IR 05000327/1981007

IE Insp Rept 50-327/81-07 on 810211-19.Noncompliance Noted: Containment Spray from RHR Sys Actuated,Rhr Spray Valve Misaligned & Personnel Authority Not Clearly Delineated

ML20009G647
Person / Time
Site:	Sequoyah
Issue date:	05/22/1981
From:	Butler S, Crlenjak R, Dance H, Lenahan J, Quick D, Whitener H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20009G635	List: IR 05000327/1981007 ML20009G634 ML20009G638
References
50-327-81-07, 50-327-81-7, NUDOCS 8108040511
Download: ML20009G647 (31)

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.I U. S. l\\ uclear Regulatory Commission lg

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CONTAliiMEi1T SPRAY EVEi1T i

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0F FEBRUARY ll, 1981 1 -

TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT NRC LICENSE JJ0. DPR-77. DOCKET NUMBER 50-327

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FEBRUARi 11-19, 1981 1]l REPORT NO. 327/31-07

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ABSTRACT This special report contains the resulcs of an int;e;tior, into the circumstances surrounding the inadvertent containment spray event which occurred at the Seouoyah Nuclear Plant, a.it No.

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cn February 11, 1981.

The inspection included a technical evaluation of tv.e event and an evaluation of the coerational management controls in effect at the time of the event. The techrical evaluation concluced that the event did not have a significant effect on tb health and safety of either, the public or plant personnel; however, issues e c identified with respect to control board board annunciator design and Residual Heat Removal System injection capability while in Mode a operation.

The evaluation of

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o,.:tational management controls identified several issues in the areas of l

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non-licensed operator training; communication requirements; procedural adherence; and management interaction with operation personnel.

TVA has implemented I

corrective actions on these issues to the satisfaction of NRC.

The generic aspects of these issues are presently under review.

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l TABLE OF CONTENTS Section Title Pace Abstract i

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1.0 Introduc'ian l

1.2 Purpose and Scope of Inspection 1.2 NRC Inspection Personnel 1.3 Licensee Persvnnel Contacted 2.0 Summary of Findings 2.1 Violations of Legal Requirements 2.2 Unresolved Issues 2.,

NRC Followup Issues 3.0 Historical Plant Description and Ev aluation 3.1 Plant Description a.2 Systematic Assessment of Licensee Performance

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4.0 Description of Containment Spray Event (

4.1 Event Summary l

4.2 Initial Plant Conditions

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4.3 Sequence of Events 4.4 Plant Recovery 1.5 NRC 9esponse to Event 5.0 Evaluation of Containment Spray Event 5.1 Sequence of Events Technical Evaluation 5.2 Operational Aspects Evaluation 6.0 Summary of Conclusions and Recommendations 6.1 Issues Requiring Evaulation and Resolution As Appropriate

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6,2 Current Status of Operational Readiness (

7.0 Exit Interview

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1.0 Introduction 1..

urcose and Scope of Inspection

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I This special inspection was conducted on February 11-19, 1981, by an NRC inspectico team from Region II, Office of Inspection and Enforce-ment. This inspection was conducted for the following purposes:

1.1.1 Establish a factual reccuntino of the significant events surrounding the Sequoyah Unit 1 incident of February 11; and 1.1.2 Evaluate the performance of the licensee with respect to this

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event to develop a casit for corrective or enforcement action as appropriate.

The inscection involved 283 inscector-hours on site, by a team of sevaa inspectors.

The inspectors concentrated on the areas of operator training, commun! cations, management controls, operator response, use of procedures, system design, and control board design.

Although concerns were identified in all seven areas inspected, no violations of NRC requirements or deviations from standard nuclear practice were identified in four areas; communications, operator I

response, system design, and control board design. Three violations of NRC requirements were identifiec in the following three areas;

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1.1.3 Failure to folicw procedures - see paragraph 5.2.5; 1.1.4 Fa iure to properly train non-licensed operators, see paragraph 5.2.3; and 1.1.5 Failure to adequately implement administrative procedures to ensure proper plant control - see paragraph '.2.4.

1.2 NRC Inspection Personnel Inspection Insoector Dates H. Dance, Se. tion Chief, RRPI 2/12-13/81 H. Whitener, Reactor I1spector 2/12-13/81 J. Lenahan, Reactor Inspector 2/12-13/81 R. Crlenjak, Reactor Inspector 2/13-19/81 S. Butler, Resident Inspector 2/11-19/81 I

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P. Harmon, Instructor, 2/18-19/81

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IE Training

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D. Quick, ection Chief, RRPI 2/18-19/81 1.3 Licensee Personnel Contacted

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Tennessee Valley Authority L. M. Mills, Manager, Nuclear Regulation and Safety A. W. Crevasse, Manager, QA J. M. Ballentine, Plant Superintendent W. T. Cottle, Assistant Plant Superintendent J. M. McGriff, Assistant Plant Manager M. R. Harding, Engineer I

D. L. McCloud, QA Supervisor M. A. McBurnett, Engineer J. Johnson, Training Franch

H. A. Arnold, Training Branch r

W. J. Glassen, QA Coordinator

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D. W. Kelley, QCRU Supervi sor

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l I. N. McLeod, Ir f ormatica Other licensee employees contacted included seven Auxiliary Unit

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Operators, five Unit Operators. ;nd five Shif t Engineers.

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All persons listed attended one of the two Exit Intervie is held at the Sequoyah site on February 13 and 19,1981.

2.0 Summary of Findings 2.1 Violations of Regulatory Requirements I

2.1.1 Adequate training was not provided to Auxiliary Unit Operators on duty in the Sequoyah Unit 1 Plar.t as requireo by Technical Specification 6.4.1.

Inadequate specific plant on-the-job training contributed to the inadvertent opening of the Residual Heat Removal System I

(RHR) containment spray valve (FCV-72-40), which initiated the event (327/81-07-01)* - see paragraph 5.2.3.

This item has been referred to NRC Headquarters for generic evaluation of the adequacy of training for non licensed personnel.

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• These identification numbers are included for NRC tracking purposes.

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I 2.1.2 Proper implemertation of the Residual Heat Removal (RHR)

System operating procedure was not accomplished as required by Technical Specification 6.8.1.a.

The RHR system operating procedure alignment checklist was not utilized by the Auxiliary Unit Operator while I

realigning the system for shutdown cooling and RHR letdown following surveillance test'ng.

This con-tributed to the initiation of the opr " event (327/81-07-02) - see paragraph 5.2.5.

2.1.3 Adequate administrative procedures which delineated authorities and responsibilities of operations personnel involved in safety-related activities was not accomplished as required by Technical Specification 6.8.1.a.

I Existing administrative procedures failed to describe the authorities, and responsibilities of the Auxiliary Unit Operators as related to the watch stations they are responsible for. These procedures also failed to adequately I

describe the standard communication policies to be followed

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oersonnel involved in safety-related activities.

<!,1-07-03) - see paragraph 5.2.4.

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2.2 Unresolved Issue, Unresolved issues are Matter:. obout which more information is required for the NRC to determine whe * 9er they are acceptable.

These issues could develop into items cf noncompliance with NRC requirements or deviations from nuclear industry practices.

2.2.1 Communicatier. emong the operating staff was identified as being a weak area. Adequate pen ?dures were not provided or implemented to control the mitnt u and formats by which ocerations personnel are kept :nformed and inform others of plant status changes. There was no acceptable method in use to assure that orders were properly understood and carried out (327/81-07-04) - see paragraph 5.2.1.

This item has been referred *e NRC Headauarters for generic evaluation of the need for revised communication controls.

2.2.2 plant communications equipment maintenance was identified as a problem area in that, the two telechones lonted closest to the location of the RHR scray valve were inoperable at the time of the event (327/81-07-05) - see paragraph 5.2.2.

2.2.3 P rsonnel access control for the main control room was not being implemented in that; the inspection team observed an excessive number of personnel (greater than t.enty) in the

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control room on two separate occasions during the inspection.

This situation contributed to a high noise level in the control room on both occasions (327/81-07-06) - see paragraph 5.2.6.

2.2.4 Management interaction with operations personnel for the purpose of scheduling personnel and maintenance was identified as weak, for the following reasons:

2.2.4.5 Auxiliary Unit Operators were inappropriately I

scheduled for watch stations on which they had not been adequately trained i.nd; 2.2.4.6 Maintenance has been performed on occasion by the outage group without proper coordination with

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operations cersonnel (327/81-07-07) - see paragraph 5.2.7.

2.2.5 The practice of manually seating safety related motor-operated valves was identified as being questionable.

Specifically, improper torquing may cause valves to become inoperable when called upon to operate automatically or could cause excessive leakage (327/81-07-08) - see paragraph 5.1.1.

This item has been referred to NRC Headquarters for generic evaluation of the implications of this manual seating practice.

2.3 NRC Followup Issues

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NRC Followup Issues are matters that are not specifically in violation I

of NRC requirements; however, they are issues which could, upon further evaluation, be significant or should be resolved to enhance the safety of operation of a nuclear facility.

2.3.1 Containment building lighting was inadecuate for safe personnel evacuation during the event since mosc Ifght bulbs in the containment burst when tney were sprayed with water (327/81-07-09) - see paragraph 5.2.11.

2.3.2 Seating of the RHR system suction check valve from the I

Refueling Water Storage Tank (RWST) was identified as a potential problem in that, reduced flow from the RWST was experienced during ths event due to RCS pressure exceeding tne head pressure of the RWST, causing the check valve to remain at least partially seated.

This item has been referred to NRC Headquarters for evaluation because cegraded injection flow coulc result under certain operating conditions. (327/81-07-10) - see paragraph 5. ~

2.3.3 The lack of an audible and visual reflash alarm capability for indication of the mispositioning of key sa f ety-rel ated valves contributed to the length of time that the open spray valve went unnoticed by operations personnel.

This problem I

could be significant in both the operational and shutdown modes. This item has been ref erred to NRC Headquarters for generic evaluation of the human engineering aspects of I

this design (327/81-07-11) - see paragraph 5.1.2.

2.3.4 Evaluation of Plant Couputer printout information appeared to be a weak area in that, the ocerations personnel interviewed had difficulty interpreting the information available to them on the alarm printout (327/81-07-12) - see paragraph 5.2.1.

3.0 Historical Plant Description and Evaluation 3.1 Plant Description The Sequoyah Nuclear P' ant is a dual unit site located on the west shore of Chickamauga LaAe, approximately 9.5 miles northeast of Chattanooga, TN. The Nuclear Steam Sucply System was designed by The Westinghouse Corporation. The balance of the plant was designed cy the Tennessee Valley Authority.

The entire plant was constructed and is being operated by the Tennessee Valley Authority. Basic plant layout consists of reactor buildings for each unit and common auxiliary, control, and turbine buildings.

The Nuclear Steam Supply System is a Westinghouse four loop pressurized water system with "U" tube steam generators.

Each unit is supplied with Upoer Head Injection for additional emercency core cooling capa-city.

Reactor containment buildings are of the ice condenser design

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l which consists of a free standing steel containment vessel surrounded l

by a concrete shield building. The steel containment vessel is diviced into three major areas; upper volume, lower vr. i ume and the ice

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' condenser.

All high energy fluid systems are located in the lower ccrtainment volume.

The upper volume contains ruueling equipment, E

compartment cooling fans, hydrogen recombir.ers, anc containment cprav

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headers.

The ice condense * is located between the upper and lower volumes such that steam released by a high energy line break would be l E forced through the ice to remove heat energy and to limit containment i E pressure increase.

The steam and water vaper woule then enter the upper volume and eventually be returned to the lower volume by the containment air return fans to repeat the cycle.

After all ice has

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melted, the containment ? pray system would operate in the upper volume to remove heat anercy ud prevent containment prassure increase beyond acceptable values.

Sequoyah's nuclear units are each designed to procuce an output of 3411 megawatts thermal and 1183 megawatts

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I Sequoyah Unit 1 was licensed for fuel load and low power (5%) testing on February 29, 1980.

Initial criticality was achieved on July 5, 1980, and zero power and low power natural circulation testing was completed on July 19, 1980. A full power license for Unit 1 was issued on Septemcer 17, 1980.

Power ascension testing began and was hampered by problems causing shutdowns and delays. Many of these problems were I

on the secondary plant side.

Sequoyah Unit I reached 30% power on October 31, 19R0; 50% power or November 17, 1980; 75% pcwer un December 5, 1980; and 100% power on January 11, 1981. Power ascension tests required by the NRC that remain to be completed as of the end of this inspection include: load swing and load rejection tests from 100%

power; generator trip and turbine trips from 100% power; and the Nuclear Steam Supply System acceptance test.

At the time of this inadvertent containmcnt spray event, the unit had been in cold shutdown (Mode 5), for six days while routine maintenance was being accomplished.

Core history at the time of the incident was 40.14 Effective Full Power Days and a burnup of 1545 megawatt days per metric ten of uranium.

An earlier containment spray event occurred on February 2,1980, before licensing, which resulted in 16,000 gallons of borated water being sprayed into t%e containment from the refueling water storage tank.

The M89. event occurred during performance of a periodic test on the Conti S w.t Spray System which extended over two consecutive days. The generai cause appears to be somewhat cimilar to the 1981 spray event in that, it resulted from a combination of inadequate procedures and a relatively inexperienced technician performing the test. However, the Reactor Coolant System (RCS), inventory was not affected by the 1980 event since the Containment Spray System involved does not interface l

with the RCS.

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3.2 Systematic Assessment of ticensee Performance Systematic Assessmen'; of Licensee Performance (SALP) evaluations for each site are performed as prereq,isites to the NRC identifying the general I

performance level of each utility with an NRC license. The assessment for i

Sequoyah Unit No. I was presented to TVA on October 23, 1980, and is summarized in this report as background information.

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Sequoyah Unit 1 Evaluation 3.2.1.1 Nonccmpliance Summary l

During most of this audit period, the plant w's finishing the last phases of i s praoperational vis ing t

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program and awaiting the end of the licensing pause lg following the Three Mile Island accident. The total

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I noncompliance points accrued by Sequoyrh since licensing (four months) are equal to the regional average for a yearly period.

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3.2.1.2 Licensee Event Report Summary Some events resulted from confusion due to plant staff I

inexperience with Technical Specification requirements and reporting requirements. The reporting accuracy was seen to improve toward the end of the audit period.

I Recent LER's, ( Aoril, 1980 through August, 1980),

indicated adverse trends in completeness of information submitted and timeliness of report submittal.

Additionally, the earlier period LER's indicated a personnel error rate (29?;) that is couble the average rate for this type of facility.

More recent LER trending (October, 1980 - March, 1981) indicates that the personnel error rate has improved dramatically ( 11?s). This indicated that site personnel are becoming more f amiliar with Technical Specification and other operational requirements of the f acility.

3.2.1.3 Management Conferences Several management conferences have been held with TVA over the past year for the purpose of discussing both operational and management control type problems identified by the NRC at Sequoyah and other TVA facilities.

TVA management has been responsive in providing corrective action to these problems.

The following is a short summary of these meetings:

3.2.1.3.1 A management meeting was held on July 10, I

1980, at Tennessee Valley Authority corporate offices in Knoxville, Tennessee, relating to all TVA nuclear I

facilities under construction.

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discussed were enforcement history, j

changes in NRC organization and inscection policy, and QA/QC organi-

ation effectiveness.

,g 3.2.1.3.2 Management meetings required by the Ig routine inspection program prior to

issuance of an operating license were conducted.

I 3.2.1.3.3 A management meeting was held on

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l October 23, 1980, at Tennessee Valley

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Authority offices in Chattanooga, Tennessee, to discuss the Systematic A,sessment of Licensee Performance

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evaluation for the Sequoyah 'acility.

3.2.1.3.4 A management meeting was held on December 4,1980, in the Region II office ta discuss concerns of this office, bring about an improvement in communications, and obtain TVA's response to ceficiencies I

observed in safety-related activities at TVA's nuclear power plants in v;rious

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stages of construction and operation.

I 3.2.1.3.5 A management meeting was held on February 27, 1981, in the Region II office to discuss the results of this special inspection relating to the containment spray event which occurred on February 11, 1981. ~his meeting provided I

the opportunity for TVA management to discuss their plans for corrective action with respect to items contained in the I

Confirmation of Action letter, dated February 23, 1981, issued by NRC as a result of the spray event.

The content I

of this letter is providad in paragraph 6.1.1 of thi s report.

3.2.1.4 Sequoyah Evaluation The licensee's performance of licensed activities is acceptable.

This facility was recently licensed and therefore, the evalua' ion as an operational #acility covers a relatively short period of time.

Apparent trends in noncompliance, LER completeness and personnel I

error will be closely monitored to ensure they ai e corrected.

a.0 Description of Containment Spray Event 4.1 Event Summary At 7: 40 p.m. (CST), on February 11, 1981, with the reactor in a cold shutdown condition, an Auxiliary Unit Operator ( AU0) erroneously coened a containment spray vaive that resulted in 105,000 gallons o# water being sprayed into the containment.

The valve is located in the auxiliary builcin ~_

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Earlier in the shif t, the NRC licensed unit operator had instructed the auxiliary unit operator to verify that the containment spray valve from the Residual Heat Removal System was physically closed and seated.

This action was considered necessary since the valve had been stroke tssted on the preceding shif t.

Due apcarently to miscommunications, the spray valve was manually opened by the AUO. The open spray valve was not recognized as being open by control room personnel for 35 minutes. This was apparantly due to the fac'. that many valves had been repositioned for cold shutcown (Mode 5) causing related annunciator wincow to be illuminateo.

In this condition, the audible annunciator function is inoperable since it is designed to function only on the repositioning of the first valve in a group of valves that are monitored together. It does not have a refissh capability incorporated into the design - see paragraph 5.1.0 As a result of the open spray valve, a rapid decrease in pressurizer water level and reactor coolant system pressure occurred. Control voca operators resconded to the loss I

of coolant. The two operating reactor coolant pumps were secured and the RHR Pump suction vel.e wcs opened from the refueline water storage tank.

Pressur;:er level was lost for ten minutes until additional makeup to the reactor coolant system could overcome the loss rate. Containment caray was secured at 8:15 p.m. when the auxiliary operator returned to the control rocm and reported that aa had opened the RHR spray valve.

A detailed sequence of events is provided in Sectien 4.3.

The reactor building was evacuated during the above event.

Thirteen workers in containment were wetted at the time of sp ay initiation.

Eight wo*kers required decontamination.

The reactnr building vent monitor indicated a small radioactive release that was less than one percent of the NRC allowable linits specified in the Technical Speci-fications.

4.2 Initial Plant Conditions Unit I was shutdown on February 5,1981, due to excessive vibration of the main generator excitor shaft.

The reactor was placea in a cold (

shutdown condition (Mode 5) on February 6 and had remained in this moce prior to the February 11, cortainment spray event.

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System (RCS) pressure and temperature were 310 psig and 175'F, I

resoectively.

Number 1 and 2 Reactor Coolant Punps (RCPs) were operating for Reactor coolant circulation.

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train of the residual heat removal (RHR) System was in service to control decay heat. RHR letdown flow was in service through the volume control tank.

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'A' centrifugal cnarging pump was operating to supply RCP sail pressure.

Reactor building atmospheric purge from upper and lower containment was in progress at the time of the event.

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Routine surveillance stroke testing of safety-related motor operatea valves had been performed on the previous shift. The repositioning of these valves for system restoration had been accomplished.

Workmer were weighing ice baskets within the ice compartment of the containment as required by Technical. Specifications.

During the outage,' low voltage modificat' ions to safety-related switchboards had been in progress which required repeated realignment of systems to allow I

deenergization of equipment.

4.3 Sequence of Events The following sequence of events for the February 11, 1981, spray actuation was assembled from review of pertinent plant records, plant ILgs and interviews with plant personnel.

The primary source of information for each listed event is indicated in parenthesis.

Reactor Coolant System Status at the time of the event was as indicated below:

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RCS pressure 310 psig

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RCS temperature 175 F

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Pressurizer Water Level 25?6

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The following equipment was operating at the time of the event:

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Reactor Coolant Pumps (RCPs) 1 & 2 I

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' A' Centrifugal Charging Pump

' A' Residual Heat Removal (RHR) Pump

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Containment Purge From Uppe-and '.cwer Containmen't Time Elaosed Time (Mi Q Event (CST)

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RHR containment spray valve cpened I

(unknown to control. room operators).

1940

Pressurizer low level alarm (13?;)

cue to manual opening of RHR Spray Valve (FCV 72-40) (Computer)

Reactor Coolant System (RCS)

I pressure and Pressurizer level decreasing rapidly (Recorder)

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Shutdown 1 and 2 RCP's (Computer)

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RCS pressure atmoscheric;

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l Pressurizer level zero (Recorder)

1943

Switched 'A' Charging 'umo suction

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l from Volume Control Tank (VCT) to Refueling Water Storage Tank (RWST)

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(Recorder)

Placed maximum cooling on 'A'

RHR (Recorder)

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Started 'B' RHR pur.:p sith suction from loop (Computer)

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Reactor Building Evacuation - voice announcements (Log)

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Opened RHR pump suction to RWS7 (FCV l

63-1) (Recorder)

i Reactor Building Floor and Equip-

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ment Sump Pumps secured (Vercal)

l placed in " pull-to-lock" position 1947

Stopped containment purge (Log)

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Pressurizer level 13?; and I

increasing (Computer)

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Pressurizer pressure increasing to l

15 psig (Recorder)

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I Pressurizer level cycled through 13?s (Decreased and Increased)

apparently cue to RHR suction chec?-valve from RWST momentarily reseating due to RCS pressure increase (Computer)

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Implemented IP-4, Site Emergency l

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Called NRC Emergency Center - No Answer (Log)

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Initiated Manual Auxiliary Building Isolation (Log)

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Started 'B' Centrifugal Charging Pump with suction from RWST

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Started 'A' Safety Injection Pump (Verbal Unconfirmed)

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Started closing RHR Spray Valve I

(Log)

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RHR Spray Valve Closed (Recorder)

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Stopped 'A'

Safety Injection Pump (Verbal Unconfirmed)

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Stopped

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Centrit gal Charging Pump (Ccmputer)

Reestablished RHR letdown to VCT (Recorder and Computer)

Normal RCS pressure and pressurizer level established 2025 S

Called NRC Emergency Center ("RC Log)

2045

All Clear announced for Site Emergency (Log)

4.4 Plant Recovery Following the event. TVA plant personnel attention was directed toward assignment of an Investigation Task Force, water recovery, contami-nation centrol and equipment checkout.

TVA assigned an onsite engineering group as a task force to review this event.

Prompt iebriefings were held with personnel involved by having these personnel I

record their recollections in writing before leavirg the plant. These statements proved helpful to the NRC and TVA in reconstructing the event.

Equipment af fected by this event was limited to that located in the reactor containment building.

The containment purge that was in i

E progress at the start of the containment spray event was isolated

during the event and was not resumed until later in the cleanup phase after TVA engineering assured that the moisture within containment would not damage the shield buildinc ventilation exhaust filters.

Accumulation of water in the reactor building resulted in approximately

? feet in the reactor building sump (RHR).

This corresconds to a capth d

of 16 inches of water on the floor.

Level senscrs for the reactor building are located 6 inches above the floor. An actual measurement I

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of 18 inches on the floor was made about 0300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> on February 12, thus a reasonable correlation was obtained. The NRC resident inspector accompanied plant personnel on this first containment entry.

Water level was equalized in the reactor building at the 679.8'

elevation including the raceway outside the crane wall.

A doorway between the two areas was later confi-med as being open to permit this I

equalization.

The refueling water storage tank level had decreased from 97?e to 68?; which calculates to be 105,000 gallons.

Independent calculations by a NRC inspector of the flooded area confirmed that this was the acproximate volume of water on the floor including.4.5 feet in the containment pit sump.

I The containment pit sump located in the area under the reactor, has a single level device which alarms in the Incore Instrument Room. This alarm was found to be illuminated when the contairment entry was made following the event.

Subsequent measurement indicated 4.5 feet of I

water in thi s pit. Water collected in this pit is believed to have originated as leakage past the avcore instrument support guide sleeve, the top of which extends 9" above the reactor building 679.3' floor I

elevation. Maximum water level in the sump was aproximately 10' below the bottom of the reactor vessel.

A portable cump was placed in this pit and the water pumped back to the main containment floor.

The pumping of water from the containment to the auxiliary building began on February 13. This was accomplished using a portable pump with the discharge hose connected to a flange labeled " Flood Mode Discharge I

from RCD Pump," shown on Drawing 47W830-1.

The water was pumped through the 3" line directly to the CVCS Holdup Tank to minimize the time required for subsequent water cleanup. The Containment Floor and I

Equipment Drain Sump pumps were available for use if needad.

Health physics concerns were promptly addressed during and following tne event.

Shieid building purge was in progress and was isolated approximately seven minutes af ter the spray valve was opened.

The shield building effluent monitor indicated an increase from 40 cpm to 250 cpm anc returned to normal over a period of 15 minutes.

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l release was subsecuently calculated by TVA.to be 0.0215?s of the noole gas limit in the Tecnnical Specifications.

l Thirteen people in containment became slightly contaminated when i

sprayed.

These personnel were in the ice condenser compartment and were wearing arctic type clothing which assisted in minimizing their I

contamination.

Maximum contamination sas 14,000 dem on hands and

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beards.

Decontamination was accomplisned by routine showers.

Sub-sequent whole body counts indicatec only traces (0.05?; of permissible body burden) of Cobalt 58 on four individuals and of Zinc 65 on a fifth i

indivicual. Initial entry into containment was made with respiratory

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protection.

Airborne activity was tnen confirmed to be well within permissible limits for entry without respiratory protection.' Con-tainment air activity was monitored as the upper containment began to dry out.

When decon tami ntition was ini*iated on the evening of February 12, respi atory protection was again utilized as a precaution.

Floor swipes indicated 10 mr/br gamcna and 150 mr/hr beta.

Demineralized water used for decontaminating the upper containment was flushed tempurarily to the refueling canal.

Equipment inspection and checkout was performed criar to the main I

period of this investigation. It consisted of an intensive and cisciplined approach of checking equipment including junction boxes, pumps, motors, valves, and piping systems within containment.

This I

effort has been followed by the resident inspector and will be documented in his monthly report.

A complete baseline inspection of the hydrogen ignitor, system was planned incorporating the newly approved Technical Specification requirements.

One aspect of an ice I

condensor containment is that due

,o compartmentalization of the equipment, the ice condenser was not subjected to direct spray action.

Therefore, the ice bed was not damaged.

Additionally, since the I

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control rod drive missile shield was in place, the control rod drive coil stacks were not wetted.

4.5 NRC Response to Event The NRC Duty Officer was informed of this event by a Sequoyah Senior Reactor Operator utili:ing the Emergency Notification System at I

8:25 p.m. (CST), on February 11.

The NRC Resident Inspector arrived onsite at 10 : 10 p. m.

(CST), on I

February 11. He accompanied plant personnel on the initial containment bu lding entry.

i A Region II supervisor arrived onsite on February 12, to direct NRC onsite activities related to the technical review and evaluation of the ever t.

Two NRC inspectors onsite, performing unrelated inspections, wre diverted to assist in this review.

On February 17, a second

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Region II supe * visor, another inspector, and a member of the NRC Training Center staff arrivec onsite to continue the ongoing review of g

the event. More specifically, this second group evaluated the acmini-

strative control and personnel training aspects of the event.

j Region II issued a Confirmation of Action letter to TVA on February 23, 1981, outlining the corrective actions to be completed by TVA prior to restart of the unit. Details of these actions are providec in Section 6.1 of this report.

TVA management attenced a meeting with the

Region II Director and staf f on Feoruary 27, to present their proposed

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correct.ve actions. Region II found che TVA proposals to be accept-able.

Verification of satisfactory implementation was accomplished by the Resident Inspector and documented in his March report.

I 5.0 Evaluation of Containment Spray ' Event 5.1 Sepuence of Events Technical Evaluation The items listed and described in this section constitute the technical review cond6 ted by the NRC with respect to this event.

Items I

requiring further review or resolution are denotec by a unique identi-fication number located in parenthesis at the end of applicable paragraphs.

5.1.1 Manual Seating of Motor-Operated Valves Followiro the cycling of the RHR spray valve by the previous shift, in accordance with surveillance instruction, SI 166.3,

" Full Stroking of Category A and B Valves During Cold I

Shutdown", olant personnel gave a verbal instruction at shif t turn:ver that manual seating of the RHR spray valve in the closed position should be confirmed. This evidently has been a practict for certain valves to assura leakage through the I

valve was not occurring. The surveiliance instruction left tr)e RHR spray valve in a closed position and did not address hand tightening of any valves. The inspectors questioned the practice and training of personnel involved in such valve seating since valves must be assured of being operable when needed. A shift eng'neer indicated that hand tightening of I

the spray valve was a routine precaution to ensure no leakage to the spray header.

General Operating Instruction, GOI-6, Aoparatus Operations, provides 'ge n e ra l guidance for motor-operated valves and states not to exceed a maximum of b turn of the handwheel after contact is made be. ween the disc and the seat. This I

matter is censidered unresolved until the training of personnel and experience of manually seating motor operated valves i s reviewed (327/31-07-08).

I 5.1.2 Spray Valve Position Indication Va au position of the ' A' RHR spray valve is indicated at two locations on the control board.

The valve position switch has indicating lights for open and close limit positions of the valve.

Approximately eight feet away on the control I

ocard, the " Monitor Light Group A" status panel has a one I

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inch si:ed status wino.u labeled "PCV-72-40 RHR Spray Open".

I During the time the valve was open, neither of these indicators was observed, due possibily to the many indicating lights already in an abnormal condition for reactor shutdown.

Emergency procedure E0I-0, Immediate Actions and Diagostics, states in section II.A.4 to veri fy isolations and system I

alignment by status monitor lights. Flant personnel stated that this procedure was being specifically followed during the event. Nevertheless, the valve position indications were overlooked.

The emergency procedures E0I-0 and E0I-1, Loss of Reacter Coolant, are primarily written for conditions originating in operating : odes of 1 through 4; therefore, the procedure was of minimal benefit for a loss of coolant event I

while in a Mode 5 condition because system alignments are changed significantly for (cold shutdown (Mode 5)).

The audible alarm, associated, with the RHR spray valve indicator located on one of the group monitor status panels, is a common audible alarm serving all valves assigned to the group. The group monitors are designed to alert the operator when a key valve is not in the position required for injection, but proper alignment of these valves for injection is only required in Modes one through three.

In Modes four and five, many of the valves are realigned for shutdown cooling and isolation purposes.

Since the audible alarm does not have reflash capability at Sequoyah, it only serves to I

alert the operator whe.n the first valve of a group is realigned. It will then remain silent as other valves of the same group are realigned. During this event, cther valves of the group containing the RHR spray valve had already been realigned; tnerefore, no audible alarm was received when the j

spray valve was inadwtently opened.

ll 5 It was noted by the inspection team and generally agreed upon by the operators that had there been an alarm reflash

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capability of the RHR systems status, tne Unit Operator would

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have been alerted by the alarm indicating a mispcsitioning of tha RHR containment spray isolation valve. The operator then could have taken corrective action which would have resulted in a snorter duration of containment spray.

In evaluating this problem, the inspection team identified the need for an analysis by the licensee of the -aed for incorporating

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"reflash" on the control m m control ocards. Thi s i'.em will be referred to NRC Headcuarters for further generic

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evaluation.

This concern is designated as a NRC Followup Item (327/81-07-11).

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5.1.3 Water Chemi stry 5.1.3.1 Radioactivity Total radioactivity samples taken before and after the event indicated very little change. Thus, this supports the conclusion that there was no problem with the reactor core.

DATE TIME TOTAL ACTIVITY SOURCE 2/11 (-) am 1.17x10 2 mci /ml Reactor Coolant 8:05 pm 9.89x10 3 Reactor Coolant 2/12 11:08 am 1.37x10 2 Ir. side crane wall I

2.07x10 2 Outside crane wall 1E55 am 3.95x10-1 Pressur1:er 6:20 am 6.78x10 2 Reactor Coolant 5.1.3.2 Baron

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Reactor coolant system (RCS) boron concentration on

February 11, prior to the event, was 1100 ppm and l

had increased to approximately 1800 ppm following the event. This indicates that a significant amount l

of 2000 ppm water was injected into the RCS from the

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refueling water stnrage tank (RWST).

Based upon a boron c'oncentration of 1695 ppm, obtained from the spilled water on February 12, the I

net water sprayed.uto the containment during the

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event was approximately, t,000 gallons from the RWST and 41,000 gallons from the RCS.

5.1.3.3 Chlorides l

Analysis of the spilled water in containment I

indi: ated chlorides to be 300 ppo.

Subsequent smears of the stainless steel piping were

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incorocrated into tne recovery procedures to I

fyaluate any special cleaning techniques that may be required.

5.1.4 RHR Pump Surtion Check Valve The pressuri:er level recorder cnart indicated a 13% levei l

cycling during the pressurizer lesel recovery. Analysis of I

this transient indicates that the check valve at the suction i

of the RHR oumo must have momentarily closed when the

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increasing pressure (0 to 15 psig) of the reactor coolant I

system (RCS) became greater than the static pressure of the refueling water storage tank (RWST).

The RHR loop temperature recorder chart and the computer event printout

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substantiate this occurrence.

Suction of the RHR pumps was aligned oath from the RCS and the RWST at this time.

The significance of the check valve closing is the potential that it could remain closed when RHR cooling is in service and result in the loss of the RWST water as a supply source for the RHR pumps.

This would restrict this source of water addition to the reactor coolant system.

This phenomenon would be particularly significant if a loss of coolant event were to occur during the time when the plant is in Mode 4 on shutdown cooling, since the RCS te.nperature would be above I

212 F and RCS pressure would be controlled by the saturation temoerature of the RCS. However, the out:ome of this event was not af fected significantly since the RCS temperature was below the boiling point.

One means to correct this,wtential condition would be to I

specify closure of the RHR suction valves from the Reactor Coolant System whenever the RHR pumps are required for cold leg injection from a makeup water source.

Plant personnel have subsequently bee" provided these instructions.

This I

item has been referred to NRC Headquarters for generic evaluation since degraded injection flow conditions could exist under certain system operating configurations.

The item is designated as a NRC Followup Item (327/81-07-10j.

5.1.5 RHR Spray System Piping The ef fect of the inadvertent opening of va'.ve number FCV 72-40 on the integrity of the RHR Containment Spray System Piping was discussed with licensee engineers.

The normal design pressure and temperature for operation of the RHR Containment Spray System during an accident (LOCA) is 220 psi at 190 F.

I g These were the parameters used in design and procurement o'

g the RHR Containment S p rrj Siping and nozzles (See Figure 6.2-

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l 6.3 of tne FSAR). However when valve FCV 72-40 was opened, the RHR system was operning at 710 psig and 175 F.

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fhe discussions with licensee engineers disclosed that the maximum stresses on the piping system are a result of a

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comoination of seismic loads, dead loads, and the " normal" I

LOCA Internal pressure of 22C psi at 190 F.

Since the system is required to remain operational during a seismic event, the maximum stresses for tnis combination of loads are within

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code allowables. The stresses produced from a combination of the deadicad and the internal pressure of 220 psi at 190 F (no seismic) are approximately one-third of the code allowable values.

Based on this, licensee engineers were confident that the opening of spray /alve FCV 72-40 resulting in the subjection of the RHR containment spray piping and nozzles to higher internal pressures and temperatures had no effect on the integrity of the system.

The licensee committed to analyze the RHR Containment Spray System for tne conditions to which it was subjected during the spray event. The resident inspecter subsequently reviewed a TVA design recort dated March 2, 1981, which stated that RHR spray piping was B" schedule 40 pipe and would withstand a max tmum operating pressure of 1103 psi. NRC considers this issue resolved.

5.1.6 Adecuacy of Core Cocling Due to uncertainty as to the exact flow history from the RWST during this sequence of events, it is not possible to exactly calculate the minimum water level reached in the core.

However, it is possible to bound the minimum level in several ways:

5.1.6.1 The boron concentration before and after the event can be used to calculate that about 40,000 gallons of water were replaced in the primary system. The balance of the total of 105,000 gallons drawn from the RWST was sent directly through the RHR system to the spray header. Conservatively assuming the 40,000 gallons all "leakec" 6afore any replacement, about a 6,CC0 gallon volume would have been voided ir the RPV since the steam generators, pressurizer and hot legs contain about 34,000 gallons.

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6,000 gallons out of the RPV would lower level less I

than 5 feet in the 14 foot I.D. RPV, leaving the l

water level well above the core.

(There is

I feet of water above the core in the cylindrical portion of the RPV, plus additional water above that in the hemischerical head.)

5.1.6.2 The RHR pumps in the core recirculation cooling mode cannot draw inventory from be!ow tne bottom of the hot leg no tles (temperature was 175 F). This I

would leave about 3 feet of water accve the core,

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conservatively assuming that water was pumoed to that level. With the cecay heat levels present

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I February 11, it would have taken 5 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> to boil away : hat 3 feet of water (pressurizer level indication was lost only 3 to 10 minutes).

I 5.1.6.3 Items (1) and (2) above provide conservative bounds. The best estimate is that the water level I

remained high enough to keep the RPV (including the head)

full since control rod drive venting following this event produced no gas.

Based on the above, it was concluded that adequate core cooling was provided throughout the spray event and that core damage did not occur.

5.2 Operational Aspects Evcluation 5.2.1 Communication Discussions with the unit operator (UO) and the auxiliary unit operator (AUO) revealed that at the beginning of the I

shift, the UO verbally told the AU0 that later in the shift, the AUO was to open two RHR valves ar.d to check that the 'A'

RHR spray valve was fuliy closed. T'e spray valve had been cycled the previous shif t during a planned surveillance. The AUO wrote down the valve numbers on a slip of paper but neglected to record the desired positions. About 1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br />, the AU0 contacted the U0 by telephone and asked if he was ready for the valves to be opened. Details of this discussion are vague but an affirmative reply was given. Subsequently,

'B' RHR train temperature was noticed by the UO to increase, l I indicating that the two RHR valves must have beer. openeo.

The AUO proceeded to another valve room and reportedly considered l

calling the UO, but did not, since the phone was inoperable.

I He then proceeded to open the RHR spray valve, erroneously thinking that this was the action desired. The AU0 exited the area, made a clothing change, and proceeded to the contral room where the valving performed was brought to the attention of control room personnel.

The control room panel valve position light was then noted to indicate the

'A-RHR scray l

valve was open.

The valve was immediately closed at 2015 l

hours. The opening of the RHR spray valse at 1940 hours0.0225 days <br />0.539 hours <br />0.00321 weeks <br />7.3817e-4 months <br /> was l

an operator error, apparently due to a miscommunication or misunderstanding between the UO and AUO.

The area of communications between the NRC licensed coerating

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staff and the AUC's was found to be weak.

The AUO's interviewed expressed a feeling that the directions of the j

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lo Unit Operators should never be questioned.

This inabiiity to cevelop and ma!rtain a proper exchange of information among n

watchstanders is considered a weakness.

The inspectors further noted that no formal requirement was implemented which required a systematic turnover between the on watch AVO anc the relieving AUO. Untii the licensee assesses the need for and implements a

system for formal / standard I

communications and a formal turnover requirement for the AUO's, this item will remain open.

It is designated a NRC Unresolved Item (327/31-07-04).

5.2.2 Communications Equipment Problems were noted in the plant communication systems equipment. The inspection team noted that the two telephone sets nearest the compartment in which the RHR Containment Spray header isolation valve is located were inoperable. Also noted was the lack of a speaker from the plant public acidress system to this crmpartment.

In summary, there is no way for the control room to contact an operator or visa versa, while the operator is in this compartment.

Jntil the licensee evaluates the need for an expanded and upgraded communication network, this item will remain open and is designated a NRC Unresolved Item (327/81-07-05).

5.2.3 Auxiliary Unit Operator Training and Supervision

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The inspection team concucted interviews with two Shift Engineers, two Unit Ocarators, and seven Auxiliary Unit Operators (AUO) on the following subjects:

5.2.3.1 AU0 caily routine; 5.2.3.2 AU0 training; 5.2.3.3 AUD watch scheduling; and 5.2.3.4 AUO supervision.

The discussions revealed an overall weakness in the supervi; ion of the I

plant AUO's. There was no clear cescription outlining the duties of the AUO.

Furthermore, no daily routine, such as the recording of logs, plant tours or machinery checks, existed "or the AUO's.

Because of this, much of the AUO's time appeared to be spent in a nonduty type status awaiting tasks to be assigned.

For scheouling of AUG watches, little effort apoeared to ce ecce to consider the qualifications of the individual or his need for mair.cairiing proficiency on a particular watch

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As of February 19, 1981, AUO's were scheculed for and allowed to perform on watcnes for wnich, in scme cases, a period of on-the-job training or break-in vas not conducted at this site.

The lack of developing proficiency on a watchstation was evidenced by the fact that on Februa ry 11, 1981, an AUO manipulated an P.HR containment spray valve resulting in the actuation of containment spray. Although the ALO had been previously qualified at the Watts Far site, he was standing his I

first auxiliary building watch at Sequoyah and no break-in training was provided at Sequoyah in preparation for this watch.

This failure to properly train non-licensed operators constitutes a violation of I

Technical Soecification 6.4.1, which requi res that a retraining and replacement training program bc established for the unit staff which meets or exceeds the requirements and recommendations of ANSI N18.1-1971, (327/81-07-01).

5.2.4 Operator Control of Plant The inspection team interviewed two Shif t Engineers (SE's)

and two Unit Operators (UO's) on the subject of ooerator control of plant activities.

The interviews revealed a

vea kne s s in thc area of operator " control" of plant operations. There was no system implemented within the plant organization which assured the Shift Engineer and the Unit Operator are both inf ormed of changes in plant status.

Findings are as follows:

5.2.4.1 The Shift Engineer, in some cases, authorized Hold Tags without informing the control board Unit Operator.

The issuance of these hold tags could affect plant systems / operations under the supervision of the Unit Operator.

5.2.4.2 When two Unit Operators are assigned to the cor. trol board, one Unit Operator may, on occasion, order changes in plant status without the knowledge of the othar Unit Operator.

These changes could affect plant systems / operations uncer the l

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supervision of the other Unit Operator.

5.2.1.3 Organizations such as the TVA Outa;e Group have entered the plant and performed maintenance or

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otherwise affected plant systems without first informing the Shif t Engineer or the Unit Operator.

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l Maintenance Requests (MR's) without informing the l

control board Unit Operator.

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These examples af weaknesses in the area of plant control could result in plant conditions which could have a negative effect on the decision making process of the Uait Operators daring normal and abnormal plant conditions. This failure to implement adequate plant procedures which clearly delineate the duties. authorities, and responsibilities of operations personnel involved in safety-related activities constitutes a violation of Technical Specification 6.8.1.a, which requires that I

procedures be established and implemented in accordance with Item 1.b of Appendix A to Regulatory Guide 1.33, Revision 2, dated February 1978 (327/81-07-03).

I 5.2.5 Use of Procedures I

The inspectors noted a general lack of procedure use by operations personnei. On February 11, 1981, no procedure was utilized whi'e changing the RHR system lineup. Specifically, the on-watch AUO realized the potential for mis positioning I

of RHR system valves during the valve alignment change, but did not utilize appropriate procedures or diagrams.

This lack of procedure use contributed to the cause of the in-I advertent containment spray event and constitates a violation of Technical Specification 6.8.1.a, which recuires that procedt.res be established and implemented in accordance with I

Item 3.c of Appendix A to Regulatory Guide 1.33, Revision 2, dattd February 1978 (327/81-07-02).

5.2.6 Control Room Access Control The $ni#t Engineer and the Unit Operator do not effectively utili : the authority to control personnel entering the I

control room. Excessive noise and activity as a result of the presence of more than twenty persons was noted by the I

inspection team on two separate occasions.

Until the I

licensee ef fectively controls access and activities in the control recm, this item is open and is designatec a 'NRC Unresolvec Itan (327/81-07-06).

5.2.7 Plant Management / Operating Shif t Interactions The interviews conducted by the inspa: tion team with members

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of the operations staff indicated a lack of irteraction between Plrt Management and the operating shifts.

Examples I

indicative of this problem are:

5.2.7.1 Auxiliary Unit Operators (AUO's) were scheduled by the Operations Superintencent to "on sn'f;" watches without the approval of the Shif t Enginar.

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5.2.7.2 The TVA outage maintenance group has c.; occasion, entered the plant to perform maintenance withcut coordination between shift personnel and p l ar.t management.

5.2.7.3 Ef forts of manageraent to keep operating shifts informed of plant scheduling for outage periods or for the changing of plant modes appears to be inadequate.

5.2.7.4 Tnere is a general feeling among the AUC's that poor communications exist between the AUO's and management. The AUC's feel that had management I

communicated more effectively with shift personnel, problems should have been cetected more easily and necessary currective actions taken. The system for communication needs to be improved for plant I

managemer.t anc shif t personnel to interact more effectively.

This item is designated a NRC Unresolved Item. (327/81-07-07).

5.2.8 Shift Status Check The reactor operators routinely complete a detailed thirteen page System Status Checklist (AI-5) for a formal plant turnover on each shift.

According to the licensee, enmpletion of this checkout typically takes 15-45 minutes cepencing upon operations in progres:,.

The containment and

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RHR Spi.y System valves were noted to be included on this check. For the shift turnover prior to the February 11, spray I

event, A01-5 indicated that the surveillance procedures utilized for cycling the RHR spray valves was in progress.

5.2.9 Shif t Technical Advisor (STA)

The STA position was not manned during +.his event and is not required to be when the plant is in cola shutdown (Mode 5).

l The STA watch had been secured on February 6.

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flooding event, the STA watch was reestablished at 2147 hours0.0248 days <br />0.596 hours <br />0.00355 weeks <br />8.169335e-4 months <br /> l

on February 11, to assist as required during plant recovery.

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5.2.10 Ccemunication with NRC At approximately 8:00 p.m. (CST), the shift Engineer (SRO)

stated he attempted to contact the NRC Duty Officer over the dedica ed telephone but that he stoppec af ter 7-3 rings to devote his attention to the eveilt. A second SRO successfully contacted the NRC later at 8:25 p.m. (CST).

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5.2.11 Evacuation of Personnel Evacuation of personnel from containment was given high priority.

The inspector noted supervisory personnel and others were dispatched to the containment exit to assist those exiting and to cetermine that all personnel were accounted for. Voice evacuation aanouncements over the plant I

public address system were provided initially.

One dif ficulty reported was that it was relatively dark inside.

Most containment light bulbs burs + when they were sp ayed I

with water. TVA is addressing the need for portable lighting in containment in their administrative controls.

This item is designated a NRC Followup Item. (327/81-07-09).

5.2.12 Interpretation of Plant Computer Information During the evaluation of plant computer printouts, the inspection team noted a weakness on the part of the Shift Engineers and Unit Orerators interviewed en the use and capabilities of the plan; compute,-

The pl ant computer can be I

a valuable tool during nornal and abnormal plant conditions and transients. Until the licensee evaluates the need for a training program v1ich details the plant computer capabilities, this item will remain open and is designated a NRC Followup Item. (327/81-07-12).

6.0 Summary of Conclusions and Recommendations 6.1 Issues Requiring Evcluation and Resoulution as Appropriate 6.1.1 Short Term Resolution This inspection revealed several areas of concern.

As a rcsult of these concerns, a Confirmation of Action letter was issued on February 23, 1981, to TVA by the U.S. Nuclear Regulatory Commission's Region II Office.

TVA actions required by the letter prior to Unit 1 restart were:

6.1.1.1 Evaluate and revise administrative controls to I

assure that responsibi14 ties and authorities of on-

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shif t operating personnel see clearly delineated in

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writing.

In particular, assure that the responsible Shift Engineer has positive control of I

activities occurring during his shift th t could have an effect on safe operation of tne unit.

I 6.1.1.2 Develop and implement administrative controls that clearly delineate method:

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personnel involved in the conduct of safe operation of the unit.

These controls shoula address as a minimum, routine and special instructions, communications, and responsibilities of all I

personnel involved in safety-related activities.

6.1.1.3 Upgrade the in plant on-the-job training and certi fi cati on system of non-licensed operating personnel involved in the safety activities.

6.1.1.1 Review the certification of non-licensed ocerating I

personnel to provide positive assurance that only'

qualified personnel with experience on the

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operating unit are assigned to perform functions I

that can affect the safety of operations.

A meeting was held with TVA corporate management level personnel in I

Region II on February 27, to disc:ss the containment spray event.

The discussion included a presentation, by TVA, of the results af their review of the event, as well as their proposed corrective

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actions, both as a result of their review and in response to the Confirmation of Action letter.

TN corrective action plan proposed by TVA, to be implementec pr or to rer*. art of Unit 1, was judged to be acceptable by NRC. TVA was informed, at this meeting, I

that all items contained within the Confirmation of Action letter would be inspected and resolved to the satisf action of NRC prior to the restart of Unit 1.

6.1.2 Longer Term Resolution I

All issues addressed in this report, will be eins;. cted by Region II perscnnel and ratisf actorily resclved prior to closecut of the items.

In addition, the following items will be referred to NRC Headquarters f" ultimcte I

resolution and gener c evaluations.

i 6.1.2.1 Violation - (327Al-07-01) - Paragraph 5.2.3 -

I Inadequate Training for Non-Licensed

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Personnel:

This item will be reviewed by the Division of Human Factors Safety to determine 4h:t changes, if any, should be made to current requirements.

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6.1.2.2 Unresolved Issue - (327/81-07-04) - Para graph 5.2.a

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Operations Staff Communication Policies and Procedures:

This item will be reviewed by the Division of Human Factors iafety to determine what requirements, if any, should be implemented in this area.

6.1.2.3 Unresolved Issue - (327/81-07-08) - Para graph 5.1.a - Manual Seating of Safety-Related I

Motor-Operated Valves:

This item will be reviewed by the Division of I

Systems Integration to determine what, if any, requirements should be incased in this area.

6.1.2.4 Followup Item '- (327/81-07-10) - Para graph 5.1.4 - RHR Pum Suction Check Valve Seating Problem:

This item will be reviewed by the Division of Systems Integration to determine what should be done to resolve this problem.

, 6.1.2.5 Followup Item - (327/81-07-11) - Paragraph 5.1.b - Annunciator Reflash Capability:

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This item will be reviewed by the Division of Human Factors Safety to determine what, if any, changes to requirements should be made in this area.

l 6.2 Current Status of Operational Readiness The following items are the conclusions of this NRC inspection effort:

l 6.2.1 Operator error was the cause of this event; however, this l

conclusion is tempered by the fact that the responsible AUO I

did not rec 9ive adequate training on the watch station prior l

to assuming full resconsibility for the auxiliary building watch station.

6.2.2 Inadecuate communication policies, procedures, and equipment I

were contributors to this event.

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6.2.3 Lack or an annunciator reflash capability delayed recognition of the cause of the event and therefore prolonged the event.

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6.2.4 Inadequate delineation of duties, authorities, and responsi-bilities contributed to an operational control problem among the operations staff, especially among the AUO's.

6.2.5 Poor management interaction with the operating staff was a contributor to the operational control problem, again, especially among the AUO's.

6.2.6 Operational control problems were contributors to the event in that, poor operational controls foster laxity and in-atterition to detail.

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NRC finds that procer implementation of TVA's proposed corrective actions in response to the Confirmation of Action letter corrected the programmatic I'

deficiencies identified in this report. Verification of the implementation of these corrective actions to the satisfaction of NRC inspectors therefore constituted the basis for Sequoyah Unit 1 resuming operation. Resident Inspector followup inspections have indicated that the licensee has achieved more effective and efficient operational control of the facility.

7.0 Exit Interview Exit Interviews were conducted to inform the licensee of preliminary findings at the conclusion of each segment of this inspection. These meetings were conducted at the Sequoyah site on February 13 and 19,1981. Those persons indicated in Section 1.3 of this report attended one or both of these meetings. The licensee ackiowledged the findings presented at both meetings and responded in a highly competent manner during discussions pertaining to significance and possible corrective actions related to each finding.

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