ML20215A982

Insp Repts 50-327/87-24 & 50-328/87-24 on 870406-0505. Violations Noted:Failure to Properly Notify NRC of 870429 RCS Spill Event.Unresolved Item Noted:Adequacy of Primary & Critical Drawing Lists

ML20215A982
Person / Time
Site:	Sequoyah
Issue date:	06/04/1987
From:	Branch M, Brooks C, Carroll R, Harmon P, Jenison K, David Loveless, Mccoy F, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF SPECIAL PROJECTS
To:
Shared Package
ML20215A952	List: ML20215A950 ML20215A963 ML20215A982
References
50-327-87-24, 50-328-87-24, IEB-79-22, IEC-79-06, IEC-79-07, IEC-79-6, IEC-79-7, NUDOCS 8706170171
Download: ML20215A982 (19)

See also: IR 05000327/1987024

Text

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4 Houg UNITED STATES

l. o NUCLEAR REGULATORY COMMISSION

/[4 p REGloN 11

J* 'j 101 MARIETTA STRE ET, N.W,'

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e. ATLANTA, G EORGI A 30323

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• s,,*-

/ Report Nos.: 50-327/87-24 and 50-328/87-24

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Licensee: Tennessee Valley Authority

500A Chestnut Street- '

Chattanooga, TN -37401

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

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Facility Name: Seq'uoyah. Units 1 and 2 l

Inspection Conducted: April 6, 1987 thru May 5, 1987

Inspectors: WY$ $ - $l$)$Y

K.M.Jenison,seniorRfdeynspe'ctor D&te Signed

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nesident; f pseg r),' Browns Ferry

Approved by: /d f [/ / 6[#' 7

F. R.'McCoy, Chief TVA Proieg s( Section 1 Dsti Sighed

Office of Special Projects

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l SUMMARY

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l; Scope: This routine, announced inspection involved inspection onsite by the

Resident Inspectors in the areas of: operational safety verification

(including operations performance, system lineups, radiation protection, i

= safeguards and housekeeping inspections); review of previous inspection

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findings; followup of events; review of licensee identified items; review of IE  ;

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Information Notices; and review of inspector followup items. This inspection '

also involved special review of drawing control, the operability look back

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B706170173 870604

gDR ADOCK 05000327

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. program, : recent .. reactor coolant spill- events, and the new employee concern

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program.

Results: One violation'was identified:

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327, 328/87-24-03, Failure to notify the NRC of the April '29,1987 ' reactor

coolant system spill event, paragraph 10.

-ThreeLunresolved' items were identified:

.327,328/87-24-01, Adequacy of primary and critical- drawing lists,

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paragraph 14.

327,328/87-24-02, Control of temporary changes to drawings,

paragraph 14.

327, 328/87-24-04, Inadequacies in procedures and procedural implementa-

tion, causing concerns over control in the areas of system and

equipment status, procedural changes,-and testing, paragraph 10.

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REPORT DETAILS

1. Licensee Employees Contacted

H. L. Abercrombie, Site Director

J. T. La Point, Deputy Site Director

• L. M. Nobles, Plant Manager

• B. Willis, Operations and Engineering Superintendent

• B. M. Patterson, Maintenance Superintendent

R. J. Prince, Radiological Control Superintendent

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M. R. Harding, Licensing Group Manager

L. E. Martin, Site Quality Manager

D. W. Wilson, Project Engineer

R. W. Olson, Modifications Branch Manager-

J. M.' Anthony, Operations Group Supervisor

• R. V. Pierce, Mechanical Maintenance Supervisor

M. A. Scarzinski, Electrical Maintenance Supervisor  ;

• H. D. Elkins, Instrument Maintenance Group Manager

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J. T. Crittenden, Public Safety Service Chief  :

• R. W. Fortenberry, Technical Support Supervisor

• G. B. Kirk, Compliance Supervisor

• J. H. Sullivan, Regulatory Engineering Supervisor

• J. L. Hamilton, Quality Engineering Manager

• H. R. Rogers, Plant Operations Review Staff

• R. H. Buchholz,.Sequoyah Site Representative  !

• M. A. Cooper, Compliance Licensing Engineer . t

• A. M. Qualls, Plant Manager Bellefonte

• T. M. Galbreath, Employee Concerns Program Supervisor

• T. A. F11ppo, Quality Surveillance Supervisor

• T. L. Howard, Quality Assurance Manager >

• E. K. Sliger, Manager, Employee Concerns Program

• J. E. Boyles, Employee Concerns Program

• W. R. Simonds, Employee Concerns Program

• G. R. Mark, Employee Concerns Program

• J. E. Maddox, Project Administration Supervisor

Other licensee employees contacted included technicians, operators, shift

engineers, security force members, engineers and maintenance personnel.

• Attended exit interview.

2. Exit Interviews j

The inspection scope and findings (including those discussed during the

April 24, 1987 drawing control exit and the May 1,1987 operability look ,

back exit) were summarized with the Plant Manager and members of his staff f

on May 5, 1987. No violations or deviations were discussed at this exit. '

The licensee acknowledged the two unresolved items in the drawing control

area.

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A supplemental exit was held on May 29, 1987, to discuss recent reactor I

coolant spills identified in paragraph 10 and associated Violation

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327,328/87-24-03 and Unresolved Item 327,328/87-24-04. The licensee was

not in full agreement with the findings as presented at this supplemental j

exit. The NRC was represented by the Section Chief for the Sequoyah site

and the Senior Resident Inspector. The licensee was represented by Deputy

Site Director, Plant Manager and Site Licensing Manager among others who

made the following paraphrased comments:

1. The use of 10 CFR 50.72.b.21 in Violation 327,328/87-24-03 is con-

sidered by the licensee to be a. misapplication.

2. The licensee was not given sufficient notice prior to this supple-

mental exit to ensure that the appropriate licensee personnel could -

attend this meeting and/or properly brief Sequoyah management. The

NRC acknowledged this comment, however, because of the importance of

these events coupled with other recent events it was necessary to

conduct the exit on an impromptu basis in order to ensure that there

was proper communication between the NRC and the licensee at the

appropriate level of management.

The licensee did not identify as proprietary any of the material reviewed j

by the inspectors during this inspection. During the reporting period, I

frequent discussions were held with the Site Director, Plant Manager, and

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other managers concerning inspection findings. Inspection findings

concerning drawing control and the operability look back review program )

are presented in paragraphs 14 and 15, respectively. j

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3. Licensee Action on Previous Inspection Findings (92702)

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(Closed) Violation 328/84-21-01, Failure to have adequate procedures for ,

air compressor maintenance. This item was reviewed in Inspection Report j

84-35 during the closure of Violation 327/84-20-01. Based on this review l

Violation 328/84-21-01 is closed.

4, Unresolved Items

Unresolved items are matters about which more information is required to i

determine whether they are acceptable or may involve violations or devia-

tions. Three unresolved items were identified during this inspection, and

are identified in paragraphs 10 and 14.

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5. Operational Safety Verification (71707)

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j a, plant Tours

The inspectors observed control room operations, reviewed applicable

logs, conducted discussions with control room operators, observed

shift turnovers, and confirmed operability of instrumentation. The

inspectors verified the operability of selected emergency systems,

and verified compliance with Technical Specification (TS) Limiting

Conditions for Operation (LCO). The inspectors verified that main- i

tenance work orders had been submitted as required and that followup j

activities and prioritization of work was accomplished by the j

licensee. j

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Tours of the diesel generator, auxiliary, control, and turbine

buildings, and containment were conducted to observe plant equipment ]

conditions, including potential fire hazards, fluid leaks, excessive

vibrations, and plant housekeeping / cleanliness conditions, j

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No violations or deviations were identified. I

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b. Safeguards Inspection i

In the course of the monthly activities, the inspectors included a-

review of the licensee's physical security program. The performance

of various shifts of the security force was observed in the conduct

of daily activities including protected and vital area access

controls; searching of _ personnel and package's; badge issuance and

retrieval; patrols and compensatory posts; and escorting of visitors.

In addition, the inspectors observed protected area lighting, protec-

ted and vital areas barrier integrity. The inspectors verified an

interface between the security organization and operations or main-

tenance. Specifically, the resident inspectors inspected security

during outages, reviewed licensee security event reports, and

verified protection of safeguards information.

No violations or deviations were identified.

c. Radiation Protection

The inspectors observed health physics (HP) practices and verified

implementation of radiation protection control. On a regular basis,

radiation work permits (RWPs) were reviewed and specific work

activities were monitored to ensure the activities were being con-

ducted in accordance with applicable RWPs. Selected radiation

protection instruments were verified operable and calibration

frequencies were reviewed.

No violations or deviations were identified.

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6. Engineered Safety Features Walkdown (71710)

Module 71710 wts not performed during this inspection period as a result

of the augmented inspection program being implemented.

7. Monthly Surveillance Observations (61726)

The inspectors observed / reviewed TS required surveillance testing and

verified that testing was performed in accordance with adequate {

procedures; that test instrumentation was calibrated; that LCOs were met; i

that test results met acceptance criteria requirements and were reviewed l

by personnel other than the individual directing the test; that i

deficiencies were identified, as appropriate, and that any deficiencies l

identified during the testing were properly reviewed and resolved by {

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management- personnel; and that system restoration was . adequate. For

complete tests, .the inspector verified that testing frequencies were met

and tests.were performed by qualified' individuals.

The ' resident and .0ffice of Special Programs inspectors are currently

reviewing post-modification and post-maintenance functional testing on

site. This review includes preparation, performance, procedures, review,

and' paperwork involved with functional testing. Testing observations will

continue throughout the month of May. Summaries of testing observed and

additional comments will appear.in inspection report 327, 328/87-28.

8. Monthly' Maintenance Observations'(62703) j

a. Station maintenance activities of safety-related systems and com-

ponents were observed / reviewed to ascertain that they were conducted

in accordance with approved procedures, regulatory guides, industry

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codes and standards, and in conformance with TS.

The following itens were considered as ancillary issues to an

extended functional testing inspection which is ' described in

paragraph 7 of this report: LCOs were met while components or

systems were removed from service; redundant components were

operable; approvals ' were obtained- prior to initiating the work;

activities were accomplished using approved procedures and were

inspected as. applicable; procedures used were adequate to control'the

activity; troubleshooting activities. were controlled and the repair -

record accurately reflected what actually took place; functional

testing and/or calibrations were performed prior to returning

components or systems to service; quality control records were

maintained; activities were accomplished by qualified personnel;

parts and materials used were properly certified; radiological

controls were implemented; QC ' hold -points were established where

required and were observed; fire prevention . controls were

implemented; outside contractor force activities were controlled in

accordance with the approved Quality Assurance ' (QA) program; and

housekeeping was actively pursued. The following work request (WR),

work plan (WP) and preventive' maintenance (PM) procedures were

reviewed.

WR B233555, Check out diesel generator setups with vendor

WP 1285-8721, UHI level switch modification

PM 1897-087, UHI accumulator isolation valve low level activation

level switches

PM 756-410, Door interlock system

No violations or deviations were identified.

9. Licensee Event Report (LER) Followup (92700) t

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The following LERs were reviewed and closed. The inspector verified that: 3

reporting requirement. ad been met; causes had been identified; correc- ]

tive actions appeared appropriate; generic applicability had been '

considered; the LER forms were complete; the licensee had reviewed the

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event; no unreviewed safety questions were involved; and no violations of

regulations or Technical Specification conditions had been identified.

LERs Unit 1 ,

327/84-54, Reactor . trip due to loss of relay rack 1-R-15. The licensee

determined that the initiating trip signal resulted from relay rack 1-R-15 i

breaker tripping which resulted in the closure of steam generator (SG) #1

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main feedwater regulating valve and a reactor trip from flow mismatch in

conjunction with low SG 1evel. The licensee's corrective actions appear

to be acceptable.

327/86-26, Standby diesel generator start when sudden pressure relay

failed on common station service transformer (CSST) D. Due to the loss of

CSST D and the resulting undervoltage condition sensed on the shutdown

boards, all four standby diesel generators received a start signal. Power

was returned to the shutdown boards prior to the diesels loading onto the

boards. The licensee's corrective actions appear to be acceptable.

10. Event Followup (93702, 62703)

During the inspection period, an investigation was conducted of three

separate events that have occurred at Sequoyah. Eaca of the events

involve the leakage of primary coolant from the Reactor Coolant System

(RCS). Each of these events was investigated in depth by two separate

review committees appointed by the licensee. The on-site review committee

was appointed by the site director and consisted of inter-disciplinary

members that were headed by the supervisor of the plant operations review

staff (PORS). The resultant report by that group is referred to as the

PORS report. A second, independent review group was appointed by the

Manager of Nuclear Power, and consisted primarily of individuals assigned

to the nuclear manager's review group (NMRG). Both review groups used TVA

personnel as well as consultants to assist in their investigations. The

NRC investigation effort encompassed an independent investigation of the

three events as well as a review of the scope, methodology, and results of

the TVA investigations. The first two events occurred on January 28,

1987, and February 1, 1987. Both review groups were chartered to perform

investigations into the events after the second one occurred. The third

event took place on April 29, 1987, and was investigated by a third group j

consisting primarily of P0RS personnel,

a. The first event occurred while the RCS was partially drained to allow

for steam generator (SG) primary side maintenance. The sight glass

used to determine RCS level became plugged by debris and corrosion

products. The unit operator (V0) was unable to determine the exact ,

level by use of an installed TV camera and monitor, and sent an '

Auxiliary Unit Operator into containment to verify level in the sight

glass. The AU0 reported that level was 11 inches higher than the

previous recorded level. The U0 decided to lower the level in the

RCS back to the normal control level. This was accomplished over the

next 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> by increasing the letdown flow rate while holding the

charging rate constant. The U0 did not realize that the sight glass

was plugged and was not responding properly. The observed level

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decrease over this period was only 2 inches in the sight glass while

the' actual RCS level decreased approximately 18 inches. The level

decrease was terminated when the RHR pump displayed signs of cavita- 1

tion and loss of flow, indicating that the actual level dropped below l

the minimum for adequate RHR pump suction. When this occurred, the

U0 stopped the running RHR pump, and began increasing level to gain

RHR shutdown cooling to the core. His primary concern at that time

was to restore adequate level to enable the resumption of RHR flow.  ;

The UO realized that the sight glass indication was misleading, but '

nevertheless continued to increase level based on that indication.  ;

Personnel monitoring' the SG work by a separate TV monitor observed

the RCS level beginning to rise in the primary channel head through ,

the open manway door. They phoned the control room and told the UO

of the imminent spill of water out the manway. The U0 secured from

increasing the level, but the water continued to rise for approxi-

mately 3 minutes after the charging stopped. This resulted in .

approximately 500 gallons of RCS water being spilled out the open I

manway. There were no personnel injuries or contamination associated

with this event.

b. The second event occurred while the RCS was still partially drained . -%

and open at the primary side manway for SG repairs. The U0 on shift

was stroke-time testing valves on a scheduled surveillance interval.

The surveillance instruction in use for this evolution was SI-166.3,

Full Stroking of Category "A" and "B" Valves during Cold Shutdown.

The list of valves included FCV-63-1, the refueling water storage

tank (RWST) isolation valve. This valve isolates the RHR pumps from '

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the RWST, and is shut while the RHR system is aligned to the RCS for

shutdown cooling. With the RCS depressurized, opening this valve

would result in RWST water filling the RCS through the RHR suction

line connected to RCS loop 4, due to elevation head differences. I

The inspector interviewed the U0, shift engineer (SE) and assistant

shift engineer (ASE). As as result of these interviews, the inspec-

tor determined that the U0 knew that this potential for flooding the

( RCS existed, and that the procedure used did not include the appro-

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priate isolation of the RWST from the RCS prior to opening FCV-63-1.

Additionally, administrative instructions associated with hold orders j

were not utilized to assure proper isolation of the RWST from the

drained opened steam generator. The UO knew the procedure was

inadequate in that all valves required for isolating the RCS from the

RWST were not included in the procedure, but did not stop the test as  !

required and get the procedure corrected. Instead, the U0 informally

changed the procedure by closing what was thought to be the appropri-

ate isolation valves. The U0 did not refer to a flow diagram, but '

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relied on memory alone to construct a lineup. Neither of the two

l series RCS suction isolation valves were included in the isolation

) process. As a result, there was a direct flow path from the RWST to

l the open depressurized ECS when FCV-63-1 was opened during the stroke

test. The RCS was imnediately filled, and water began flowing

l rapidly from the open ranways. The event was terminated by reclosing

l FCV-63-1. Approxir..s i.e ly 3000 gallons of water was spilled and 1

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"several workers in - containment were wetted down. No injuries l

occurred and no personnel contaminations were identified.

SI-166.3 ' was not~ adequately established in that changes to the l

instruction were necessary for the conditions in effect at the time j

of the test to prevent draining the RWST to the open steam generator. i

The instruction was nevertheless used by the operator to perform the

stroke-time testing of valve 1-FCV-63-1. The operator attempted to l

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make the instruction usable by performing an informal, unreviewed

change to the instruction in the form of additional valves that were

repositioned in an attempt to isolate the RCS from RWST. Changes and 4

revisions to plant instructions are controlled by Administrative

Instruction (AI)-4, " Preparation, Review, Approval and Use of Plant

Instructions." The operator did not implement this instruction. j

Instead, an improper uncontrolled change was implemented to modify

SI-166.3. i

c. The third event on April 29 1987, was a result of valve misalignment

of a normal system configuration that did not get entered on the

configuration log as a deviation from normal position. Prior to this

RCS spill, the operators were refilling the RCS after the SG work had

been completed. The refill was to be followed by pressurizing the

RCS to 325 psig, the minimum pressure for RCS pump operation. The

reason the pumps were to be run, was to " sweep" air and gasses

through the system to allow thorough venting. The operators had

checked the configuration log for deviaitons from the normal RCS

lineup, but one valve (68-594, the pressurizer spray line drain

isolation valve) was open which was not listed as a deviation in the

configuration log. As water level in the RCS was raised, air and

gasses were being vented through a power operated relief valve

(PORV). When water began flowing through the PORV, the operator shut

it and continued charging water to raise RCS pressure to 325 psig.

When the RCS pressure began rising, water flowed out the open 68-594

valve, through an attached hose, onto the side of the pressurizer,

and down onto the containment floor. There was no indication of

leakage until an auxiliary reactor building floor and equipment drain

sump level alarm occurred. This sump receives water from floor

drains, among several other sources. The operators checked the sump

level indicators, found level above normal, but thought that the

source of water to the sump was probably instrument sense line

leakage, and continued the pressure increase. After reaching 325

psig, the operators began matching charging and indicated letdown

flow rates to stabilize RCS pressure. When this was done, however,

pressure began decreasing immediately, because of the unidentified

leakage out of valve 68-594. Several attempts at matching charging

and letdown yielded the same result. This was postulated as a

calibration error on the charging line flow rate instrument, which

had a work request written on it for recalibration. Approximately 30 1

minutes later, a high containment moisture alarm occurred. At this l

point the operators realized a leak existed. They immediately began j

depressurizing the RCS and investigating the location of the leak.

Water was observed streaming from the hose attached to valve 68-594.

An operator shut the valve and terminated the leak. Approximately

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5000 gallons had spilled onto the containment floor. No personnel

injury or contamination occurred.

10 CFR 50.72, Immediate notification requirements for operating

nuclear power reactors, states in section b.2.(1) that the licensee

shall notify the NRC as soon as practical and in all cases within

four hours of the occurrence of any event found while shut down,

that, had it been found while the reactor was in operation, would

have resulted in the nuclear power plant, including its principal

safety barriers, being seriously degraded or being in an unanalyzed

condition that significantly compromises plant safety. In this

specific example, the leak event would have been classified as a

small-break loss of coolant accident (LOCA). If an equivalent leak

had occurred at operating conditions, it would have also exceeded TS 3.4.6.2 allowance for unidentified RCS leakage. In this instance,

the " event" is the leak itself, not the precursor of a misaligned

valve.

10 CFR 50.72 states in section b.2.(vi) that four-hour reports shall

be made for any event or situation, related to the health and safety ,

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of the public or onsite personnel, or protection of the environment,

for which a news release is planned or notification to other govern-

ment agencies has been or will be made. Information related to this

event was made available for release to the news media by the

licensee in the form of an input to the licensee's wire service

(referred to by the licensee, as the " Knoxville News Tape"). This is

considered to constitute planning for a news release and necessitates

reporting the event under this section of 10 CFR 50.72 as well.

Contrary to the above requirements, no report was made to the NRC

within the time frame specified. This is a violation (VIO) 327,

328/87-24-03.

An NRC review to determine if these three events shared common root causes

was conducted. It was determined that all three events, along with others

which have been identified during the time frame of inspection report

327,328/87-30, resulted from inadequate or unimplemented procedures.

Areas of concern include valve alignment, configuration log use, procedure

change control, hold order and and caution order use, and testing control.

This wil be followed as unresolved item 327,328/87-24-04.

11. IE Information Notices a'nd IE Circulars (92701)

The inspector reviewed the following IE Circulars, determined that they

are not applicable to Sequoyah, and closed them.

IEC 79-01-06, Failure to use syringe and bottle shields in nuclear

medicine

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IEC 79-CI-07, Unexpected speed increase of recirculation pump MG set

resulted in power increase

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12. IE Bulletins (92701)

IE Bulletins are documents issued by the NRC which require certain

specific actions of the addressee. The inspector reviewed the following

IE bulletin, determined that it was not applicable to Sequoyah, and closed

it.

IEB 79-80-22, Possible leakage of tritium gas used in time pieces for

luminosity

Based on discussions with Region technical personnel and the fact that IEB

77-BU-07 (Containment electrical penetration assemblies at nuclear power

plants under construction) was closed for unit 2, IEB 77-BU-06 (potential

problems with containment electrical penetration assemblies) is also con-

sidered to be closed for Unit 2.

13. New Employee Concerns Program

The New Employee Concerns Program was commenced by the licensee on

February 1, 1986, in order to address all employee concerns identified

after that date. Employee-raised concerns about safety and quality have

been determined by the licensee and the NRC to be issues that need to be

evaluated prior to the startup of either unit.

The scope of this inspection was limited to the New Employee Concerns .

Program as implemented at Sequoyah, and did not address in any detailed j

manner the Watts Bar Special Program or the New Employee Concerns Program l

(NECP) as implemented at other TVA sites. The inspectors did ubserve that l

generic and/or Sequoyah specific concerns generated in the NECP at sites l

other than Sequoyah, did get evaluated in the Sequoyah NECP. The

inspectors reviewed the following NECP procedures to determine the

adequacy of the licensee's New Employee Concerns Programs.

ECP-SR Procedure 1, Revision 5 - Site Representative Procedure 1

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ECP-SR Procedfre 4, Revision 1 - Identification of Employee

Concerns that are Potential Restart Items (Sequoyah)

In addition to the above procedures, a memo dated March 13, 1987, Restart

Requirement Criteria, and an Office of Inspector General (OIG) audit of ,

September 1986 were reviewed. The inspectors were also briefed by the l

licensee on an anticipated change to the NECP scope and administrative i

process that will be incorporated into the NECP in response to the above I

mentioned OIG audit and NRC inspection report 327, 328/86-52.

The inspectors reviewed the following NECP concerns and open files. The

licensee has defined an open file to be "an issue brought to the attention

of the NECP which can be resolved informally and is not an employee

concern." These open files generally fall into the category of an issue

that has been referred back to the line organization for resolution with

the full support of the person who originally brought the issue to the

NECP. An open file will be tracked to various stages of completion by the j

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NECP depending, on the. complexity and scope' of the open file.- Approx-

-imately.~ 1,000 concerns and open files exist, of which approximately 120  ;

are concern files.

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CONCERNS' OPEN FILES

ECP-86-SQ-015-01 ECP-86-SQ-060 through 065

ECP-86-SQ-044-01 ECP-86-SQ-070

ECP-86-SQ-111-01 ECP-86-SQ-291 'i

ECP-86-SQ-125-05 ECP-86-SQ-420 j

ECP-86-SQ-046-01 ECP-86-SQ-514 i

ECP-86-SQ-252-01 ECP-86-SQ-638-

'ECP-86-SQ-441-01 ECP-87-SQ-097

ECP-86-SQ-496-01 ECP-87-SQ-149

ECP-86-SQ-554-01 ECP-87-SQ-153

ECP-86-SQ-709-03

ECP-86-SQ-254 01

ECP-86-SQ-303-01

ECP-87-SQ-135-01

ECP-86-SQ-258-01

Neither the licensee nor the inspectors identified any concern fi;1e items

which appeared to require corrective action prior to the startup of either

unit. The licensee identified two startup related. items that originated .

at another TVA site and were incorporated in Sequoyah site open files.

The two startup related items were identified in open files ECP-87-SQ-241' )

and ECP-86-SQ-350, .and concerned seismic loading on conduits and 6.9 KV i

The licensee has included the

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. electrical calculations 'respectively. l

resolution 'of these items' in the condition : adverse to quality (CAQR)

system identified as SQT870626 (SAL 0164). S. ,

The inspectors rev'iewed previous NRC inspection [ completed' on the NECP.

The following reports were reviewed to determine if the 1Neensee had

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addressed previously identified NRC open items.and comments.

50-327, 328/86-29 .

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50-390/86-15- ,

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50-327, 328/86-52 j

The following open items are considered closed.

(Closed) Inspector Followup Item (IFI) 327, 328/86-52-01, Confidentiality  !

(Closed) IFI 327, 328/86-52-02, Resolution of generic issues

(Closed) IFI 327, 328/86-52-03, Justification for non generic items

(Closed) Inspector comment 327, 328/86-29, Linkage between'the NECP and  ;

the Watts Bar'special program

The NECP appears to be well run and adequately staffed. The facilities i'

and staff support appeared to meet the needs of the NECP staff. The

inspectors identified no NECP items or issues which would prevent the

startup.of either units. l

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14. Drawing' Control Inspection

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A special inspection.:of plant' drawings was conducted to verify accuracy, l

usability, control' and distribution of plant drawings and changes to the '

drawings' ~~ Inadequate drawing control in the p'ast caused the licensee to

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ins.titute a short term corrective action program as a startup prerequisite ,

and a long, term program for total resolution of the problem.

The short term commitments' for. restart are described in a December 12, j

1986 -letter ' from R. ' L Gridley (TVA) to J. N. Grace (NRC). - This program - l

was to correct. legibility and accuracy problems for a group of drawings'

the licensee . selected as required for startup and operation of Unit 2.

The inspector was unable to determine the criteria used to select this set

> of drawings. .. The drawings were selected by operations personnel using

their ' judgement with no documented guidelines or other criteria. For the

selected drawings the licensee has completed such corrective actions as ,

restoration .of' illegible sections, removal of extraneous markings, and -  !

integration of .the Unit 1 'and Unit 2 drawings into single as-constructed

drawings.that'are applicable to both Units. It is the licensee's position

that the restart commitment for drawings has therefore been completed. .In

the absence of some documented criteria for . selection of the list of .

drawings to'be repaired, the . inspector cannot conclude that the program .is

currently satisfactory for restart. The licensee's continuing drawing

restoration program should complete the upgrading activities for all

primary drawings by mid summer 1987 and consequently should precede the

currently scheduled restart date. The scope of primary ' drawings is

described below. The inspectors consider that repair of all primary

drawings prior to restart will provide for adequate drawings during the

restart evolution.

Primary drawings are defined in Administrative Instruction (AI)-25,

Part I, " Drawing Control" as all drawings which are necessary to startup,

operate, and shutdown the plant. Drawings for both emergency and normal

shutdown are to be included.. Primary drawings are located in the unit

control rooms and are referred to during daily operation of the plant. A l

list of these drawings is included as an attachment to AI-25. The opera- '

tions superintendent maintains control over which drawings can be added or

deleted from the list. As part of the restart drawing program, many

drawings previously included on the primary drawing list were removed and

the drawings were physically removed from the control room. While these

removed drawings are still available to the operators, (being located just

outside the control room), availability to the Technical Support Center l

(TSC) and the Chattanooga Emergency Control Center (CECC) is a concern.

This relates to the licensee's category of critical drawings. Critical

drawings are also identified in'AI-25 and are drawings depicting features l

which are used by the plant TSC and the CECC to determine system operation i

and function. These drawings are for use in an emergency to analyze ,

problems and make recommendations for the mitigation of an accident. The I

types of drawings to be maintained as critical drawings includes

schematics, electrical, control and logic, flow, structural, and equipment

arrangement drawings. Critical drawings are a subset of primary drawings.

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Y In other words, c'f the list of primary drawings contained in AI-25, a

sn211 fraction of these are identified as critical drawings. This makes

t/ mandatory that the definition of primary drawings include critical

drawings ut a subset. The question arises as . to whether the recent

nduction$ in primary drawings also removed some critical drawings. Since

the Emerde'ncy Preparedness Group within the Division of Nuclear Services

is retpgnsible -for the list of critical drawings, coordination between

this group and Plant Operations is essential. An apparent weakness was

detectec in 61s area by the inspector during a tour of the CECC. The

CECC is maintaining 47W200 Series of drawings, which are equipment

arrangement drawings. The set maintained by CECC was not controlled and

was in fact, stamped "This drawing expires after December 14, 1986."

The inspector became aware of a licensee finding that questions the l

adequacy of the primary and critical drawing list. This finding was  !

identffied in TVA Employee Concern Special Program Report Number 206.1(B)

Revision 1. Finding f states that "it appears to the evaluation team that

the primary and critical drawings listed in the drawing control instruc-

tions do not meet the as-built drawing criteria of NUREG 0737 Supplement 1

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or of NUREG 0696". The issue was judged to be beyond the scope of the l

report, which was not prepared to evaluate TVA's compliance with

regulatory requirements for emergency response capability. The licensee's

compliance organization stated that this adverse finding was not trans-

ferred to any other program for resolution. The inspector informed

licensee _ management during the exit meeting that this would be an

Unre wlad Item (URI 327,328/87-24-01) pending resolution of the apparent

noncompliance with the Order Confirming Licensee Commitments on Emergency i

Response Capability issued January 15, 1984. l

In the, area of management control, another apparent inconsistency should

be addressed by the licensee. In TVA's Corporate Nuclear Performance i

Plan, one of the contributing causes of the management breakdown is l

identified as a failure to implement the overall nuclear program on a

consistent basis. This was due to the division of authority and respon-

sibility throughout many groups with autonomous organizations. TVA

restructured itself to provic'e strong central leadership and control, yet

in the area of drawing control Brown's Ferry (BFN) and Sequoyah (SQN)

plants are heading in totally opposite directions prior to restart. At

SQN, drawings which were previously unitized (a drawing applicable for

Unit 1 and a separate draw hg applicable for Unit 2) are being combined (a

single drawing applicable to both units). At BFN, drawings which were

previously combined are being unitized. Discussions with engineering

representatives (DNE) at SQN indicated that in the long term, SQN would

eventually revert back to unitized drawings in a new Configuration Control

Drawing (CCD) system. However, this was not formally documented on any of

the drawing ccqtrol program plans. j

Of the drawings repaired and re-issued by the licensee for restart, two

areas of concern were detected. First, the problem inherent to combining 1

drawings is that when mit specific differences exist in the as-built j

systems, the drawing ret accurately depict the difference. Several {

examples were found in, which neither the inspector nor operators could i

ascertain the difference, This comes from the practice of using an arrow l

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with a note that indicates that a particular feature or component only

exists on' one unit and not the other. The boundary is not clearly

depicted, such that how much of the feature or how many ' components the

note is applicable to is readily apparent. The second problem relates toc

the interim process of marking up control room drawings with red or green

markers following a modification to the system. These marked up drawings

are made available to the op rator until. permanent changes are completed.

Numerous errors were detected in this " red-line" process by the

inspectors. Additionally,,the inspectors noted that no independent review

was conducted by the licensee of this drawing change process. This

appears to be contrary to 10 CFR 50, Appendix B, Criteria VI. Information

made available to the inspectors just prior to the inspection exit meeting

indicates this issue may be licensee identified.. Until that is deter-

mined, this item ~ will be tracked as an Unresolved Item (URI 327, 328/

87-24-02) as a _ potential violation of 10 CFR 50 Appendix B, Criteria VI,--

Document Control. Resolution of this deficiency is considered by the-

inspectors to be required prior to restart.

Examples of errors in the red-line process were found on the following

drawings:

1. 47W839-1, Flow Diagram, Diesel Starting Air

2. 47W813-1, Flow Diagram, Reactor Coolant System

3. 47W809-1, Flow Diagram, Chemical and Volume Control System

4. 47W810-1, Flow, Diagram, Residual Heat Removal System

5. 47W610-26-3, Mechanical Control, High Pressure Fire Protection

-System

6. .45N772-4, 480-V, MCC Wiring Diagram

7. 47W610-30-4&8, Mechanical Control, Containment Ventilation

8. 47W610-31-9, Post Accident Sampling HVAC

Examples of unclear depiction of the differences between units were found

on the following drawings:

1. 47W804-2, Flow Diagram, Condensate System

2. 47W813-1, Flow Diagram, Reactor Coolant System

3. 47W812-1, Flow Diagram, Containment Spray i

4. 45N765-11, 6.9 KV Shutdown Auxiliary Power Wiring Diagram

Additional miscellaneous drawing problems observed during the inspection

are listed below:

1. One drawing (recently issued) was found with legibility problems

caused by the reproduction process (35N711-1 R9).

2. Spurious red and orange markings were -found on 47W809-3. This

could be confused with the red-line process.

3. Drawing 47W809-5 (Unit 2) shows Temporary Alternation number  !

84-2002-62 installed. No such alteration could be located. The i

correct number was determined to be 84-2004-62. I

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~4. Uncontrolled paper copies of . drawing 45N772-4 and 47W610-26-3

'were found~in the control room mylar drawing. set.

5. Between 25% and 40% of the drawings reviewed in the CECC had

. legibility problems. In particular, drawing 47W812-1 Rev.11, i

Flow Diagram For Containment Spray, was completely unusable.  !

The. root cause ' appears to be serial reproduction. l

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6. A perfunctory check of the TSC' drawing set revealed some missing

drawings in the 45N703 series.

.The inspectors consider that these deficiencies require correction prior

to restart.

The inspectors reviewed and closed the following IFIs based on review of

the short-term (interim) drawing control process now in place at Sequoyah:  !

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(Closed) IFI 327,328/86-20-06, Accura'cy of Control Room

Drawings.

• (Closed) IFI 327,328/86-37-07, Drawing Control

(Closed) IFI 327,328/86-49-04, Review Problems Caused By Main-

taining Unitized-Prints When They Show The Same Equipment.

15. Sequoyah Operability Look Back Review

As a result of violations identified in Inspection Reports 50-327,

328/85-45 and 50-327,328/86-37 regarding the adequacy and timeliness of

corrective actions for repetitive equipment failures and out-of-tolerance

conditions, Sequoyah recently implemented a tracking and trending program.

From conception, this new tracking and trending program was geared towards

identifying present and . future deficiencies. Consequently, during an

October.29, 1986 meeting with TVA, a discussion took place involving

previously expressed NRC concerns over potential operability questions

resulting from past undetected repetitive failures. This resulted in a

TVA commitment to establish and submit their plans for an operability

"look back" review.

Under the control of the Technical Assessment Group of the Plant Opera-

tions Review Staff (PORS), the Sequoyah ' operability' look back review was

conducted from December 1,1986, through March 19, 1986, and involved the

expenditure of approximately 7,500 man-hours by its 30 person staff. It

was designed to identify adverse conditions associated with equipment

operability, evaluate the conditions for significance with respect to

safety, document the existence and effectiveness of corrective actions,

and propose additional or modified corrective actions where necessary.

.This was accomplished by analyzing data and information collected from:

(1) units 1 and 2 maintenance related potentially reportable occurrences

(PR0s) from 1980 through 1986 which fell under cause codes "B" (Design,

Manufacturing, Construction / Installation), "E" (Component Failure), and

"X" (Other); and (2) interviews' of senior plant engineers from operations,

maintenance, and PORS. There were 132 plant employees interviewed,

identifying 355 conditions associated with equipment operability problems.

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In addition, there were 1,917 PR0s examined, of which 1,569 were asso-

ciated with equipment operability, and were therefore assessed during this

review effort.

The review process identified and evaluated 651 equipment operability

issues involving 62 separate plant systems and 9 generic equipment groups

(i.e.,ASCO,Foxboro,etc.....). An individual issue summary package was

prepared for those plant systems and generic equipment groups involved.

Of the 587 issues involving safety-related equipment, 135 concerned

conditions where no corrective action had been previously identified, or

additional corrective action was recommended. There were 72 issues found

to have corrective actions identified, but not yet completed. From these

207 issues, 44 conditions, with corrective action recommendations, were

identified to plant management for resolution prior to restart. These

issues involved: condenser vacuum exhaust flow; upper head injection

(UHI) instrumentation and valves; ice condenser "I" beam seismic qualifi-

cation; instruments plugged into wrong plug molds; adequacy of RHR bypass

flow analysis; electric board room and main control room cooler valves; ,

defective or missing penetration room cooler dampers; containment hydrogen

analyzers; reactor coolant pump sealwater injection lines; replacement of

specific Foxboro transmitters; essential raw cooling water (ERCW) and

component cooling system (CCS) containment isolation check valves; diesel

generator (DG) governor connector plugs; steam generator (SG) blowdown

containment isolation valves; safety injection (SI) flow indicators; plant

electronic transmitters; EQ operators; SG power operated relief valves; GE

transmitters installed with vents on bottom and sense lines on top;

installation problems associated with compression fittings; air regulators

on auxiliary feedwater bypass level control valves; auxiliary air com- .

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pressor failures; non-essential use of essential air system; seismic

qualification of auxiliary control air pressure switches; sticking sample

valves; ice condenser lower inlet door leakage; ERCW supply valves to ,

diesel generators; CCS flow balance; CCS cavitation problems; radiation

monitoring pump failures; auxiliary feedwater level control valves;

motor-driven auxiliary feedwater pump bearings; auxiliary feedwater (AFW)

flow modifier calibration problems; AFW steam supply swapover pressure

switches; high pressure cold leg accumulator pressure switch; agastat

relays; emergency gas treatment system (EGTS) damper response times;

shield and auxiliary building stack flowrate monitor transmitter;

auxiliary building gas treatment system flow controllers; pressurizer loop

seal heat trace; EGTS cooldown valves; radiation monitor vacuum switch

calibration problems; unit I condensate reservoir; pressurizer level

transmitter; and chemical volume control recirculation flow control valve

timing.

The NRC inspection and assessment of the Sequoyah operability look back

review program was performed during the week of April 27, 1987. This ,

assessment involved a detailed review of the issue summary packages that '

were prepared for systems 87 (UHI) and 67 (ERCW). Selected reviews were

also conducted of issues contained in summary packages prepared for

systems 63 (SI), 82 (DG), and generic equipment (ASCO), as well as of the

44 restart items discussed above. Additionally, interviews were conducted

with lead review engineers (2 of 4), the project manager and his j

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assistant, members of Sequoyah's restart task-force, and the tracking and i

trending program manager.

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Collectively, the inspection finding inputs indicated that the scope,-

guidelines, and implementation of the - Sequoyah operability look back

review program ~ satisfactorily accomplished its intended purpose. Its-

identification of existing equipment operability and reliability problems

re-emphasizes the need for the' newly implemented tracking and trending

program. Operability issues identified by the 'look back' program which

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involved safety injection relief valves and ~ containment isolation valves,

indicated that the sliding-window time span being used in the tracking and

trending program -to - detect repetitive equipment deficiencies was too

small. The time. span has subsequently been , increased to assure the

tracking and trending program will identify such 1tems in the future.

Because the tracking and. trending program has been established to identify

future repetitive equipment failures 'and ~ the issues identified by the i

operability look back program are to be corrected and tracked to comple-

tion, the findings of the look back program are not being fed back into t

the' tracking and trending program. Consequently, it was recommended to  !

the licensee that the operability look back issue summary packages be made

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readily available to those groups designated to ~ evaluate future deficien-

cies which are -identified by the tracking and trending program. The

licensee' concurred.

With respect _to the implementation of the look back corrective action

recommendations for'the 207 issues involving safety related- equipment, the

corrective actions associated with the 44 restart issues have been

encompassed by line item 930 of the Sequoyah activities list (SAL), with

individual actions being tracked on the P-2 schedule. At the time of the

inspection, there was no formalized method established to ensure timely

disposition and completion of the remaining non-restart corrective action

recommendations. The licensee indicated that 'such a program will be

established under the responsibility of the Technical Assessment Group of

PORS.

NRC's review of the identified issues also revealed that for some of the.

restart issues, as well as for several others, compensatory measures were

used .as interim corrective action to justify system operability for i

restart. NRC indicated to the licensee that such reliance on compensatory '

measures may not be appropriate. A case in point, involves the use of an

assigned watchstander to open and/or verify open the normal ERCW supply

valves to the emergency diesel generators to preclude further failures of

the valves to automatically open when the diesels are called upon to

start. . The look back recommendation identified valve operator replacement

prior to restart. Seismic analysis of these larger, more powerful

limitorque operators has the potential to delay a July restart.

Therefore, the interim compensatory corrective action is specified for

restarting the unit. It was also pointed out to the licensee that their

present restart criteria does not reflect the use of compensatory measures

to consider systems or equipment operable. The inspector requested a

complete listing of issues where the restart evaluation was based on

compensatory measures and justifications for operation. This issue, along

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with the.: final' disposition . of the' non-restart issue recommendations will .

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.be. inspected at a'later date during the restart readiness inspection.

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No violations or de'iations

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