IR 05000259/1987026

Insp Repts 50-259/87-26,50-260/87-26 & 50-296/87-26 on 870601-30.Violations Noted.Major Areas Inspected:Maint Observation,Environ Qualification of Electrical Equipment, Employee Concerns Program & Operator Training

ML20236M013
Person / Time
Site:	Browns Ferry
Issue date:	07/31/1987
From:	Bearden W, Brockman K, Brooks C, Ignatonis A, Andrea Johnson, Patterson C, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20236L984	List: IR 05000259/1987026 ML20236L980 ML20236M000
References
50-259-87-26, 50-260-87-26, 50-296-87-26, IEB-79-14, NUDOCS 8708100445
Download: ML20236M013 (24)

Text

pn Riou

. UNITED STATES

'

o NUCLEAR REGULATORY COMMISSION

[ -

REGloN ll

~

n g.

,j 101 MARIETTA STREET, N.W.

.*

ATI. ANTA, GEORGIA 30323

'\\.....lc

.

i Report Nos.

50-259/87-26, 50-260/87-26, and 50-296/87-26 Licensee: Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.

50-259, 50-260, and 50-296 License Nos. DPR-33, DPR-52, and DPR-68 Facility Name:: Browns Ferry Nuclear Plant Inspection at Browns Ferry Site near Athens, Alabama Inspection Conducted: June 1-30, 1987 Inspectors:

b 9.'

Ilo4-~~.

'7 /.w /t 7 p G. L. Paulk, Senior Resident Inspector Date Signed C" ' Odh~

7 /av h 7 C. A. Patterson, Resident Inspector Date Signed 8c dA_

,/24 4,

C. R. Brooks, Resident Inspector Date Signed p&

P.<. / l l / m.

74 S /n A. H. Johnson, Project Engineer Date Signed 621w

,In h,

n (o n.

O W. C. Bearden, Resident Inspector Date Signed p

(%

A ll-oleh m

'v * K. E. Brockman, Training Inspector Date Signed

'7[3/ /87 Approved by:

6-

- c /cw

~

Date 61gn'ed /

A.J.IgnaYonis,yctionChief, Inspection

~

Programs, Division of TVA Projects i

SUMMARY Scope: This routine inspection was conducted in the areas of operational. safety, maintenance observation, reportable occurrences, environmental qualification of electrical equipment, IE Bulletin 79-14, the Employee Concerns Program, operator training, previous enforcement matter, corrective actions, Nuclear Safety Review Staff, and special nuclear material inventory.

Results:. A violation of 10 CFR 50, Appendix B was identified for failure to properly disposition a significant condition adverse to quality.

k[

[

e

)

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

_. _ _ _

_

DETAILS 1.

Licensee Employees Contacted:

H. G. Pomrehn, Site Director J. G. Walker, Deputy Site Director P. J. Speidel, Project Engineer

• R. L. Lewis, Plant Manager J. D. Martin, Assistant to the Plant Manager

• R. M. McKeon, Superintendent - Unit Two

• J. S. Olsen, Superintendent - Units One and Three T. F. Ziegler, Superintendent - Maintenance D. C. Mims, Technical Services Supervisor J. G. Turner, Manager - Site Quality Assurance M. J. May, Manager - Site Licensing

.

I P. P. - Carrier, Compliance Supervisor A. W. Sorrell, Health Physics Supervisor i

R. M. Tuttle, Site Security Manager

• J. R. Kern, Fire Protection Supervisor Other licensee employees contacted included licensed reactor operators,

'

auxiliary operators, craftsmen, technicians, public safety of ficers,

quality assurance, design and engineering personnel.

2.

Exit Interview (30703)

The inspection scope and findings were summarized on July 7,1986 with the Plant Manager and/or Superintendents and other members of his staff.

The licensee acknowledged the findings and took no exceptions.

The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.

• Attended exit interview 3.

Licensee Action on Previour Enforcement Matters (92702)

(Closed) Unresolved Item (259,260,296/85-49-05, RPS Power Transfer and Containment Isolations), The licensee has revised Surveillance Instruction, SI-4.1.B-16, Electrical Maintenance Instruction, EMI-13, and Operating Instruction, 01-99, to include precautions to warn the operator that a RPS power transfer would result in a containment isolation.

Additionally, j

i EMI-13 and SI-4.1.B-16 were revised to include the requirement that all transfers be performed in accordance with 01-99.

This item is closed.

(Closed) Open Item (259/85-06-09, Capacitor Life), The licensee has com-

'

pleted the program to identify all aluminum electrolytic capacitors main-tained on the master inventory materials management system (MAMS) data base and established an adequate program for tracking shelf life and controlling issuance of any capacitors used on safety related systems. Additionally,

,

any capacitors in inventory that have exceeded shelf life have been replaced

]

i i

i a

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

l

.

.

s l

or identified and tagged to warn maintenance personnel of the nonconforming condition. A CAQ must be used to track any expired capacitor that must be used in a safety related application and a non-comformance tag attached to the affected equipment until a acceptable replacement capacitor can be obtained.

This item is closed.

(Closed) Open Item (259/85-06-13, Core Spray Check Valve Solenoid Mainte-nance), The licensee has completed the evaluation of the problems associated with the solenoid valve, 75-26.

The problem was that parts from the Unit 1 valve were found not to be interchangeable with the Unit 2 valve. The Unit I solenoid valve was cf a newer design (ASCO model # WPHTX834A73) than the valve installed in Unit 2 (ASCO model # WPHTX834472).

The original valve design (model # WPHTX834472) is no longer available and solenoid valves of the newer design are automatically provided from the supplier along with an ASCO certificate of compliance whenever replacement valves are ordered.

Both valve designs are interchangeable since the valve body fittings are the same., but the various parts are not interchangeable between the two designs. Mechanical Maintenance Instruction, MMI-51, Section 8.2.2b was revised to require that when solenoid problems were found the complete

,

solenoid valve assembly would either be replaced or an approved detailed rebuilding procedure utilized to perform the work.

This item is closed.

(Closed) Inspector Follow-Up Item (259, 260, 296/84-48-04, Log book Not Kept on Real Time Basis), The licensee has issued Standard Practice, SF-12.24, Conduct of Operations since the inspectors observation of the usage of unofficial logsheets by operations personnel.

Section 5.4.1 of SF-12.24 requires that all entries shall be made in black ink at the time indicated on the log. Section 5.4.2 further states that formal logs are to be main-tained as up to date as practical during the shift. Routine tours by the inspector through the control room have not revealed any use of unofficial logsheets by operations personnel.

This item is closed.

(Closed) Unresolved Item (259, 260, 296/81-37-05, Water Level Perturbation af ter Test), The requirement for reactor vessel water level perturbations per note 5 of Technical Specification table 4.1.A has been deleted from each of the three unit's Technical Specifications.

This revision is reflected in Amendment 113 (Unit 1), Amendment 107 (Unit 2), and Amendment 81 (Unit 3).

This item is closed.

(Closed) Open Item (259/260/296/84-24-01), The disagreement between the FSAR and Browns Ferry Standard Practice BF 4.8 concerning the amount of respon-sible power plant experience which the shift engineer shall have at the time of his appointment to the active position was corrected.

The FSAR was revised to say that the shift engineer shall have five years experience of responsible power plant experience; this agrees with the requirement as outlined in the Standard Practice.

(Closed) Deviation (259/260/296-84-24-02), 10 CFR 55.31(e) stated that if a licensee had "not been actively performing the functions" of an operator or senior operator for a period of four months or longer, certain requisite actions needed to be taken prior to resuming such activities.

Browns Ferry Standard Practice BF 4.8 defined "not performing the functions" of an

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

_ _ _ _ _ _ _ -

_.

_____

_-

_

.

.

1 operator as not being at the plant site; in this regard, it did not consider the possibility of being on site and still not performing the functions of an operator.

BF 4.8 was superseded by PMP 0202.05, which correctly referenced 10 CFR 55.31 (e) and did not restrict the interpretation of not performing operator duties. Furthermore, 10 CFR 55 was revised, effective May 26, :387. The revised regulation is specific in its description of how an operator meets the requirements for maintaining an " active" license and is prescriptive in the actions which must be accomplished to convert from an

" inactive" to " active" status.

The need to follow up on this procedural shortcoming is no longer considered appropriate, given the guidance of the new regulation.

4.

Unresolved Items * (92701)

There were two unresolved items identified in paragraph 10 and one unresolved item in paragraph 13.

l

'

5.

Operational Safety (71707,71710)

The inspectors were kept informed of the overall plant status and 'any significant safety matters related to plant operations. Daily discussions were held with various members of the plant operation staff.

The inspectors made routine visits to the control rooms when an inspector was on site. 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 operation; purpose of temporary tags en equipment controls and switches; annunciator alarm status; adherence to procedures; adherence to limiting conditions for operations; nuclear instruments operable; 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 their supervisors.

General plant tours were conducted on at least a weekly basis. Portions of the turbine building, each reactor building and outside areas were visited.

Observations included valve positions and system alignment; snubber and hanger conditions; containment isolation alignments; instrument readings; housekeeping; proper power supply and breaker; alignments; radiation area controls; 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.

Weekly verifications of system status which included major flow path valve alignment, instrument alignment, and switch position alignments were per-formed on the electrical distribution system, standby gas treatment system and residual heat removal system.

• An Unresolved Item is a matter about which more information is required to determine whether it is acceptable or may involve a violation or deviation.

_________-__________--__-___

-

-

.

In the course of the monthly activities, the inspectors included a review of the licensee's physical security program.

The performance of various shifts of the security force was observed in the conduct of daily activities to include; protected and vital areas access controls, searching of personnel, packages and vehicles, badge issuance and retrieval, escorting of visitors, patrols and compensatory posts.

In addition, the inspectors observed protected area lighting, protected and vital areas barrier integrity.

6.

Vendor Manual Control Program Status The Division of Nuclear Engineering (DNE) continues to review and approve vendor manuals. However, maintenance and operating instructions are being rewritten assuming at this time that there will be no changes in vendor manuals.

-

The following is the status of the incorporated information from the Vendor Manual Control Program into the operating, maintenance, and surveillance instructions (NPP. Volume 3, Attachment IV-2, Item 20).

(1) Maintenance and Surveillance Instructions (combined totals)

(a) Mechanical - 74 completed instructions (PORC reviewed) out of 87 (b) Electrical - 91 completed instructions (PORC reviewed) out of 178 (c) I & C - 49 completed instructions (PORC reviewed) out of 179 (2) Operating Instructions and Surveillance Instructions (separate totals)

(a) 9 operating instructions (PORC reviewed) out of 71 (b) 6 abnormal operating instructions (PORC reviewed) out of 69 (c) 0 general operating instructions (PORC reviewed) out of 10 (d)

17 surveillance instructions (PORC reviewed) out of 73 7.

Maintenance Observation (62703)

l Plant maintenance activities of selected safety-related systems and com-

.

ponents were observed / reviewed to ascertain that they were conducted in l

accordance with requirements. The following items were considered during this review: the limiting conditions for operations were met; activities were accomplished using approved procedures; functional testing and/or calibrations were performed prior to returning components or system to service; quality control records were maintained; activities were accom-plished by qualified personnel; parts and materials used were properly certified; proper tagout clearance procedures were adhered to; Technical Specification adherence; and radiological controls were implemented as required. Maintenance requests were reviewed to determine status of out-standing jobs and to assure that priority was assigned to safety-related

-

__

. _ _ _ - _ _ - _ _ _

!

.

,

equipment maintenance which might affect plant safety. The inspectors observed the below listed maintenance activities during this report period:

a.

At 12:51 p.m. on March 3,1987, fire protection dampers in diesel generator rooms 3B and 3C were found to be inoperable. These dampers are required to close upon actuation of the carbon dioxide (Cardox)

fire protection system in each room.

Both dampers were found stuck in the open position by the licensee.

The fusible alloy link which is designed to part in the event of a fire and initiate closure of the damper was found to be separated in one of the rooms.

Emergency priority maintenance requests (MRs) were written (numbers 759311 and 785752) and worked that day.

The system was returned to service by 6:00 p.m. that evening. As part of the routine review that takes place by Planning and Scheduling, a failure investigation was initiated on the next day. The inspector randomly selected this activity for review and identified the following items of concern.

(1) The failure investigation attributed the cause of the damper failure to a collection of dust on the damper blades and infre-quent cycling. A visual inspection of the dampers during the week of June 8, 1987, found that an excessive dust buildup remained on the dampers.

Licensee representatives confirmed that the dampers had not been cleaned as part of the maintenance performed in March. The work instruction on the MR was simply to " lubricate and repair". The work performed block on the MRs shows that the dampers were lubricated.

This lubricant was inappropriately applied over the dust accumulation.

(2) As of June 19, 1987, the Plant Operations Review Committee (PORC)

had not reviewed the circumstances surrounding the damper failure.

All similar dampers in the remaining diesel rooms were inspected as part of the failure evaluation and four additional dampers were found stuck open. Thus, 6 of the 16 diesel room fire dampers were

)

found inoperable even though they are operated annually during the

)

performance of Surveillance Instruction (SI) 4.11.B.I.a, CO2 Fire

)

Protection Logic System Functional Surveillance last performed on l

February 21, 1987.

Technical Specification 6.2.B.4 requires that PORC shall maintain a general surveillance of plant activi-ties to identify possible safety hazards and that PORC shall review abnormal performance of plant equipment.

Although, not explicitly required in any site procedure, the plant Maintenance l

Superintendent had not reviewed the Failure Investigation Report for these dampers until the week of June 15, 1987, after the issue I

l was raised by the inspector. Once appropriate management atten-tion was brought to bear on the issue, the root cause investigation was reinitiated.

(3) Although, the original failure investigation report was completed on March 16, 1987, little progress has been made on the corrective

I

_ _ _ - _

_ _ _ _

A

_ _ _-___ _ ____

.

.

actions to prevent recurrence.

These were to include the following.:

(a)

Increase frequency of preventive maintenance (PM)

(b)

Increase damper inspection program (c) Change lubricant if possible (d) Adjust damper setting to increase initial gravity force The dampers are not yet included in the PM program. No resolution has been reached on which lubricant should be used and where the lubricant should be applied.

Current thinking is that any lubricant may be adverse to the dampers since it may increase dust accumulation.

It is not yet known how the damper linkages are meant to be adjusted to provide the proper gravitational driving force for closure. Administrative control over failure investi-gation corrective action recommendation was found to be deficient in that they are not placed in any other tracking or closure system.

Thus, when the failure investigation report is completed, closure of the outstanding corrective action is not assured. This is a programmatic deficiency.

(4) No failure investigation was initiated on the failed fusible alloy link.

The inspector learned of an additional fusible link failure which occurred in the oil dispensing room on June 8,1987 (NR number 791499).

(5) The work instructions and post maintenance test requirements on the MRs were inadequate. The work instructions were to " lubricate and repair". No details were available on what lubricant was to be used and what points were to be lubricated.

No details on how the damper linkages were to be adjusted was provided. No vendor manuals are yet available on these dampers.

The post maintenance test requirement simply stated that the craftsman was to verify proper operability of the damper.

No f urther documentation of what type of check was performed to verify operability was con-tained on the MR. The failure codes listed on the MR was for loose mechanical parts or fasteners. This did not correspond to the failure investigation root cause assessment.

(6) Two Licensee Reportable Event Determinations (LRED) were initiated

,

for this problem (LRED numbers 87-3-128 and 87-3-132).

The i

deportability logic was confined to whether fire protection technical specifications were violated and if appropriate com-pensatory actions were timely.

It did not consider whether a damper failure in the closed direction would make the diesels inoperable due to loss of ventilation to the diesel room nor did the logic address the common mode failure deportability criteria of 10 CFR 50.73(a)(2)(V).

- - - - - - - - - - - - - - - - - - - - - - -

__j

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

-

,

(7) Other administrative abnormalities were detected by the licensee during their review of this event. These included such problems as lost MRs, failure of QA to perform a required review and improper descriptions in the work requested sections of MRs.

These concerns were collectively addressed as a violation of the corrective action requirements of 10 CFR 50, Appendix B (259,260, 296/87-26-01). 'They were discussed with the Plant Maintenance Superintendent on June 19, 1987, and with the plant manager during the monthly exit meeting, b.

The resident toured the off gas building on June 24, 1987, for a general housekeeping inspection. The following concerns were identi-fied by the inspector.

The licensee has taken the following actions:

(1) Concern:

Bent position indicator on valve 2-66-600.

Resolution: MR763871 has been written to correct.

(2) Concern: Absorber drain valves 2-66-622,2-66-623, 2-66-634 and 2-66-638 have Chicago fittings installed instead of pipe caps.

Resolution: Drawing 2-47E809-4 shows valves 2-66-634 and 2-66-638 with Chicago fittings. MR763872 will replace the pipe caps on valves 2-66-622 and 2-66-623.

(3) Concern:

Unattended, uncontrolled instruction in off gas building (C.I.466.2 - post treatment /off gas procedure Rev. 0)

Resolution: This concern was discussed within the chemi stry section with emphasis on instruction control within the plant.

(4) Concern: Air damper 0-31-123, AC unit Man. Damper excessively dirty.

Resolution: MR702254 written to clean damper.

System engineer will determine the need of a PM item for the periodic cleaning of the air damper, c.

Containment Spray Header Examination For Rust The NRC requested the licensee to inspect the Unit 2 containment spray headers for rust deposits that might affect system operabilit/. There is no history of leaks into the containment spray Header or inadvertent actuations of this system on the licensee files. The containment spray header nozzles are tested in accordance with Surveillance Instruction 4.5.2a (using air). This SI is performed every 5 years. 'There have been no indications of blockage of the nozzle heads found during the past performance of this SI.

On June 25, 1987, the Unit 2 containment spray header nozzles at elevation 601', azimuth 45 and 315 were removed and inspected for rust per MR (maintenance request) A-710489.

There was a slight amount of rust uniformly distributed and tightly adhered inside the carbon steel piping (i.e. 10" Spray Header and 1-1 1/2" Standard Nipples).

The brass nozzle heads had no signs of loose rust and no signs of i

____

_

N

o

a

t I

oxides.

Therefore, based on these findings, the operability of this system and_the nozzle spray pattern will not be adversely affected by these indications.

8.

Operator Training On June 2,1987, two inspectors from the Regional office inspected the Accelerated Requalification Training Program for the licensed operators.

The program is being conducted in the Training Facility at the plant site.

It consists of both classroom and simulator components; it was started in early 1986 in response to the poor. performance of the operators on the Requalification Examination. administered by Regional examiners in November 1985.

The inspectors observed training in both the classroom (refueling equipment-and procedures) and on the simulator (Emergency Operating Procedures Useage

- ATWS).

They found the training to be consistent in both its scope and relevancy to previous requalification presentations inspected during the past 18 months. The classroom training concentrated on the equipment used and the operational restrictions imposed (by interlocks and rod blocks)

during fuel movement operations. The simulator training was a continuation of the previous day's class and exercised the operators in the use of the sympton-based Emergency Operating Procedures in an ATWS situation.

In both cases, the instructors were highly qualified and provided excellent information.

l Additionally, the inspectors conducted interviews with several of the licensed operators who were participating in the training curriculum.

Results of these interviews indicated that the trainees felt the program

continued to be an improvement over the requalification training which

!

existed before the November 1985, exam. The use of contractor instructors was seen to be decreasing and this was seen to be a positive influence on attaining long-term solvency in the training department.

Two Open items from a Training Assessment inspection conducted in 1984 (Inspection Report 50-259, 50-260, & 50-296/84-24) were reviewed by these inspectors; the corrective actions of the facility were found to be satis-factory and these items closed as noted in paragraph 3 of this report.

9.

Reportable Occurrences (90712,92700)

The below listed licensee events reports (LERs) were reviewed to determine if the information provided met NRC requirements.

The determination included: adequacy of event description, verification of compliance with technical specifications and regulatory requirements, corrective action taken, existence of potential generic problems, reporting requirements I

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

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

• conducted.'The following licensee event reports are closed:

I

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

-

.

'i

l-LER No.

Date Event 259/85-06 3/4/85 Inoperability of High Pressure Coolant Injection (HPCI) System 259/85-15 5/1/85 Inoperable Residual Heat Removal Valve (FCV-77-66) Due to Sheared Gear Teeth in Limitorque Operator 259/85-19 5/23/85 Failure to Align Fire Pump Isolation Valves Properly 259/85-36 6/26/85 Ongoing 10 CFR 50 Appendix J Reviews 259/85-45 9/4/85 Inadequate Emergency Equipment Cooling Water (EECW)

Flow to Residual Heat Removal (RHR) and Core Spray (CS) Room Coolers 259/85-53 11/18/85 Failure to' Meet 10 CFR 50, Appendix J Criteria 259/85-56 11/19/85 Incorrect Wiring of Shutdown Board 259/86-19 6/8/86 Inadvertent Secondary.

Containment Isolation from Radiation Monitor Spike 259/86-20 6/19/86 Unexpected Auto Start of Emergency Cooling Water (EECW)

Pumps 259/86-27 7/31/86 Overload Settings Cause Control Room Ventilation (CREV)

Fan Trips 259/86-29 9/11/86 Personnel Error Leads to Engineered Safeguards Actuation 259/86-33 12/2/86 Inadvertent Secondary Containment Isolation from a Radiation Monitor Spike 259/86-34 12/9/86 Control Room Emergency Ventilation (CREV)

System Initiation from High Radiation Trip

-

.

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

.. _ _.

_ _...

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

}

.. -

_

-____--

.

.

LER No.

Date Event 259/87-07 4/9/87 Radiation Monitor Connection Faults Cause Control Room Emergency Ventilation (CREV)

Initiation 260/86-14 10/3/86 React.or Water Cleanup (RWCU) System Pipe Crack'

The cause of the inoperability of the HPCI system (LER 259/85-06) was a blown fuse. The fuse was replaced and the surveillance instructions were successfully completed. A licensee investigation determined that the fuse failure was a random failure.

A new spline gear was installed in the limitorqua operator (LER 259/85-15),

the post maintenance-surveillance instruction was performed satisfactorily, and the valve was returned to service. The licensee considered this to be a random failure.

The licensee found that two of the fire system isolation header valves ~(LER 259/85-19) had been left closed after maintenance repair work to anotherz header valve. A review of the fire header isolation incident with emphasis on procedural controls and verification of valve positioning was conducted

'for operations personnel. Personnel corrective action was taken with the involved licensed shift engineer and assistant shift engineer.

-It was discovered that additional reactor core isolation cooling and high pressure coolant injection system isolation valves (LER 259/85-36) were not being local leak rate tested. These additional valves have been added to the licensee Appendix-J program and will be tested as required.

I During the performance of TI-33, EECW Flow Verification Test, (LER 259/

85-45) the EECW flow to both loops of core spray room coolers on Unit I and loop 2 of the RHR room coolers on Unit 3 was found lower than specified minimums. The required flows to the RHR_and core spray room coolers were reset to their required valves.

An evaluation of past TI-33 data was performed to evaluate the frequency of performing TI-33 and no change to the frequency was made.

In addition, tags were hung on all throttle valves that regulate EECW flows to prevent inadvertent manipulation.

An ongoing review of the Browns Ferry Appendix J program (LER 259/85-53)

determined that valve packings on the reactor core isolation cooling and high pressure coolant injection system should be leak rate tested in order to meet Appendix J requirements. The valve packings have been added to the licensee Appendix J program and will be tested as required.

During the performance of a surveillance instruction it was discovered that the normal and alternate control power supplies were reversed (LER 259/

85-56) to a shutdown board because of a wiring error.

The wiring error was corrected and properly terminated. The wiring to the remaining shutdown.

boards was verified to be wired properly.

o

_ _ _ _

_.

.

.

.

.

.

..

.

...

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

._

.

The inadvertent secondary containment isolation (LER 259/86-19) was caused I

by a trip of the refuel zone ventilation radiation monitor. After a third isolation a complete inspection was performed on the monitor. An electrical connector plug was found to have two pins recessed which prevented reliable electrical contact. The female portion of the electrical connector plug was replaced.

A raw cooling water system pressure switch (LER 259/86-20) was found to have an abnormally high setpoint drift.

The pressure switch was designed to start the EECW pumps on sensed raw cooling water system pressure. Until the switch is replaced the licensee will perform monthly calibrations of the switch.

Following a number of CREV unit A failures, (LER 259/86-27), due to thermal overloads, it was determined that the thermal overload settings needed to be increased from 100 percent to 114 percent. TVA design guidelines allowed these adjustments and no further thermal overload tripping problems have been encountered.

Personnel erroneously opened the bus potential transformer cabinet on a shutdown board (LER 259/86-29) to inspect conduit floor penetrations.

Opening the cabinet door pulled fuses which caused an engineered safeguards actuation.

The caution labels on the cabinets were replaced with more specific warning instructions.

An investigation into the inadvertent secondary containment isolation (LER 259/86-33) revealed the suspect radiation monitor was performing normally and that a keyed two-way radio caused the radiation monitor to spike.

Warning signs were placed on the refuel floor area to preclude the use of two-way radios in the vicinity of the radiation monitor.

After the CREV system initiation, due to a radiation monitor trip, (LER 259/86-34) the licensee determined a partially inserted check source caused the radiation monitor to trip. The surveillance test was changed to verify the radiation monitor background reading at the start of the test and to visually verify that the check source is withdrawn.

Licensee investigation into the cause of the CREV initiation (LER 259/87-07)

revealed a broken terminal lug on the 110 volt neutral wire, along with a poor detector connection to the radiation monitor. The broken lug and the high voltage connector were repaired and replaced.

The functional test was then satisfactorily run.

Using ultrasonic techniques inservice inspection personnel detected and sized a crack indication in the Unit 2 reactor water cleanup system piping (LER 260/86-14) at a butt weld between the inboard and outboard isolation valve.

The weld was repaired by weld overlay. Additional welds accounting for 100 percent of the accessible RWCU system welds were examined.

No indications were found in the additional sample.

. _ _

____-___--__D

_

_ _ _ _ _ _ _ _

-

.

10.

IE Bulletin 79-14 Program The licensee's 79-14 Program is described in the Nuclear Performance Plan Volume 3, page III-26.

Basically, Phase I of the program involved field inspection of pipe supports in order to determine and document the as-built configuration. The field teams documented the as found cos.dition of the restraints by marking (in red ink) on the controlled drawings.

If a drawing of the support was not previously in existence, the Phase I team was to make a field sketch.

These drawings were then brought back to the office and analyzed by a qualified engineer for interim acceptance of the support.

Phase II of the program is to involve a more rigorous set of calculations to assure full code compliance of the piping support.

Phase III involves modifications required as a result of the rigorous Phase II analysis. The licensee has committed to completing Phase I prior to Unit 2 restart and the remainder of the program prior to the next operating cycle.

In 1985, after a major portion of the Phase I activities was complete, questions surfaced regarding the adequacy of the previous field inspections.

The licensee initiated a sampling program in order to disposition these

concerns. Although, the sampling program review of 60 supports confirmed that many discrepancies existed in the data recorded during the Phase I field inspections, the discrepancies were judged to be of a minor nature which would not have invalidated the original engineering acceptance of the support.

The sampling program therefore concluded that the inspection activities that had been completed prior to May 1985, were not compromised.

The number of deficiencies were, however; sufficient to prompt a revision to the program activities remaining.

This revision required a two party verification during completion of the Phase I walkdown activities.

For the supports which were walked down prior to May 1985, an additional verifi-cation walkdown is required as part of the Phase II process.

The inspector witnessed one of these Phase II verification walkdowns and noted many discrepancies in the Phase I data.

For example, a lug recorded as 4 inches on the Phase I data sheet was actually 3 inches. The inspector questioned whether this discrepancy would have an impact on the original Phase I engineering acceptance of the support.

The licensee indicated that the original Phase I evaluations are not questioned since their sampling program confirmed that although discrepancies may be present, none of j

those found during the sampling program adversely affected the original judgement.

The inspector indicated that when a difference between the as-built configuration and the Phase I documentation is found, a judgement must be made by a qualified individual as to whether the prior engineering evaluation remains valid.

It appears to be inappropriate for one to assume that a sampling program of 60 supports can provide insight into a specific deviation from the previously analyzed condition. This question as to whether a sampling program is an acceptable disposition to the concerns raised regarding the adequacy of the prior-to-1985 walkdown inspections will be left as an unresolved item pending further review by NRC specialists (259/260/296-87-26-02).

Should the sampling program be unacceptable, this might also impact on the schedule for completion of Phase II.

In other words, the Phase II verification walkdown may need to be completed prior to Unit 2 restart in order to validate the Phase I inspections which were performed prior to May 1985.

J

- _ _ _ _ _. _ _

-

.

An additional area of concern was identified in the 79-14 program related to drawing control. In many instances, the Phase I drawings and sketches are the only support drawings available on site. In other cases the official controlled drawings differ significantly from the Phase I drawings and actual support configuration. The Phase I drawings are not controlled drawings and are not yet official " design output documents" and will not be until completion of the program several years away. In the interim, main-tenance, modifications, engineering and other activities may inappropriately be performed to the inaccurate " controlled drawings".

The licensee had previously identified this problem but has not yet decided how to properly control activities in the interim period.

The 79-14 program has undergone close scrutiny by various licensee audit i

groups including Quality Assurance, Quality Surveillance and Engineering

'

Assurance. Several Corrective Action Reports (CARS) and Condition Adverse to Quality Reports (CAQRs) are outstanding on the program.

One finding worth following up on for generic implications will be emphasized here.

This finding came from Engineering Assurance Audit 87-13 as a Deficiency No.

87-13-6 and will be tracked as unresolved item (259,260,296/87-26-03).

-

The 79-14 program discrepancy problem 081281-05 deals with RHR pump suction line anchors not qualified for design loadings, and no valid design calcu-lations for these supports are available. The discrepancy form states the anchors are qualified per " existing pipe analysis and nozzle allowables as

,

per BFN-RAH-307." The supporting calculations for this discrepancy focuses

!

l almost entirely on the pump nozzle allowables rather than the anchors. No l

mathematical calculations are included in the body of this report, and none are referenced to indicate if these anchors have ever been. structurally

'

qualified at any time. In addition, the statement is made in the discre-pancy calculations that BFN-RAH-307, section 5.0, allows a nozzle overstress of 20 percent. The handbook actually states that component analysis section (CAS) can normally justify an increase of 20 percent above the standard allowables.

It in no way implies a " blanket" approval of a 20 percent nozzle overstress.

It states that approval of increased nozzle load allowables must be obtained (from CAS) on a case-by-case basis. Also, the discrepancy calculation references a phase 1 analysis N1-274-9R and includes checked copies of nozzle qualification sheets from this calculation for information. The analysis N-1-274-9R is to date not approved or issued; therefore, it is (1) incorrect to reference that calculation and loads in the discrepancy calculations because no calculation revision level is available yet to be referenced, and (2) to use this unapproved information warrants an unverified assumption which is not marked on the discrepancy calculation.

Finally, the analysis calculation N1-274-9R nozzle qualifi-cation for RHR pump 2C has been prepared and verified, and dispositioned as acceptable. However, investigation of this qualification shows it to be erroneously calculated, and to date it is still in error.

11.

Environmental Qualification (10 CFR 50.49)

The Browns Ferry environmental qualification (EQ) program was scheduled for

,

completion in December 1987, with the first preliminary audit to be con-ducted by the NRC in August. The prerequisites for this audit were for TVA

_ _ - _ - _ _ _

- _ _ -.

. _.

___

_

_

._

-.

. _ _ _ _

i j

t

-

.

to have completed at least 30% of the environmental qualification data packages (EQDP), have a finalized 10 CFR 50.49 list of equipment, and have

,

engineering approved environmental profiles.

Current status is that many of the EQDPs are completed as Revision 0 with many open items.

The audit will take place when 30% of the EQDPs are approved as Revision 1 with all of the

" critical" open items closed out.

This date is currently unknown due to the impact on the EQ program of the new engineering contractual changeover to the "shell contract" concept recently announced by TVA. The 50.49 list is scheduled to be completed in mid July and TVA may still meet this date. The schedule for environmental profile drawings should not be impacted since this activity is being conducted by DNE - Knoxville. initial NRC audit is scheduled for September 1987.

The inspector selected PS-85-35A1, Static-0-Ring pressure switch, used as the input to the Reactor Protection System (RPS) trip signal on low scram air header pressure as an example to evaluate the EQ process. The EQ documentation was contained in EQDP BFN2EQ -IPS-001, Pressure Switches Static-0-Ring INC., Rev 0.

This document was exceptional overall, however, several items were identified and discussed with licensee representatives as follows:

a.

The weakest part of the EQDP was the discussion of demonstrated operability.

This Rev 0 document judged the operability satisfactorily demonstrated by EQ testing; however, there was no discussion of temperature induced setpoint drift documented during the test. AETC Test Report 18441-83N indicates that during the temperature transient of the accident test, the pressure switch setpoint went from the pre-test value of 2.95 psig up to 8.8 psig. This was acceptable in the AETC generic qualification report because the acceptance criteria was that the setpoint had to remain within the 0-12 psig adjustable range.

Although the EQDP described the operability testing and acceptance criteria to which the device was subjected during qualification test-ing, it failed to conclude whether these tests and criteria are acceptable in the BFNP specific application of the switches. A licensee representative indicated that the issue of evaluating generic accep-tance criteria to the plant specific application had been previously identified as a weakness and was being addressed in the Rev 1 versions of the EQDPs. The issue on setpoint drifting and accuracy is identi-fied as an open item in all EQDPs until engineering approved Setpoint and Scaling Documents (SSD) are available. These will not necessarily be available prior to Rev 1 publication and may remain an open item during the initial NRC audit.

b.

The qualified life for this device was established as 40 years based only upon the Arrhenius methodology of thermal aging.

This is contrary to the guidance contained in Browns Ferry Engineering Project (BFNP) - Instruction PI-87-13, Attachment F which states

" qualified life predictions based solely on Arrhenius models of thermal degradation and ignore the effects of other stresses which tend to decrease qualified life are technically unjustified".

Section 7.3 of the AETC Test Report No. 17344-82N-D emphasizes this concern further when it states that the predominant age

__

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _

_______________j

- _ _ _ _ _ _ - _ _

__

_-.

._

i

-

.

related failure mode is mechanical wear and electrical contact resistance, neither of which lend themselves to Arrhenius modeling.

Although the test specimen was tested for 33,000 cycles, the EQ checklist in the EQDP did not evaluate this against the expected cycles in the BFNP application and evaluate the potential for impacting the qualified life judgement.

t c.

The EQDP states that no known synergisms are applicable to this device. The licensee was asked to provide a list of the known synergisms (or other reference material) to which this device was evaluated against in order to confirm this statement.

The inspector discussed the methodology for development of the 10 CFR 50.49 list with licensee representatives.

This process is outlined in BFNP-PI-87-06, Environmental Qualification Procedure for 10 CFR 50.49 List Development. One additional cut will occur during the final review to eliminate the " essentially mild" equipment from the list. This category is defined in BFNP-PI-87-01, EQ Project Program Document as follows:

Essentially Mild (EM) - Equipment located in a harsh zone and required to function or not fail for mitigation of a specific DBA; however, for the same specific DBA, the accident environment in the area in which the device is located would at no time be significantly more severe than the environment for normal opera-tion, including anticipated operational occurrences and, thus, the accident environment is considered mild. EM classification is also applied to equipment whose mild environment is actually greater (but not significantly greater) than the normal / abnormal environ-ment (including anticipated operational occurences) and thus, requires documentation of the engineering basis for classifying the equipment as mild.

This concept is vague and not well understood by licensee per-sonnel. It appears to have questionable basis and no equipment has yet been found to fit in this category. The licensee agreed to review the necessity of this type of review.

12.

Employee Concern Project Status The licensee's Employee Concerns Program status was reviewed by the resident inspectors. This inspection included a meeting with members of the Employee Concerns Task Group, review of the Stone and Webster Engineering Corporation Systematic analysis, and the review of NSRS reports.

The subjects are addressed herein.

.

I.

Meeting Summary l

The residents attended a special meeting on June 10, 1987, with the

!

members of the Employee Concern Task Group (ECTG)

staff to discuss

{

ECTG program implementation and status.

Topics of discussion were:

i i

_ _ _ - _ - - - _ - _ - _ __ __

_ _ - -

_.

'

.

1'

l i.

(a) ECTG's responsibility in resolving employee concerns originating prior to February 1, 1986.

(b) ECTG's responsibility in closing out the Stone and Webster Systematic Assessment (SWEC) items and open Nuclear Safety Review Staff (NSRS) reports.

(c) Categorization of Employee Concerns, SWEC Concerns, and NSRS Concerns.

(d) Discussion of responsibility of the corporate senior review panel of industry experts used to overview the program implementation.

(e)

ECTG procedure implementation guidelines and evaluator training.

(f) Corrective Action documentation on the Corrective Action Tracking.

Document (CATD) emphasizing the corrective action plan definition, approval, concurrence, closure verification, and tracking methodology.

(g) ECTG organization framework The meeting proved beneficial in outlining the overall program commit-ments and schedules. Future program inspections will be scheduled to evaluate implementation and corrective action status for Unit 2 restart.

!

II. ' Stone and Webster Engineering Corporation (SWEC) Systematic analysis of identified Issues / Concerns at TVA The Stone & Webster Engineering Corporation (SWEC) Systematic Analysis of Identified Issues / Concerns at TVA was performed by a group of 22 senior-level Stone & Webster personnel from January 20 - January 31, 1986, at TVA. In a meeting with the NRC Commissioners on January 9, 1986, TVA Directors committed to a review and evaluation of previously identified issues / concerns as a means of assessing the current situa-tion as well as identifying certain root causes of problems. To meet this commitment a Systematic Analysis was to accumulate issues and concerns from sources external to TVA, encode these into a data base, analyze the resultant information, determine. root causes where possible and support the preparation of a report to NRC outlining the TVA Recovery Plan. The sorts of the resulting data base were utilized as a foundation for preparation of the revised Volume I of the TVA Nuclear-Performance Plan submitted to NRC in February 1986.

All issues /

concerns accumulated by SWEC were turned over to the Employee Concerns Task Group (ECTG) for evaluation.

Stone and Webster identified issues and concerns from TVA's incoming correspondence over a 16 month period ending January 1986.

ECTG determined that the sources of the issues and concerns for Browns Ferry Nuclear Plant (BFN) were as follows b

_- - -

__. _ - _ _ -

_

_,

._

_

__

_

l

.

t l

17-l i

l

'13 issues identified by the Nuclear Regulatory Commission (NRC)

including violations,' inspector follow-up items, unresolved items, unnumbered concerns, and items identified-in meetings.

48 issues included in NRC's 1984 and 1985 Systematic Assessment of

!

Licensee Performance (SALP) Reports.

30 issues identified by 'the Institute of Nuclear Power Operations (INPO).

4 issues identified by the Management Analysis Company (MAC)

)

4 issues ' identified in letters to US Senators by TVA employees or former employees.

The purpose of ECTG's verification activities for the SWEC issues was to determine the status-of ' corrective action for each of the SWEC issues, and to identify any areas where additional actions.were-required. All Browns Ferry site-specific issues identified by SWEC, numbering 299 issues, were verified by ECTG for-completion status.

. The verification activities were documented in 64 files called BFN SWEC Element Files.

Each file covered the documentation review activity, interviews with cognizant personnel, and issue analysis needed to establish background, corrective action, and completion status for each SWEC issue.

O a.,

Summary data of the BFN SWEC issues is as follows:

(a)

133 issues were statused by ECTG as closed. Each of these

issues was verified to assure that it had been satisfac-i torily addressed, and if an NRC issue, that it was closed by NRC, (b) 44 other issues were statused as having completed correc-tive actions.

These issues will be considered closed following closure by the NRC.

(c)

108 issues were statused as having satisfactory corrective action in progress

!

(d)

14 issues were statused as not having sufficient evidence of corrective action.

The 14 issues discussed in item II.(1)(d) above are speci-

'

fied below:

1)

TVA failed to provide adequate corrective actions in its response to the NRC concerning its deficient condition reporting procedure.

<

L-

-_

_ _ _.

__

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

_-

_ - _ -

-

.

2)

TVA failed to provide adequate corrective action to assure that defined deficisnt conditions were evaluated correctly.in accordance with applicable Technical Specifications requirements.

3)

By' original design a LOCA concurrent signal with loss of offsite power would have shutoff exhaust fans in Unit 1

& 2 shutdown board rooms.

The design erroneously

assumed the signal could be reset after 10 minutes following a LOCA.

This condition could result in overheating of vital equipment during design basis accident conditions.

"

4)

High Pressure Coolant Injection (HPCI) and Automatic Depressurization System (ADS) cable separation criteria 1~'

in FSAR section 8.9 were not met.

5)

TVA failed to take appropriate action on NRC IE Notice 73-32 regarding HPCI and ADS cable separation.

6)

By original design both the exhaust and the recircula-ting air conditioning units in some shutdown board rooms are powere( from the same electrical source.

7)

Reactor building heating system lines do not contain secondary containment isolation valves as required by FSAR Sectioni3.3.3.5.

8)

Inaccurate work plan developed by untrained maintenance /

modifications engineers.

Improper materials used in class A piping system.

9)

Drawings for several systems which connect to safety systems do not reflect in plant configuration.

10) No specific criteria or checklist for HPCI piping and support walkdowns.

11) Delays in approval of and inconsistencies in the Sur-veillance and Calibration Program.

Discrepancies in the

.

Technical Specifications including the cross reference.

.

")q 12) Design modifications implemented via ECN to Reactor Protection System and reactor vessel head spray isola-tion valves prior to' approval by NRC.

-

_=

--

--__

_

_ - -

_

__

-

_._--_ _ _ -

-

.:

l l

13) A local suction pressure gauge at Residual Heat Removal pump

"D" was found reading a higher pressure than i

expected.

I 1A) Significant weakness dealing with improper emergency classification.

Need improvement in offsite agency notification, public emergency news information,-and in command and control of response teams.

Each of these 14 issues' has been discussed with BFN plant management, and the preliminary BFN plans for corrective action for the fourteen areas are detailed in the ECTG element file for-the issues.

Corrective Action Tracking Documents (CATDs) for the 14 issues have been prepared. These items will be evaluated and inspected by the NRC in a future inspection.

Stone & Webster analysis assigned the 299 BFN SWEC items to particular categories by type of activity.

Following ECTG's completion of verification activities for.the SWEC issues, three ECTG reviewers independently assigned each SWEC issue to one of the categories as defined by SWEC. These ECTG assignments, when

. compared with the SWEC assignment, were found to coincide reasonably close - in all but three categories:

Management, Inspections /QA, and Other.

CATEGORY SWEC %

BFN ECTG %

Operations 33.0 32.5 Management 11.2 23.4 Radiation Control 6.3 2.9 Testing 6.5 3.9 Design Engineering 8.6 8.9 Inspection /QA 4.2 7,9 Maintenance 15.4 14.1 Modification 3.2 2.6 Other 12.6 3.6 The most significant difference is that the ECTG team felt management should assume a greater responsibility for the satis-factory completion of outstanding concerns. Note, however, the BFN ECTG considered the term " management" to include line i

management.

'

Stone and Webster and BFN ECTG analyzed all SWEC issues and iden-tified the causes as_follows:

CAUSES SWEC %

BFN ECTG %

Procedure compliance inadequacy

16.6

Procedure inadequacy

18.9 Supervisor inadequacy

15.?

,

L N

.

.-

.

_

-

_

_

!

%

\\

f4 14'-

9

/

-

'\\*

y

't pL

,.

h.e

,

i>

+

A t

%

}l p

A I <\\

G~ 20

..

W

!*

/

, y.

. y,

-

>

9y

/

#

• +1 g#

q' BFN Ed G %\\

O.,,

Cd35i:S

[

SWEC %

'

,/. -

v

.

, T

.

j/

I r

'

%ckofcorrec@veaction

J 7.8 '

,'

'

-

f (including t'.ime11 ness)

Ai

.

f J h4gulatory commitment

9..

q/.

2.6

'

,

j y, '-

non compliance.-

,

,

/

i Tec8v;ical requirement documert

8.8

fud 1}

j g s -

i

Traini,equateng inadeo p, cy

11.4

_

,

y Testing or ins 46ction ina6bquacy

11.7

't 1 Other (

a 12.6 3.6

/,

l r'

'

,,

'

The ECTG person e$to evaluated th0FN SWEC issues generallyf'[

concurred with Mhe Above Stone & Webster listing with the. 3

..,,

exceptionfof,tnrae areas which arp reguYitory commitment ncr7 1

. compliance,' training inadequacy,/ and testing or inspectici V

,

gg

inadeqtacy.

,,.

t

<

<

<

v

-,

,

ECTG verified thaq the ccpr'ective actiny for 58% of thv2% BFN /

'

,c

,

issues identified by Stvae & Webster had been completed at the J

.

,

time of the SWEC anal.ysis',N and 24% of these had been closed by the NRC. Th;is correctiviCactioh stat h was not part of the Stone &

Webster report., Atithe time'of the ECTG verification activity, eight months after4t%'SWEC analysis, satisfacfgry corrective action wasufpund~to be'in progress",tior 111 of the remaining 125

~

issues. In sydmary, ECTG verified that corrective actions had been completed or were in progress for 285 of the 299 SWEC issues 'at

~

, P,FN.

Followup review of corrective actions will be reviewed,

<

j.1uringfutureinspectionsi y

t

.

e

,.}

e, a

III. Nuc ear Safety Review Staff (NSRS) Reports n

r

.,

'

j

.

,

After the accident at Three Mile Island, the TVA Board of Dipectors

'

-

established an inderoadent' group reporting to the Board charged with

'p,

the responsibility for reviewing and investigating issues which might affect ^.he safety of TVA's nuclear plants.,This group was called the a

'

'

.

Nuclea/, Safety Reyjew Staff.

It was given a rather broad charter,

,

V including the responsibility to recommend cW ective action in areas of

'

their investigation.

• /}q \\.

>

g

,

,7

,

.

,

As ae result of the major restructuring of TVA's nuclear program in.

. December 1985, the Board of Directors decided to riassign the NSRS's

! reporting authority from itself to the nW1y created Manager of Nuclear

'

,

-

This change took place in January 1986.

.

Power.

s In order to determine the most effective.use pf the NSRS in its new

'

,.

position with!re the line organization, the Manager cf Nuclear Dower contracted for the conduct of an independent review"of NSRS's past y

activities, itOpresent capabilities, and possible (future roles.

Evaluation of the investigation findings yielded the following addi-

-

t.tional progrcm changes:

s n

,

[(1) IThenameofthesroupwaschangedtotheNuclear. Manger'sReview

'

. Tiroup (NMRG).

'.

'

>

t q

y

!

'}

,f L

II.

b

_ _ _ [ :_ _.

_

__,_________n__.____________ _ _ _ _ - _ - -

-

.

)

j (2) The NMRG Director will report directly to the Manager of Nuclear

,

Power.

I

'l (3) The-primary function of the NMRG is to provide the Manager with an j

independent review, appraisal, or assessment or areas, functions, j

operations, or events related to TVA's nuclear program as directed by tne.. Manager. While there are no restrictions' as to what the i

Manager may assign to the NMRG, the intent is that it will review matters related to the design, construction, operation, or main-tenance of TVA's nuclear plants.i (4) The members of the NMRG are to be TVA employees who have experi-ence in nuclear design, construction, operation, or maintenance.

In most cases members shall be degreed engineers. All members of the NMRG shall be appointed by the Manager.

(5) The functioning of the NMRG does not in any way relieve any line manager assigned responsibilities.

In order to retain its independence, members of the NMRG will not be tasked to perform any line function.

'

(6) The findings of the NMRG will be provided only to the Manager and he will decide what action, if any, is required. The NMRG, being an advisory group, does not have direct line authority.

In order to evaluate items addressed by NSRS during its history a licensee review was conducted to assure Unit 2 startup concerns were properly dispositioned.

A review of all Nuclear Safety Review Staff (NSRS) open items was undertaken by Browns Ferry Nuclear Plant (BFN) staff and the Employee Concerns Task Group (ECTG).

Twenty-four items were identified as requiring closure verification by the ECTG before Unit 2 startup. An additional 85 items were considered to be applicable to BFN but did not appear to require closure before startup.

The twenty-four items identi#ied as. requiring verification by the ECTG before Unit 2 startup are parts of ten NSRS reports. Copies of those ten NSRS reports and other background documentation is maintained on site by the Plant Operations Peview Staff (PORS). The twenty-four items and some of the additional 85 items considered applicable to BFN, but not requiring closure before startup, were placed on the site tracking system.

,

PORS considers many of the NSRS items complete pending verification and accumulation of documented evidence that work is complete or justifi-cation that negates the necessity of action regarding the item.

Final authority for identification of startup issues rests with the BFN Restart Review Board.

a k

- - - - - - - - -

-

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

______)

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

- - - _ _

-

_

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

_

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

.

i The NRC will review the implementation and adequacy of the NSRS close-out actions in future inspections.

13.

Special Nuclear Material On June 18, 1987, the licensee reported an irregularity involving a shipment of Special Nuclear _ Material (SNM) to ac. tier-licensed facility.

The licensee made ar. informational report to the NRC Headquarters.0perations Center on the same day since a previous occurrence in this area had resulted in special attention by the NRC in late 1986. The licensee shipped what was thought to be five Intermediate Range Monitors (IRM), each containing 1 milligram of Uranium-235 to Peach Bottom Nuclear Station on June 16, 1987.

Peach Bottom personnel informed Browns Ferry via telephone on June 18, 1987, that a sixth IRM was received in the shipment.

The resident inspector performed a brief inspection of the activities surrounding this event; however, this will be an unresolved item (259,260,296/87-26-04) until a detailed followup is performed.

Upon notification from Peach Bottom of the need for five IRMs, the licensee personnel located a group of IRMs still in their original shipping crate.

Although the original shipment contained 12 IRMs, the most recent inventory indicated that 5 IRMs remained in the crate. On the evening of the ship-ment, an inventory was performed by a cooperative education student which identified the following IRMs to be in the crate TANCE 1 - 001 TANCE 1 - 002 TANCE 1 - 004 TANCE 1 - 005

.TANCE 2 - 001 A discrepancy was detected in that the previous inventory performed on January 30, 1987, had not identified serial number TANCE 1 - 005 as being present but had instead identified serial number TANCE 1 - 003. Another previous inventory on October 28, 1986 had also not identified the - 005 serial number but did list the - 003 as being present.

Licensee personnel suspected a transcription error or error in reading the serial number labels had occurred on the previous inventories and that the recent pre-shipping inventory was correct. The co-op student returned to the crate and verified that the IRM label was indeed a - 005 and not a - 003.

The crate was released for shipment. Peach Bottom personnel performing their receipt inspection learned that the crate contained both the - 005 and the - 003 serial numbe'ed IRMs along with the other four.

The inspectors questioned whether the inventory discrepancy detected on the evening of the shipment should have resulted in a Condition Adverse to Quality Report (CAQR) that might have stopped the shipment and correctly identified the extra IRM in the crate.

Nuclear Quality Assurance Manual

Part.I Section 2.16, Corrective Action, does not specif'cally idenfity SNM inventories as being within the scope of the CAQR program. Licensee per-sonnel were additionally not certain whether or not a serial number dis-crepancy should be considered an inventory discrepancy since all inventories L

j

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

__

_ _

23 actually agreed on the physical count of 5 IRMs. TI-14 does provide clear guidance on this subject in its definition of physical inventory.

A physical inventory is a list compiled by physically ascertaining the presence of an individual SNM by serial number (if possible). Thus, a serial number discrepancy is an inventory discrepancy. TI-14 currently states that anytime SNM is not found to be located where the most recent

inventory records say it should be located is considered a safeguard event I

with one hour reporting and notification requirement. This requirement for designation of the safeguard event and deportability was not adhered to on June 16, 1987, when the inventory discrepancy was first noted.

L

__

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