Text

Resident Insp Repts 50-327/93-09 & 50-328/93-09 on 930228- 0403.Violations Noted.Major Areas Inspected:Operations, Maint,Surveillance,Evaluation of Licensee self-assessment Capability,Ler Closeout & Followup on Previous Findings
	ML20035H226
Person / Time
Site:	Sequoyah
Issue date:	04/20/1993
From:	Holland W, Kellogg P; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20035H222	List: ML20035H221; ML20035H224; ML20035H226;
References
	50-327-93-09, 50-327-93-9, 50-328-93-09, 50-328-93-9, NUDOCS 9305030362
	Download: ML20035H226 (26)
	v • d • e

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UNITED ST ATES

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NUCLEAR REGULATORY COMMISslON

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ATLANTA, GEORGt A 30373

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Report Nos.: 50-327/93-09 and 50-328/93-09

Licensee: Tennessee Valley Authority

6N 38A Lookout Place

1101 Market Street

Chattanooga, TN 37402-2801

Docket Nos.: 50-327 and 50-328

License Nos.: DPR-77 and DPR-79

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Facility Name:

Sequoyah Units 1 and 2

Inspection Conducted:

February 28 through April 3, 1993

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Lead Inspector: M 8. goJI

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W. E. Holland, Senior Resident Inspector Date Signed

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Inspectors:

S. M. S

ffer,

esident Inspector

Approved by:

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Date Signed

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ChieK Section 4A

Division

Aeactor Prof'. cts

SUMhi... '

Scope:

This routine resident inspection was conducted on site in the areas of plant

operations, plant maintenance, plant surveillance, evaluation of licensee

self-assessment capability, licensee event report closecut, followup-on

previous inspection findings, and review of the fire protection prevention

program. During the performance of this inspection, the resident inspectors

conducted several reviews of the licensee's backshift or weekend operations.

Results:

In the area of Plant Operations, good operator performance was noted with

regard to response to the Unit 2 transient on March 1, 1993. Also, licensee

actions to provide for additional operational staffing based on projected

weather conditions for the period on March 12 through 14 was proactive and

proved to be a proper decision (paragraph 3.a).

In the area of Plant Dperations, an example was identified where a lack of

control room annunciation and/or information for control air system parameters

9305030362 930422

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limited operator knowledge with regard to auxiliary air compressor operation

(paragraph 3.b (1)).

In the area of Plant Operations, a weakness was identified with regard to

control of safety-related fuses in a 125 volt battery board room (paragraph

3.b (2)).

In the area of Plant Operations a violation of Technical Specification 6.8.1

was identified for failure to provide for or maintain adequate configuration

control of safety-related valves and power supplies (paragraph 3.c).

Interviews with several operators indicated that operators appeared to be well

trained and qualified; however, most of the training time was devoted to

required licensing material leaving little time for other material associated

with day-to-day activities.

In addition, concepts such as attention to

detail, being responsible for all actions, thinking before acting, looking for

potential problem areas and getting them addressed, need to be stressed

frequently. Communications also was an area that needed additional attention;

however, the new Operations Control Center was considered to be a positive

action in relieving control room congestion (paragraph 3.d).

In the area of Surveillance, a Non-cited violation of 4.6.5.1.b was identified

with regard to a missed surveillance on the Unit 2 ice condenser (paragraph

5.b).

In the area of Maintenance / Surveillance a violation of TS 6.8.1 was identified

for failure to provide adequate instructions for performance of safety-related

instrument calibrations within required intervals (paragraph 8.c).

In the area of Operations, a review of the fire protection

and its implementation indicated that the program was accep/ prevention program

table.

The

inspectors considered that previous programmatic problems in this area are

being adequately addressed and corrected. The licensee's progress within the

fire protection improvement plan appeared to be generally on schedule.

Fire

Operations management monitoring of fire protection issues was noted to be

good.

In addition, innovations to improve fire operations performance were

being successfully tested and implemented (paragraph 9).

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REPORT DETAILS

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Persons Contacted

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Licensee Employees

R. Fenech, Site Vice President

R. Beecken, Plant Manager

L. Bryant, Maintenance Manager

J. Baumstark, Operations Manager

G. Boles, Corporate Maintenance

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M. Cooper, Site Licensing Manager

T. Flippo, Site Quality Assurance Manager

J. Gates, Outage Manager

C. Kent, Chemistry and Radiological Control Manager

R. Rausch, Modifications Manager

D. Lundy, Technical Support Manager

J. Smith, Regulatory Licensing Manager

R. Thompson, Compliance Licensing Manager

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P. Trudel, Nuclear Engineering Manager

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J. Ward, Engineering and Modifications Manager

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N. Welch, Operations Superintendent

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NRC Employees

P. Kellogg, Chief, DRP Section 4A

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S. Sparks, Project Engineer, DRP Section 4A

Attended exit interview.

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Other licensee employees contacted included control room operators,

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shift technical advisors, shift supervisors and other plant personnel.

Acronyms and initialisms used in this report are listed in the last

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paragraph.

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On March 1, 1993 the Sequoyah Project Manager, Mr. Dave LaBarge arrived

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on site for one week of inspection activities including operator

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interviews.

This inspection activity is addressed in paragraph 3.d of

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this report. Mr. LaBarge became a member of the AIT which was

dispatched to Sequoyah on March 3, 1993.

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On March 3, 1993 a five man AIT lead by Mr. Jerry Blake, RII Section

Chief for Materials and Processes Section, was dispatched to Sequoyah to

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review the Unit 2 reactor trip and secondary pipe failure event of March

1'(see paragraph 3.f (1)).

The team remained on site until March II,

1993 when an inspection exit meeting and press conference was held with

the licensee and local media respectively.

Inspection report 327,

328/93-10 addressed the inspection findings.

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On March 5, 1993 the NRC Region II Administrator, Stewart Ebneter,

visited the Sequoyah Nuclear Plant

Mr. Ebneter met with the resident

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inspectors and licensee management, and toured the plant with the

residents.

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On March 11, 1993 the NRC Region II Administrator, Stewart Ebneter, and

the NRC Region 11 Section Chief for Sequoyah, Paul Kellogg, attended the

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AIT exit meeting and press conference discussed above. Mr. Kellogg also

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remained on site March 12, 1993 to review inspection activities with the

residents and to meet with plant senior management.

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On March 17, 1993 the NRC Chairman, Dr. Ivan Selin, visited the Sequoyah

Nuclear Plant. Dr. Selin met with the inspectors and licensee

management, toured the facility, and conducted a press conference at the

licensee's training facility. Accompanying the Chairman during these

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activities were the NRC Region II Administrator, Stewart Ebneter, the

NRC Region II Section Chief for Sequoyah, Paul Kellogg, and Janet

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Kennedy, Technical Assistant to the Chairman.

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plant Status

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Unit I began the inspection period at full power.

The unit operated at

full power until March 2, 1993 when the unit was shut down to MODE 3 due

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to secondary pipe integrity concerns based on the Unit 2 pipe rupture

event. The unit entered MODE 5 on March 15 and remained in MODE 5 for

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the remainder of the inspection period.

Unit I commenced its Cycle 6

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refueling outage on March 29, 1993.

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Unit 2 began the inspection period at full power. On March 1, 1993 the

unit was manually tripped when increased voltage was noticed on the 6.9

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KV shutdown boards and the main generator.

This event is further

discussed in paragraph 3.f (1). The unit was taken to MODE 5 commencing

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on March 5 and remained in cold shutdown through the remainder of the

inspection period while inspections and repairs were being made to

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secondary system piping.

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3.

Operational Safety Verification (71707)

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a.

Daily Inspections

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The inspectors conducted daily inspections in the following areas:

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control room staffing, access, and operator behavior; operator

adherence to approved procedures, TS, and LCOs; examination of

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panels containing instrumentation and other reactor protection

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system elements to determine that required channels are operable;

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and review of control room operator logs, operating orders, plant

deviation reports, tagout logs, temporary modification logs, and

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tags on components to verify compliance with approved procedures.

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The inspectors also routinely accompanied plant management on

plant tours and observed the effectiveness of management's

influence on activities being performed by plant personnel.

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(1)

On March 1, Unit 2 was manually tripped from approximately

full power (see paragraph 3.f (1)). During the event, the

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residents responded to the control room and monitored

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licensee recovery actions. Overall plant response to the

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transient appeared to be good. Operator response to the

event was good with proper control being exercised. The

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inspectors observed what was later determined to be a piping

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failure of the 10 inch extraction steam line going to the #

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2B feedwater heater.

The inspectors observed the failure

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area approximately 10 minutes after the trip and noted that

the break was approximately I foot downstream of a tee

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connection with a 20 inch extraction steam header line for

the # 2 feedwater heaters.

Flow of steam from the break was

slowly dissipating and equipment in the near vicinity of the

break appeared wetted.

The inspectors also noted that 6.9

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KV Unit Board cabinets in the turbine building had been

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wetted by the steam; however, no electrical problems

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appeared to be exhibited after the unit boards transferred

to the common station service transformers as designed after

the unit trip.

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(2)

During the period of the evening of March 12 through

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March 14, 1993 Sequoyah Nuclear Plant experienced

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significant snowfall (approximately 24 inches during the

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first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the period) resulting in difficulty in

reaching the plant. The licensee, in anticipation of the

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weather conditions, staffed the plant with two operations

shifts and arranged for sleeping and eating accommodations

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onsite during this period.

The inspectors toured the plant

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on March 14 and determined that all required positions were

staffed with additional operations personnel available on

site.

Le inspectors consider that the licensee actions to

providt cor additional staffing based on projected weather

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conditions for the period was very good and proved to be a

proper decision.

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b.

Weekly Inspections

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The inspectors conducted weekly inspections in the following

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operability verification of selected ESF systems by valve

areas:

alignment, breaker positions, condition of equipment or component,

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and operability of instrumentation and support items essential to

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system actuation or performance.

Plant tours were conducted which

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included observation of general plant / equipment conditions, fire

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protection and preventative measures, control of activities in

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progress, radiation protection controls, missile hazards, and

plant housekeeping conditions / cleanliness.

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(1)

On March 10, during a routine tour of the refueling deck

areas, the inspectors noted that the B train air compressor

for the auxiliary control air system (also known as

essential air) was continuously running, while the normal

configuration is in standby. The air pressure on the system

appeared not to be degraded and the air dryers were cycling

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as required; however, the inspectors noted a constant

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blowdown through an air system drainline which appeared

abnormal. The inspectors informed the control room of the

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observation. Operators were not aware that the system was

in operation and no alarms had been received to alert them

to a ongoing or intermittent loss of control air situation

which could cause a start of the system.

Investigations

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could not determine what started the compressor; however, it

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was postulated that an intermittent air load may have been

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placed on the system enough to decrease control air pressure

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and cause a start of the B train essential air system.

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Operators stopped the unit and placed the controller back in

the automatic position.

The compressor did not restart and

all of the skid mounted essential air system appeared to be

operating correctly. The A train portion of the essential

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air system was not running and appeared to be unaffected.

The licensee logged the inadvertent start of the compressor

for future information.

In addition, discussions were held

at operations shift turnover meetings to remind personnel

not to use the control air system to supply service air

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requirements. The system engineer stated that approximately

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Once per year, he is notified of an inadvertent start of one

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of the auxiliary compressors.

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The inspector noted that earlier on March 10, t'se B

auxiliary compressor was out of service for replacement of

the air prefilter. During these activities, the compressor

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was run as part of the PMT.

Indications showed that the

compressor was properly returned to operable status before

the inspectors identified that it was running.

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On March 25, the system engineer requested that operations

run the B auxiliary compressor in order to assure that

abnormalities were not exhibited during operation. No

problems were identified. The inspector and the system

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engineer walked down the compressor skid after the run and

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did not identify any operability concerns.

The system

engineer agreed to review the symptoms observed by the

inspectors during the next scheduled performance of 0-PI-

SFT-032-Oll.B, AUXILIARY CONTROL AIR OPERABILITY TEST,

Revision 2, which is required to be performed once per

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quarter.

The inspectors concluded that the quarterly test

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would provide additional assurance that the B train

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auxiliary control air system was functioning according to

design.

The inspectors considered that the system engineers

involvement in addressing the inspectors concerns was

adequate. The inspectors concluded that a lack of control

room annunciation and/or information for control air system

parameters limited operator knowledge with regard to

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auxiliary air compressor system operation.

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In addition to the above, the inspectors noted that pressure

indicator 0-PI-32-105 was labeled CONTROL AIR HEADER B,

TRAIN A PRESSURE. The correct identification should

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indicate TRAIN B.

The licensee submitted a tagging request

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to correct the error.

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(2)

On March 23, on a routine plant tour which included the 125

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volt battery board room (#1), the inspectors identified

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approximately one dozen fuses in a metal, wall mounted box

labeled " Fuses". The fuses were Flas 5 150 volt DC or 250

volt AC indicator fuses from various lot numbers. No other

fuses were found in the other battery board rooms. The

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inspector informed the CR of his finding and the fuses were

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immediately removed.

It appeared to the inspector that the

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fuses were not in a controlled fuse storage location. The

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licensee agreed that the fuses were not properly controlled

and took corrective actions which included considering

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removal of the metal boxes in each of the 125 volt battery

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board rooms. The inspectors considered the discovery of the

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fuses to be an isolated event; however, the improper control

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of the fuses was considered to be a weakness.

c.

Biweekly Inspections

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The inspectors conducted biweekly inspections in the following

areas: verification review and walkdown of safet

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in effect; review of the sampling program (e.g., y-related tagouts

primary and

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secondary coolant samples, boric acid tank samples, plant liquid

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and gaseous samples); observation of control room shift turnover;

review of implementation and use of the plant corrective action

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program; verification of selected portions of containment

isolation lineups; and verification that notices to workers are

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posted as required by 10 CFR 19.

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On March 19, 1993 the inspectors were informed by the Operations

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Superintendent that 5 containment isolation valves on Unit 2 were

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found to be improperly configured during performance of valve

lineups in accordance with surveillance instruction 2-SI-0PS-088-

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014.0, VERIFICATION OF CONTAINMENT INTEGRITY, Revision 3.

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valves were:

VALVE

EQUIPMENT ID

REQUIRED

AS FOUND

POSITION

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2-70-764

Drain on CCS from

LOCKED

UNLOCKED

Excess Letdown HX

CLOSED &

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CAPPED

2-70-765

Drain on CCS to

LOCKED

UNLOCKED

Excess Letdown HX

CLOSED &

CAPPED

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2-70-760

Drain on CCS to

LOCKED

UNLOCKED

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Excess Letdown HX

CLOSED &

OPEN &

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CAPPED

2-70-762

Drain on CCS to

LOCKED

UNLOCKED

Excess Letdown HX

CLOSED &

OPEN &

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CAPPED

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2-67-772

2D Lower Contmt

LOCKED

UNLOCKED

Vent Cooler Supply

CLOSED &

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test conn

CAPPED

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After identification of the deficiencies, the licensee initiated

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an incident investigation to review the findings and determine

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causes for the deficiencies.

In parallel with the investigation,

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licensee management commenced additional verifications of valve

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alignments for both units. At the time of discovery, both units

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were in MDDE 5 with the RHR systems aligned to remove decay heat.

No abnormal problems were identified with alignment of RHR or

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supporting systems.

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Operations management met with the inspectors on March 22, 1993

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and discussed actions to be taken prior to either unit changing

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MODE. The actions included complete valve lineups for required

systems on Unit I for MODE 5 and 6 operation first. After

completion of Unit I alignment verifications, Unit 2 system valve

lineups were to be re-performed as required by system and

equipment status control procedures. Unit ? lineups are expected

to be completed by the middle of April 1993.

On March 23, 1993 the inspectors were informed that an additional

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valve on Unit 1, 1-74-549, RHR Supply Line Drain between 1-FCV-74-

1 and 1-FCV-74-2, was found to be positioned approximately two

turns open when the required position was CLOSED & CAPPED. _ Later

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that day the inspectors were informed that an additional Unit I

val ve , 1-43-497, Post Accident Sampling Test, was found UNLOCKED &

CLOSED when the required position was LOCKED & CLOSED.

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The inspectors obtained copies of the valve lineup check sheets

which were performed after the Unit 2 Cycle 5 refueling outage in

May 1992 and determined that the documentation indicated that the

subject valves had been properly aligned and verified as being in

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the required positions. The inspectors then focused on other

procedures which may have been used to perform' valve operations

since that time.

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On March 24, 1993 the inspectors met.with personnel involved in

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the incident investigation review for this issue and discussed

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conclusions to date. The inspectors discussed the administrative

requirements which governed configuration control of valves and

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breakers.. The procedure was Site Standard Practice SSP-12.2,

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SYSTEM AND EQUIPMENT CONTROL, Revision 1.

The inspectors noted

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that the procedure had been revised since valve lineups were

conducted after completion of the Unit 2 Cycle 5 outage.

SSP-12.2

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specifically required that all safety-related systems and

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equipment required to be operable shall be included in the

configuration control scope with the associated checklists listed

in Attachments 1 - 6 as applicable. 2-SI-0PS-088-014.0 was one of

the procedures listed in Attachment 2 of the SSP for control of

containment isolation valves during Unit 2 operation. Members of

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the review team noted that after positioning of valves in

accordance with the SI, additional valve operations were allowed

in accordance with other procedures. These other procedures were

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System Operating Instructions (S01), S0s(newer operating

instructions), and other approved procedures to conduct

maintenance and/or testing on systems or components. The II team

members had determined that several operation procedures were in

conflict with sis that were used to establish configuration

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control of valves.

Specifically, valve checklists for S0s could

reconfigure valves after operation in accordance with procedural

steps.

For example, 50 checklists differ from the SI checklists

in that the five containment isolation valves listed above were

required to be LOCKED CLOSED & CAPPED by 2-SI-0PS-088-014-0;

however, the 4 system 70 valves were only required to be CLOSED

AND CAPPED by 2-50-62-6, Att. 2, EXCESS LETDOWN VALVE CHECKLIST 2-

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62-6.02, Rev. O, and the system 67 valve was only required to be

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CLOSED by 0-S0-30-5, VALVE CHECKLIST 2-30-5.02 ATTACHMENT 4, Rev.

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All of the above checklists were required by SSP-12.2,

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Attachment 2 for Unit 2 configuration control in MODES 1 through

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An additional configuration control problem was identified by the

licensee on March 26, 1993, with regard to incorrect fuses being

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installed in the trip and close circuit for the Electric Board Air

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Handling Unit A-A while performing power availability checklist 0-

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S0-30-1.01.

No other valve or power configuration problems were

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identified prior to the end of the inspection period.

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The inspectors considered that some of the deficiencies identified

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could be attributed to the lack of adequate coordination of valve

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lineup' checklist procedures. However, the examples of valves

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found open or partially open could only be attributed to a lack of

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adequate performance of personnel in accomplishment of required

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tasks.

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The inspectors considered that the licensee's configuration

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control program as implemented for system and equipment status

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control in accordance with SSP-12.2 was inadequate.

In addition,

in those examples where containment isolation valves were

involved, TS 3.6.1.1 which required containment integrity to be

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maintained in MODES 1 through 4 may not have been complied with.

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However, some form of boundary has been maintained in all cases

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identified by the licensee, to date.

In addition this problem

appeared to date back to the middle of 1992. At that time,

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several configuration control problems were being identified and

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the licensee was taking actions to correct these deficiencies.

Technical Specification 6.8.1 requires, in part, that written

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procedures be established, implemented, and maintained. This

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includes procedures for control and operation of safety-related

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systems.

The inspectors determined that the requirements of SSP-

12.2 were inadequate with regard to specifying proper locking

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device control for several safety-related valves.

In addition,

valve checklists which identified that safety-related valves were

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verified as shut did not provide proper control in that the valves

were determined to be open or partially open.

Failure to provide

for or maintain adequate configuration control of safety-related

valves and power supplies is identified as a violation of TS 6.8.1

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(327, 328/93-09-01).

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d.

Other Inspection Activities

Inspection areas included the turbine building, diesel generator

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building, ERCW pumphouse, protected area yard, control room, Unit

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I containment, vital 6.9 KV shutdown board rooms, 480 V breaker

and battery rooms, and auxiliary building areas including all

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accessible safety-related pump and heat exchanger rooms.

RCS leak

rates were reviewed to ensure that detected or suspected leakage

from the system was recorded, investigated, and evaluated; and

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that appropriate actions were taken, if required.

The inspectors

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routinely independently calculated RCS leak rates using the NRC

RCS leak rate computer program specifically formatted for

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Sequoyah.

RlPs were reviewed, and specific work activities were

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monitored to assure they were being accomplished per the RWPs.

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Selected radiation protection instruments were periodically

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checked, and equipment operability and calibration frequencies

were verified.

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Early in the inspection period, the NRR Project Manager was at

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Sequoyah to review station activities. The Project Manager

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conducted interviews of eight operators regarding recent plant

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events and interfaces with other station organizations. The

information obtained during the interviews was discussed with the

Plant Manager, Operations Department Manager, and Operations

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Department Superintendent on March 8, 1993.

Although only a

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limited number of operators were interviewed, the following

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conclusions were drawn by the project manager.

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Most of the training time was devoted to required licensing

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material leaving little time for other material associated

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with day-to-day activities.

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Operators were not fully knowledgeable regarding the status

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of certain work requests.

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Implementation of an Operations Control Center (OCC) has

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been an improvement in relieving control room congestion and

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the quality of operational reviews.

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The licensee indicated that the above noted conclusions would be

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reviewed and acted upon as appropriate.

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Physical Security Program Inspections

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

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area access controls; searching of personnel and packages;

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escorting of visitors; bacge issuance and retrieval; and patrols

and compensatory posts.

In addition, the inspectors observed

protected area lighting, and protected and vital areas barrier

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integrity.

f.

Licensee NRC Notifications

(1)

On March 1, 1993 the licensee made a notification to the NRC

as required by 10 CFR 50.72 with regard to a manual reactor

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trip of Unit 1 from full power. The unit was tripped by

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operators when they noticed an increase in voltage on the

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generator and 6.9 KV shutdown boards. After the trip, the

unit boards transferred to preferred power (common station

service transformers) and the unit board and shutdown board

voltages returned to normal. The cause of the high voltages

was determined to be a steam leak in a 10 inch extraction

steam line approximately 1 foot downstream of a tee. The

line supplied extraction steam to feedwater heater B2. The

Unit 2 generator voltage regulator cubicles were discovered

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to be wetted due to the steam leak. The licensee determined

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that the generator voltage regulator failed due to excessive

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moisture from the steam leak. An investigation was also

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conducted to evaluate the overvoltage condition in order to

determine if any station service or safety-related

electrical loads were effected. No personnel were injured

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by the steam leak. Unit 2 was stabilized in MODE 3 with

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steam dumps removing decay heat to the condenser. The

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licensee established a post trip review team to review the

event.

The NRC, after initial review by the residents,

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dispatched an AIT to Sequoyah to review the event and

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licensee corrective actions. The AIT inspection activity

was addressed in inspection report 327, 328/93-10. The

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licensee submitted an LER for the event.

(2)

On March 2, 1993, the licensee made a notification to the

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NRC as required by 10 CFR 50.72 with regard to notification

of another agency. The licensee notified the Federal

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Aviation Administration at 6:51 p.m. with regard to an

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aircraft warning light on the south side of natural draft

cooling tower 1 being extinguished. The remaining lights on

i

both cooling towers were function.1.

(3)

On March 9,1993, the licensee made a notification to the

i

I

NRC as required by 10 CFR 50.72 with regard to notification

of another agency. The licensee notified the Federal

!

Aviation Administration at 4:48 p.m. that the Unit I and

I

Unit 2 Cooling towers each have one aircraft warning light

extinguished. The remaining lights on both cooling towers

!

were functional.

!

(4)

On March 13, 1993 the licensee made a call to the NRC as

required by 10 CFR 50.72 with regard to determination that

t

the 107 evacuation sirens for offsite notification may be

i

inoperable due to present weather conditions. Significant

snowfall had resulted in numerour power outages throughout

!

the area. The information was furnished by the TVA

!

emergency preparedness manager due to feedback signals not

'

being received from the towers. The State of Tennessee was

!

l

notified. At the time of the call, Unit I was in MODE 4 and

!

Unit 2 was in MODE 5.

Offsite power was being supplied to

the plant with emergency onsite power fully operable if

>

needed.

'

(5)

On March 20, 1993 the licensee made a call to the NRC as

required by 10 CFR 50.72 with regard to a four hour

notification due to an ESF actuation on Unit 1.

The event

involved a blown fuse in the control circuitry for 1-FCV-90-

111, a lower compartment radiation monitor containment vent

,

isolation valve, which caused the valve to go closed.

-

Immedicte corrective actions included entry into the

applicable TSs, replacement of the 125 volt DC fuse, and

reopening of the valve.

The fuse was inadvertently blown

during set-up foi response time testing of the valve when

electrical leads were shorted on a recorder. The cause of

the event appeared to be human error.

(6)

On March 21, 1993 the licensee made a call to the NRC as

required by 10 CFR 50.72 with regard to a four hour

r

'

notification due to an ESF actuation on Unit 2.

The event

involved a high spike on radiation monitor 2-RM-90-278, a

post accident radiation monitor, causing the isolation of 2-

!

FCV-77-10, RCDT pump discharge valve.

Immediate corrective

j

-

actions included monitoring the redundant channel, blocking

of the affected channel input to the affected valve,

reopening of the affected valve, and writing a WR to

troubleshoot the problem.

i

(7)

On March 24, 1993 the licensee made a call to the NRC as

i

I

required by 10 CFR 50.72 with regard to a four hour

notification due to an unplanned ESF actuation on Unit 1.

.

-

-.

-

--

.- -

.

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11

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,

The event occurred when a reactor building containment

ventilation isolation (CVI) valve was mistakenly de-

)

energized and was caused to close during a equipment tagout

i

process on another system. The particular valve isolates

!

the upper containment gaseous, particulate, and iodine

activity monitor from one of its two parallel sample points

!

in the upper containment. The improperly pulled fuse was

!

immediately replaced and the valve reopened.

No valid ESF

l

actuation signal was generated nor required as a result of

I

the event.

Within the areas inspected, one violation was identified.

f

!

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4.

Maintenance Inspections

(62703 & 42700)

'

i

'

During the reporting period, the inspectors reviewed maintenance

i

activities to assure compliance with the appropriate procedures and

requirements.

Inspection areas included the following:

,

'

3

a.

On March 30, 1993 during the Unit 1 outage shift turnover meeting,

i

the inspectors noted that containment penetrations were being

opened in order to install temporary services to support outage

j

activities. One of these penetrations, X-117, had been opened and

preparations were being made to temporarily seal the penetration

with foam (with temporary lines running through the penetration)

for the duration of the outage.

Over the next two days the inspectors reviewed activities

associated with installation of temporary services through

,

containment penetrations for outage activities. The inspectors

i

!

were focusing on TS requirements for containment integrity during

4

core alterations. TS LC0 3.9.4 requires, in part, that each

containment building penetration providing direct access from the

containment atmosphere to the outside atmosphere shall be either

closed by an isolation valve, blind flange, or manual valve, or be

capable of being closed by an OPERABLE automatic Containment

Ventilation isolation valve. TS LCO 3.9.4 is applicable whenever

CORE ALTERATIONS or movement of irradiated fuel within containment

is in progress.

The inspectors reviewed WO No. 92-12430-00 which was written to

support WR C049480. The WO provided the instructions to open,

foam, and close penetrations per 0-MI-MXX-088-001.0, OPENING

,

PENETRATIONS X-54, X-88, X-Il7, and MK-72 FOR MAINTENANCE

ACTIVITIES, Rev. 3, for installation and removal of steam

'

generator related temporary . services. The inspectors reviewed the

'

MI and noted that penetration X-117 had been foamed after

installation of temporary electrical cables. The inspectors

conducted an inspection of the penetration in the Unit I

containment and determined that most of the electrical : ables were

.

-

~

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12

installed in a group such that they could not determine if leakage

between the cables may occur. Also, the inspectors were informed

that the foam filled penetration was not required to be tested

i

prior to core alterations.

i

lhe inspectors were also provided with a copy of a safety

assessment / safety evaluation which was prepared when procedure 0-

MI-MXX-088-001.0 was revised in September, 1991. That safety

evaluation concluded that the method of installing temporary

,

services through foam filled containment penetrations did not

t

differ with or affect compliance with Technical Specifications.

The inspectors were reviewing this position when the inspection

i

period ended. This inspection activity will continue during the

next inspection period and will be resolved prior to fuel

movement.

b.

On April 1,1993, the inspectors reviewed activities related to WR

C174431. This WR was initiated on March 8 due to abnormal CR

i

board indications observed by operators for the Unit 2 CCS surge

tank autcmatic makeup level control valve 2-LCV-70-63. With the-

handswitch for this valve in the P-Auto position and adequate

i

level in the surge tank, the makeup valve was open. Operators

.

reconfigured the valve to the closed position via the system

status file until troubleshooting of the problem could be

,

accomplished.

The handswitch remained under this configuration

'

control, except during troubleshooting activities, for the

'

duration of the inspection period.

During review of maintenance activities, the inspectors determined

that bPween March 9 and 11, troubleshooting activities were

performed for this abnormal condition. The inspector reviewed the

WR package and noted that the amount of troubleshooting detail

documented in the work performed section was very good.

The

activities identified that a wiring discrepancy existed such that

the surge tank low level switch was jumpered out of the circuitry

that controlled the operation of 2-LCV-70-63. This resulted in a

demand signal for a low condition always being in and the level

,

was essentially being controlled only by the high level setpoint.

Once this was identified as a discrepancy, a drawing deviation was

initiated to resolve the issue. The wires were then left in the

wrong configuration per the licensee's corrective action program

until the issue could be reviewed by engineering.

In October of 1992, as documented in IR 327,328/92-31,the

'

inspectors identified through discussions with operators that

automatic makeup for both unit's CCS surge tanks was not always

maintained as required by the FSAR. The system was found

configured for automatic makeup capability at-the time of this

'

previous inspection.

The inspectors identified that part of this

problem was that the handswitches for the makeup valves were not

!

under configuration control.

Subsequently, the licensee addressed

'

,

y

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(

13

!

configuring the handswitches per the applicable system operating

t

instruction.

Based on reviews of the work package, control room status files,

'

and discussions with operators and instrument maintenance

personnel, the inspectors raised the following issues / concerns to

,

management on April 2, 1993.

'

,

1)

Due to the repositioning of the Unit 2 CR CCS surge tank

autcmatic makeup handswitch to the closed (non-automatic)

position, what evaluations or reviews were performed to

justify system operation outside of that specified in the

,

FSAR?

!

2)

Due to the wiring discrepancy still existing, are the

l

annunciators associated with the surge tank levels adversely

r

affected?

3)

When did the wiring error occur and was it an isolated

problem?

,

4)

Prior to the identification of the problem, were there any

adverse effects with regard to expected radiation doses post

accident due to the system not being isolated from its

1

makeup source (demineralized water)? flote: The FSAR

describes the CCS system as normally closed.

l

5)

The inspectors also identified several annunciator response

procedures that identified surge tank level instrumentation

to be monitored by the operator if required; however, the

1

annunciation responses contained information which

j

conflicted with labeling of the CR panels. The inspectors

i

noted that the errors were identified in recent revisions to

the annunciator response procedures.

The inspectors discussed the above concerns with the licensee.

During subsequent discussions near the end of the inspection

period, the licensee responded to several of the inspectors

-

concerns as follows:

-

The licensee indicated that the wiring discrepancy would not

,

affect the operability of the annunciation for the CCS

system.

-

The system engineer stated that he would address the

problems noted with the annunciator response procedures.

-

The licensee indicated that the makeup valve would close at

the high level setpoint; therefore, concern # 4 would not be

applicable.

-

- -

-

.

,

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14

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The inspectors did not identify any concerns with these responses.

The licensee stated that they would continue to review the other

concerns during investigation of the root cause of the wiring

i

problem / drawing discrepancy. This inspection activity will

+

continue during the next inspection period.

.

Within the areas inspected, no violations were identified.

!

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5.

Surveillance Inspections (61726 & 42700)

!

During the reporting period, the inspectors reviewed various

i

surveillance activities to assure compliance with the appropriate

!

procedures and requirements. The inspection included a review of the

!

following procedures and observation of surveillances:

'l

a.

During the inspection period, the inspectors reviewed activities

-

associated with testing of the Unit 1 main steam safety valve

testing performed on March 7, 1993. The testing was performed

with the unit in MODE 3 via test procedure SI-759, TESTING AND

i

SETTING 0F MAIN STEAM SAFETY VALVES, Revision 1.

The'results of

'

l

the testing indicated that 7 out of the 20 valves (10 per valve

l

vault) had failed their established test acceptance criteria.

,

Each of the valves were immediately adjusted to within their

respective acceptable relief range (1 percent + or - setpoint).

The inspectors noted that the failed valves had all drifted high

!

and were all only marginally exceeding the acceptance criteria.

{

The inspectors reviewed the as-performed procedure and the last

[

successful performance of M e same procedure. No problems were

identified and the procedure appeared to be adequate to control

the activity. The inspectors also reviewed with the system

i

engineer, previous failure rates of the main steam safety valves

and the specifics of the current failures. All of the valves

i

which failed to meet the acceptance criteria were located in the

west valve vault. Differences were examined between the two valve

<

vaults and their respective testing methods such as possible

temperature changes between the vaults, different personnel or

j

testing apparatus, etc. No definitive inconsistencies were

identified which would account for the failure. The inspectors

concluded that the licensee's evaluation of the failures and the

corrective actions taken were adequate. The inspectors noted that

a PER was initiated to document the failure of the valves.

b.

On March 24, the inspectors were informed that the licensee had

exceeded the time requirement for Unit 2 TS required ice condenser

boron concentration sampling. TS surveillance requirement , 4.6.5.1.b requires, in part, that the ice condenser shall be

1

determined operable at least once per 12 months by chemical

analysis which verifies that at least 9 representative samples of

stored ice have a boron concentration of at least 1800 ppm as

i

sodium tetraborate. Contrary to this, the required sampling was

l

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.

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15

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not performed for approximately 18 months. Upon identification,

I

the licensee initiated sampling of the ice condenser and began an

I

incident investigation to determine why the surveillance timeframe

<

was exceeded.

The required surveillance is accomplished in accordance with 0-TI-

l

CEM-043-016.5, SUPPORT SYSTEMS - SAMPLING METHODS, Revision O.

'l

'

This procedure requires that the ice condenser samples be taken

1

from the top of the ice condenser baskets and consist of ice from

the top of the basket and also ice from a depth of about one foot

.

from the top of the basket. A total of 27 samples (3 baskets from

!

~

each of 9 ice bays) are collected.

Each of the 3 samples per bay -

1

is then combined to give the 9 required samples for analysis.

Initial results of the ice condenser sodium tetraborate samples

indicated that two samples were below the TS limit of ~1800 ppm.'

.

The two low concentrations were 1752 and 1768 for ice bays 13 and

14, respectively. Due to the unit being in Mode 5, the licensee

did not have to take any immediate operational action based on the

i

sample results. The ice condenser is required to be operable in

MODES 1 through 4.

Re-sampling was'then performed from the two

affected bays, approximately one foot below the original sample

t

depth.

Subsequent results indicated a sodium tetraborate

!

,

concentration of 2074 and 2359 for bays 13 and 14, respectively.

l

The licensee, based on these results, concluded that the ice

condenser was operable, with regard to boron requirements, during

the last operational cycle.

1

The inspectors reviewed the results of the samples, the sampling

'l

methods, and the applicable TS and FSAR sections. .The inspectors

!

discussed with the licensee the method of sampling from the very

top of the ice condenser, and whether this sampling method was the

!

most ideal representative sample of the ice in the condenser. The

j

inspectors considered that a more representative sample may need

-i

to include the ice in other locations of the ice baskets. The

licensee indicated that this sampling method was based on

.

Westinghouse recommendations; however, they stated that a

clarification as to the reasoning behind this type of sampling

would oe requested from the vendor.

In addition, the inspectors

'

discussed possible reasons why the original samples for the two

affected bays were found below the limit. The licensee initiated

1'

PER number SQPER930091 to document the low sample results and to

determine root causes for the problem. The inspectors considered

that licensee's initial actions to investigate the above

considerations were appropriate.

i

!

In addition, the inspectors reviewed the original problem of the

'i

missed surveillance as required by TS 4.6.5.1.b.

The periodic

!

surveillance is performed and tracked via SI-58, ICE CONDENSER

1

CHEMISTRY, Revision 14. The licensee concluded that.the

l

surveillance was missed due to a rescheduling error during a

j

special performance of SI-58, which had been performed during the

.

'!

._

_

16

Unit 2 cycle 5 refueling outage in March, April, and May of 1992.

This special performance was identified as the TS required

performance (i.e., the scheduled periodic performance) when logged

into the surveillance tracking system. As a result, during the

,

administrative closecut of the special performance, the periodic

i

surveillance required performance timeframe was reset for another

12 months. The inspectors concluded that the scheduling problems

were attributed to personnel error, procedural weaknesses, and,

training deficiencies; however, the inspectors noted that there

were also no additional backup verifications to assure that the

,

surveillance was properly scheduled per TS requirements. The

!

licensee's proposed corrective actions appeared to address the

'

,

root causes of the missed surveillance.

Included in the

corrective actions, is a OA review of special performance sis over

the last year. The licensee intends to submit an LER for this

event.

The failure to perform the subject surveillance within a

1

'

periodicity as required by TS 4.6.5.1.b is identified as a

violation (328/93-09-02), Failure to Perform Ice Condenser Boron

Sampl i ng..

However; this violation will not be subject to

enforcement action because the licensee's effort in identifying

!

and correcting the violation meet the criteria specified in

i

Section VII.B of the Enforcement Policy.

.

'

Within the areas inspected, one non-cited violation was

identified.

6.

Evaluation of Licensee Self-Assessment Capability (40500)

i

'

i

During this inspection period, selected reviews were conducted of the

'

licensee's ongoing self-assessment programs in order to evaluate the

effectiveness of these programs.

!

On March 31, 1993 the inspectors attended the PERP meeting for II-S-93-

!

'

Oll, CONFIGURATION MANAGEMENT.

This issue is also discussed in

paragraph 3.c of this report. The inspectors noted that the

,

investigation team concluded that several root causes were associated

with the configuration control problems.

These causes included-

t

,

-

Plant procedures were not consistent in assuring that system valve

lineup configuration control was maintained.

-

Previous corrective actions for past problems were ineffective.

-

Work performed subsequent to initial verification left components

improperly configured.

,

-

Initial verification of components was performed incorrectly.

.

J

.

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i

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.

,

17

The inspectors noted that the PERP meeting addressed several corrective

actions to correct the valve lineup configuration control problems.

However, based on the fact that past corrective actions have been

ineffective to correct configuration control problems, the inspectors

i

consider that continuing management attention should be focused on

additional actions to improve performance in this area.

i

Within the areas inspected, no violations were identified,

7.

Licensee Event Report Review (92700)

.

The inspectors reviewed the LERs listed below to ascertain whether NRC

reporting requirements were being met and to evaluate initial adequacy

'

of the corrective actions. The inspector's review also included

followup on implementation of corrective action and/or review of

i

licensee documentation that all required corrective action (s) were

'

either complete or identified in the licensee's program for tracking of

outstanding actions.

(Closed) LER 327/92-24, Failure to Establish a Fire Watch as a Result of

Personnel Inattention to Detail. The issue involved a determination

i

that a continuous fire watch had not been established within the

'

required timeframe for an alarm received on the control room fire

detection panel on December 11, 1992. The event occurred due to a fire

operator failing to identify the alarm condition upon completion of

related panel testing activities. The local fire detection panel switch

that removes power from the panel's automatic actuation relays had

~3

failed causing the alarm condition. The root cause of the event was

inattention to detail on the part of the fire operator. The operator

acknowledged the alarm; however, failed to take the appropriate

compensatory actions.

Additionally, the inspectors noted that an operations shift turnover

occurred while the alarm condition was in; however, the problem was not

'

identified by the shift turnover process. The panel alarm condition was

later discovered by other operations personnel reviewing the fire

protection system alarms the next day. The inspectors considered the

'

failure of the fire operator to identify the condition an isolated

failure; however, the weaknesses exhibited by the shift turnover process

'

in not identifying the issue is an example of a continuing problem of

operator inattention to detail.

Within the areas inspected, no violations were identified.

8.

Action on Previous Inspection Findings

(92701, 92702)

a.

(Closed) URI 327, 328/91-26-02, Compliance with TS LC0 3.4.10.c

Action Statement. The issue involved licensee handling of relief

-

requests for temporary repairs to ERCW return lines from component

cooling water heat exchangers OB2 and 2A1.

Since identification

1

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.

,

18

l

r

of the issue, the licensee has discussed handling of relief

requests with the NRC Office of Nuclear Reactor Regulation. The

discussions resulted in clarification of requirements for required

i

submittal of relief requests.

,

'

Subsequent to the identification of the issue, the licensee

submitted a relief request in a letter from TVA to the NRC dated

December 2, 1991.

Proper code repairs were accomplished on the

!

affected components and these repairs were verified as completed

by the inspectors. The inspectors also noted that a code relief

request for another through-wall flaw was submitted to the NRC in

a letter from TVA to the NRC dated August 6, 1992.

Evaluation of

,

the licensee's current policy for submittal of relief requests

,

indicates that TS requirements are currently being met.

The

i

inspectors and the NRR Project manager met with licensee

management on March 9, 1993. During this meeting, NRC and

licensee personnel discussed additional clarifications of

j

requirements for moderate energy Class 3 piping. The inspectors

concluded that the licensee's program for compliance with TS

<

requirements was adequate.

b.

(Closed) URI 328/93-05-01, Review of licensee justification and

safety evaluation for operation with a steam dump out of service.

The issue involved licensee identification of piping deflection of

'

a Unit 2 steam dump line due to a water hammer event in January

,

1993. The issue was discussed in inspection report 327, 328/93-

05.

In that report it was noted that Unit 2 was operating at

power with the steam dump line valve, 2-FCV-1-lll, shut and

'

inoperable.

This condition had been documented in PER

!

SQPER931502. When the last inspection period ended, the

inspectors had requested that the licensee provide documentation

'

of the safety evaluation for operation with the steam dump out of

-

service.

,

On March 19, 1993 the inspectors were provided with a copy of the

engineering evaluation for PER SQPER931502. The evaluation, which

had been completed on March 18, 1993, concluded that the main

-

steam lines structural integrity was maintained. Attached to the

package was a safety evaluation for the steam dump line

'

configuration addressing the dump line being out of service. The

evaluation concluded that the configuration did not create an

i

,

unreviewed safety question and therefore was acceptable for

continued operation.

!

The inspectors reviewed the evaluation and concluded that it did

'

provide the documented review as required by 10 CFR 50.59.

However, the inspectors also concluded that the amount of time

taken to conduct the review (46 days) was excessive.

!

c.

(Closed) URI 327, 328/93-05-02, Review of licensee corrective

action for SQSCAR 920009 for deferral of safety-related

,

instrumentation calibrations. The issue involved identification

!

l

A

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19

in SQSCAR 920009 of several instruments wnich were not being

recalibrated within the periodicity required by precedures. This

issue was discussed in inspection report 327, 328/93-05.

In that

report, the inspectors determined that safety-related

instrumentation calibrations were being deferred in accordance

<

'

with requirements specified in administrative procedure SSP-8.2,

,

SURVEILLANCE TEST PROGRAM, Revision 0.

The SSP required that an

.

Appendix 0 be filled out and sent to work control whenever a

surveillance instruction would not be completed when scheduled.

The Appendix D form required that a reason be stated as to why the

SI would not be completed, and required concurrence on the

exception by Senior Plant Management.

During this period the inspectors continued with their reviews in

this area. The inspectors met with licensee personnel on March 12

t

and 30, 1993. During these meetings the inspectors reviewed

administrative procedure SSP-8.2 and SSP-6.8, INSTRUMENTATION

SETPOINT, SCALING, CALIBRATION PROGRAM, Revision 0 and determined

,

that procedural requirements were not in conflict. However,

additional review of several of the Appendix D forms for deferral

,

of sis in accordance with SSP-8.2 determined that minimal actions

!

had been accomplished to perform required calibrations.

Specific

,

Appendix D forms reviewed included:

,

APP. D Form

Extension

Reason

Action

Procedure No.

Date

SI-597, U-2

5-21-92

SI on Admin.

SI being replaced

hold.

by IDPs.

>

SI-597, U-0,1

5-21-92

SI on Admin.

SI being replaced

hold.

by IDPs.

i

SI-620, U-0,1

10-21-92

Revise SI and

SI not performed

perform. Sch.

by 3-30-93.

date 1-24-93.

SI-695, U-0

9-13-92

SI on Admin.

IDPs written. Not

hold.

performed by 3-30-

93

The inspectors determined that the above listed sis included over

50 safety-related instruments. They also. determined that although

administrative actians had been taken to identify the sis as

having missed their extension date, none of the instruments had

been calibrated as of March 30, 1993.

In addition, the licensee

!

ar.d the inspectors determined that the SCAR did not address any

type of corrective action with regard to SSP-8.2 requirements.

1

The stated purpose of SSP-8.2 was to specify general

responsibilities and standard programmatic controls for

implementation of the Surveillance Program to ensure that safety-

1

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.

9

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b

20

b

,

related structures, systems and components will continue to

!

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operate or operate on demand in accordance with design and

regulatory requirements. The SSP scope included Non-Technical

Specification related plant instrumentation calibrations and

required their performance at a periodicity specified in the SI.

The inspectors reviewed SSP-8.2 in detail and discussed use of

,

Appendix D forms for deferral of sis that were written to perform

b

calibrations with licensee personnel.

Based on these reviews and

,

discussions, the inspectors concluded that SSP-8.2 did not provide

adequate instructions to assure that calibrations were conducted

.

'

as required.

In addition, the use of Appendix D forms to defer SI

,

performance for reasons stated above appeared to be outside of the

scope of the use of this deferral process.

.

Technical Specification 6.8.1 requires, in part, that written

!

procedures be established, implemented, and maintained.

This

includes procedures for the testing of safety-related systems and

components. The inspectors determined that the requirements of

SSP-8.2 were inadequate with regard to assuring that calibrations

of safety-related instruments were performed when required.

Failure to provide adequate instructions for performance of

safet3-related instrument calibrations within required intervals

is identified as a violation of TS 6.8.1 (327, 328/93-09-03).

Within the areas inspected, one violation was identified.

l

9.

Review of Fire Protection / Prevention Program (64704)

During the inspect 1an period, the inspectors conducted a review of the

fire protection / prevention program at Sequoyah. Areas evaluated

included, but not linited to: ' fire protection procedures; compliance

with compensatory measures; control of transient materials; fire

protection program training; adequacy of fire brigade; fire protection

management and system engineer involvement; the fire watch program; and

'

maintenance of fire protection equipment.

Portions of the inspection

included interviews with fire protection personnel, review of fire

protection related procedures, review of completed fire protection

surveillances, and walkdowns of fire protective equipment and personnel

'

practices.

The inspector's review included the following observations:

-

Tours of the safety-related plant areas were conducted with regard

to transient fire loads, fire detection and protection devices,

ongoing hot work, and plant fire watches. No major concerns were

identified in the licensee's program other than minor transient

fire load discrepancies which the licensee immediately addressed.

-

The licensee had partially initiated an innovative bar code reader

system for the monitoring of compensatory fire watches throughout

i

the plant. This system, once fully implemented, will provide the

,

.

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21

i

licensee with a state of the art mechanism for providing TS

required monitoring of compensatory measures and will eliminate

j

many of the administrative burdens associated with the fire watch

program.

Fire protection management plans to review similar bar

I

code system uses in other areas, including fire protection

surveillances, which monitor fire protection and detection

devices.

-

The inspectors reviewed the use of batteries in a variety of fire

protection related equipment. A previous problem identified by

,

the licensee in 1991 involving the replacement of non-QA level III

i

batteries being replaced in some emergency lighting was noted.

The inspector considered the corrective actions for the problem

adequate to prevent recurrence. Walkdowns regarding 10 CFR

Appendix R lighting requirements did not identify any

discrepancies. A survey was also performed by the inspector of

the stocking of various types of batteries for use in the fire

protection system. The results indicated that the licensee had an

adequate supply of the battery types reviewed and the licensee was

>

monitoring the shelf life of the components. The inspector also

'

reviewed the consequences of a failure of selected fire protection

related batteries and concluded that the loss of these batteries

did not impact the ability to detect and actuate an alarm

signal / response. The inspector also reviewed selected

performances of SI-234.3, TECHNICAL SPECIFICATION FIRE DETECTORS,

and verified that adequate testing of the detection panel

batteries was being accomplished.

-

The tracking of required training for fire protection personnel

was noted to be good. The system allows for adequate lead time

for scheduling of training within the required time allowances.

In addition, various specific subject matter and training

techniques were verified as being incorporated in the fire

protection program.

i

-

The inspector reviewed the maintenance history of the three main

fire protection system pressure control valves, PCV-26-15, PCV-26-

109, and PCV-26-110. The records indicated that the reliability

of these valves has improved since previous poor material

conditions were identified during previous fire protection

inspections.

However, continued attention to these components is

t

warranted due to their importance to the fire suppression system.

t

-

A review was conducted of a June 1992 performance of 0-SI-FPU-026-

,

171.0, PERIODIC FLUSHING AND CHLORINATION OF HIGH-PRESSURE FIRE

'

PROTECTION SYSTEM, Revision 4.

The inspectors concluded that

performance of the procedure was acceptable.

It was noted that

,

controls were in place to assure adequate coordination of

'

activities for timely restoration of fire protection equipment if

+

needed. However, the inspectors also noted that activities to

assure acceptable chlorination levels in remote fire protection

!

piping were challenging for the test performers and needed to be

!

.

L

4

'

.

22

closely monitored to assure success.

This added attention is

necessary due to the complexity of the surveillance testing and

the importance of maintaining adequate chorine levels in all fire

protection piping for a sustained period of time to control the

seeding and growth of asiatic clams. The inspectors discussed

this observation with the licensee.

Fire protection management

indicated that they were aware of the tests complexities and a PER

,

had been issued to document the problem. Revisions to the

procedure were being considered to make it more user friendly.

-

The inspector reviewed the relationship of the fire protection

program with regard to erosion corrosion of fire protection system

piping. Because of the constant flowing through portions of the

-

high pressure fire protection system piping, the inspector

,

discussed the possibility of wall thinning problems due to

erosion / corrosion. The licensee indicated the fire protection

system was currently not covered by the erosion / corrosion program

at Sequoyah; however, a review was planned to evaluate this type

of monitoring in light of other systems exhibiting

erosion / corrosion problems. By the end of the inspection period,

the II with regard to recent erosion / corrosion issues at Sequoyah

was still in progress. The final decision as to the extent of

coverage of the fire protection system under the erosion corrosion

program will be determined once the II followup is completed.

-

The inspectors noted the continued reliance of the fire protection

system to supply certain raw water needs throughout the plant.

This design routinely requires the running of at least one fire

pump. Although the raw water system has been tested to provide

.

for its own needs, raw water system alarm problems required the

use of the fire protection system as a compensatory measure.

-

'

The licensee has established a schedule within the fire protection

improvement plan for completely separating the fire protection

,

system from the raw service water system.

Design completion is

~

currently scheduled for June 1994, with full implementation by

June 1995.

-

The inspectors sampled the staffing levels of the plant fire

brigade on a random basis. No discrepancies were identified. The

inspectors also verified that certain fire protection positions,

such as who serves as Incident Commander, were properly assigned.

One potential problem was identified, in that, a person listed on

,

the Shift Manning List as a Level No. I fire brigade member was

not present on site during the assigned shift. Another person

onsite adequately filled the position. A PER was initiated to

document the problem and corrective actions. The inspector had no

ML20035H226

Text

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