ML20151X879

Replacement Insp Repts 50-327/85-46 & 50-328/85-46 on 851209-13.Violation Noted:Surveillance & Sys Operating Instructions Inadequately Maintained & Review of Measuring & Test Equipment Not Formally Conducted

ML20151X879
Person / Time
Site:	Sequoyah
Issue date:	01/28/1986
From:	Bearden W, Ignationis A, Ignatonis A, Jenison K, Shymlock M, James Smith, Weise S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20151X795	List: ML20151X790 ML20151X828 ML20151X879
References
RTR-NUREG-1154 50-327-85-46, 50-328-85-46, GL-85-13, IEB-85-002, IEB-85-2, NUDOCS 8602120530
Download: ML20151X879 (24)

See also: IR 05000327/1985046

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C Dio UNITED STATES

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NUCLEAR REGULATORY COMMISSION

REGION li

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• 't ATLANTA, GEORGI A 30323

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Report Nos.: 50-327/85-46 and 50-328/85-46

Licensee: Tennessee Valley Authority

6N38 A Lookout Place

1101 Market Street

Chattanooga, TN 37402-2801

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

Facility Name: Sequoyah Units 1 and 2

Inspection Conducted: December 9, through December 13, 1985

Irsoectors: d d, f- ams b //3 7b 4

A. J. Ignatonisy Inspection Team Leader Da'te Sf gned

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04te S(gned

K. M. Jenils'on, Sepior Resident Inspector

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Dite Signed

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W. C. Beard (f, Res1 gent I'nspector

d0 - ~$i, //27lW

J. D. Smithf/InspectJbri Specialist, OIE Date Si'gned

M.B.ShymloqK

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Date Si'gned

enioJResidentInspector

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Approved by: L

S. P. Weise Section Chief Date Signed

Division of Reactor Projects

SUMMARY

Scope: This special, announced inspection involved 210 inspector-hours onsite in

the areas of 50.54(f) letter followup and operational readiness verification

including, NRC Bulletins and Notices, Corporate and Sequoyah Nuclear Plant

Commitment Tracking Systems. Operating Experience Review, Reactor Trip Reduction

Program, Modifications, Surveillance Instruction review, and licensee's evalua-

tion of the Davis-Besse Event described in NUREG-1154

Results: In the areas inspected, three violations with multiple examples were

identified:

1. Failure to establish and maintain adequate surveillance and system operating

instructions-(paragraphs 6.a. 6.b., and 10.a.). j

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8602120530 060127

PDR ADOCK 05000327

0 PDR

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2. Failure to implement procedures (paragraph 6.a).

3. Failure to conduct adequate PORC reviews (paragraph 10.b.).

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REPORT DETAILS

1. Licensee Employees Contacted

• • H. L. Abercrombie, Site Director

• P. R. Wallace, Plant Manager-

• L. M. Nobles, Operations and Engineering Superintendent

• B. M. Patterson, Maintenance Superintendent

• J. M. Anthony, Operations Group Supervisor <

• L. C. Bush, Operations Group Assistant Supervisor I

• R. W. Olson, Modifications Branch Manager

• M. R. Sediacik, Electrical Section Manager, Modifications Branch

• L. D. Alexander, Mechanical Section Supervisor  !

• M. A. Skarzinski,-Electrical Maintenance Supervisor '

• H. D. Elkins, Instrument Maintenance Group Manager

G. B. Tiner, Instrument Maintenance Engineer j

• M. R. Harding, Engineering Group Manager j

D. C. Craven, Quality Assurance Supervisor j

• G. B. Kirk, Compliance Supervisor <

• R. C. Birchell, Compliance Engineer

• R. W. Fortenberry, Engineering Section Supervisor

• R. M. Mooney, Systems Engineering Supervisor

• R. J. Griffin, NSRS Site Representative

"J. A. Dunlap, DPSO Supervisor

• C. R. Brimer, Site Services Manager

• W. S. Wilburn, Technical Services Supervisor

• J. H. Sullivan, Regulatory Engineering Supervisor

• D. L. Cowart, Quality Surveillance Supervisor

• C. E. Bosley, Quality Assurance Auditor

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

• T. E. Burdette, Quality Assurance

• R. W. Moore, Quality Assurance Manager

• C. E. Chmielewski, Nuclear Engineer

• C. L. Wilson, Nuclear Engineer

Other licensee employees contacted included technicians, . operators, shif t

engineers, security force members, engineers and maintenance personnel.  ;

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NRC Resident Inspector  !

• "S. P. Weise l

• L. J. Watson

• Attended exit interview December 13, 1985

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• • Attended exit interview telecon January 14, 1986

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2. Exit Interview

-The inspection scope and findings were summarized with the Plant Manager and

members of his staff on December 13, 1985. After Regional management

L review, a telephone exit interview was conducted on January 14, 1986, to

further present the inspection findings. Three violations with examples

described in paragraphs 6.a. , 6.b., 10.a. and 10.b. were discussed in

detail. Four unresolved items were. identified during this inspection and

are discussed in paragraphs 6.a, 8, and 10.c.*. The licensee acknowledged -

the inspection findings. Information on reactor protection setpoint

methodology was identified as proprietary, but is not incorporated in this

report. During the reporting period, frequent discussions were held with

the Site Director, Plant Manager and his assistants concerning inspection

findings. At no time during the inspection was written material provided to

the licensee by the inspector.

3. Licensee Action on Previous Inspection Findings (92702)

i (Closed) Unresolved Item 327, 328/85-43-01, Failure to Update Procedure

S0I 30.6, Auxiliary Building Gas Treatment System ( ABGTS). Inspector review

of SOI 30.6 and ABGTS walkdown identified a discrepancy in the amperage

rating of fuses specified in SOI 30.6 versus the ones installed in the local

control panel for the ABGTS humidity control heaters. The inspector

reviewed ABGTS modification made in 1984 and upgraded this Unresolved Item

to a violation. Details are provided in paragraph 6.b.

, 4. Licensee Commitment Tracking System

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The licensee's commitment tracking system was reviewed to determine its

viability, extent and implementation. The following documents were

reviewed:

a. TVA's Nuclear Performance Plan submittal dated November 1, 1985,

containing Volume 1, the - Corporate' Plan and Volume 2, the Sequoyah

Plan.

b. TVA memorandum L44 850919 805, Policy Regarding Control Over Making

Commitments To The Nuclear Regulatory Commission, Tracking Commitments

Through Implementation, and Maintaining Commitments Throughout Plant

Life - H. G. Parris, September 26, 1985.

c. TVA memorandum L44 850927 801, Policy Regarding Control Over Making

Commitments To The Nuclear Regulatory Commission, Tracking Commitments

Through Implementation, and Maintaining Commitments Throughout Plant

Life - W. T. Cottle, October 2, 1985.

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

determine whether they are acceptable or may involve violations or deviations.

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Volume 1, Section 3.2 of the Corporate Nuclear Performance Plan (NPP) states

that Sequoyah Nuclear Plant (SQN) is working on full implementation of the

corporate policy for maintaining all NRC commitments on the Corporate

Commitment Tracking System (CCTS). Full implementation of the CCTS at SQN,

was to be completed by December 31, 1985. The corporate Nuclear Licensing

Staff (NLS) was assigned the responsibility of making initial entries into

the CCTS and ensuring that they have appropriate management review and

approval.

TVA memorandum L44 850927 801 provides program guidance for implementing the

corporate policy on commitment tracking. Included in this letter is the

purpose of the CCTS and delineation of the TVA nuclear facility and Cor-

porate Nuclear Licensing Branch responsibilities. The purpose of the CCTS

is to ensure that commitments to NRC are evaluated, approved, documented,

tracked, implemented, and maintained to ensure regulatory compliance. The

SQN staff responsibilities are as follows:

a. Make and/or modify commitments to NRC relating to SQN.

b. Evaluate proposed commitments to ensure that they are necessary,

accurately defined, achievable, and sufficient to satisfy regulatory

requirements.

c. Track, implement, and maintain continued compliance of NRC commitments.

d. Maintain appropriate coordination of commitment actions with other TVA

organizations.

Although the CCTS was not fully implemented, the inspectors reviewed the

current SQN tracking system and compared it to the available CCTS. Site

input to the ft mative stages of CCTS appeared minimal. The SQN staff

appeared to have had little participation in the formative process. The SQN

staff was maintaining a separate computerized tracking system (Commitment

Action Tracking System - CATS) which they planned to use to support the

CCTS. The inspectors found that the format of the CCTS is incompatible with

CATS and that the information presented in CCTS is not detailed enough to

identify multiple facets within the same commitment. The tracking identi-

fication numbers of the two system > used different numbering schemes to

itemize commitments. Further, the inspectors found a lack of program

coordination between the corporate Nuclear Licensing Staff and the SQN )

staff. For example, SQN did not use the prescribed format for data entry i

into the CCTS. Instead, the locally generated CATS form was used. The SQN

use of the CCTS appeared to be in the input made only.

The inspector discussed the above concerns with the SQN Site Director. The

SQN Site Director acknowledged that the SQN staff does not use the pres-

cribed format input for CCTS and that there is format incompatibility I

between CATS and CCTS. The Site Director indicated that the CCTS Corporate l

policy would be properly implemented at SQN by December 31, 1985.

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As reviewed, neither the CCTS or the CATS addresses written commitments that

are completed based on exit interview information and orior to the issuance

ofgan NRC viclation response. This means a record of the commitment and its

completion.is not preserved. If a commitment . required future repetitive

actions (i.e., training, operator experience review, Health Physics audits,

etc.), these future actions would not appear in either system because the

item would be closed when the commitment was met initially.

The' definition of commitment per TVA memorandum L44 850927 801, is a written

and docketed statement of TVA actions taken or to be taken by some future

date. By this definition, written TVA commitments can encompass a variety

of subject items- which should include FSAR ' commitments, written licensee

commitments on which SER assumptions were based, responses to deviations,

and written commitments made in response to NRC/TVA meetings and NRC

letters. Hence, according to the commitment definition, the scope of-the

commitments can be very. broad. To address the potential of missed commit-

ments at SQN the licensee committed in SQN NPP, volume 2, to review past

NRC commitments back to January 1,1981, in the areas of past violation

responses, IE Bulletin responses, licensee event reports, and NUREG-0737

items. TVA will review the above items prior to unit startup.

The SQN staff was developing an implementing policy Standard Practice

(SQA-135) to support the CCTS. This procedure was in the review process at

the time of this inspection. The NRC will review this implementing policy

and verify . implementation of CCTS per SQA-135 after the program is imple- ,

mented. The licensee also had not established a system for independent '

verification of commitment completion at the time of the inspection.

The above issues constitute an Inspector Followup Item (327,328/85-46-01).

5. IE Bulletin No. 85-02, Undervoltage Trip Attachments on Westinghouse DB-50 j

Type Reactor Trip Breakers

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The inspectors reviewed the IE Bulletin and the licensee's response letter

dated December 3,1985. The licensee committed in their response to IEB

85-02 to install the automatic shunt trip modification on the reactor trip

breakers prior to the restart of each respective unit. The inspectors also

verified that the Main Feedwater System Isolation Valve, Feedwater Regula--

tion Valve, and Feedsater Regulation Bypass Valve electrical configuration  ;

were as described in IEB 85-02 (reference: drawing 47W611-3-2)_ l

Ir. conjunction with the bulletin review, the failure of the undervoltage

output circutt' boards in the Westinghouse designed Solid State Protection

System (SSPS), whf ch was addressed in IE Information Notice 85-18 was also

reviewed. The following procedures were reviewed:

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IMI 99 - SSPS, Reactor Protection System l

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TI 52, Special Instruction for Removing the SSPS from Service and

Returning it to Service. '

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IMI 99 FT 18, Reactor Protection System Functional Test

SI-227, Response Time Testing Reactor Protection System Trip Function

SI-227.1, Post-Maintenance Response Time Test of Reactor Trip Breakers

i RTA and RTB

Surveillance Instruction (SI) 227.1 requires that, after performance of

maintenance on the reactor trip breaker or when the technician has reason

to believe that damage has been done to the protection circuit, Instrument

Maintenance Instruction (IMI) 99 FT 18 be performed. SI 227.1 does not

require that this functional test be performed following trouble shooting in

the Solid State Protection System circuits. However, per the requirements

of IMI 99-SSPS, a functional test of the SSPS is performed after each

entry into the system controlled by a maintenance request. The inspector

determined that adequate procedural controls existed for verifying oper-

l ability of the reactor trip circuitry.

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6. Surveillance Instruction (SI) Verification

The inspectors reviewed the following sis which implement Technical Specifi-

cation surveillance requirements:

Surveillance Instruction Title

SI-2 Shift Log

SI-3 Daily, Weekly, and Monthly Logs

SI-6.1 Containment Building Ventilation Isolation

(100 Hr/7 Day)

SI-9 Actuation of Automatic Valves Via SI Signal

for Nontestable Boric Acid and ECCS Flow

Path Valves

SI-12 ECCS Valve Alignment Verification

SI-40 Centrifugal Charging Pump

SI-128 ECCS Residual Heat Removal Pumps

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SI-129 ECCS Safety Injection Pump Cperability

51-137.02 Reactor Coolant System - Unidentified

Leakage Measurement

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SI-143 Control Building Emergency Air Cleanup

System Filter Train Test Requirements

SI-144.1 Control Room Emergency Ventilation Automatic

Actuation

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SI-166.10 Accumulator / Injection Primary and Secondary

l Check Valve Integrity

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SI-166.18 RHR Return Valve Leak Rate Test

Si-168 Calibration of Control Room Air Intake

Chlorine Detection System

SI-240 . Functional Test of Control Room Air Intake

Chlorine Detection System

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SI-256 Periodic Calibration Overcurrent Relays

and Distance Relays on 6.9KV Reactor

Coolant Pumps on 6.9KV Unit Boards

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SI-257 Periodic Functional of RCP Overcurrent

Devices (Refueling Cycle)

l SI-258 Inspection of Molded Case and Lower Voltage

Circuit Breakers

SI-266 60 Month Circuit Breaker Inspection

SI-270 Inspection of Molded Case and Lower Voltage

Circuit Breaker Backup Fuses

SI-413 Hydrogen and Oxygen Level for Gas Decay

Tank

Additionally, the inspectors reviewed the following calibration and

operating procedures:

IMI-92-PRM-CAL Nuclear Instrumentation Channel Calibration

SOI 30.1 Control Buildir.g and Control Room Heating,

Air Conditioning, and Ventilation System

501 30.6 Auxiliary Building Gas Treatment System

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As a result of this review, concerns were noted in the following areas:

a. SI-256, Periodic Calibration of Overcurrent Relay and Distance Relays

on 6.9 kv Unit Boards

TS 3/4.8.3 for operability and surveillance of Electrical Equipment

Protection Devices and Containment Penetration Conductor Overcurrent

Protection Devices was reviewed to determine specific testing require-

ments. Major differences were identified by the inspectors between the

TS requirements for Unit 1 and Unit 2 testing of the primary and

secondary protection devices of TS Table 3.8-1:

(1) For the Unit I reactor coolant pump penetration backup overcurrent

protective devices, the licensee sets the trip setpoints at

20,000 amps instead of the 2,000 amps specified in TS Table 3.8-1.

Per discussion with the licensee, the backup device trip setpoint

values in the Unit 1 TS were identified to be incorrect, based on

the normal current load through the breaker. The backup circuit

breaker is the normal feeder breaker for the 6.9 kv unit board.

(2) The Unit I and Unit 2 primary device trip setpoint values are

inconsistent. In the Unit 2 TS, only the instantaneous trip

feature (plunger) of the primary conductor overcurrent protective

device is specifit .'or testing. The Unit 1 TS requires testing

of only the delayed primary protective device feature (rotating

disc). The inspector determir ed that the licensee tests both trip

features of the primary protective devices on each unit. The

location for the Unit 2 reactor coolant pump number 4 primary

and backup devices stated in the TS is PNL-9 on the 6.9-KV

Auxiliary Power Board 20. The devices are actually located in PNL-7

of that board.

(3) The response time values in TS Table 3.8-1 for the primary

protective devices should have units of minutes instead of i

seconds.

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(4) These TS errors have existed since initial licensing of both i

units. The licensee submitted TS change request number 62 on  !

November 7,1984, which proposed deleting TS Table 3.8-1, but did j

not address the above errors. This proposed TS cha,nge request is )

under NRC review. The correction of TS Table 3.8-1 is required

prior to unit startup and is identified as an Inspector Followup

Item (327, 328/85-46-02).

Due to inadequate and incorrect requirements identified in the current

l TS Table 3.8-1 described above, the inspectors were unable to determine

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if the intent of the TS and plant design were fully met by use of

procedure SI-256. Additionally, the licensee failed to seek correction

of TS Table 3.8-1 for an inordinate amount of time. These issues

constitute an Unresolved Item (127, 328/85-46-03) pending further

review of the licensee's testing methodology.

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SI-256 is performed to accomplish the surveillance requirement of TS 4.8.3.1.a.1(a). The most current completed SI data package for SI-256

(dated October 1,1985) was reviewed by the inspector. Item (2) in

Section I of the Acceptance Criteria of SI-256 required that the

primary overcurrent relays pickup and critical time are to be within a

tolerance of 5 percent of the trip setpoint values. However, TS for

Unit 2 primary devices on the reactor coolant pump (RCP) containment

penetrations require a tolerance of 12 percent. Item (2) also required

that the relay targets operate properly between 1.0 amp and 2.0 amp

with DC voltage applied. However, the vendor instruction manual for

the General Electric type IAC66K relay indicated proper operation to be

between 0.1 an.p and 2.0 amp. Item (3) in Section . I of the Acceptance

Criteria required that the distance relay, impedance circle show the

angle of maximum torque to be close to 75 degrees (phase angle). The

correct angle e- maximum torque was actually verified at 105 degrees,

which is the proper ' val ue . These invalid . criteria constitute a

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violation for failure to adequately establish a surveillance procedure

(327, 328/85-46-04). As part of the corrective action, the licensee

should determine if this resulted in TS setpoint violations. Further

examples of inadequate procedures are described elsewhere in this

report.

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During the review of the completed Routine Relay Test Record sheets,

the inspector identified that recorded target settings documented

target operation at 0.2 amp. Item (2) of the acceptance criteria was

.igned off and verified by a second person that the 1.0 amp to 2.0 amp

requirement was sati s fi e.d , despite the . 0.2 amp recorded value. The

inspector could not ascertain the reason ~for this discrepancy. The

inspector also found that the completed SI package had been reviewed

by both the section supervisor and quality assurance (QA). These 1

verifications / reviews of the completed SI package and signoffs did not '

identify that the acceptance criteria was not satisfied and did not

identify the procedural discrep ncies. This constitutes a violation

for failure to adequately implement the signoff and review provisions

of procedure SI-256 (327, 328/85-46-05). Additionally, several Routine

Relay Test Record sheets in the completed 51-256 data package had

numerous uncontrolled changes made to the Setting Record column

Instrument Setting parameter units. This was due to the Test Record

sheet being a generic data sheet for all relays. These procedure l

changes were not controlled per AI-4 Plant Instructions - Document

Control for control of procedure changes. Failure to implement pro-

cedure change requirements of AI-4 is a further example of violation

327, 328/85-46-05. The licensee should address corrective actions to

ensure that employees understand the need to follow procedures or

properly correct them when technical errors exist.

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b. System Operating Instruction (501) 30.6 for the Auxiliary Building Gas

Treatment (ABGT) system was compared to the as-built configuration of

the plant through inspector walkdown. The inspection was performed as

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a followup to a previous inspection of the ABGT system reported in

Inspection Report 327, 328/85-43. The inspectors noted that SOI 30.6

specified fuses of a different amperage rating than thnse that were

c-tually installed. This was identified as an Unresolved Item 327,  ;

328/85-43-01 pending review of pertinent system modifications. In

1984, the licensee approved and implemented Engineering Change Notice

(ECN) L 6278 which modified the ABGTS circuitry for humidity control.

The inspector reviewed S0I 30.6 for compatibility with these ABGTS

modifications. The procedure was found to be deficient in the

following areas:

(1) The procedure listed vent boards 2B1-B and 2Al-1 as having three

FRS 45 ampere fuses. Fif ty ampere fuses were actually installed.

The installed fuses were verified by the inspector to be the

required fuses, based on modifications performed under Engineering

Change Notice (ECN) L 6278 and Work Plan 11326. ,

(2) The procedure listed vent boards 281-B and 2Al-1 as having three

KTN 2 ampere fuses. One ampere fuses were actually installed. The

installed fuses were verified by.thc inspector to be the required

fuses, based on ECN L6278 and Work Pl., 11326~.

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(3) The procedure prescribed the position of a current block switch

which had been removed from the circuit by ECN L6278 and Work Plan

11326.

Based on these deficiencies, failure to maintain system operating

procedures affected by plant modifications is a further example of

violation 327, 328/85-46-04.

c. The inspectors selected the same sis at Sequoyah that were found i

deficient at the Watts Bar facility during SI review inspections. The

inspection findings at Watts Bar are presented in- NRC Inspection l

Reports 50-390/84-73, 50-390/85-21, 50-390/85-32, and 50-390/85-51. l

The inspectors reviewed seven sis to determine if the deficiencies

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identified at Watts Bar existed at Sequoyah. The sis reviewed were: 1

l SI-3, SI-9, SI-12, SI-40, SI-128, SI-129, and SI-144.1.

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i rev ew of these sis, the inspector determined that the Watts Bar SI l

deficiencies were either corrected or did not exist at Sequoyah, with

the exception of SI-12 and SI-144.1.

SI-12 provides instructions for Emergency Core Cooling Systems valve

alignment verification per the surveillance requirements of TS 4.5.2.

This SI did not specify verification of valve position for the two

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automatic flow path valves, LCV-62-132 and LCV-62-133, located at the

outlet of the volume control tank. The. inspector discussed this item ,

with the licensee and determined that the subject valves are verified

for position by SI-3 during the check of system boration paths.

Furthermore, these valves close upon an ECCS actuation signal. The

inspector had no further questions.

SI-144.1 controlg testing of the Control Room Emergency Ventilation

(CREV) Automatic Actuation feature. The test objective for -this SI is

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to verify that on a safety injection signal (SIS), the control room

! ventilation system automatically divert air inlet flow through the HEPA

l filters and a charcoal absorber bank. SI-144.2 requires the same type

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of verification by a radiation detector test. These surveillance

tests must be performed at least once per 18 months as required by

TS 4.7.7.e.2. Per FSAR Section 9.4, control room isolation occurs

l automatically upon actuation of SIS, indication of high radiation, and

i either high temperature, chlorine, or smoke concentrations in the

l outside air supply to the control building. Upon actuation, the

i control room emergency air cleanup fans will operate in a recirculation

mode through the HEPA filters and charcoal absorbers. The inspector

found no TS requirement to test the CREV automatic actuation on signals

other than SIS and high radiation. SI-168, Calibration of Control Room

j Air Intake Chlorine Detection System and SI-240, Functional Test of

Control Room Air Intake Chlorine Detection System, do not appear to

test the control room isolation feature on high chlorine. As a result,

l all the features that are designed to initiate control room isolation

do not appear to be tested. Further inspection to ascertain if these

features are tested by-the licensee is an Inspector Followup Item (327,

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l 328/85-46-06).

The inspectors also reviewed IMI-92-PRM-CAL, Nuclear Instrumenv.ation

Channel Calibration, and verified that the procedure calls for

independent verification during removal and replacement of instrument  :

power fuses.  !

7. NUREG 1154 (Davis-Besse Event Review) l

In response to the NRC findings of the Juna 9,1985, Davis-Besse event the '

licensee assigned a task team to evaluate the NRC Generic Letter 85-13, l

which transmitted NUREG-1154, and an INPO report entitled "The Operational '

Performance of Auxiliary Feedwater (AFW) Systems in U.S. PWRs 1980-1984".

! The inspectors reviewed TVA's evaluation of the two documents for the l

l Sequoyah Nuclear Plant. TVA's evaluation addressed the significance of the l

l Davis-Besse loss of main and auxiliary feedwater event with respect to l

Sequoyah. The INPO report was utilized by TVA to review the Sequoyah AFW  !

system for problems that have been experienced by other utilities. The j

following nine major topics were evaluated from the Davis-Besse Event:  ;

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a. Interaction of Plant Security Features and Operator Actions

The inspectors determined that the interaction of plant security

features and operator action problems which occurred at Davis-Besse

would not have occurred at Sequoyah. At Davis-Besse, the equipment

operators were dispatched to manually open valves and operate the

turbine-driven AFW pumps in which they had to cope with chained and i

padlocked accesses to the pump rooms as well as padlocked manual '

handwheels on valves. For manual control at Sequoyah, the operators

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only have to deal with normal card reader doors. Guards are available

in the vicinity with keys to open doors in the event of failure of the

card readers. None of Sequoyah's AFW valves or other components are

l located in locked high radiation areas, so accesses to the AFW valves

are not required to be locked.

b. Availability of Shift Technical Advisors (STA)

An inspector toured the control room for the purpose of observing the

designated work area and availability of the Shift Technical Advisor

l (STA). The Sequoyah STAS have a desk and file space in the main

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control room (MCR), and are generally confined to this a ea. The STA

may leave the MCR to perform his duties provided he can return withi,

l ten minutes. The inspector determined that these conditions would

l assure that the STA would be available for utilization during an

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operational event such as the Davis-Bese.e event.

l c. Reliability of the AFW Containment Isolation Valves and Other Safety

l Related Valves

Unlike Davis-Besse, Sequoyah's AFW System does not have any motor- i

operated (MO) containment isolation valves. Sequoyah has experienced

reliability problems with other MOV's in the AFW system and failure of '

the main FW isolation valves have occurred due to improper limit switch

settings. The licensee is implementing increased MOV maintenance, and 1

the Motor-operated Valve and Test System (MOVATS) is being used.

The inspector observed an operator training session conducted locally

at the Unit 1 Turbine Driven Auxiliary Feedwater Pump. The licensee

instructor adequately covered: problems experienced by operators

during the Davis-Besse event, resetting and local operation of the

Turbine Trip and Throttle Valve (TTV), and local operation of the AFW

! Steam Generator Level Control Valves. The inspector found that a

laminated sign had been installed near the TTV with a drawing of

the TTV and instructions for local resetting of the TTV following a

mechanical overspeed trip. Discussions held with management indicate

that all operators will receive training of a similar nature prior to

startup of either unit.

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The inspector examined the operator requalification training records

and noted that the program contains a requirement for annual simulator

training on a complete loss of feedwater event (normal and emergency).

The records were adequate to demonstrate that the training is being

performed.

d. Reliability of AFW Pumps

The reliability of AFW pump turbines is not as critical at Sequoyah

as Davis-Besse because of two 100 percent capacity motor-driven AFW

pumps. The AFW reliability is being further improved by the licensee's

implementation of enhancements in response to ar INP0 finding.

e. Reliability of Power Operated Relief Valves (PORV)

Sequoyah surveillance programs provide some assurance of operational

readiness of the Power Operated Relief Valves (PORV). However, it does

not provide reliability data for repeated openings and closings under

actual slow conditions, when failures have been known to occur. The

licensee does not support the NUREG-1154 suggested automatic block ,

valve closure as a potential remedy for PORV failures. The use of

Automatic block valve closure for isolation of PORV could result in the

use of the code safeties as a pressure relief path. The code safeties,

which have a history of failure to reset could then be subject to the

same multiple openings as the PORV anc rinnot be isolated. This issue

was previously reviewed by NRR for idl Item II.K.3.: regarding

automatic isolation of PORVs. By Safety Evaluation Report dated

March 27, 1985, NRR found that Sequoyah's existing system was

acceptable.

f. Adequacy of control room instrumentation

The inspector reviewed control room instrumentation including the

location of the acoustical monitoring instrumentation for detection of l

PORV operation / failure. The acoustical monitoring instrumentation for l

both units is located in the common area of the control room, approxi- 1

mately equal distance from the Unit 1 and Unit 2 controls. I

This location will be evaluated by the licensee during the NUREG-0700

control room design review. The controls, display and location of the

remainder of the control room instrumentation appeared to be accept- l

aule. I

g. Adequacy of plant procedures

This item was not assessed during this inspection.

h. Adequacy of safety system testing

The adequacy of safety system testing was assessed from the AFW system

post mcdification standpoint discussed paragraphs 8.e. and 8.f. of this

report,

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i. Acceptability of current safety assessment methods

This item was addressed in paragraph 7.c. above regarding operator

1 training on a complete loss of feedwater event and resetting of the ,

Turbine Trip and Throttle Valve. l

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Based-on the above reviews, the team concluded that licensee actions in

response to Generic Letter 85-13, combined with their AFW Reitability

Improvement Program, exceeded regulatory requirements.

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8. Design Changes and Modifications

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Selected design changes were . reviewed to ensure that the submitted and

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J 1mplemented changes were in accordance with 10 CFR 50.59 requirements and

j that licensee technical reviews were adequate. The inspectors verified that

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design changes were reviewed and approved in accordance with Technical

Specifications and Quality Assurance (QA) controls, that post modification

tests were performed when necessary, that adequate licensee record and

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! review functions were performed, that operating and surveillance procedure

revisions were made and approved in accordance with Technical Specifica-

l tions, that operator training programs were revised, that operator training

occurred prior to system startup for significant design changes to safety

{ related systems, that as-built drawings were cnanged to reflect the modifi-

! cations, and that the required 10 CFR 50.59 annual report to the NRC

, included those modifications, audited.

Administrative Instruction, AI-19 (Part IV), Plant Modifications Af ter I

l Licensing, describes the method for implementing all facility modifications.

]' Per AI-19 requirements, the Work Plan (WP) package includes such items as

the affected engineering drawings, Field Change Request, Engineering Change

Notice (ECN) or Design Change Request (DCR) that authorizes the modifica-  ;

tion, applicable Modification and Addition Instructions (M&Als), appropriate

work permits (e.g., breeching of fire barriers, concrete chipping), material ,

traceability forms, and post maintenance testing results. The selected Work l

Plan packages were reviewed for compliance with the requirements of AI-19

j by the inspectors. The modification packages reviewed were applicable to l

1 changes made in the instrumentation system, reactor coolant system, emer-

gency core cooling system, containment system, and the auxiliary feedwater

>

system. The selection of these modification packages was based on a review

of the licensee's annual 10 CFR 50.59 report submittal for 1984, dated

March 15, 1985. This submittal included a summary of all facility changes

I which the inspectors used to select modification packages for review. In

j addition, the inspectors reviewed modification packages that were completed

j in 1985.

.

The following ECNs, DCRs, and Design Modification Work Plan (WP) packagn

i were reviewed:

a. ECN L 5600, which included WPs 9598, 9519, and 9518, modified .the  !

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activating system for automatic switchover of Residual Heat Removal

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system suction from the Refueling Water Storage Tank to the containment

sump to improve reliability. ,

b. ECN L 6055, which included idP 107CS was established to install cold

over pressure protection (COP) circuitry in the Solid State Protection

System racks.

c. ECN L 5095, which included WPs 9980, 11378, and 9969 was established to

install drain and block valves for containment isolation valve penetra-

tions to allow local leak rate testing with air. No post modification

testing was required for this modification. Many of these valves have

exhibited leakage which has affected local leakrate testing results.

d. ECN L 2780, which included WP 9516, was established to install reactor

shield building penetration sleeves to support Post Accident Sampling

System installation.

e. ECN L 5842, Post Modification Test (PMT) 53, was conducted on Unit 1 to

test the Auxiliary Feedwater (AFW) System Cavitating Venturis installed

under WP 10920. PMT 53 was performed to verify that the venturis would

prever.t pump runout, that the piping vibration levels were acceptable,  ;

and that the AFW Pump would deliver 440 gpm at 400 psia S/G pressure

through the AFW bypass level control valve without motor overload.

Test Instruction Deficiency Report DN-2 for Unit 1 was written because

the piping vibration data did not meet the vibration acceptance

criteria of SQN-DC-V-13.13. The deficiency was dispositioned by

preloading piping hanger 1AFDH-345. The preload of the hanger reduced

the vibrations to acceptaFle levels.

For Unit 2, test deficiency DN-3 Identified that vibration exceeded the I

acceptance criteria in the Y-axis where displacement was 250 mils zero

to peak versus acceptable displacement of 219 mils. This deficiency

was noted at full flow conditions and less than 100 psig in the steam )

generator. For corrective action the disposition stated that pump )

operation above 440 gpm should be limited to reduce the detrimental

effects of downstream vibration to prevent hanger and instrument line

damage. The adequacy of the design is questionable since the purpose

of the venturi is to protect the AFW pump from' runout damage y to a

maximum of 650 gpm flow, and the Technical Specification bases require

the pump to provide no less than 440 gpm. At the time of inspection

insufficient data was obtained to show at what flowrate vibration

levels were acceptable. This is identified as an Unresolved Item (327,

! 328/85-46-07) pending further information from the licensee. -

f. ECN L6285, which included WP 11360, was established to replace the

motor operator of component cooling water system isolation valve

j 2-FCF-70-87 with an environmentally qualified actuator per NURF.G-0588,

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! g. ECN L5883, which included WP 11005, was established to replace and

I relocate flow and pressure switches at penetration room cooler fans in

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order to meet NUREG-0588 requirements.

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h. DCR 775, which included WP 10183, was utilized to replace existing

Solid State Protection System block handswitches (HS-63-135A, 1358,

136A, and 1368).

i. ECN L 5490, which included WP 9360, was utilized to relocate the Unit 2

Terry Turbine control panel due to temperature effects on the panel.

This package control form did not contain signatures to document

completion of drawing revisions, or'a signature for review for

Technical Specification impact by an SRO. The package appeared to be a

reconstruction of a lost original work package.

Minor discrepancies were identified during the review of Work Plans

described in paragraphs 8.a., 8.c., 8.d. and 8.f. of above. These discrep-

ancies included such items as an incomplete nameplate data form, failure to

include material traceability information, lack of signatures, and unavail-

able engineering justification for such items as severing of reinforcing

bars when making a penetration through a shield wall or using TVA standard

hanger configuration for modification requiring installation of additional

valves. The inspectors noted that the licensee was-cognizant of similar

deficiencies prior to this inspection and had made revisions to the

controlling plant modification procedure AI-19 (Part IV). For example,

, AI-19 (Part IV), Revision 11 dated August 22, 1985, added instructions

j to document material purchased (i .e. material traceability)', added the

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requirement for the Shift Engineer to make a configuration log entry when

equipment is removed from service due to a modification, and included a

checklist to ensure that the package is complete. AI-19 (Part IV),

Revision 12, provided, in part, a requirement to verify that all affected

instructions have been revised. Most of the discrepancies identified by the

l inspectors were in Work Plan packages completed prior to the implementation

of AI-19 (Part IV), Revisions 11 and 12. Therefore, the inspectors have

! concluded that the licensee har taken positive steps in improving admini-

strative control of modification packages.

The inspectors also reviewed the licensee's program for temporary modifica-

tions, lifted leads, and jumpers. The following deficiencies were

l identified:

1

a. Approximately 200 temporary alterations are currently active for

Sequoyah Units 1 and 2. This number appears to strain the administra-

tive control system effectiveness. Step 3.1 of Al-9 requires that

l where practical, plant management shall initiate a design change

request (DCR) or field change request (FCR) in accordance with AI-19 to

, eliminate the need for temporary alterations. Aithough a nanagement

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action tracking system requires routine review for the purpose of

determining justification for continued need, many temporary altera-

tions over three years old are still in place. Discussions held with

licensee employees indicated that the licensee has committed as the

result of an INPO audit to clear all temporary' alterations made prior

to January 1, 1984, before startup following completion of Unit l'

cycle 4. This is identified as an Inspector Followup Item (327,.

328/85-46-08),

b. No adequate system appears to exist to ensure that post modification

testing is accomplished during restoration of temporary modifications

that do not result in permanent modifications. This has been corrected

for recent temporary alterations, but not addressed for older altera-

tions. Revision 19 of AI-9 requires that retesting requirements be

identified on the Temporary Alteration Contral Form, but the inspector.

was unable to determine if long term temporary modifications are

covered by this requirement. This is identified as an Unresolved Item

(327,328/85-46-09) pending further review of the licensee's program.

9. Operating Experience Review

The inspectors review of the Nuclear Operations Experience Feedback Program

consisted of a review of Standard Practice SQA-26 and training documents,

and discussions with licensee personnel. Additionally, Watts Bar Nuclear

plant's Standard Practice WB6 3.13, Nuclear Operations- Experience Review

procedure, was used for comparison.

SQA-26 provided vague details on how the operating experience received

outside TVA is being processed to different departments within the SQN

organization. As a result, the inspector discussed this matter with the

SQN's Regulatory Engineering Supervisor and the Training Shif t Engineer.

The inspector was informed that TVA's Division of Nuclear Services does

receive operating experience information outside the TVA system such as '

NRC Generic Letters, IE Information Notices, IE Bulletins, INPO reports, '

and vendor letters. This information is then routed to various departments  :

including the TVA Training Center and to the Training Shif t Engineer. The i

inspector sampled the processing of several operating experience reports i

and verified that the information was being provided to the operators,

i The inspectors found that some duplication existed in the routing of lessons

l learned materials to different sections. The inspectors reviewed the modi-

fications performed during Units 1 and 2, cycle 2 refueling outages.

, Selected modifications which af fected plant operation from the control room l

j were traced through the trainfog process to ensure that the operations staff

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was trained prior to plant startup. For the cases reviewed, appropriate

training was provided prior to' plant startup. Implementation ' of the ,

operating experience feedback program was found acceptable. I

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10. Westinghouse Setpoint Methodology Verification

The Westinghouse Setpoint Methodology (WSM) for the Sequoyah Nuclear Plant

(SQN) established the appropriate margin between the actual Technical

Specification setpoints used for reactor protection system instrumentation

l and the setpoints required to meet the Technical Specification safety

! limits. The margin is calculated by conservatively estimating the errors

associated with the reactor protectio _n system instrumentation and actuation

of the protection equipment. One of the sources of error evaluated was the

l accuracy of the Measuring and Test Equipment (M&TE) used to calibrate the

I

reactor protection system instrumentation.

l

l On April 15-19, 1985, an NRC inspection at Watts Bar Nuclear Plant (WBN)

l identified that certain inconsistencies existed between the calibration

l accuracy of the M&TE used to calibrate Solid State Protection System (SSPS)

equipment and the accuracy of the M&TE assumed in the WSM. These inconsis-

tencies were such that the safety margins for at least two parameters at

Watts Bar (WBN), including containment pressure, were in doubt. The

licensee's review of this discrepancy identified that Sequoyah Nuclear Plant-

was potentially affected. Information on the inconsistencies between the

WSM and the calibration M&TE used at WBN was provided to the SQN staff at a

meeting with SQN, WBN, and Westinghouse on May 7, 1985,

a. Accuracy of Measuring and Test Equipment (M4TE)

The incorporation of the WSM into the calibration procedures for the

SON Solid State Protection System (SSPS) was evaluated. The WSM

assumed that the M&TE had an accuracy of ten times that of the equip- '

ment being calibrated. The WSM referenced a Scientific Apparatus

Manufacturers Association (SAMA) iocument entitled " Process Measurement

and Control Terminology", which Jescribed the required M&TE accuracy.

The incorporation of this MATE accuracy standard allowed the enginee-

ring calculation of inputed error to the sensor calibration accuracy to

be estimated by Westinghouse. (The actual values of the different ,

error categories and the error categories are themselves proprietary

data and will not be discussed in this report.)

Setpoints based on the WSM were incorporated into the SQN surveillance '

and calibration programt Several pieces of M&TE used at SON do not

achieve the ten to one accuracy requirement assumed in the WSM.

Examples of this equipment include instruments used to provide current

inputs such as the Fluke 8600, Keithly 197 and 175, and instruments

used to provide pneumatic inputs such as the Heise 711B and Ashcrof t .

Digigage. These pieces of M&TE are used at SQN to calibrate and  !

functionally test the SSPS instrumentation.

Tecc..ical Specifications (TS) require that written procedures shall be

established, implemented, and maintained covering TS surveillance and

test activities or safety related equiptrent. Instrument Maintenance <

Instruction IMI-99, Reactor Protection ' System, was established to I

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implement these requirements for the calibration and functional testing

of the Solid State Protection System._ The calibration procedures of

IMI-99-were inadequately established since they did not reflect the

assumptions of the methodology study and did not justify the technical

adequacy of the deviation from the methodology. This is a further

example of violation 327,'328/85-46-04. Other calibration and functional

testing procedures in addition to IMI-99 may be affected by the failure

to incorporate this requirement. The licensee has committed to identify

and correct these procedures,

b. Calibration of Containment Pressure Transmitters

The SQN containment pressure transmitters (Barton 764) were previously

removed from Watts Bar Nuclear Plant (WNP) and sent to SQN for replace-

ment of two non-environmentally qualified Foxboro transmitters. Tne

Bartor, transmitters were installed under Work Plan 11554, which was

approved by PORC on March 30, 1985, and completed or: April 3, 1985.

Af ter the May 7, 1985 licensee methodology meeting, a contract with

Westinghouse was established for Watts Bar to determine the effect of

the incorporation of the actual M&TE accuracy on the calibration of

reactor protection system instrumentation to meet the WBN safety limit

margins. preliminary calculations, received by WBN and SQN about

J uly "3, 1985, indicated that the containment pressure instrument

calibration woulo result in values that were outside both the Technical

Specification setpoint and the Technical Specification safety limits

when the reduced accuracy of the M&TE was included.

Informal calculations were performed by the SQN compliance staff about

July 8, 1985, which incorporated actual observed values for other

parameters, including setpoint drift, rather than the conservative

values assumed in the WSM. These calculations demonstrated that, based

on the actual historical error values for certain parameters at SQN,

including the M&TE, the setpoint was within the safety limit.

Based on this calculation, the licensee concluded that there war, no

engineering concern; however, the licensee failed to recognize and

promptly evaluate the potential failure to meet the Technical Specifi-

cation limits based on the potential error of reactor protection

instrumentation as determined by the design basis document, i .e. , the

WSM. In addition, the calculations made were informal and were

reviewed and formally approved by only one level of plant management.

During this informal review, the licensee also determined that the

original WSM for SON had a negative safety margin for containment

pressure. This is an inspector followup item (327, 328/85-46-11).

Technical Specifications require that the Plant.. Operations Review

Committee (PORC) review unit operations to detect potential nuclear

safety hazards and investigate all violations of the Technical Speci-

fications. A formal PORC review was not performed af ter additional

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information was received by the licensee, including PORC members, about

July 3, 1985, which indicated that the calibration of the Barton

containment transmitters could be outside the technical specification

safety limits. The licensee continued to operate both units at full

power until late August 1985 without formally reviewing this potential

nuclear safety hazard. Failure to conduct required PORC reviews

constitutes a violation (327, 328/85-46-10).

c. Licensae Actions to Evaluate M&TE Accuracy

SON established a contract with Westinghouse in Sertember 1985 to

determine if safety limits were exceeded based on the actual accuracy

of M&TE used at SQN. The licensee expects to have preliminary results

for the following three areas in January 1986:

Nuclear Instrumentation System RCS Delta Temperature and Average

Temperature M&TE accuracy ratios

Transmitter and rack M&TE accuracy ratios

Containment Pressure Transmitters accuracy ratios

Until the results of this evaluation are available, adequacy of the

current reactor protection as-left setpoints is an Unresolved Item

(327,328/85-46-12).

In summary, throughout this methodology issue, the inspection found that SQN

management failed to take positive actions to establish that safety limit

margins and setpoints met license requirements despite the known Watts Bar

deficiencies.

.

11. Reactor Trip Reduction Program

The inspector reviewed Sequoyah's Reactor Trip Reduction Program. The

licensee's program consisted of an evaluation of the areas identified in

INP0's " Scram Reduction Practices", INPO 85-011. This evaluation was issued

in a November 21, 1985 report on scram reduction practices at Sequoyah. The

report addressed in detail each of the INP0 items and identified which were

being implemented and which were standard practice.

l The licensee identified 27 trips which have occurred since January 1,1984

on Sequoyah Units 1 and 2 in a transmittal letter stating their actions to

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meet 10 CFR 50.54(f) commitments. The 27 trips were placed in one following

four categories.

Equipment Malfunctions or Failures 13 trips

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Manual Feedwater Control of Steam Generator (S/G) 8 trips

l Personnel Error 5 trips

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Inexperience with Auto-Bypass Controller 1 trip

l for S/G Feedwater Bypass Regulating Valve

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The root causes of the 13 trips were identified and long. term corrective

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actions taken consisting of preventative maintenance, -design ' reviews and

posting of warning signs to prevent reoccurrence for five trips. No long

term corrective action was felt appropriate for the remaining eight trips.

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The licensee preventative maintenance program consisted of:

Critical plant equipment which can cause scrams is inspected and tested

during each refueling outage.

Vendor simulators are used for testing systems.

Preventative maintenance on important equipment i s minimized while

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plant ~is operating.

I&C technicians verify that-control systems are functioning properly by

stroking components through their full range.

I Major equipment performance is monitored so anticipatory corrective

action can be taken prior to_a scram.

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A design change to install automatic control of feedwater' bypass regulating

valves was installed to reduce the trips which occurred from manual control.

Additional feedwater system modifications were made as a result of the

Davis-Besse event which will improve the AFW system reliability.

The licensee is implementing additional training to reduce personal errors.

I&C technicians receive a half day of systems training per week as part

of the continuing training programs. ,

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Simulator training is provided for. I&C technicians, engineers, and I

certain maintenance personnel based on availability of simulator. l

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Newly hired technicians must complete a certification program that

includes procedures, policies, system -training and practical factors.

Certification must be completed satisfactorily prior to performing-

unassisted testing.

On-the-job training is conducted by a foreman as part of the training -

qualification process.

Vendor training programs are used for critical plant equipment (e.g. ,.

EAC, governors, motor operated valves).

Operations personnel receive training on plant modifications prior to

placing new equipment in service.

Trainees, including available auxiliary operators, observe and in some

cases, receive hands-on experience during the plant evolutions, such as

start-up,-synchronization and shutdown in the control room.

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Operations personnel are given addition in-depth training on balance of

plant equipment.

2 Emphasis is placed on ' promoting operators up through the ranks from

entry-level positions.

The licensee has also implemented the following practices to reduce plant

trips.

A system engineer is assigned for each plant system. His responsi-

bilities include the following:

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reviewing and trending surveillance test results

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recommending preventative maintenance

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coordinating all design changes

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writing procedures and design changes

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reviewing all maintenance on the system, conducting

post-maintenance testing and assisting in troubleshooting

The Shift Technical Advisors perform a comprehensive post-trip review

to determine the root cause and the correction of the cause for each

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scram.

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The Shift Supervisor and Shift Engineer perform a joint review after a

scram and an unusual occurrence report is prepared.- A committee of

l operations, maintenance, engineering is convened to investigate the

event. The group reviews data and interviews personnel to determine

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the causes of all failures or unusual occurrences for the implementa-

j tion of corrective actions.

! Plant startup does not commence until all reviews are complete. The

superintendent or Assistant Superintendent must give the approval to

restart the plant.

!

A historical data base is maintained to allow analysis and trending by

scram cause codes.

The licensee is a member of the Westinghouse Owners Group.which has a

program for investigating each scram.

Since the majority of scrams are caused by problems in the Balance-

of-Plant (BOP) systems, a licensee procedure requires that . the same

case is exercised in surveillance, maintenance, operation and engineer-

ing of BOP systems as is in the NSSS systems.

-The licensee has implemented numerous other procedure changes, per-

sonnel training and equipment modifications not addressed in this

report.

The licensee was also pursuing improved reliability and trip reductions by

other prog-ams, such as the task force identified AFW system action items

discussed in the Davis-Besse section of'this report.

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The actions being taken by the licensee indicated an adequate effort to meet

the 10 CFR 50.54(f) commitments made in their letter dated November-1, 1985,.

and to improve plant reliability through trip reduction.

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The inspector verified licensee implementation of steps taken to reduce the

number of reactor . trips on a sampling basis and. held discussions with the

training department and operations personnel on this subject matter. .The

! inspector concluded that the licensee has taken positive steps to improve

plant reliability,

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