~ 0-ring, plant activities were well

controlled and personnel involved were technically astute and

receptive to NRC initiatives. However, in reference to

feedwater controls, less than cohesive disciplined management

activities were'noted.

. The plant's material condition, preservation, and housekeeping

status was adequate. Occasionally maintenance debris and other

material / housekeeping deficiencies existed in the auxiliary

L bu11 ding and other plant spaces. Additionally, work in progress

was often left open, uncovered, and unattended during work crew

breaks and turnover periods, Examples of these ccnditions were;

ice condenser cleanliness prior to Unit 2 initial heatup, loose

items and debris found by the NRC in safety-related electrical

panels and distribution boards.

'

During the assessment period the Preventive Maintenance

(PM) program at Sequoyah was in the midst of a significant

amount of change. The licensee initiated a PM Upgrade Program

which was very detailed and resulted in a significant increase

in' the number of PMs required for plant equipment. This PM

upgrade effort was in place for the majority of the assess-

ment period and the developmental stage will last another year.

Weaknesses were identified in the number of outstanding

delinquent PMs, and the existence of a significant percentage of

recently developed PMs that had never actually been performed on

plant equipment. The everall conclusion in the Pti area was that -

a very strong PM program was being developed with involved

management support. The program is being developed as a quality

activity and will improve the safety and reliability of plant

equipment when it is fully impleme 'ed. The results of this

effort, in the form of benefit to tant equipment, has r.ot yet

been realized. .

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Predictive- analysis techniques were well integrated into the

licensee's maintenance program. Vibration analysis and M0 VATS

testing .were active at the site and were found to be

instrumental- in the. identification of much of the corrective

maintenance. These two techniques were also found to be used as

an integral part of the licensee's post-maintenance surveillance

activities. In addition, the licensee implemented a- system

performance monitoring program to improve station reliability.

The program includes vibration monitoring, system and component

. parameter trending, System of the Month reviews, and performance

walkdowns. Upper plant management is very attuned to the

results from these maintenance techniques and plant operational

decisions were made using this data.

At the beginning of the assessment period, ' management

continued to experience' a lack of . full understanding of the

technical requirements necessary to fully resolve some NRC

identified procurement issues. Following NRC identified adjust-

ments to the program, Sequoyah established an acceptable program

for resolving replacement part issues. Following the NRC

findings, management demonstrated a clear understanding of the

issues involved, proposed timely resolution of the findings, and

proposed resolutions which were . technically sound.- In a

specific case (e.g., molded case circuit breakers), Sequoyah I

exceeded the. bulletin response requirements which enabled the

NRC to provide up-to-date. guidance ' to other licensees. In

addition, procurement and maintenance management coordinated

closely during the second half of the assessment period to ,

reduce, by approximately 50 percent, the outage work that could

not be performed due to outstanding material items.

Safety-related equipment storage continued to be well managed ,

throughout the assessment period. Several cases existed

where detailed storage and material information was necessary to

support plant operability determinations. In each case the

information was retrieved, clearly' supported operability and

demonstrated a service related role for the storage and

procurement organizations.

Staffing in the procurement and storage areas was adequate.

Staffing of the contract engineering group (CEG) was generally

good. While site and corporate management had the expertise for

the procurement operation, potential impacts on continued

performance were identified as a result of their possible

involvement in other TVA' site procurement activities.

I

During this assessment period, Sequoyah transitioned from a

separate dedicated EQ organization to a matrix organization

within the site DNE organization. This transition occured without

interruption or degradation of the quality of EQ corrective and

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preventive maintenance implementation. EQ maintenance decisions

were made at appropriate levels. Additionally, plant

organizations had well stated policies to guide them in

completing field work. Management authority and

responsibilities were defined and understood in the EQ area.

Sequoyah management continued their resolution of technical

issues in the maintenance area with conservative approaches

during the assessment period. This was illustrated by the

implementation of corrective maintenance activities to support

the qualification of silicone rubber electric cable installed

inside containment and the qualification of transmitter cable

nylon butt splices. The maintenance department was adequately

staffed with personnel having the appropriate expertise.

Surveillance performance and technical adequacy continued to

improve through an extensive surveillance review and inplant

validation process that continued throughout the assessment

period. Surveillance scheduling was reorganized resulting in

only one administrative 1y late TS required surveillance

occurring following the restart of Unit 1. This improvement in

surveillance management was the result of the licensee's

aggressive SI planning and scheduling program. The licensee's

scheduling performance of non-TS required surveillance and

preventive maintenance is less aggressive and appears to rely

heavily on input from upper plant management rather than first

and second line supervision.

In the vast majority of surveillcoces performed implementation

of the surveillance testing was excellent reflecting adequate

planning and assignment of priorities, and indicating an

aggressive level of management overview. However, surveillance

procedural adherence problems continued throughout the assess-

ment period, although improvement in this area was noted I

following the initial Unit 2 restart activities. Exampl'es of

procedural adherence problems were; surveillance of a Reactor

Coolant System (RCS) flow indicator resulting in a reactor trip

when the instrument was returned to service, and a power operated

relief valve (PORV) opening when an RCS resistance teniperature

device (RTD) was returned to service. Licensee resolution of

surveillance related technical issues reflected a thorough

understanding of the appropriate issues. Management was

responsive to NRC initiatives in that they established new

surveillance instructions in response to NRC information notices I

and bulletins. Personnel performing as test directors while

conducting surveillance testing activities appeared to have a

good working knowledge of the surveilltrce procedures and were

trained in the use of required instrumentation.

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A management initiative, designed to minimize the recurrence of

mispositioned valves, was to form a dedicated Operations

Department surveillance instruction performance team. Forming

such a team limited the number of people performing surveillance

instructions, increased the exposure of each team member to the

various instructions, and enhanced internal communications. The

team appeared to be effective in improving efficiency and

control. The SI team concept was a case of effective technical

resolution and management involvement that occurred during the

assessment period. ,

During the assessment period physics-related activities

associated with the restart of Units 1 and 2 demonstrated the

ability of the licensee to perform at a technical level above

that required to meet regulatory requirements. A number of

complications were experienced during startup testing, including

significant differences between the measured and predicted

critical boron concentrations on both units and a positive zero

power moderator coefficient on Unit 1. Licensee management

responded effectively to the complications which were

encountered. Management ensured that' adequate personnel

resources were allocated to properly perform the test program

and that an atmosphere existed which encouraged feedback from

the ~ersonnel invohed with the testing. This resulted in a

continuing improvement of the reactor physics testing program.

-

A significant investment was made in the training of 'inexperi-

enced personnel and in the cross training of design specialists,

which should benefit future reactor engineering activities

and result in further improvement of the program. Marked

improvement in the control of nuclear design calculations

and computer codes was observed during the assessment period.

Management involvement in assuring quality was demonstrated in

that the chemistry program was very actively supported by the

corporate chemistry staff. The staff was involved in developing

a corporate policy statement and directive which established

philosophy, directives and responsibilities for a chemistry

program which endorsed the guidelines recommended by the steam

generators owners group (SG0G) and Electric Power Research

Institute (EPRI). Management emphasized the need for quality

control in all aspects of the chemistry program to meet the

stringent criteria recommended by SG0G and EPRI for prevention

of corrosion.

Adequate resolution of technical issues was exhibited in the ,,

short term wet layup of Unit 2, the long term dry layup of

Unit 3 and the startup of Unit 2. Modifications to the moisture

separator reheaters replaced copper-nickel tubes with stainless

steel tubes, reducing the potential sour.ce of copper corrosion

prcducts to the steam generators. Replacement of all resins in

the polisher vessels prior to restart of Unit 2 was a

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contributing factor to the good water quality during restart.

Consequently, a lengthy chemistry hold was not necessary. .

However, the shortage of demineralized water limits the nunber

of polishers that can be used. The ' licensee has initiated

investigatory programs to improve the all volatile treatment

-(AVT) chemistry control program. The areas of wet and dry layup

of plant systems, and corrosion and erosion progrems were

determined to be acceptable.

Even though there were major changes in key staffing positions

in the plant water chemistry program, the defined program was

implemented with an adequate number of qualified, experienced

supervisors in accordance with licensee procedures.

As determined at the end of the assessment period, the ISI

program and procedures were acceptable and management

involvement in the ISI process was apparent. Based on a review

of ISI program submittals and program changes, TVA's responsive-

ness to NRC initiatives and staffing for ISI work was adequate.

During the assessment period the Inserv'ce Test (IST)

program and records were greatly improved and preclude the

problems identified during the basis period. Management

appeared to be involved in assuring quality in IST activities.

Responsiveness to NRC initiatives was evident. Based on

observation of in-process testing and review of IST activities,

staffing levels appeared to be adequate. IST personnel observed

and interviewed in the field conducted themselves in a

professional manner, and appeared to bc well traircd and

qualified for their responsibilities.

Seventeen violations were identified:

a. Severity Level IV violation for failure to have a procedure

for composite maintenance crews. (87-78-02)

b. Severity Level IV violation for failure to adequately l

implement surveillance involving RCS temperature,  ;

containment spray system flow, and ice condenser

operability. (88-02-01)

c. Severity Level IV violation for failure to adequately

implement work instructions involving resistance

temperature detectors, a system hold onder, and the

safety-related air system. (88-17-01)

d. Severity Level IV violation for failure to have an adequate

fire protection surveillance instruction for containment

penetration sleeves. (88-19-01)

e. Severity Level IV violation for failure to have an adequate ,

SI for fire barriers. (88-19-03) )

f. Severity Level IV violation for failure to establish and

implement plant instructions (TS interpretations) that

complied with TS 3.7.1.2. (88-20-01)

E_-----_-----_--.-_---------_----------------__----____--__ _ - - - _ - - _ _ _ - . - - _ - - - - - - - - - - - - - - - - - - - - - - - _ . - - - - - _ - - - - - - - - - - - - - - - - --_-------. _ - _

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g. l Severity. Level IV ' violation for failure to implement ~{

surveillance requirement 4.5.1.1.1.6 involving cold leg' j

accumulator boron concentration. (88-20-02). 1

h. ' Severity Level IV violation for failure to control

maintenance activities related to a steam gen:.-ator level

~

. indicator, and flow transmitter 2-FT-68-718 (88-28-01).

i. Severity Level IV violation for structural walkdown issues.

-(88-29-02)

j. Severity Level V violation for failure to control work

practices involving' the installation of beveled washers, y

spring cans and anchor bolt alignment. (88-29-03) -l

k. . Severity Level IV violation for failure to perform an.

adequate ASME section XI test. (88-29-04)

1. Severity Level IV violation for UHI system inoperable due

.to failure to perform surveillance. (88-34-02)

m. Severity Level IV violation for EDG surveillance. not

performed when one EDG was made inoperable. (88-34-03)

n. Severity Level IV violation for two examples of failure to '

follow procedures for radiation monitor work. (88-39-01)'

o. -Severity Level IV violation for failure to have an adequate

work plan. (88-39-03)

p. Severity Level IV violation for failure to follow AI-47

requirements. (88-40-01)

'

q. - Severity Level IV violation for failere to follow incore

flux detector withdrawal procedures. (88-44-02)

,. 2. Performance Rating:

Category 2

3. Recommendations:

The Board recognized that improvements in the maintenance area

were the direct result of initiatives instituted by the new

maintenance management. The Board also recognizes that an

. aggressive FM program has been developed, but is not fully -

implemented, ind that benefit to the equipment has not yet been

realized.

.

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D. Emergency Preparedness

1. Analysis

, The inspections conducted curing this assessment period ir.cluded

i two routine Emergency Preparedness (EP) inspections and a full

participation EP exercise. .

The routine EP inspection performed March 7-11, 1988, disclosed

that the licensee had revised its system for reviewing and

approving changes to the Radiological Emergency Plan and

Implementing Procedures. The inspection noted that the changes

made under the new system were being properly cpproved and

distributed in a timely manner. Emergency supplies and

equipment met regulatory requirements. Although several key

personnel changes had occurred, personnel had been properly

trained prior to integration into the emergency response

organization with one exception. The exception resulted in a

violation for failure to provide annual retraining to an

alternate Technical Support Center communicator. In the EP

area, preparedness audits were found to meet regulatory require-

ments.

The routine EP inspection performed Septernber 1-4, 1988,

discicsed that the licensee hcd declared six Notification of

Unusual Events (!!OUE) since February 4,1988. All events were

promptly classified with the exception of a " seismic alarn

received" on February 8, 1988. The licensee's failure to

promptly report this event as an NOUE was identified as a

violation for failure to adequately -implement an emergency

procedure. In addition, a second example of failure to prcmptly

declare an NOUE en high RCS leak rate wcs also identified. The

licensee was maintaining an adequate notifications and commun-

ications capability in the event of an emergency. The areas of

shift staffing and augmentation, training, and dose calculation

< and assessment were found to be adequate ~.

The emergency exercise with full participation was conducte.d on

December 14, 1988, and demonstrated that the licensee could

satisfactorily respond to an emergency at the facility. The

most significant of the negative observations was a failure of

the Shift Operating Supervisor to recognize an explosion as an

entry into the emergency classification logic. However, the

licensec adequately demonstrated the ability to classify higher

levels of emergency after entering the emergency classification

logic. The overall performance was fully satisfactory and an

adequate critique was conducted by the licensee,

i

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Three violations were identified.

a. Severity Level V violation for failure to provide annual

retraining to an alternate Technical Support Center

connunicator. (88-18-01)

b. Severity Level IV violation for failure to promptly report

an NOUE when a seismic alarm was received. (88-33-01)

c. Severity Level IV violation for late reporting of a NOUT on

high RCS leak rate. (88-34-04)

2. Performance Rating

Categury 2

3. Recommendations

None

E. Security

1. Analysis

During the assessment period three routine security inspec-

'

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tions and one special inspection resulted in the issuance of

three licensee-identified-violations relative to key control,

unescorted visitors and officers being found inattentive to

duty. The reactive inspection reviewed the licensee's invest-

igation of suspected or alleged drug cbuse and found the

licensee's investigation and resolution to be adequate

In February 1988, the licensee performed both an Operational

Readiness Review (NSB/CA 88-01) and its annual Quality Assurance

Audit (SSA-88-06) which resulted in the identification of

persistent hardware and equipment inadequacies and the continued

dependence on compensatory measures. While no Conditions

Adverse to Quality were identified, the Audit concluded that

some of the equipment was obsolete and restricted the

effectiveness of the security program. NRC has ascessed the

Safeguards Event Logs, pursuant to 10 CFR 73.71, and found that

nearly 93% of the logged security incidents are attributable tc

failed alarms, cameras, computers and coded-key card readers.

The same assessment noted a minor reduction in the number of

compensatory measures, due to the correct prioritization of work

requests and a relatively short turnaround time for repair of

security equipment. It is noted that the licensee-identified

violations for officers being found inattentive to duty have a

,

'

direct relationship to the extensive use of compensatory

measures. Much of the security equipment was poorly designed

and installed, and has over the years fallen into a state of

disrepair such that replacement parts are not always readily

available. The NRC found several examples where vendor

furnished parts needed to be extensively altered before being

!

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used in the current security system. In the interim, the

licensee implemented appropriate compensatory measures.

At the Corporate level, the licensee continued to experience

attrition at its senior security management level. During this

' assessment period the ninth manager in the last 10 years re-

-

signed. As a result of this continued turnover, numerous

assessments, evaluations and studies have been conducted with

correspondingly few corrective action programs reaching fruition.

After appointment of the most recent and current managers the

NRC can now begin to see significant progress made on several

old projects, some of which have been successfully completed.

In July 1988, the licensee finalized the reorganization of its

Corporate Nuclear Security Services Branch so that there now

exists a centralized (and accountable) management system.

Within this Branch there is a security compliance section, a

consolidated plant access and screening unit, a separate section

responsible for equipment upgrade and another section tasked

with plans and procedures. A key element of the Branch is a

Safeguards Information Network which will computerize all site

and corporate data. Another indication of improvement is the

upgrading of security training and increased tactical exercises,

Multiple Integrated Laser Engagement System (MILES) is available

to add to the realism of these drills. The licensee's canine

corp is recogniz.ed by other federal and state agencies for its

expertise in detecting contraband.

At the site level, there exists a direct management matrix from

the Site Security Managcr to the Corporate Manager of Protective

Services within the Nuclear Power Group. The Site Director and

the Plant Manager have been instrumental in c'edicating site

L support to reduce the number of security compensatory measures.

While technically there is a matrixed relationship between the

site and its security organization there is a very strong

matrixed interface.

Changu to Physical Security, Contingency, and Cuard Training

and Qualification Plans were generally well-prepared and

coordinated, with one exceptior.. The licensee withdrew one

revision to the Physical Security Plan when it was discovered to

contain a number of errors and omissions. The licensee has been

very responsive to questions and concerns raised on licensing

submittals.

The NRC has noticed an improvement in the quality of the

security staff while the size of the staff has been reduced.

This is evidenced in such key elements as training and

procedural knowledge. There now appears to be a premeditated

implementation of the security program, as opposed to a reactive

security program.

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p ,

No violations were identified:

.

! 2. Performance Rating:

l'

Category 2

3. Recommendations:

The Board recommends that the licensee review it's security

upgrade priorities at all three facilities to ensure that the

Sequoyah security program continues to reduce its long term

reliance on compensatory measures in lieu of reliable security

equipment and systems.

F. Engineering / Technical Support

1. Analysis

NRC involvement in the engineering and technical support area

was more comprehensive than normally applied to licensee

activities. This resulted from interactions between NRC OSP

and the licensee necessary to achieve acceptable engineering

resolutions as described previously in the summary section and

the technical complexity of many of the engineering issues.

The Engineering / Technical Support functional crea eccresses the

adequacy of the technical and engineering support for all plant

activities. To determine the adequacy of the suppcrt previded,

specific attention was given to assurance of quality, includir.g

management involvement and control, the identification and

approach to resolution of technical issues, respersiveness to

NRC initiatives, enforcement history, opera tior,al and

construction events, staffing, and effectiveness cf training,

, and qualification. This area includes all licensee activities

associated with design baseline evaluation irrplcr.:entation in

terms of Sequoyah plant modifications, engineering and

technical support provided for operations, maintenance,

surveillance, training, procurement, and configuration,

management. This evaluation was based on Sequoyah site

inspections conducted by the NRC staff in the above areas and on

licensee technical submittals reviewed by the staff containir.g

engineering evaluations . supporting the Sequoyah Nuclear

Performance Plan (SNPP). .

Inadequacies during the basis period were in the areas of design

analysis, modification control, engineering docume nta tion ,

design basis utilization, and design verification. In order to

correct these weaknesses, TVA senior management increased their

involvement and control during this assessment period to improve

the quality of engineering support. TVA nanagement involvement

was demonstrated through issues including; the Replacement Items

Prngram, in which TVA Corporate and Sequoyah management were

greatly involved in the program to ensure immediate and effective

corrective action; the issuance and use of procedures in the

civil / structural area, including pipe supports and restraints;

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'the drawing: control' process,.which is considered .now to be .of ~

Io ' high quality and. accuracy; and the procedures .for control: of

I thermal expansion tests. The procedures used for the thermal

expansion tests were well defined and explicit, demonstrating

evidence of prior planning with a proper assignment of

priorities.

,

In . response to ' concerns expressed by the NRC, TVA revised

Sequoyah's snubber surveillance program procedures, resulting in

a- more conservative selection.of the number of snubbers to be

tested upon occurrence of test failures.

-TVA DNE continued the control of the EQ activities as had been

established in 1986 and 1987. During thisLassessment period,

Sequoyah'transitioned from a separate dedicated EQ' organization

to a matrix organization within the site DNE organization. This

transition appeared to occur without interruption or degradation

of the quality of DriE support to the plant. Engineering

decisions were made at appropriate levels. This is'a clear

example' of TVA . DNE management involvement and control in

assuring quality.

Other issues in which DNE management oversight and involvement

was 'strongly prevalent included DNE representation during the

morning and outage planning meetings, the initiation cf a duty

. DNE manager for weekend and back shift engineering support for

'

Op.erations, and the direct management involvement in the

organization.and allocation of resources for the P,estart Test -

Program.

TVA DNE management, hoviever, has not been adequately involved to

ensure quality in all cases. S 1

provided in Generic Letter (GL) specifically,

86-10, for spuriousthe staff guidance

actuations

from high-impedance faults had not been followed by TVA.

Similar problems with 'the implementation and ' applicability of

other portions of GL 86-10 had been previously discussed with

the licensee early in the assessment period. This instance

indicated a reliance of the licensee on the NRC to establish an  ;

adequate scope and content for this generic letter with respect j

to the extent of applicability and indicated a lack of ,

!

responsiveness to this NRC initiative.

'

TVA did not follow their design commitments made to the NRC

involving criteria for pipe supports and piping analyses. These i

cases indicated a lack of management involvement in the

activities they supervise and a lack of quality verification for I

commitments made to the NRC. ,

TVA experienced problems in engineering documentation adequacy

and in the backlog of open plant change packages. For example,

TVA did not properly document changes to the Emergency Diesel

)

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Generator (EDG) 2B-B load analysis (SQN-E3-002) from Rev'ision 7,

which was used as the' basis for Unit 2 restart, to Revision 10,

in which all EDGs were analyzed. for Unit 1~ restart. Revision

10 which documented that EDG 28-B had reduced diesel generator

loading,~ 1acked complete information and required additional

supporting data to explain the leading changes. 'Furthermore,

the summary letter of EDG load analysis dated August 11, 1988.

contained three incorrect-numbers, only'_one of which was later

identified by TVA. NRC staff discussions with modification

- personnel revealed there were approximately 1300 engineering

design change workplans: remaining open, some dating back to

1980. All required physical work was completed on these work-

plans prior to plant startup, however, the workplans were

'left open!for various reasor.s. These problems indicate lack of

quality, verification for submittals made to the NRC and a lack-of

management'_invoiva ent.

The approaches taken by the site end corporate engineering-

staffs to resolve technical issues from a safety standpoint were

adequate with improvement shcwn during the assessment period.

For example, in the civil / structural area, the staff reviewed

- TVA's submittals for justifying the adequacy _of Interim (or.-

Restart) Criteria and design calculations for a. field erected

~

tank, cable tray supports, pipe supports, conduit and supports,

ERCU pipe access cells, the ERCW pump station, masonry walls,

.the steel . containment vessel, equipment supports and miscel- .

laneous civil / structural issues, and found that the engineering

records and design calculations were generally complete end

documented. However, as a result of NRC reviews, some of the

design calculations were regenerated two cr three times by TVA

before lVA was able to r'eet and implement restart requirement

design criteria which was acceptable to the NRC. The evaluation

results for' the issues' iden:1fied were' reascnable, logical and

-

net the Sequoyah restart requirements. In the area of pipe

supports, cable tray supports, pipe restraints and equipment

supports, staff review ano evaluation found that there was a

defined set of procedures for the control of engineering

activities. It was concluded that engineering records were

available, relatively easy to access and were clear. Minor

errors were found in some of the specific calculation packages

reviewed, however, the general assessment was that TVA had

improved the quality of the results of the engineering and

technical support groups.

TVA engineering personnel were found to have an understanding of  !

the issues involved when evaluating changes to the facility.

The staff audited the licensee's report required under 10 CFR

'

50.59 supporting the seismic qualification of the interim and

final designs associated with the component cooling water (CCW)

heat exchanger replacement and associated piping modifications.

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The detailed analyses provided to the staff exhibited a

comprehensive evaluation of the CCW system to justify continued

operation of Unit I while the piping modifications were being

implemented. The engineering records were extensively

documented and readily available for staff audit. The licensee

exhibited a thorough understanding of the technical analyses and

clearly explained the rationale for allowing continued operation

of Unit 1 during the CCW heat exchanger changeout.

Further examples of adequate TVA engineering reviews included

the piping thermal expansion test program which demonstrated a

sound and thorough approach to identifying potential inter-

ference to piping thermal growth as a result of implementation

of plant modifications. Also, TVA's response to the staff's

concerns regarding potential damage to the containment during

the Sequoyah extended shutdown period demonstrated a sound

approach to resolving the staff's concerns.

However, in several instances during the assessment period, TVA

actions indicated an inconsistency in the thoroughness of

technical resolutions and a lack of attention to detail.

Examples of weak technical resolutions and lack of thoroughness

included TVA's initial cable testing program, EDG voltage

analysis (SQN-E3-011, Revision 2,) and a proposed TS change

which applied to the Turbine Driven Auxiliary Feedwater Pump.

(TDAFWP). TVA demonstrated a general understanding of the

safety issues' involved, however, the engineering analysis

accompanying these issues did not reflect an indepth review of

all applicable safety aspects. The DNE effort supporting the

Sequoyah Unit 2 pressurizer safety valve steam trim / leakage

resolution was another exmple of a lack of effective DNE action

to resolve plant problems.

The staff audited the licensee's modification to correct a

deficiency in the teismic qualification of Bailey Meter elec-

trical_ instrumentation cabinets involving the use of aircraft

cable. The staff found the licensee's modification to be  ;

unacceptable. The licensee did not demonstrate an under- i

standing of the seismic qualification requirements for the l

Bailey Meter cabinets and thus its fix, using aircraft cable, j

was not sound. In addition, only after the modification using i

the aircraft cable was found to be unacceptable, did the f

licensee establish that the electrical instrumentation was not

required for safe shutdown.

'

While the level of cooperation between DNE and plant personnel

has substantially improved, the technical adequacy of the

engineering support has not been of a consistently high level.

While progress over the assessment period was evident, errors

and incomplete evaluations have continued.

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' During the assessment period, tha licensee generally responded

well to NRC initiatives. While NRC'had to. insist on cable type

-

'

testing, TVA has since been responsive in all remaining areas of H '

the cable testing program. . Other examples of TVA's responsive-

ness .were demonstrated in the ' area of procurement. In.a few -  ;

Leases (e.g. molded case circuit. breakers) Sequoyah engineering- l

staff exceeded reporting requirements to the NRC with respect to l

reporting the s_ cope of problems. ThisJ assisted the NHC in  !

providing up-to-date. guidance to other licensees..'In the area  !

> 'of fire protection,- responses to NRC requests have generally -

been timely as well;as thorough except for certain provisions of

GL 86-10. An exception was_in the area'of~ establishing welding >

inspector certification where records were not complete nor well

maintained and corrective action was not timely. Other respon- i

'

sive efforts worth noting include the timely corrective action

taken for problems identified during the pre-operational thermal j

expansion- test program. These efforts represented timely  ;

corrective action implementation for an NRC initiative which  ;

went beyond minimum NRC requirements and, with TVA's proper i

completion - of = the test program, significantly enhanced the

reliability of the Sequoyah piping systems.

During the assessment period two violations were issued in the  !

Engineering / Technical Support area. The first violation was for '

failure to take adequate corrective action and follow procedures  ;

relative to dedication of commercial grade items for use in  ;

safety-related applications. While NRC had observed improve- l

ments in TVA's procurement of purchased parts due to previous i

corrective actions, the inspection determined that Sequoyah was

still procuring commercial grade parts without adequate H

dedication of the parts for use in safety-related applications. j

The second violation documented that TVA did not have hydraulic -j

+ . and thermal design calculations for the containment spray l

system, which estcalished the design basis for the pressure ard

temperature bourcaries. Corrective actions for both of the

above violations have been implemented and were determined

edequate.

Operational and construction events which involved TVA )

engineering have been properly reported to the staff via the

Licensee Event Reporting system. Engineering support for these ,

occasions was adequate to support both proposed and implemented j

'

corrective actions.  !

l

TVA staffing levels in the engineering / technical support area,

including management, were adequate. Position identifications I

and definitions of authority and responsibility were well

established and managed during the assessment period. In the

civil / structural engineering area, the items that required

resolution by TVA engineering from the NRC's Safety System l

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Quality Evaluation, were in some instances delayed because of '

lack of available staff. However, this was noted as an

exception rather than the norm.'

9

The effectiveness of TVA's training and qualification programs

in engineering and technical support has generally been adequate

with a few exceptions. Lack of adequate training was a major

cause of a violation in the procurement area. A lack of

adequate training in administrative procedures was found to j

be a major contributing factor in ISI training and documentation j

problems and in the reluctance by the ISI group members who

performed radiography on welds to follow administrative

requirements for procedure changes. These events were

inconsistent with the observed results of training for other TVA

organizations (e.g. plant modification training, maintenance

craft training, and Shif t Technical Advisor and Operator

training). The pre-operational thermal expansion test program

engineers were noted as being well trained ano qualified for the i

performance of their required duties. In general, the training

and qualification programs contributed to an adequate under-

standing of work and general adherence to procedures. The number

of exceptions were acceptable. Management of the training and

qualification program within the ISI area was inadequate in that

adherence to administrative procedures was not enforced.

Two violations were identified:

a. Severity Lesel IV violation for failure to take adequate

corrective acticn and follow procedures relative to

dedication of commercial grade items for use in safety-

related applications. (88-07-01)

b. Severity Level IV violation for failure to hase hydraulic

and thermal design calculations for the cont 6inment spray

system. (88-29-01)

2. Performance Rating:

Category: 3 Improving

3. Recommendations:

The Board is encouraged by the initiative and efforts expendeo

by TVA to improve the quality and effectiveness of its ,

engineering suppcrt for the Sequoyah Nuclear Plant. The Board

recognizes that a significant amount of complex engineering work '

was completed. Since considerable NRC effort and input was

needed to obtain acceptable engineering resolutions, the 00ard

concluded that TVA has not yet demonstrated independent

performance at a level greater than that necessary to meet

minimum regulatory requirements. The Ecard recoiserds that

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management attention to this area continue, that those long term j

commitments made ' to assure continued improvement after the '

initial restart of both units be completed as scheduled, and

that adequate long term staffing and funding be maintained to i,

'

support completion of the long term commitments.

G. S_afety Assessment / Quality Verification

1. Analysis

The area of Safety Assessment / Quality Verification included

quality assurance and the corrective action process, safety

committees, the 10 CFR 50.59 safety evaluation program, event

reporting and root cause assessment, the employee concerns

program, licensing activities, and corporate support for quality

verification. The most significant improvement *las i~n the

corrective action program which is now functioning adequately.

Improvements were ncted in safety committee performance and root

cause assessment. Weaknesses were noted in the 10 CFR 50.59

safety evaluation program.

While both site and corporate management were involved in the CA

area and the policies were adequately stated, NRC inspections

and other NRC staff reviews and evaluations indicated that all

new policies were not fully understood by Seoucyah personnel.

Problems continued to exist during the early part of the rating

period in the corrective action process and cdequate corrective

action was occasionally not effective resulting in repetitive

CAQRs. In addition, CAQR resolutions were sometimes delayed.

Changes to the QA topical report are requirea to be submitted to

the NRC at least yearly. TVA made several extension requests

for submittal of changes indicating a slow approval process end

a reliance on the NRC to establish an adequate time frame for

submittal. * While the violations that occurred during the

assessment period have not been directly related to the QA

program, they have involved failure to follow procedures or

failure to take adequate corrective action.

Key positions in the QA department were identified and

authorities and responsibilities were well defined. The staff

expertise level was considered excellent. Trcining contributed

to an adequate understanding of the QA prcgram.

The licensee continued the implementation of the CAQR program

which was established during the basis pericd. Early in the '

assessment period CAQR reviews indicated weaknesses in opera-

bility and significance determinations, reviewer and management

training, timeliness, documentation, and auditability of re-

cores. The Sequoyah Site Deputy Director personally took charge

of the implementation of the Sequoyah CAQR program to ensure

that implementation problems would be resolved. The CAOR

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process required an encrmous amount of dedicated upper nanage-

ment effort to ensure that it contir:ued to function adequately.

.One major reason that the dedicated management attention was i

,

necessary was that a large number of issues were identified at

! Sequoyah, and at other TVA plants which had implications on

Sequoyah, that required resolution through the corrective action

program, resulting in a significant CAQR backlog. A second

reason was that time-sensitive equipment operabilty determina-

tions en engineering issues required determinations prior to the

completion of the CAQR technical evaluations resulting in the

required use of large amounts of predecisional information. The i

corrective action process was determined to be adequate to allow

the restart of both units. To this end an order, which dealt

with a management breakdown in controls fcr safety concerns

having generic implications to other TVA sites, was considered

adequately resolved for Sequoyah.

In order to reduce the amount of dedicated upper nanagement

effort necessary to make the CAQR system work, the licensee

developed a change to the CAQR process and implemented it in

September 1988, immediately prior to the restart of Unit 1. The

change provided several administrative control programs to act

ds Corrective action screening processes. Those issues that did

not meet the acceptance criteria for being a CAQR stayed in the

administrative control programs for resolution. A Quality

Verification Inspection (QVI) conducted near the end o' the

-

assessment period fcund that the changes were adequately

implemented and strongly supported by ser.ior line n;anagement.

The char.ges appeared to have the desired effcct of forcing

insignificant and less significant issues down to the proper

level for resolution, while keeping safety significant items at

the senior management level.

The QVI reviewed for quality and quality verification in the

areas of plant operations, surveillance, maintenance, corrective

actions,* modifications, and implementation of commitments made

to the NRC. The QVI concluded that site line management was

strongly dedicated to quality and was convincing workers that

quality work was what was expected. One exception to this

attitude was in the radwaste processing area as revealed by a

resin transfer event that occurred at the end of the assessment

period. This event indicated that management attention had been

lacking in the radwaste processing area and that overall site

procedure upgrades had not had an effect on upgrading quality in

this area.

The function c' the quality monitoring organization was to

assist site management in meeting quality objectives by

identifying ccr.ditions adverse to quality on a real-time basis

before they impacted on nuclear safety, reliability, or

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

_

_ _ _ _ _ -__

'-

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7

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50

,

component' operability. The quality monitoring organization was

observed to be a well qualified and adequately staffed

organization which was adequately performing its function.

The use of interfaces between groups, by the organization as a

whole, to verify and accept quality when deliverables were

trar,sferred was not emphasized as a quality verification tool.

For example, the maintenance department was using an interface

organization between the shops and QA to ensure that completed

surveillance tests represented quality work prior to their

transfer to QA for review, however some of the problems that

were being identified for correction had resulted because

procedure changes had not been adequately communicated to the

shop organization responsible for perfchaine them. An interface

problem was also identified between engineering and the plant in

relation to vendor manuals having conflicting data and resulted

from a lack of communication between the two organizations.  ;

Although interface problems between engineering and the plant

were identified by the NRC staff during the basis period, inter-

faces were-not actively used by site or corporate mar,agement for

the purpose of quality verification.

The licensee identified that the percentage of Boron-10 isotope

in the boron being added to the reactor coolant was outside of

the established procurer:ent and design specifications. Although

this and related nonconforming ccnditions were identified by

licensee personnel on at least three distinct occasiens, the

established corrective action process ecs not implemented in a

timely manner and was only initiated after the issue was raised

by the NRC. Once identified by the licensee, corrective actient

were adequate.

The licensee's 10 CFR 50.59 program was reviewed and in most

cases found to comply with minimum regulatory requirements,

however weaknesses were identified. The first weakness was

identified as a violation and related to non-conservative

translation of regulatory requirements into procedures; the

second weakness was related to the lack of qualification

requirements for the performance of screening reviews; the third

weakness was related to a lack of definition for when

interdisciplinary reviews were required, and the fourth weakness

was related to coordination of the reviews between groups.

These weaknesses indicated minimal management involvement in

assuring the quality of this function. In addition, a failure

of the 10 CFR 50.59 process was identified in relation to the

,

excessive post trip cooldown effect on shutdown margin which was

identified early in the assessment period and issued after the

end of the assessment period as a Severity 1.evel III violation.

1

'

A reorganization of the Plant Operations Review Staff (PORS),

i

which is responsible for reporting and investigating plant

'

events, occurred at the beginning of the assessment period. NRC

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

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l; ,

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.. 51

concerns about inadeouate root cause analysis for- plant events

were addressed by prcviding training for the PCRS staff. Root

cause determinations and licensee corrective actions improved

throughout the SALP period and have becore more reliable and

technically correct near the end of the period. One failure of

'

the root cause reviews was in the area of excessive post trip

cooldowns and the resulting effect on end-of-life shutdown

margin which was issued after the end of the assessment period

as a Severity Level 111 violation.

The objective for ISEG and the other safety review committees to

identify underlyinc problems before they become issues was

recognized by TVA management. The safety comnrittee reorganiza-

tions which occurred near the end of the basis perioc began to

have an effect in accomplishing that objective during the

assessment period. PORC was more aggressive and technically

involved in the resolution of issues affecting the safe

operation of the units. PORC improvements were due to

consistency in perscnnel staffing, strong leadership from the

new plant manager, and use of the Plant Operations Review Staff

(PORS) as a part-time support group for PORC. FORS employed

specialized training end skills to perform root cause

evaluations and determine corrective action plans associated

with plant events, which were then submitted a:. completed

projects te PORC. The use of the P0RS to perform investigative

data gathering and initial evaluat. ions has allowed PORC to be

'

more deeply involved in day-to-day plant eversight. The NSRB

has continued to chcw a low profile with respect to crisite

ectivities functioning principally in the areas of LER

evaluation, TS change approval and cther area:: that allow fcr

offsite review. The ISEG was reorganized as a result of a

TS change and became more aware of industry issues, showed a

greater presence in the plant, and by the end of the assessment

period, was becoming an effective auditor of piant activities.

Near the end of the period, ISEG and the other safety committees

were working together better in understanding what each of their

roles should be in accomplishing the overall objective. j

l

A broad spectrum of safety issues was identified by TVA

employees in the ECTG program which reflected a previous lack of

management involvement with quality. The NRC staff review of

the Sequoyah ECTG investigations, corrective actions, and

planned programmatic improvements concluded that the evaluations

were generally adequate and well documented. I

i

I

The Employee Concerns Program (ECP) continued to be implemented

in an impressive and professional rcnner. Several audits cf ECP

open files ar.c' concerns were completed with no significant 1

l

findings or wealnesses. Restart determinations performed on

open files and concerns were accurate and conservative.

Followup on issues which were both NRC issues and ECP issues

]

_ _ _ _ _ . _

_ _ _ _ _ _ _

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f .

. 52

,

resulted in parallel, conservative conclusions. The ECP

encouraged the return of issues to line managenent for

resolution ar.d in dolng so, has strengthened line inanagement

responsiveness to issues identified by non-canagement employees.

There was a tremendous amount of activity in the licensing area.

Supplemental information regarding licensing ectivity is

provided in Section F, under Supporting Data and Summmaries.

Generally, the large majority of the work done by TVA on

licensing issues was good and showed evidence cf prior plenning

by management. Hcwever, TVA had a tendency to be optimistic in

i

establishing submittal dates which has resulted in frequent

requests for extensions. Ir. addition, two examples, TSCR 87-47,

'

Control Poom Emerger.cy Ventilation System, and ISCR CC-21, River

Water Level and Temperature, were noted where TVA knew that a TS

l

change would be needed and the submittals were not made on a

timely basis,

i

Submittals by TVA generally shcwed an understanding of the

technical issues beinD discussed. The approach to the technical

'

l

issues exhibited conservatism and were viable, thorough, and

j generally sound as demonstrated in their quick response to a

l

primary to secondary leak that developed in a Unit 2 steam

generator during start-up, in their response to hCC Eulletin

88-02, " Rapidly Propagating Tatigue Cracks in Steam Gercrator

Tubes", and in their sube dttals requesting relie' from ASNE code

Section XI, inservice Inspection and Operating Plant Cece. In

additicn, TWs proposal tc revise ira;trument accuracy

calculations for the PCP undervoitage reactor protection channel

in TSCR 87-18, RCP uncervoltege reactcr trip, could Le censidertd

illustrative of a rigorous evaluation cf technical problems and

a timely update consistent with ir.dustry practice. This,

however, was t.ot true for TSCR 88-T0, Upper lieed Injectinn

Accumulator Level Switch Setpoint which was submitted without

TVA understanding thet its application dia net meet 10 Cfh

50.46(a)(1) and therefore required an exarption.

Conservatism in the licensee's alternate approach tc problems

was generally exhibited and decisicn making was usually at a

level that ensured adequete managerent review. The technical

reviews occasicnbily were lecting in detail and/cr technical

basis. Licensee statements at meetings were not always well

thought cut prior to presentation to the NRC indicating that

communication between licensee organizations was not always

clear.

TVA was generally responsive to NRC initiatives. NRC

expectations regarding the issue of Ste6m Binding of Acxiliary

Feedwater (AFW) pumps were met in the area of technical accuracy

and were exceeded in the area of scheduling. The overall

_ -

__ _ __. _ _

_ _ . _ _ _ _ _

, ._ __ __ _ _ _ ___

,

,: '

.

,'

t

Y s. S3

staffing to support operating activities was adequate with the

>y. licensing engineer-being well qualified and adequately trained.

- The site licensing organization has been successful in improving- 1

h . the timeliness and quality of responses to NRC violations.

'

TVA Nuclear Power cor) orate management was usually involved in

Sequoyah site activit'es in an effective manner. The corporate

level was reorganized on-~ July 1,1988, as part of a general

reorganization of TVA itself, and resulted in a reduction in the

number of levels of management between the Senior Vice President-

Nuclear Power, who is manager of the TVA nuclear power program,

and the site. Also, the manager of the TVA nuclear power

program, who was a contract employee, was replaced by a perma-

nent TVA employee. The emphasis of TVA's nuclear power program

has switched.to operating the Sequoyah units within constrained

TVA budgets, compared to past budgets, and reduction-in-force

within TVA's nuclear power program including the site. The

effects of the new emphasis is ur.certain, however, the NRC has

noted that TVA was reassessing the' dates and scope for commit-

ments.

Corporate support for site activities was observed in the areas

of Operations, Quality Assurance, and outage inanagement. The

support in these areas was limited to activities and managers

necessary . to support the restart of Units 1 and 2 and the

refueling of Unit 2. The support was not global in nature and

. consisted mainly of loaned corporate managers and specialists

that met specified needs. Activities appeared to be well

supported by corpor~ ate management and the mai. agers supplied by

corporate management were professional and well suited to the

assigned tasks. A site Radiological Assessor position has been

established. The position reports to the Manager of

Radiological Control, a corporate position rather than to the

Site Director. The position provides a programmatic cverview of

the- Sequoyah radiological control program and an independent

reporting path offsite. The Site / Corporate interface was

adequate and programmatic overview of the site was occurring.

For the assessment period, ccrporate mt.negement continued to be

generally responsive to NRC initiatives. The responses to NRC

were generally timely, sound and thorough. /ilthough Unit I was

restarted in November 1988, the restart date was only three

months later than originally scheduled by TVA, as compared to

(. two years later for Unit 2, which showed evidence of improved

L planning and assignment of priorities.

.The significant exceptions to TVA's general responsiveness to

NRC initiatives and timely submittals in the rating period were

the resolution of the silicone rubber insulated cable testing

issue and the tardiness of TVA in submitting Revision E of the

Corporate Nuclear Performance Plan to reflect the July 1,1988

reorganization.

.

I _ _ _ _ _ _ _ _ _ . _ _ _ . _ _ _ . . . . , _ . . _,

- _ _ - _ _ _ _ _ _ _

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9 P

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54

Seven violations were identified:

a. Severity Level IV violation for failure to follow

procedures for authorization to exceed plant overtime

limits.(327,328/87-70-01)

b. Severity Level IV violation for failure to follow

procedures for installation and inspection of seal table

bolts. (327, 328/88-09-01)

c. Severity Level IV violation for failure to take prompt

corrective action for deficiencies in QA record storage.

(327,328/88-09-02)

d. Severity Leve'l IV violation for failure to properly l

translate 10 CFR 50.59 requirements into instructions or

procedures. (327,328/88-43-01)

e.. Severity Level IV violation for failure to take adequate

corrective action for prevention of reactivity changes

while both trains of control room ventilation are

inoperable. (88-27-01)

!

Severity Level IV violation for failure to. take adequate

'

f.

corrective action to preclude repetition of violation

87-S0-01 involving lack of control over plant evolutions, ,

and system and equipment status in the radioactive weste -

area. (88-50-01)

g. Severity Level IV violation for three examples of failure

to promptly identify and initiate adequate corrective

action for Boron-10 procurement problems. (88-60-01) l

2. Performance Rating

' Category: 2

3. Recommendations

None j

V. SUPPORTING DATA AND SUMMARIES

l

A. Investigation Review

The NRC's Office of Investigations closed fourteen cases which dealt

with TVA during the assessrrent period. None of these involved

enforcement action pertaining to Sequcyah.

l

1

-_ _ __ . _ - _ _ _ _ _ _ _ _ _ _

!. . 1

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l .

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L

. 55

! B.. Escalated Enforcement Action

1. Civil Penalties

4

Severity Level III violation issued on July 3,1988, concerning

failure to ccmply with TS when both centrifugal charging pumps

were inoperable and failure to report this condition pursuant to

10 CFR 50.72. ($50,000 CP)

,.

2. Discretionary Enforcement for Shutdown Plants

Failure to meet the 10 CFP 50.59 requirements for a 1984

auxiliary feedwater pump modification. No Notice of Violation

or Civil Penalty was issued as discussed in a letter dated

May 9, 1988.

C. Licensee Conferences Held During Appraisal Period

During the appraisal period, meetings were held with the licensee to

discuss various issues, as follows:

1. Management Meetings

Date Purpose

February 11, 1988 Meeting to discuss load sequencing of

plant diesel generators.

March 09, 1988 Meeting to discuss technical issues related

to 10 CFR 50 Appendix R.

April 14, 1988 Meeting to discuss differences between

Sequoyah, Units 1 and 2 in the Sequoyah

Nuclear Performance Plcn.

April 29, 1988 Meeting to discuss (1) the Unit 2 steam

generator tube leakage and (2) loop seals '

.

for the pressurizer safety valves.

June 13, 1988 l'eeting to discuss the restart of Unit 2 in

light of the five scrams from power in

May 1988.

June 22, 1988 Meeting to discuss the TVA commitments for

Unit ?.

July 21, 1988 Meeting to discuss Phase II of the Design

Baseline and Verification Program fcr

Sequoyah.

September 8, 1988 Meeting to discuss changes to the TVA

Conditions Adverse to Quality Program at

-

Sequoyah.

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

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'

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4

56

September 13, 1988 Meeting to discuss TVA's preparation for

Unit I restart and the post-trip cooldown

shutdown margin issue.

September 15, 1988 Meeting on TVA's Microbiological 1y

Induced Corrosion Program at Sequoyah.

October 24, 1988 Meeting on the status of TVA's commitments

to NRC on Sequoyah.

November 28, 1988 Meeting on the Essential Raw Cooling Water

'.

pumphouse formulation and roadway access

cells.

2. Enforcement Conferences

March 17, 1988 Enforcement Conference at Sequoyah

concerning centrifugal charging pump

operability which resulted in EA 88-86.

(IR 88-20)

July 28, 1988 Enforcement Conference at Sequoyah

concerning upper head injection system

operability. Issued as Severity Level IV.

(IR88-34)

December 19, 1988 Enforcement Conference at NRC Headquarters

concerning the affect of excessive cooldewns

following reactor trips on end-of-life

shutdown margin which resulted in EA 88-307.

(IR 88-35 & 88-55)

D. Confirmation of Action Letters

1. April 26, 1988 Reinstatement of Hold Points for

Unit 2 Restart from Steam Generator

Outage

2. June 16, 1988 Confirmation of Release from Unit 2

Hold Points

3. November 7, 1988 Reinstatement of Unit 1 Mode 2 Hold

Point

a

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

_ _ _ _ _

'

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, . 57

E. Review of Licensee Event Reports

During the assessment period, there were a total of 78 LERs analyzed

for Units 1 & 2. The distribution of these reports by causes, as

determined by the hRC staff was as follows:

LER CAUSES UNIT 1 UNIT 2

Component failure ................. 2 6

Design ............................ 2 1

Construction / Installation /.......... 1 3

Fabrication

Inadequate Procedure............... 11 3

Test Calibration.................... 7 3

0ther............................... 7 3

Personnel

- operati ng acti vity. . . . . . . . . . . . . . . . 5 6

- maintenance activity.............. 2 4

- test / calibration.................. 2 6

- other............................. 3 1

Total 42 36

F. Licensing Activities

The assessment of licensing activities was based, in part, upon

licensing actions successfully completed duri,ng this period. These

- include the following:

1. Discretionary Enforcement /ilaiver of Compliance

January 30, 1989 Emergency Diesel Generator Surveillance

Testing

2. Reliefs Granted

February 8,1988 American Society of flechanical

Engineers (ASME) Code Case N-411

May 11, 1988 ASME Code Section XI Relief for the

Microbiologically Induced Corrosion

(MIC) Program

August 18, 1988 Hydrogen Analyzer Sampling Valves,

ASf1E Code.Section XI Relief

September 15, 1988 ERCW Valves on CSS Heat Exchangers,

ASME Code Section XI Relief

September 15, 1988 Generic Relief on Use of Ultrasonic

Monitoring of Pump Flow

November 4, 1988 Temporary Deviation from Appendix R to

to 10 CFR 50, Section III.G.

. .

_ _ _ - _ _ _ _

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.

_

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- 58

3. Exemptions

July 14,_1988 Schedular Exemption to Appendix J,

Type B and C Testing

September 22, 1988 Exemption to Appendix J. Type C

-Testing for C/RHR Spray System Check

Valves

October 26, 1988 Temporary Exemption to Appendix K ECCS

Calculations to May 31, 1989

January 26, 1989 Exemption to 10 CFR 50.46(a)(1),

Approved ECCS Analysis for Operating-

Cycle 4

4. Orders

March 31, 1988 Modification of Order 85-49 stating

that Sequoyah had satisfied the

requirements of the Order.

5. Emergency or Exioent Technical Specification (TS) Amendments,

June 30, 1988 Exigent TS /cendment on Ct rporate -

-

Reorganization

January 3'0, 1989 Emergency TS Amendment on Diesel

Generator Surveillance Testing

6. Malti-Plant Actions (MPA) Resolved

Date MPA Description

fiarch:21, 1988 F-05, Procedures Generation Package

May 5, 1988 A-21, Pressurized Thermal Shock

May 18, 1988 B-60, Environmental Qualification

for Unit 2

July 20, 1988 B-98,Bulletin 85-01, Steam Binding of

AFW Pumps

September 9, 1988 B-101, Boric Acid Corrosion of Carbon

• Steel RCS Components

November 28, 1988 B-81, GL 83-28, Items 4.2.1/4.2.2

February 3, 1989 B-60, Environmental Qualification for

Unit 1 _

.

' - _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _

. _ _ _ _ _ _ - . ._ ______

'

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,

l

59

7. Significant Plant-Specific Issues Resolved

Date Description

February 23, 1988 Sequoyah Pipe Support Criteria

February 23, 1988 Unit 2 Extended Heatup Prior to Restart

March 11, 1988 Unit 2 Restart Employee Concern Element

Reports

March 14, 1988 Revised Sequoyah IST Program

March 21, 1988 Hydrogen Analyzer Operability

May 18, 1988 NUREG-1232, Volume 2, Review of

Sequoyah Nuclear Performance Plan for

Unit 2 Restart

May 25, 1988 Silicone Rubber Insulated Cable Inside

Containment

June 23, 1988 Bulletin 86-02, Static-0-Ring Switches

Jul.y 6, 1988 GL 87-06, Periodic Verification of PIV

Leak Tight Integrity

August 3, 1988 10 CFR 2.206 Petition on Emergercy

Diesel Generators

September 22, 1988 JC0 for Operation with C/RHR Spray

_

System Check Valves without

Appendix J, Type C Testing

November 4, 1988 Unit 1 Restart and Both Units

Non-Restart Employee Concern Element

Reports

December 5, 1988 GL 87-12, Loss of RHR with RCS

Partially Filled

February 3,1989 NUREG-1232, Volume 2, Supplement i

Review of Sequovah Nuclear

Performance P' for Unit 1 Restart

.

.

d

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

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G. Enforcement Activity ,

l

All violations for the appraisal period were cited against Unit 1 I

and Unit 2.

NO. OF DEVIATIONS & VIOLATIONS IN SEVERITY LEVEL

FUNCTIONAL

AREA DEV V IV III II I

PLANT OPERATIONS 1 4 1

RADIOLOGICAL CONTROLS 2

MAINTENANCE / 1 16

SURYLILLANCE

EMERGENCY PREPAREDNESS 1 2

SECURITY

ENGINEERING / TECHNICAL 2

SUPPORT

SAFETY ASSESSMENT / 7

QUALITY VERIFICATION

TOTAL 1 2 33 1

H. Reactor Trips

A total of seven automatic reactor trips occurred during the

assessment pericd, five above 15% power and two below 15% power. ~

No

manual trips were initiated and no trips occurred with the unit

subcritical. In general, these reactor trips occurred during power

esca11ation activities ano were followed by extended periods cf

continued operation. The trips are described in more detail below:

May 19,1988 - Unit 2 tripped from 73% pcwer due to a steam / feed

flow mismatch coincident with low steam generator level. This

situation occurred due to maintenance being performed concur-

rently on two p'ieces of equipment which together could cause a

reactor trip (one channel of steam generator level indication to

replace an unqualified splice and the #3 heater drain tank level

controller which resulted in plant oscillations).

May 23,1988 - Unit 2 tripped from 70% power due to low flow on

RCS Loop #4. This situation occurred due to a personnel error

while performing a surveillance on the Icop #4 flow transmit-

ters.

June 6,1988 - Unit 2 tripped from 98% power on steam / feed flow

mismatch coincident with low level in li4 steam generator. The

trip occurred while performing a surveillcrce on the feedwater

regulating valves and resulted because a diode was missing in

the block circuit.

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

<

'

, *:

e

• 64

June 8, 1988 - Unit 2 tripped from 12% power on low-low level in

1. 2 steam generator due to an operator error when placing the

feed pump controller in the automatic position resulting in

steam generator level oscillations.

June 9, 1988 - Unit 2 tripped from 20% power on low-low level in

1. 2 steam generator due to feedwater heater isolations which

caused feed flow and steam generator level transients.

November 18,1988 - Unit 1 tripped from 72% power due to an

electrical ground in the main generator which tripped the main

turbine.

December 26,1988 - Unit 1 tripped from 75 power on low-low

level in #4 steam generator. The trip was caused by a series of

events that started with a manual trip of the main turbine due

to generator seal rubbing. After the turbine trip, steam

generator level was controlled using manual feedwater control

which resulted in a feedwater isolation from high-high level in

1. 2 steam generator followed by the reactor trip on low-low *

level

in #4 steam generator.

I. Effluent Release Summary

1985 19.86 1987

Gases (Curies) (Curies) (Curies)

Fission and Activation

Gases 4.57 E+03 1.21 E-00 0.0

Halogens and

Particulate 6.63 E-03 1.56 E-03 5.04 E-04

Liquids

Fission and Activation

Products 2.08 E 00 1.65 E-01 4.66 E-01

Tritium 6.33 E+02 1.72 E+02 1.19 E+02

J. Acronyms

ALARA - As-Low-As-Reasonably-Achievable

ASME - American Society of Mechanical Engineers

ANSI -

American National Standard Institute

ANI -

American Nuclear Insurer *

AVO -

Assistant Unit Operator

AVT -

All Volatile Treatment

CAQR - Condition Adverse to Quality

CCW -

, Component Cooling Water

.

, _ _ . _ . _ _ _ _ _

_ _ _ _ .

, .

-..

.

.

!p .

c 65-

'

CEG - Contract [ngineeringGroup.

'

' NPP.- -

Nuclear Performance Plan

'DBVP - Design Easeline Verification Program

DNE. - Division of Nuclear Engineering

EA - Escalated Enforcement Action

Emergency Core Cooling-System

~

ECCS -

ECP -

' Employee Concerns Program

.ECTG - Employee-Concerns Task Group

EDG - Emergency Diesel Generator

E0P - Emergency Operating Procedures

EP -

Emergency Preparedness

L EPRI. -

Electric Power Research Institute

EQ -

Environmental Qualification

ERCW - ' Essential Raw Cooling Water

, FT -

Flow Transmitter

GET. - General Employee Training

GL - Generic Letter

HP - Health Physics

IDI - Integrated Design Inspection

INP0 - Institute for Nuclear Power Operations

IR- - Inspection Report..

ISEG - Independent Safety Engineering Group

ISI. - Inservice Inspection

IST - ' Inservice Testing

LC0 - Liraiting Cordition'for Operation

.LER

- Licensee Event Report

'MIC - Microbiologically Incuced Corrosien

MILES -

Multiple Integrated Laser Engagen.ent System

MOVAT - Motor Operated Valve Actuators

MSIV -

Main Steam Isolation Valve

NMRG - Nuclear Maintenance Review Group

NOUE -

Notice of Unusual Event

NRC - Nuclear Regulatory Commissior..

.NRR - Nuclear Reactor Regulation

NSRB - Nuclear Safety Review Board

OPDT - Over Power Delta Temperature

OSP - Office of Special Projects

OTDT - Over Temperature Delta Temperature

PM -

Preventive Maintenance

PMT - Post Modification Testing

PORC - Plant Operations Review Ccmaittee

PWR - Pressurized Water Reactor

QA - Quality Assurance

QMDS - Q6alified Maintenance Document System

QVI - Ouality Verification Inspection

RII -

Region II

RCA -

Radiation Centrolled Area

RCS - Reactor Coolant System

RHR -

Residual Heat Removal

RIP - Replacement Items Program

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

( ,. . _ _ - _ _ _ _ _ _ _ _ . _ _ _ - . - _ . _______ _

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66;

,

RTD- -- Resistance Temperature Device

SALP.: - Systematic Assessment of Licensee Performance

SG0G- - Steam Generators Owners Group

SI' -- Surveillance Instruction

. SNPP - Sequoyah Nuclear Performance Plan

. 501 .

System Operating Instruction-

' TACFs

.

-

' Temporary Alterations

' TDAFW- - Turbine Driven Auxiliary Feedwater Pump

TS . Technical Specifications

TSCR - Technical Specification Change Request

TVA' - Tennessee Valley Authority

TVAPD - 'TVA Projects Division (NRC)

UHI - Upper Head Injection

VCT- - Volume' Control Tank

.

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