ML20195B237

Insp Repts 50-259/88-21,50-260/88-21 & 50-296-88-21 on 880701-31.Violation & Unresolved Items Noted.Major Areas Inspected:Operational Safety,Maint Observations,Surveillance Testing Observations & Restart Test Program

ML20195B237
Person / Time
Site:	Browns Ferry
Issue date:	10/21/1988
From:	Carpenter D, Little W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF SPECIAL PROJECTS
To:
Shared Package
ML20195B228	List: IR 05000259/1988021 ML20195B219 ML20195B231 ML20195B237
References
50-259-88-21, 50-260-88-21, 50-296-88-21, NUDOCS 8811010408
Download: ML20195B237 (25)

See also: IR 05000259/1988021

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.y.m UNITED STATES 'l

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1* E NUCLEAR REGULATORY COMMISSION

9' . iE '

REGION H

101 MARIETTA ST N.W.  ;

\e'.... ATLAH7A. GEOROtA 30323

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' deport Nos. : 50-259/88-21, 50-260/88-21, and 50-296/88-21

Licensee: Tennessee Valley Authority

6N 38A Lookout Place

1101 Market Street

Chattanooga, TN 37402-2SJ1

Docket Nos.: 50-259, 50-260 and 50-296 License Nos.: DPR-33, DPR-52, ,

and DPR-68 i

. Facility Name: Browns Ferry 1, 2, and 3

Inspection at Browns Ferry Site near Athens, Alabama

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Inspection Conducted: July 1-31, 1988

Inspector':j 2 / /AP

Ri Carpfaterf Senior Resident Inspector Ofte Signed

Accompanying Personnel: C. Brooks, Resident Inspector

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E. Christnot. Resident Inspector

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W. Bearden, Resident Inspector

A. Johnson, Project Engineer

J. Yo k,.

/ 9nior Resident Inspector, Bellefolnto

Approved by. _. . 6h ^ MAY _, l

W. S. C tie ( Section Chief, ___ Date 5'igned i

Inspection Programs,

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TVA Projects D.yision

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SUMMARY

Scope: This rout.ine inspection was in the areas of operational safety,

maintenance abservations, surveillance testing observations, restart

test program, and licensee action on previous inspectior findings,

Plant Operations Review Committee, reportable occurrences, corrective

action program, condenser retubing, and General Electric con'.ractor

recommendations

Results: One violation was identified involving failure to perf orm CAQR

generic reviews in a timely manner. One unresolved item was identi-

fied concerning the procedures controling keys for access to high

radiation (*1000 mrem /hr) areas. Four Inspection Followup Items

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I (IFIs) were identified involving RHRSW corrosion, deficiencies

identified during the restart testing of lop /LOCA C, vaulting of

completed and approved test results, and adequacy of identifying at:d

closing out of significant hardware test exceptions.

,, All of these issues are to be resolved prior to restart,

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ADOCM 05000259

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REPORT DETAILS

1. Persons Contacted

fi Licensee Employees

• J. Walker, Plant Manager

P. Spiedel, Project Engineer

J. Martin, Assistant to the Plant Manager

• R. McKeon, Operations Superintendent

T. Ziegler, Superintendent - Maintenance

• D. Mims, Manager - Technical Services Supervisor

J. Turner, Manager - Site Quality Assurance

M. May, Manager - Site Licensing

• J. Savage, Compliance Supervisor

A. Sorrell, Site Radiological Control Superintendent

R. Tuttle, Site Security Manager

L. Retzer, Fi.e Protection Supervisor

H. Kuhnert, Office of Nuclear Power, Site Representative

T. Valenzano, Director - Restart Operations Center

• C, McFall, Compliance Engineer

Other licensee employees or contractors contacted included licensed

reactor operators, auxiliary operators, craftsmen, technicians, public

safety officers, quality assurance, design, and engineering personnel.

• NRC Attendees

• D. Carpenter

• E. Christnot

• C. Brooks

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• W. Bearden

• Attended exit interview.

Acronyms and initialisms used throughout this report are listed in the

last paragraph.

2. Operational Safety (71707,71710)

The NRC inspectors were kept informed of the overall plant status and any

significant safety matters related to plant operations. Daily discussions

were held with plant management and various members of the plant operating

staff.

The NRC inspectors made routine visits to the control rooms. Observations

included instrument readings, setpoints and recordings; status of

operating systems; status and alignments of emergency standby systems;

onsite and offsite emergency power sources available for automatic

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operation; purpose of temporary tags on equipment controls and switches;

annunciator alarm status; adherence to procedures; adherence to limiting

conditions for operations; nuclear instruments operability; temporary

alterations in effect; daily journals and logs; stack monitor recorder

traces; and control room manning. This inspection activity also included

numerous informal discussions with operators and supervisors.

Onge ng general plant tours were conducted. Portions of the turbine

bui' dings, each reactor building and general plant areas were visited.

Obse-vations included valve positions and system alignment; snubber and  ;

hangea conditions; containment isolation alignments; instrument readings;

housek0eping; proper power supply and breaker alignments; radiation area '

controb; tag controls on equipment; work activities in progress; and

radiation protection controls. Informal discussions were held with

selected plant personnel in their functional areas during these tours.

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The NRC inspector toured the residual heat removal service water (RHRSW)

pump building on July 12, 1938, and found the condition unacceptable. The

B3 pump which was in service at the time exhibited gross shaf t seal

leakage. This condition had been in existence since at least May 21,

1988, and was doc" ted on MR No. 869190. Another deficient condition

which was docume a on a tag hanging r,n the pump, MR No. 865395, since

May 23, 1988, wa. .essive vibration. The apparent reason that this pump

was in service was that of the 12 RHRSW pumps, seven pumps were

out-of-service for various reasons. General corrosion was evident on all l

piping and components with the most severe being the valve bonnets for the i

A1, 81, and B2 pump discharge valves. The licensee was asked to determine i

the minimum acceptable wall thickness for these valves and establish the

acceptability of both the current wall thickness and projected end of life '

wall thickness. This will be tracked as an Inspector Fnllowup Item (IFI)

(259,260,296/88-El-03) RHRSW Corrosion. Licensee representatives wers [

cautioned not to allow the flexibility and redundancy available with this l

system, particularly with only one unit to be placed in operation, to L

translate into a lack of aggressiveness in system maintenance. l

On July 15, 1988, the NRC inspector observed the controls established over h

high radiation areas which exceed 1,000 mrem /hr per BFN Technical  !

Specification (TS) 6.8.3.2. Fuel reconstitutien activities released l

activated corrosion products which were deposited in fuel pool cooling [

(FPC) system components. As a result, a high radiation area greater than ,

1,000 mrem /hr was created around the Unit 1 FPC heat exchangers. Access I

to the area was not secured by locks with the keys under control of the

Shift Engineer. This condition is allowed by TS for a period of up to 30  !

days provided that the area is controlled by direct surveillance to (

prevent unauthorized entry. The inspector interviewed the high radiation  ;

area watch and cofirmed that he was knowledgeable of his duties and [

responsibilities. The inspector observed that the area was properly [

posted and confirmed by review of the surveys and by independent measure-  !

ment that boundaries were properly established, however, the condition I

was not properly annotated on the survey maps posted at the Radiation i

Worker Information Boards located at the entrance to the Radiologically

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Controlled Area (RCA), nor was it listed as a "Miscellaneous Problem" or

"Unusual Condition" on the Shift Operating Supervisor's (SOS) Status

Board. The inspector questioned whether SOS permission was required for

entrance into the area since no key control was currently available.

Licensee representatives responded that 505 permission was not required

but would review the issue. The intent of '.he TS is that management, via

the Shift Engineer, be made aware of and exert positive control over each

individual entrance into a greater than 1,000 mrem /hr high radiation area.

The NRC inspector also assessed the licensee's routine program for control

over locked high radiation areas. The program is described in Browns

Ferry Standard Practice BF-19.26, Key Control and Accountability;

Radiological Controls Instruction RCI-17 High Radiation Area Door

Control; and Operations Section Instruction Letter OSIL-16 Keys. The

instructions were found to be contradictory and confusing. OSIL 16,

Section 3.1 requires high radiation area dour keys to be "under the strict

administrative control of the Shif t Operations Supervisor" (505) (new

designation for the Shif t Engineer); however, in Section 4.1 it also

allows high radiation area keys to be assigned to each control room,

assistant shift operations supervisor, RadCon, and Nuclear Security

Services with the SOS maintaining "accountability for them". Section 4.2

of this OSIL states that high radiation area keys may be used by

"Operations, Operations Training, and NRC Resident Inspection personnel

only". No allowance is made for RadCon or Nuclear Security use of their

assigned keys. RCI-17 requires in Step 6.3 that authorization to unlock

high radiation area doors will be obtained from the SOS, but in Step 6.4

it indicates that RadCon has pre-authorized use of their keys and need

only inform the Unit Reactor Operator and not the Shift Engineer.

The NRC inspector ascertained through interviews with RadCon personnel and

a SOS that high radiation area door keys were maintained by RadCon and

that the SOS permission was not sought or obtained for all entries into

the locked high radiation areas. The only control exercised by the 505

over the high radiation area door keys was a once per shif t acknowledge-

ment that the 505 clerk had performed a survey of all the keys and all

keys were accounted for. The inspector is concerned that the procedures

that control the keys controlling access to high radiation areas (11000

mrem /hr) are confusing and contradictory and this is identified as an

unresolved item pending clarification of this issue (259, 260, 296/

88-21-01).

3. Survaillance Observation (61726)

On July 12, 1988, during the performance of Surveillance Instruction (SI)

2-SI-4.9. A.2.a-2, Weekly Check for Shutdown Board C and D Batteries the

licensee declared the shutdown boards inoperable. The battery electrolyte

l temperature was found to be in excess of the 90 F acceptance criteria on

both the C and D shutdown board batteries. Later that same day, the Units

1 and 2 A, B, and C diesel generators were declared inoperable for the

same reason during the performance of 0-SI-4.9. A.2 a Weekly Check for

Diesel Generator Batteries. The licensee initiated CAQR No. 880470 in

order to document proper resol ation of the condition. The source of the

acceptance criteria on battery electrolyte temperature was the vendor

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manual which incivded a normal operating temperature range of 60-90 F.

The only adverse affect of higher temperatures is a 50 % reduction in

expected life for each 18 F above 77 F in the event of continued

exposure to the elevated temperature. The only limitation contained in

the vendor manual with regard to temperature is an absolute limit of

170 F during battery charging. The license initiated changes to all

appropriate sis to raise the upper temperature limit accordingly. The NRC

inspector followed the licensee's activities and confirmed the

appropriateness of the corrective action through a review of the vendor

documentation.

No deviations or violations were identified.

4. Plant Operations Review Committee (40700)

On July 14, 1988, the Plant Operations Review Committee (PORC) conducted a

meeting by telephone conference call at 8:00 pm. As requested, the NRC

inspector was notified and monitored the meeting by phone. TS 6.5.1.4

authorizes PORC business to be conducted by phone for expedited meetings

when it is not practical to convene as a group. Several PORC members

questioned the necessity of the telephone meeting given the issues on the

agenda. Two CAQR's requiring PORC approval in order to release

non-conforming material for testing and installation f rom the warehouse

were discussed (BFN 880476, BFN 880481). The telephone conference was

deemed necessary in order to meet schedules established for systems return

to service to support the targeted fuel load date. In both cases, the

deficiency which prevented release of the material was the lack of seismic

qualification documentation. The CAQR's clearly documented a prohibition

on considering the systems in which the components were to be installed as

operable unless and until the seismic documentation was obtained and

approved by design engineers. Part B of the CAQR's, however, took a

contradictory position to this. The "No" block was checked on both CAQR's

in answer to the question of whether the CAQR impacted unit operability.

This was a point of discussion among several PORC members, but all

subsequently approved the CAQR's as written. Several NRC observations as

a result of this meeting were discussed with the Plant Manager and members

of his staff during a routine weekly meeting. Among these concerns were,

1) Telephone conference PORC meetings should not be conducted as a matter

of convenience but should be reserved for events, in;idents or conditions

having true safety significance; and 2) The apparent inconsistency of not

checking the block marked "Yes" in response to the question of impact on

operability. These observations were considered by the inspector to be

isolated occurrences.

No deviations or violations were identified.

5. Maintenance Observation (62703)

During a control room observation on July 24, 1988, the inspector noted on

out-of-service amber indicating light for the 4KV shutdown bus no. 2

auto-transfer lockout relay 43-2. The inspector tracked the deficiency to

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MR No. 811066 dated December,1985. The current status was reported as  !

being in the Electrical Technical organization for engineering evaluation f

(since March 1988). Upon interviewing the responsible personnel, the i

inspector learned that the MR was being turned over to operations for l

J post-maintenance testing and closeout following a visual inspection which (

i found no problem. The NRC inspector accompanied the cognizant engineer on  ;

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an inspection of the light and noted that the wrong light had been tagged  ;

1 as being deficient. The engineer had been troubleshooting the light for  !

] the 4KV shutdown board A transfer switch 435A. The orange MR sticker with  !

the MR number was erroneously applied to an adjacent light. The deficient i

i condition went uncorrected for 2 1/2 years due to erroneous positioning of r

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an MR sticker and poor trouble shooting of a properly functioning com-

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ponent. This is considered to be an isolated breakdown of the MR process

j that occurred 21/2 years ago. Recent improvements in the licensee's i

programs should preclude issues such as this in the future.

No deviations or violations were identified. l

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6. Reportable Occurrences (90712, 92700) -

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i The below listed licensee event reports (LERs) were reviewed to determine l

! if the information provided met NRC requirements. The determination t

i included: adequacy of event description, verification of compliance with (

) technical specifications and regulatory requirements, corrective action f

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taken, existence of potential generic problems, reporting requirements I

1 satisfied, and the relative safety significance of each event. Additional

in plant reviews and discussion with plant personnel, as appropriate, were i

conducted. l

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(Closed) LER No. 296/83-04 Rev.1, Residual Heat Exchanger Tube Leak. A l

] leaking tube was found in the RHR 30 heat exchanger. Metallurgical i

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examination revealed a circumferential1y criented crack in an area of the l

! tube where mechanical damage had occurred. Metallographic examinations  !

did not reveal any evidence of corrosion assistance to the failure. Eddy f

current testing was performed on 380 tubes of which 12 tubes were found to  !

be mechanically damaged (dented). All 12 tubes including the leaking tube

l were plugged. The NRC inspector reviewed the completed work plans. [,

(Closed) LER No. 259/84-08 Rev. 1, Reported Failures of the Unit 1 High l

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Main Steam Line Flow Differential Pressure Transmitters (DPT) 1-25 A l

l through D. The f ailures occurred during January and Februacy of 1984. l

l Following testing of the transmitter, the licensee concluded that the  ;

j failure was due to the behavior of the pulse dampening devices (snubbers) {

installed in the instrument sensing lines. The snubbers were removed and

Unit I was operated for approximately seven months with no further

problems noted. The snubber removal occurred under Temporary Alteration

] Change Form (TACF) 1-84-079-1. The temporary alteration was made

l permanent by ECN P0126 as implemented under WP 10370. The NRC inspector

i reviewed the completed TACF, ECN and work plan.

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(Closed) LER No. 259/84-15 Rev. 1, Removal of Under Designed Vacuum

Priming Valve. During a design review of the EECW system it was

discovered that the vacuum priming valve on the north header (none on the

south header) was under designed for the system pressure. This valve had

been isolated from the system for two and a half years and testing

determined that the valve's function was unnecessary. The NRC inspector >

reviewed Work Plan and Inspection Report No. 3026-87 and performed a field

inspection to ascertain that the valve had been removed and the piping

capped.

(0 pen) LER No. 296/85-17 Rev. 1, Failed Supports On the Residual Heat

Removai System. Three hangers located on loop 1 of the RHR system of Unit

3 failed due to high vibration caused by the throttling action (resulting

in cavitation) of an injection valve during shutdown cooling mode

operation. The licensee decided to reduce the vibration to an acceptable

level by replacing the original valve disc with a fluted disc. This has

been completed for Unit 2 and vibrational measurements have been made on

the Unit 2 torus to torus portion of the RHR system and found acceptable.

However, the vibrational measurements have not been made on a part of the

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line that is used during the normal reactor cooling mode. The vendor does

not recommend running water into the reactor vessel when the fuel is not

present and the head is not on the vessel because of potential damage to

some of the reactor internals. The vibrational tests for the remaining

portion of the RHR piping will be made during post modification test (PMT)

No. 139 and will be required prior to Unit 2 criticality.

(Closed) LER No. 296/86-07, Loop I of RHR System Inoperable Af ter Two

Damaged Hangers Discovered. Hanger H3 had a 4-inch crack at a structural

tubing weld and hanger H8 had a support lug broken of f from the ceiling.

Both hangers are located on the 18-inch diameter RHR injection line above

the torus. The high vibration of this piping is caused by the throttling

action of loop I RHR injection valve 3-FCV-74-52 that occurs during the

shut down cooling mode. Metallurgical examination revealed that the parts

The NRC inspectors performed a visual

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had failed due to fatigue.

inspection of the two repaired hangers. In order to reduce the magnitude

of the vibration, the injection valves were to be modified by replacing

the present valve discs with fluted discs. The modification of the valves

has been completed on Units 1 and 2, but not on Unit 3. The modification

of the valve on Unit 3 will be followed under LER No. 296/85-17.

(Closed) LER No. 296/86-09, Damaged RHR Hanger Causes Prohibited

Operability Configuration. Hanger H10 (loop I) located on the 24-inch RHR

shutdown cooling and low pressure coolant injection line above the torus,

had a crack in a load bearing tube steel member. Metallurgical analysis

of the crack showed a fatigue mode of failure. As noted in LER No.

296/86-07, this piping on Unit 3 (loop 1) has considerable vibration

caused by the throttling action of injection valve 3-FCV 74-52. The NRC

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inspectors performed a visual inspection of the reinstalled hanger H10.

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The modification of the valve on Unit 3 will be followed under LER No.

296/85-17.

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i (Closed) LER No.296/87-02, Unplanned Reactor Water Cleanup Isolation

During Testing Due to Fuse Failure. When chanael Al was de-energized

during a functional test, there was an unexpected isolation of the reactor  ;

water cleanup system. This happened because channel B2 was de-energized I

due to a blown fuse. The functional test procedure was revised to add '

steps which verify that the trip relays are energized at the start of the

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i test. The NRC inspector reviewed the revised functional test procedure

and verified that it requires verification thot the trip relays are i

energized. I

(Closed) LER No. 259/87-08 and Rev.1, Failure of Potential Transformer

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Fuse Contact Cause E1cetrical Fault and Engincering Safety Feature

Actuation. During the performance of a monthly surveillance test a phase

to phase short occurred between contacts in the diesel generator control l

cabinet for the 200 diesel generator (DG). The fault caused a refueling

! zone isolation, initiation of standby gas treatment and control room i

emergency ventilation, and on Unit 3 a half scram and primary containment l

1solations. The cause of the fault was a f silure of the potential 3

transformer fuse contacts. The fuse and spring finger contact were

bypassed on all eight DGs after an engineering ovaluation determined that

the fuse in the DG exciter potential transformer ci rcuitry was un-

necessary. The NRC inspector reviewed the engineering evaluation and the

completed work plans that bypassed fuse and spring finger contacts for all

eight DGs.

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(Closed) LER No. 259/87-22 and Rev. 1, Engineered Safety Feature Actuation l

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Due to Personnel Error During Switch Calibration. During calibration of a '

raw cooling water pressure switch, two emergency equipment cooling water

pumps were inadvertently started due to a personnel error. The cali-

bration procedure was revised to provide an improved method of isolating

the switch during calibration. The instrument mechanics involved were

counseled on the need for increased caution when working with energized

j equipment. The NRC inspector reviewed the revised calibration procedure

1 and the documented counseling of the instrument mechanics.

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1 (Closed) LER No.259/88-03, Inadequate Procedure Causes Inadvertent Start (

of Emergency Equipment Cooling Water Pumps. During an attempt to put a i

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raw cocling water (RCW) pump into service and the taking out of ser/ ice  !

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another RCW pump, the RCW header pressure dropped below the low pressure i

setpoint. The operating instructions for the RCW system were revised to  !

provide instructions for alternating pumps in and out of service. A l

review of this event will be provided to current operations personnel. l'

! The NRC inspector reviewed the revised instruction and the event

description provided to the operations staff.

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No deviations or violations were identified, j

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7. Restart Test Program (RTP) i

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! The inspector attended RTP status meetings, reviewed RTP test procedures,

observed RTP tests and associated test performances, reviewed RTP test  !

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results (including test exceptions), and attended selected Restart

Operations Center (War Room) and Joint Test Group (JTG) meetings. The

following are the RTP activities and associated activities monitored, and

the status of testing during this reporting period:

a. Restart Tests Performances (RTP)

The following restart tests were in progress during this reporting

period:

RTP-03 A and B, Reactor Feedwater

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RTP-023, Residual Heat Removal Service Water

RTP-030, Diesel Generator and Reactor Building Ventilation

RTP-031 A and B, Control Building Heating Ventilation and Air

Conditiening

RTP-077, Turbine-generator / Electro Hydraulic Control

RTP-067, Emergency Equipment Cooling Water

RTP-064, Primary Containment Isolation

RTP-070, Reactor Building Closed Cooling Water

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RTP-073, High Pressure Core Injection

l RTP-074, Residual Heat Removal System

RTP-082, Diesel Generators

RTP-084, Containment Atmosphere Dilution

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RTP-085, Control Rod Drive

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RTP-092, Neutron Monitoring (SRM, IRM, LPRM, APRM)

RTP-099, Reac+or Protection System

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RTP-357-1, 120 V DC Diesel Generator Batteries

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! RTP-057-3, 250 V DC Unit Battery

RTP-057-5, 4 KV Distribution

RTP-BVC, Backup Control

RTP-L/L C, LOP /LOCA "C" Rev. 2

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The above tests were either in the prerequest stages, system

performance stages, initial RTP Group reviews, DNE reviews, or final  ;

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JTG reviews.

b. Loss of Power / Loss of Coolant Accident (LOP /LOCA) Testing

During the LOP /LOCA series of tests a significant test exception was  ;

identified involving the Unit 3 diesel g'enerators outpuc breakers 3A, .

3C and 3D. When performing LOP /LOCA C", these breakers, which j

supply standby power to shutdcwn boards 3EA, 3EC and 3ED  !

respectively, locked out, i.e. would not close onto their shutdown .

boards, when requirbd by the LOCA signal. The licensee modified the  !

breaker control logic circuits (See paragraph 8 of this report for

details). Also during the LOP /LOCA "C" test, a major electrical

switchboard (480V Reactor MOV Bd 2A) was not aligned as called for in  !

the test pr1 requisites. The licensee initiated CAQR 88-0399 to

document this misalignment. These two items prompted the licensee to

perform a LOP /LOCA "C" re-test referred to as LOP /LOCA "C" Revision

2. This test called for turning off the incoming plant power using

the plant unit startup switchboard breakers, which are located in the

plant, instead of the three main power feeds coming from the

switchyards. NRC Inspectors monitored this retest from various plant

locations. To perform the procedure reviews, test witnessing, and

post test evaluations, the inspectors used the NRC 2513 program

inspection modules as guidance. No problems with the test procedures

were identified.

The retest was mainly for those items that did not test satisfac-

torily during the original LOP /LOCA "C" Test. However, a new

addition to the test was added and referred to as Section 5.5, Diesel

Generator / Paralleling System. This new test was to verify a design

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feature that allowed for the paralleling of all eight (8) DGs with

of f site power while the LOCA signal was still present. The following

NRC inspector observations were made and discussed with the licensee:

(1) Two inspectors were stationed in the Unit 1 and 2 control rooms

and made the following observations:

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- RHR Pump 2A breaker failed to close

- The following loads could not be verified due to their

breakers being racted out: 480 V Shutdown Boards IA and 1B;

250 V Battery Charger 1; Fuel Pool Cooling Pump 1A; Drywell

Blower 1A; LPCI MG Set IDN; and LPCI MG Set IEN.

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- Low Pressure Coolant Injection (LPCI) MG Set 1EA should

have remained energized; it's breaker was found opened.

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- Control bay water chiller "B" should have load shed; it's

breaker was found closed.

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Step 8.3.13 of 01-82 (restoring of f-site power to the 4KV

Shutdown Boards) could not be executed. The auto transfer  !

lockout relay could not be reset (apparently due to the >

accident signal).

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I & C Breaker 204 inadvertently tripped during the test. <

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A blown fuse in the control power prevented operation of

the alternate feeder to 4KV Unit Board 2A.

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A lack of communication and proper operational coordina-

tion was observed while conducting the diesel generator

paralleling operation. A major load was re-energized (480

Shutdown Board 2B) which produced a voltage transient while

attempting to establish proper synchronization. This came

as a complete surprise to the operator who was attempting I

to parallel the Unit 1 and 2 DGs.

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Improvements were noted in control room ccmmunications and

control. The unit operator announced the receipt of

alarms, provided reports on completed actions, established

professional face-to-face communications through "repeat- ,

backs", and verified expected indications following switch l

manipulations. Additionally, a prompt review of loads lost

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following r.n inadvertent trip of an I & C breaker was

conducted. Although not everyone practiced these e

'

techniques, the Unit 2 operators established and projected

a close team-work relationship using these methods.  ;

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The amber indicating light on panel 9-23-8 for the 4KV i

Shutdown Bus 2 auto transfar lockout relay 43-2 was out of

'

service with a December 1985 MR No. 811066 attached. This '

delay is considered to be unacceptable. Refer to paragraph

5 for additional information on this subject. i

(2) An NRC inspector was assigned to the Unit 3 control room and l

made the following observation: i

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Operations personnel wer a knowledgeable testing

requirements and plant conditions, and were attentive to

their duties, The Unit 3 diesel generators were paralleled

to of fsite power in accordance with step 6.2 of BF 3-01-82,

Standby Diesel Generator System Operating Instructions; and

step 5.5 of 2-BFN-RTP-L/L-C, LOP /LOCA testing. No discre-

pancies were noted.

___ ____ ___ __ _ . _ _ _ _ _ _ _ . _ _ _ _ .

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(3) An NRC inspector was initially assigned to the Unit 2 Auxiliary

instrument Room and made the following observations:  ;

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-

In order to indicate isolation signals had been transmitted

to Unit 2, the inspector expected to observe that 5 HFA ,

relays de-energized; however, only one HFA Relay (16A-K26) l

was de-energized. At the start of the test, the inspector  ;

was told that a test exception would be written.

-

Equipment on the 4-KV Shutcown Board B performed as

required - No discrepancies were identified.

- Equipment on the 4-KV Shutdown Board D performed as  !

required. 480 V Diesel /.uxiliary Board B transformer l

TDB ACB (compartment 13) was sucposed to remain closed;  ;

however, only the yellow lir s* was "on" indicating an open

condition.  ;

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- The licensee performed these tests in a knowledgable and

professional manner QA inspectors were noted at each

location that the NRC inspector monitored.

(4) An NRC inspector was assigned to the 3EC shutdown board feeder

breaker from the 3C DG. This breaker had malfunctioned during  !

the LOP /LOCA "A" and "C" tests. The inspector made the i

following observations:  ;

- The normal feeder breaker opened upon the initiation of the

LOP signal; approxirately six seconds later the the standby

feeder breaker from 3C DG closed and then immediately

opened; the charging motor recharged the breaker springs; .

and, unlike what occurred during the original LOP /LOCA C"

test, the breaker closed and remained closed. The in-

l spector then observed the newly installed time delay relay

I

and it indicated that it had activated, timed out and  ;

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closed it's logic.  !

,

- No deficiencies were ider tified at the 3E0 shutdown boards; i

diesel generator auxiliary boards 3A, 30. A Md B; and  :

'

shutdown board B.

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- At the Unit 3 control room, the paralleling of the Unit 3

! DGs with offsite power while the LOCA simulated signal was

l still present were observed. No deficiencies were

identified.

The failure of the RHR pump 2A breaker to close is identified as IFI

259,260,296/88-21-04, pending determination of why it ftiled and any

necesury corrective action.

At the beginning of the LOP /LOCA test series, several site

departments appeared to not give these tests the type of attention

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', needed; however, by the end of the testing series this attitude was

turned around and the final test was conducted with the type of pro- l

fessionalism expected at a nuclear power facility. .

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c. Specific Test Witn'ssing - Reactor Protective Systen,  !

,

The inspec+or reviewed 2-BFN-RTP-099, Reactor Protective System

(RPS), aw observed portions of the scram testing involving various >

scrams such as high reactor vessel pressure, high main steam line  !

radiation, and low reactor vessel level. The Browns Ferry RPS

consists of two trains, A and B, with each train sub-divided into two

channels A ' # and B , B . Each channel has the same number of

l 2 3 2 l

scram signals. This arrangement allows for a half scram logic if any .

one of the channels activate, and it takes a logic of one out of two '

trips occurring twice (one out of two, twice) to initiate a full l

Scram. The overall intent of the test is to calibrate each scram

parameter such as high reactor vessel pressure and low reactor level; *

check the functions of the reactor mode switch, such as refuel and l

startup; verify the scram logic from each scram signal; verify that

,

the reactor can be scramned remotely by turning of f the power supply

j electrical breaker to the RPS Motor generator sets (a total of two),

and co-duct time response testing for each channel. l

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The NRC inspector observed the performance of Section 5.5 of the

test, Low Reactor Water Level. This section was verified using sis

2-SI-A,B,C and 0 (o* for each channel). The sis required that a  ;

'

J calibration device be hooked up to the Rosemount level transmitters

j located in the reactor building and that a calibr.ition of the trans- >

l mitters be performed. The $! also required that the Rosemount Analog

Trip Units (ATU) located in the Unit 2 auxiliary instrument room be  ;

checked. The RPS testing will continue untti each scram signal has

been verified (a total of 39 signals). It should be noted that the l

inspector Milized NRL 2513 inspection program modules as guidance in  !

'

performin, thess inspection activities. No deficiencies were l

observed. L

[

d. Test Results Review  ;

The NRC inspector reviewed the results of 2-SFN-A" ;~), Standay Gas f

Treatment System, which were reviewed by the .loi it Y ' t. Group and  !

approved by the Plant Manager on July 6, 1938, r s tdst was ,

J reviewed by the inspector from the Baseline To .equirements i

Document (BTRO) to the final results. Act W field ti,ervations were f

conducted and were documented in previon residen+. inspection f

reports. Throughout the testing activities the inspector used NRC

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2313 Inspection Prograr, Modules as ;uidance in performing the '

inspection activities.

It was noted by the inspector that a total of twenty-one (21) test

exceptions (TE) were de mentid by the Test Director, with five

i outstanding when the tr J. r$5ults were approved by the Plant Manager.

The follcwing outste-S v; 'ZS were reviened in depth:

4

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(1) TE-7 involved the zonal dampers located in stairwells and

elevator shafts separating the three unit reactor building zones >

.from the refuel zone. The test director initiated MR No. 779834

to repa,r these dampers. However, the FSAR indicates that

credit is not taken for these zona' dampers because credit is

taken for tk entire secondary containment, i.e. the three

reactor building zones plus the refueling zone. The BTRD was

revised to reflect this.

(2) TE-8 involved the four (two per train) dampers located in the

equipment access area located between Units 1 and 2. The test

requirement called for the dampers to close in ten (10) seconds,

however, all four dampers closed in approximately twenty-eight

(28) seconds. The test director initiated CAQR-880177 to

document this deficiency.

(3) TE-11 involved the attempt to document stack effect by blowing

smoke into the duct work located in the stack. This item was "

' discussed in a previous resident inspection .eport. The test

director initiated CA0R-880304 because of possible seismic

considerations with an unmonitored ground release.

(4) TE-20 involved a hold order on both A and B OG auxiliary elec-

trical boards, breakers numbered SC, which supply power to the

dilution fans.

(5) TE-21 involved an NRC Violation (259,260,296/88-05) which

documented the perforniance of iodine testing of the filters.

The inspector noted, on July 26, 1988 (20 days after final review and

approval), that the approved test results were not turned over to the <

i

QA vault in a timely manner. This item is identified as IFI

259,260,296/88-21-05, Vaulting of Completed and Approved Test

Results, pending the development of more timely administrative r

controls,

e. Test Exceptions ,

The inspector continued to followup the licensee's handling of the l

TEs identified by the RTP. As of mid July 1988, four hundred forty  ;

four (444) TE's were identified, of which one hundred and one (101)

were still outstanding. The restart testing group has reviewed the  !

TE! and have categorized them into six areas as follows.

(1) Equipment Deficiencies, which is subdh ided into equipment

malfunction (1.1) and equipment performance (1.2).

(2) Procedural 31fficulties, which is subdivided into procedure

errors /edi W rial (2.1); procedure method / performance (2.2); ,

plant condition / equip ~nt availability (2.3); and prerequisite /

initial conditions (2.4).

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(3) Personnel Errors, which is subdivided into test director errors

(3.1) and support personnel errors (3.2).

(4) Partial Release (4.0), which is used when the JTG releases a

particular section of a tast for performance.

(5) Calibration Deficiencies, which is subdivided into measuring and

test equipment (5.1) and process instruments (5.2).

(6) Other

The inspector raviewed selected TEs from Test Procedures. 052-4,

057-5, 065, and 082 against this categorization. It was noted that

-

of the four hundred forty four TEs, ninety-two (92) involved

equipment malfunction (category 1.1) and forty nine (49) involved

equipment performance (category 1.2). The inspector observed that

maintenance requests (MRs), procedure changes (intent and non-intent),

and CAQRs were used to document and close out TEs. The inspector

expressed concern that there MRs, procedure changes and CAQRs be

given appropriate consideration in the final review and approval of

each test results package. The inspector will verify this in his

review of the approved test results packages. This is identified as

IFI 259,260,296/88-21-06. Adequacy of Closing Out of Significant

Hardware Test Exceptions (Categories 1.1 and 1.2.).

No deviations or violations were identified.

8. Modifications (37700)

The NRC inspector reviewed CAQR 880394 which documented the locking out of

3EA, 3EC and 3E0 DG breakers during the initial LOP /L"CA C test and

,

>

subsequently generated a design change request. This change involved the

installation of time delay relays manufactured by ASEA Brown Boveri in

i each of the eight (8) shutdown boards in order to allow the DG output .

> breakers to close on to their respective shutdown boards during a loss of I

powe- followed by a loss of coolant accident. The inspector also reytewed

the design change implementation which was accomplished by Work Package

No. 0095-88, Engineering Change Notice (ECN) E-0-P7150, Test Scoping

Document for test no. PMT-195, and Post Modification Test 195 (PMT-195).

The inspector observed the installation process involving shutdown boards

C, B, and 3EC The licensee did not install the time delay relay into

shutdown bos- D, because that board would be deliberately disabled for

the LOP /LO( retest. The inspector observed the presence of QC in-

spectors mon the installation of the time delay relays. The review

of the test coment and the PMT-195 indicated that the delay was

to be set for 2.o - or - 1.35 seconds, because the time to recharge the

closing springs of the breakers was to be two (2) seconds or less.

H)vever, the closirg spring recharging time on some of the breakers was

'

greater than two (2) seconds. The Post Modification Testing Group ini-

tiated a CAQR which resulted in changing the time delay to three (3)

seconds. During the LOP /LOCA C retest the inspector noted that the

'

modification worked as designed. The inspector will follow up on the

installation of this design on shutdown board D.

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No deviations or violations were identified.

9. Generic Applicability of Conditions Adverse to Quality

. The NRC inspector selected various CAQRs for review and identified four

CAQRs that had not received a Browns Ferry generic review within the time

frame required by the NQAM Part I Section 2.16, paragraph 10.5 which

requires that potentially affected organizations complete a generic review

within 70 calendar days from the origination of the CAQR. Specifically

the inspector noted the following generic reviews that were performed

late: .

l

CAQR Due Performed -

SQN 871347 11/1/87 2/9/88

SQP 871003 8/10/87 2/24/88 /

SQP 871066 7/15/87 4/5/88 ,

SQT 871347 10/15/87 2/23/88

The inspector determined that the problem with late generic reviews has

existed for some time. The inspector reviewed various Site Quality

Manager memos which identified many overdue generic review items. The

memos identifying overdue generic reviews have been issued on a routine

basis. The inspector was informed by the Site CAQR Coordinator that the

l number of outstanding late generic review items has decreased from 137

during January 1988, to 24 during July 1988, and that NQAM Part I, Cection

2.16 is in the process of being revised to re-structure the time limits to

l a more workable structure. The NQAM will also require escalation to

! higher management based on late generic review items. SDSP 3.7 will be

revised to reflect the new NQAM revision within 90 days of NQAM issue.

The NRC inspector believes the problem of late generic reviews has

received insufficient management attention. This has occurred inspite of

,

the fact that licensee QA personnel have documented the problem in 2

different CAQRs during 1987 (BFP 87 0830 and BFP 87 0326). Additionally,

separate violations in this drea are documented in NRC Inspection Reports

86-43 and 87-41. Although the late generic reviews were identified by the

licensee, timely and effective corrective action has not resulted. This

constitutes an apparent violation for failure to follow procedure,

Violation 259, 260, 296/88-21-02, Failure to Perform CAQR Generic Peviews.

10. Condenser Retabing

Ouring July 18-19, 1988, an NRC inspector observed ongoing work associated

with DCN M0075A, Unit 2 Main Condensor replacement of Admirality Brass

tubes with Alleghtry Ludlum AL-6XN stainless tubes. The observed work was

being accomplished in accordance with WP 2165-88. The inspector reviewed

WP 2165-88 and noted that it included a special installation instruction

which stated various requi-ements intended to control the tubing

installation work and prevent damage to the new tubes prior to instal-

lation. The inspeccor noted various poor work practices which were not in

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accordance with the special instruction included in the work plan.

Spec.fically the inspector observed the following:

Unsupported sections of new tubing lengths of 25 to 30 feet Juring i

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installation and storage at the work location. Special instruction

required no more than 10 feet of unsupported span.

Failure to clean the full length of-new tubes with freon during the

, actual installation process.

WorAers were observed walking on new tubes located in the tube

storage rack.

Sections of heavy wood lumber used as temporary walkways were drug ,

'

across new tubes located in the tube ttorage rack, i

The inspector discussed the observed poor work practices with licensee

management and the licensee agreed to investigate the event and take

'

corrective action.

The licensee responded by way of a Modifications Manager memo dated

July 26, 1988 (R06 88 0725 876). As corrective action the licensee agreed

to revise the workplan, counsel the craft involved with the job, and take

additional measures to protect the new tubes during the ongoing work. ,

t

Although the condenser retubing wor ( is not associated with' CSSC  ;

components, there exists a significant concern that similar poor work

,

practices could exist on other jobs associated with safety-related systems ,

or components. [

No deviations or violations were iaentified.

,

11. Licensee Action on Previous Enforcement Matters (92702)  ;

i

(OPEN) Violation 259,260,296/88-04-02, Procedures improperly encouraged *

use of temporary "scratchpads" before making formal operating log

entries. The licensee admitted that this practice did not comply with the i

Nuclear Quality Assurance Manual and recently re.: 3ed Standard Practice  ;

12.24, Conduct of Operations, to eliminate this practice. Currently, the

procedure requires log entries to be made directly into the official

record at the time of the event. The inspector observed several operators '

over the cou-se of this inspection period and in all except two instances .

they were found to be in compliance with the new guidelines. In these l

two instances occurrences were not recorded in the log, even though

significant time had elapsed since they had occurred, and operators were

still using temporary "scratchpads." The operators did not appear to be ,

involved in activities that would hinder them from making prompt log *

.ntries. These cases were reported to the Operations Superintendent and

'

are considered to be example's of the continuing violation. This item l

will remain open pending furtner corrective action by the licensee and  ;

additional :smpling for compliance by all operators. $

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(CLOSED) Violation 259,260,296/84-34-04, Failure to adhere to procedures

and inadequate procedures which contributed to an incident involving

overpressurization of the Core Spray Systam on August 14, 1984. One

example of this violation involved an SI step which erroneously designated

M0V Board 2A or 2B vice the correct MOV Board 1A or 18. This SI has been

corrected. The second example involved failure on the part of an operator

to properly open a circuit breaker as required by the SI. In response to

this violation, the licensee conducted operator training on proper breaker

manipulation, clarified the step in the procedure, and added second party

verification steps throughout the instruction in order to assure that

similar operator errors would be minimized. Further, the licensee ini-

tiated a change to the TS which would eliminate the need to perform these

types of tests at power and allow testing to be performed during outages.

Thus the potential for a recurrence of this type of event and pcssible

interfacing system loss of coolant accident is diminished. The NRC

. inspector reviewed the associated procedure changes and the TS change.

The TS change was approved by the NRC on February 12, 1988. This

violation is considered closed.

(Closed) Deviation 259,260,296/87-02-01, Curbs and floor drains in

battery rooms and battery board rooms. This item concerned Section 10.11

cf the FSAR requiring that each battery room and battery board room

contain drains and curbs. A tour by a NRC inspector was made of the

battery and battery board rooms for all three units to ascertain that the

curbs had been installed. It was also noted that (a) Unit 2 had floor

drains in both rooms, (b) Units 1 and 3 had floor drains in the battery

rooms, and (c) Units 1 and 3 have a 2 inch x 6 inch opening in the wall

between the battery room and the battery board room to allow the water to

flow from the battery board room to the battery room floor drain. This

deviation in considered closed.

12. Followup of Open Inspection Items (92701)

(Closed) Inspector Followup Item 296/83-19-03, Shutdown board room conduit

damage. During a tour of the Unit 3 shutdown board rooms, the inspector

noted that several electrical conduits extending through the 3E0 room

south wall to the outside area were displaced 2 inches lower from the

- ;osition as indicated on the applicable TVA drawing 45N888-12RA.

The inspector reviewed the TVA drawing discrepancy report associated with

this item. The licensee evaluated the condition and determined the

installation as existing as acceptable and that the physical location of

the conduit was incorrectly shown on the original drawing. The inspector

reviewed the revised drawing modified to comply with drawing discrepancy

package No. 3-86-0772 which shows the correct conduit locations. This

item is closed.

(Closed) Inspector Followup Item 260/84-41-04, Relocation of HPCI EGM

control boxes. The licensee had identified the need to relocate the HPCI

EGM control bnxes (Panel 25-49 Turbine Control Panel) due to the harsh

er.vironment of high temperature and high humidity in which the control box

1

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18

was located. This item was opened to track corrective action until a

design change request (DCR) could be approved and the EGM control box

relocated.

The inspector reviewed ECN P3184, associated with DCR 2349, which called

for replacement and/or relocation of various components of the HPCI system

and determined that tne ECN was field complete and that the EGM control

box for the Unit 2 HPCI system had been relocated to a new location away

form the HPCI turbine skid. ECN P3184 had been written to upgrade the

environmental qualification of the HPCI System for Unit 2. The inspector

concludes that adequatc licensee corrective action has occurred to resolve

the original concerns as identified in the original inspection report for

Unit 2 cnly. This item is closed for Unit 2 but will remain open for

Units 1 and 3 pending future review of licensee actions.

(Closed) Unresolved Item 259,260,296/85-15-01, NDT curve out of date; no

surveillance required, and TS discrepancy between ur,its. The inspector

had identified three concerns during a review of Unit 1 TS. The concerns

identified were:

-

Out of date Figure 3.6-1 contained in TS

- No documented verification contained in G01-100-1, Integrated Plant

Operations, that reactor vessel shell temperatures were at or above

the temperature of curve no. 3 of Figure 3.6-1 as required by TS 3.6.A.2

- Inconsistency between Unit 1 and Unit 2 T: and Unit 3 TS for TS 3.6.A.1.

The 'qspector reviewed the documentation associated with the licensee's

reply to the identified concerns. The inspector noted that the following

corrective action had occurred:

-

TS for all units have been revised to remove the inconsis' /

identified above and to update Figure 3.6-1 for use until 12 LFPY

(effective full power years) of irradiation

- G01-100-1 has been revised to require that vessel shell and primary

wster temoeratures are greater than 180 F on all working indicators.

The inspector feels that the licensee's corrective actions are sufficient

to address the concerns as identified in the original inspection report.

This item is closed.

(OPEN) Unresolved Item 259,260,296/86-06-08, Inadequate slope on

instrument sensing lines. This item documented a failure to comply with

the targeted s' ope of 1 inch per foot during installation of Workplan No.

2040-35. Although 1 inch per foot downward slope is the goal, Construc-

tion $pecification G-60 allows as little as 1/8 inch per foot slope when

it is impractical to achieve the desired 1 inch per foot. The NRC

s

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inspector accompanied the modification engineer on his final . walkdown

inspection and witnessed selected slope measurements in the field.

, Revision 14 to the Workplan added a QC holdpoint to verify slopes on all

'

sensing lines. Revisions 21, 23, and 25 to the Workplan documented rework l'

necessary to meet the sloping requirement. Only one line failed to meet

the minimum slope criteria of Specifications G-60. Field change reqLest .

(FCR)86-178 documented zero slope on line B-5 shown on drawing 47W600-58.

Approval of the FCR on April 16, 1986 accepted the zero slope.

The instrument line having zero slope serves three instruments; 9T-64-160A

High Range Drywell Pressure, PT-64-57B High Drywell Pressi:re, and

PT-64-5BB High Orywell Pressure. The NRC inspector located the instrument

line on July 20, 1988, and found that it was not impossiblo to re-route

the line and achieve some downward slope. No fur;her engineering analysis

or safety evaluation was performed by the licensee to justify acceptance

of this deficient condition. Tnis aspect of the unrosolved item will

remain open pending further justification to be provided by the licensee.

All other aspects of the unresolved ite.. are esosidered closed.

$ (Closed) Unresolved item 259/260/296/86-14-02, Tuinel inspections. During

,

an April 1986 tour of the CST tunnel, NRC inspectors noted corroding

,

support base plates, pipe clamps with missing or loose fasteners, and a

'

general deterioration of the tunnel. During an NRC tour of this tunnel in

June 1988, it was noted that the area had been cleaned, painted a9d some

repairs completed. However, in a discussion with the licensee and a

review of the area drawings it was determined that this tunnel and related

piping are not safety-related and chis unresolved issue is closed.

, (Closed) Inspector Followup Item 259,260,296/86-16-03, Usage of non-

licensed operators. The inspectors had identified a concern about the use

of unlicensed operators in the control room. Although unlicensed

operators had sometimes been used to maintain the unit operator log book,

BF-12.24, Conduct of Operations, specifies that the Shift Engineer is

,

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responsible for insuring that proper records and logs are maintained and

that pericdic reviews are performed. These reviews shall be at least once

per shift, and documented by initials or signatures on each logsheet. In

the present plant condition with all units defueled, a licensed unit

operator is not required in the control room but only to be on site.

This area was reinspected in NRC Inspection Report 259,260,296/86-28 where

the inspector noted that implementation of the shif t engineer reviews was

only being done 50% of the time. This item was left open in 86-28 pending

further review.

During recent routine tours of the control room, the inspector noten chat

the unit operator log indicated proper reviews in all cases. Additionally

the inspector was informed by the licensee that the practice of using

unlicensed operators fcr this purpose has been stopped and will no longer

be necessary. This item is closed.

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(CLOSED) Unresolved Item 259,260,296/86-40-08, Failure to verify auto-

I matic initiation of primary containment isolation valves during

surveillance testing. This deficiency was identified by.the licensee's SI -

review and. upgrade program concurrently with the NRC's identification of

'

this finding. Valves 74-57, -58, -60, -61, -71, -74 and -75 were not in TS  :

Table 3.7.A which TS 3.7.D.1 references as listing the isolation valves '

required t, be operable. These valves were listed in TS Table 3.7.F.

! Primary Cw.cainment Isolation Valves located in Water Sealed Seismic Class

i 1 Lines. Table 3.7.F is not referenced in the text of tFe TS which is

,

silent on the operability and survsillance requirements for these valves.

'

The licensee has revised their sis to asure that these talves will be

tested for automatic initiation and closure. The licensee has submit ed a

! revised TS table 3.7.A incl;/ing all primary containme'it isolation valves

required to be operable.

No violation will be issued for this item since the TS d.J not clearly

l identify the operability requirements for these valves, and the licensee

l has taken action to revise the TS and include the valves in the SI test

program.

l

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This item is closed.

(Closed) Unresolved Item 259,260,296/86-43-02, Adequacy of CAQs Reviewed

i This item was associated with the adequacy of generic review of CAQs to

other nuclear facilities which TVA has in operation or under construction.

'

The concern was associated with 4 CAQs docur.. anted at Bellefonte and Browns

l Ferry Nuclear Plants and possibly applicable to other TVA sites. At the

time of the inspection there did not appear to be evidence of an adequate

l generic review for the identified CAQs due to a lack of documentation to

l verify performance.

l

l The inspector has reviewed the licensee's response to the concerns

l

identified in the original inspection report and determined that a

violation did not exist. Subsequent to the December 1986 inspection

licensee ONE personnel have provided documented evidence that potential

generic reviews had been performed or that the conditions were site

specific and did not atoly to other sites. This item is closec .

(Closed) Inspector Followup Item 259,260,296/87-09-07, Security lighting

DG building walkdown. This item had been openec' to identify <arious

t

concerns observed by the inspector during a walkdown performed in the

security lighting diesel generator building. The inspector reviewed a

licensee's Fire Protection Engineer memoranduto dated August 24,1987 (R43

87-324 882), with the attached supporting documentation. The NRC

inspector conducted a tour of the building and noted the following:

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There was no noticeable diesel fuel odor.

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DG mounting frame bolts and battery mounting bolts were secure.

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Firo extinguishers indicated current inspection.

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There has been a general improvement in housekeeping in the building.

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The inspector noted that the applicable fire extinguishers and fire

. protection valves have been added to the respective fire protection

instructions to insure routine verification. The NRC inspector concluded

that sufficient actions have occurred to add:ess the concerns as identi-

fied in the original inspection reports. This item is closed.

p (Closed) Inspector Followup Item 260/87-09-08, Deficiencies identified

during a review of the operating instruction (OI) upgrade program. A

rather extensive list of procedure deficiencies and enhancements were

noted during the inspection and tracked as a single IFI. The licensee

addressed each item and initiated procedure changes as necessary. The

inspector reviewed the changes and considered this item closed.

(Closed) Inspector Followup Item 259,260,296/87-30-01, Missed surveil-

lance due to discarded chemistry composite samples. On August 26, 1987

after completion of the monthly surveillance on radiation monitor filter

activity, the sample was inadvertently discarded. The sample would

normally have been retained for a quarterly strontium composite as

required by TS 4.8.8.3. This resulted in an unrepresentative quarterly

sample to characterize the third quarter of 1987. The licensee determined

that the error was due to personnel error i.e., failure by a chemist to

properly table the samples resulting in another chemist mistaking it for

waste. This resulted in toe issuance of LER 87-023 to report the missed

surveillance.

As corrective action to prevent reoccurrence of this event, the licensee

has revised SI 4.3.B.2-2, Airborne Effluent - Particulate Filter Analysis

(Monthly Gross Alpha), to include the requirement to properly table the

sample and store in a proper storage location. The inspector was informed

by licensee management personnel that there have been no similar

recurrences of inadvertently discarding semples since SI-4.8.B.2-2 was

revised. The inspector concluded that the licensee's actions were

adequate to cddress the concern as identified in the original inspection

report. This item is closed.

(0 pen) Inspector Followup Item 260/87-42-05, Insulation cut away around

tailpiece valves75-646 and 647. A testing manifold installed on contain-

ment Spray Loop II is equipped with a three-/luarter inch test / drain

tailpiece containing the above two valves and comes so close to a longer

insulated pipe that part of the insulation had to be removed. The

clearance between the two pipes had been questioned. The inspector

performed a visual inspection of the two pipes and noted that the larger

pipe had only dead weight supports and could be easily moved horizontally

N by hand. The inspector questioned wh6ther in a seismic event the larger

non-safety-related pipe could move he. izontally and shear of f the smaller

safety-related pipe. A CAQR was written to have design evaluate this

condition. This condition will remain open.

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13. General Electric Contractor Recommendations

The NRC inspector continued to review the status of the licensee's

resolution / implementation of recommendations made by General Electric as

part of the system review program as discussed in NRC Inspection Report

88-16. In particular the inspectors reviewed the adequacy of the

licensee's classification of closed and outstanding open items for proper

determination as to whether the item was required to be resolved prior to

Unit 2 restart. Items classified as Category A are required to be

resolved prior to unit startup while items classified as category B

through E are not required to be completed prior to restart or'may not be

completed at all.

The inspector selected system 63, standby liquid control system, for

review. The GE systems review punchlist includes a total of 36 items

classified as category B, C, D or E. No items were classified as Cate-

gory A. The ' classification of each item was compared to the restart

criteria as defined in TVA system engineering memorandums dated August 10,

1987, and November 12, 1987 (R40 870810 976, R40 87110 997). The inspec-

tor did not identify any punchlist items which did not appear to be

properly classified. However two concerns were identified and discussed

with the licensee.

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Several items associated with revisions to system operating

instructions, system drawings, and surveillance instructions were

classified as category B and showed no completion date under status

column indicating that the items were not complete. The licensee

stated that the significance of the revisions had not rated a

classification of category A fcr the items; however, the corrective

action in each case was complete. The open status was to reflect

penoing management review of each item.

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Items 63-30, 63-33 and 63-35 were associated with control of GE

Design Specifications. Design Specifications are vendor supplied

design information provided for each GE system during plant

construction. TVA has not updated or controlled the GE Design

Specifications for Browns Ferry since initial construction. This

concern exists for other GE systems also and is documented as

outstanding items on other GE systems. The items are closed on the

system review punchlist and status is stated as "TVA cloes not Control

GE Design Specifications and will not be changed." The licensee has

no plans to revise the Design Specifications and licensee management

stated that 10 CFR 50, Appendix B, Criteria III, Design Control,

requirements are met by separate design basis information resulting

from the Browns Ferry Design Baseline and Verification Program

(DBVP). The licensee further stated that the GE Desi' *pecifica-

tions were used only as information and not as basis foi Jesign work.

The inspector will review this area during the upcoming inspection

periods.

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14. Exit Interview

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The. inspection scope and findings were summarized on August 1, 1988, with

those persons indicated in paragraph 1 above. The inspectors described

the areas inspected and discussed in detail the inspection findings listed

below. The licensee did not identify as proprietary any of.the material

provided to - or reviewed by the inspectors during this. inspection.

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Dissenting comments were not received from the licensee.

, Item Number Description and Reference ,

URI 88-21-01 Administrative control of high radiation area door

keys as required by TS 6.8.3.2

VIO 88-21-02 Failure to perform CAQR Generic Reviews in

timely manner as required by NQAM Part~1, Section

2.16.

IFI 88-21-03 RHRSV Corrosion

IFI 88-21-04 Deficiency identified during the retest of

LOP /LOCA C

IFI 88-21-05 Vaulting of Completed and Approved Test Results

IFI 88-21-06 Adequacy of identifying and closing out of

significant hardware test exceptions; Licensee's

TE Categories 1.1 and 1.2.

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15. Acronyms and Abbreviations

ATU - Analog Trip Unit

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BFN - Browns Ferry Nuclear

BTRO - Baseline Test Requirement Document

CAQR - Condition Adverse to Quality Report

CSSC - Critical Structures, Systems, and Components

DCR - Design Change Request

DG - Diesel Generator

DNE - Department of Nuclear Engineering

DPT - Differential Pressure Transmitter

ECN - Engineering Change Notice

EECW - Emergency Equipment Cooling Water

EFPY - Effective Full Power Years

FCR - Field Change Request

FPC - Fuel Pool Cooling

IFI - Inspector Followup Item

JTG - Joint Test Group

LER - Licensee Event Report

LOP /LOCA - Loss of Power / Loss of Coolant Accident

MG - Motor Generator

MR - Maintenance Request

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NQAM - Nuclear Quality Assurance Manual

OI - Operating Instructions

OSIL - Operations Section Instruction Letter *

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PMT -

PORC - Plant Operations Review Committee

QA - Quality Assurance . '

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RCA - Radiologically Controlled Area

Radiologically Control Instruction

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RCI -

RCW - Raw Cooling Water

RHR - Residual Heat Removal

RHRSW - Residual Heat Removal Service Water

RPS - Reactor Protection System-

RTP - Restart Test Program

SDSP - Site Director Standard Practice

SI - Surveillance Instruction

SOS - Shift Operations Supervisor

TACF - Temporary Alteration Change Form

TE - Test Expectations

TS - Technical Specifications

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