ML20137F708

Insp Repts 50-327/97-01 & 50-328/97-01 on 970119-0301. Violations Noted.Major Areas Inspected:Operations, Maintenance,Engineering,Plant Support & Effectiveness of Licensee Controls in Identifying & Preventing Problems

ML20137F708
Person / Time
Site:	Sequoyah
Issue date:	03/18/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20137F667	List: ML20137F663 ML20137F677 ML20137F708
References
50-327-97-01, 50-327-97-1, 50-328-97-01, 50-328-97-1, NUDOCS 9704010191
Download: ML20137F708 (35)

See also: IR 05000327/1997001

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U.S. NUCLEAR REGULATORY COMISSION

REGION II

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Docket Nos: 50-327, 50-328  !

License Nos: DPR 77, DPR 79 I

Report No: 50-327/97-01, 50 328/97-01

Licensee: Tennessee Valley Authority (TVA)

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Facility: Sequoyah Nuclear Plant, Units 1 & 2

Location: Sequoyah Access Road

Hamilton County, TN 37379

Dates: January 19 through March 1, 1997

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Inspectors: M. Shannon, Senior Resident Inspector ]

R. Starkey, Resident Inspector i

D. Seymour, Resident Inspector

W. Bearden, Reactor Engineer

S. Sparks, Project Engineer l

Approved by: M. Lesser, Chief

Reactor Projects Branch 6

Division of Reactor Projects

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Enclosure 2 i

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9704010191 970318

PDR ADOCK 05000327

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EXECllTIVE SUMARY

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Sequoyah Nuclear Plant, Units 1 & 2

NRC Inspection Report 50 327/97-01, 50-328/97-01

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This integrated inspection included aspects of licensee operations,

maintenance, engineering, plant support, and effectiveness of licensee '

controls in identifying, resolving, and preventing problems. The report

covers a six week period of resident inspection. In addition, it includes the

results of announced inspections by engineering and maintenance inspectors.

Operations

e The conduct of operations during the inspection period was considered to ,

be good (Section 01.1).

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e Operators responded promptly and appropriately to a reduction in Unit 1

condenser vacuum (Section 02.1). 3

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e A violation was identified with multiple examples of Emergency Diesel

Generator (EDG) alarm response procedure deficiencies (Section 02.2). ,

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o A weakness was identified for not obtaining routine logs readings during )

EDG operation and for not actively monitoring the EDG during a 110%

loaded run (Section 02.2).

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e The compensatory actions agreed to by the licensee for the 2A A EDG l

enforcement discretion were appropriately implemented (Section 02.3). l

e The inspectors concluded that the unavailability of paper for the AFlux  ;

recorders was a negative observation (Section 02.5).

e The licensee addressed the action items, reviewed by the resident

inspectors, related to the licensee's March 1996 Reliability Study

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(Section 08.1).

Maintenance

e A weakness was identified for the licensee's failure to identify EDG '

deficient conditions related to a malfunctioning stator and bearing

temperature recorder and the lack of a work request (WR) sticker on a

local EDG panel to identify failed thermocouples (Section 02.2).

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s Maintenance exhibited good performance during a 1A A EDG preventive

maintenance outage which included outage extending emergent work

activities (Section M1.2).  !

e The increased management attention associated with the Switchyard

Improvement Project was considered a strength (Section M2.2).

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e The licensee's use of infrared thermography in the 500 kV and 161 kV  !

switchyards has resulted in identification of several potential problems i

before actual component failure. This improvement in the Predictive '

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Maintenance Program was considered a strength (Section M2.2).

e A positive observation was made for the licensee's extensive root cause  :

investigation into the equipment failures associated with the Unit 2 l

turbine runback (Section 02.4).

e A negdtive observation was made for the failures of level indicator

controller 2-LIC 6 106 and of pressure switch 2-PS47-13D, which

precipitated the Unit 2 turbine runback and terminated the runback

prematurely (Section 02.4).

e An unresolved item was identified to review the extent of condition for

inadequate surveillance testing of the reactor trip breaker P 4

circuitry (Section M4.1).

Enaineerina

e The licensee is continuing to identify needed actions to address long j

standing problems related to the freeze protection program (Section

E2.2).

e An unresolved item was identified surrounding implementation of adequate

corrective actions for vendor recommendations regarding reactor trip

breaker surveillance activities. (Section M4.1).

Plant Support

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e The licensee is adequately implementing the radiological protection

program (Section R8.1).

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Report Details

Summary of Plant Status

Unit 1 began the inspection period in power operation. On February 20, 1997,

the unit began coasting down in power in preparation for the Unit 1 Cycle 8

refueling outage. When the report period ended the unit was at approximately

87% power.

Unit 2 began the inspection period in power' operation. On February 28, 1997,

the unit experienced an automatic / manual runback to 80% power due to problems

related to #3 heater drain tank normal level control valves. The unit

returned to full power on March 3,1997 and operated at 100% power for the

duration of the inspection period.

I. Operations

01 Conduct of Operations

01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent

reviews of ongoing plant operations. In general, the conduct of

operations was good. Specific events and noteworthy observations are l

detailed in the se tions below. '

02 Operational Status of Facilities and Equipment

02.1 Unit 1 Decrease in Condenser Vacuum  ;

a. Inspection Scope (71707) l

The inspectors reviewed the sequence of events which resulted in Unit 1

experiencing a reduction in condenser vacuum.

b. Observations and Findinas ,

On February 2,1997. Unit 1 entered Abnormal Operating Procedure (A0P)

S.02, Loss of Condenser Vacuum, when an inlet valve solenoid to the i

steam dump drain tank failed during an automatic drain down of the drain

tank causing an abnormal alignment of drain tank valves. This failure

resulted in a flow 3ath which 611 owed air to be drawn into the main

condenser through t1e drain tank vent valve. Condenser vacuum reached

approximately 1.24 pounds per square inch absolute (psia) before

operators were able to identify and isolate the cause of the condition. '

i Condenser vacuum prior to the event was approximately 0.66 psia. (The

condenser vacuum low alarm annunciates at 2.7 psia) The condition was  :

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first identified by alarming condenser radiation monitors which alarmed ,

due to a high flow condition. The standby condenser vacuum pump was i

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started and assistant unit operators (AU0) were dispatched to the

turbine building to investigate the cause of the condenser inleakage. '

The AU0s discovered the misaligned valves and heard air being drawn into

the drain tank vent valve which had failed open. The failed solenoid '

was isolated and condenser vacuum was restored to normal. The failed

l solenoid was subsequently replaced.

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C. Conclusions

Operators responded promptly and appropriately to a reduction in Unit I

condenser vacuum.

02.2 2A-A Emeroency Diesel Post Maintenance Testino

a. Insoection Scooe (71707)

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The inspector observed and reviewed operational and testing activities

associated with the 2A A EDG post maintenance testing, performed on

February 13. 1997.

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b. Observations and Findinos

On February 13. 1997, post maintenance testing (PMT) was being performed

on the 2A-A EDG following replacement of two generator electrical leads.

Post maintenance testing required the EDG to be run at 110% for two

hours. During the test, intermittent alarm conditions were noted and at

{ approximately one hour into the test two alarms were annunciating

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continuously.

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At approximately one hour into the two hour run, the inspector entered

, the control room and noted that the EDG 2A A Governor Actuator

Difference and the EDG 2A-A Exhaust Temperature Difference alarms were

l actuated. Shortly thereafter, discussions between the operator and the

shift manager noted that the EDG turbocharger inlet differential

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exceeded 200 F. At this time, the shift manager stated that the alarm

response procedure required the EDG to be declared inoperable; however,

he noted that the EDG was already considered to be inoperable. The

inspector's review indicated that o wrations continued to run the EDG at

110% load for about one hour with tie alarms actuated and field verified

to be valid.

Following notification that the EDG turbocharger inlet differential

temperature exceeded 200 F, the shift manager requested maintenance

j take local pyrometer readings on the EDG turbocharger inlets.

1 Subsequently, the maintenance technicians requested guidance from

operations on where to take the readings. The inspector went to the

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diesel building to observe the pyrometer data acquisition. While at the

2A A diesel, the inspector requested operations select the various

- exhaust thermocouple temperature points on the local diesel panel. The

i readings indicated ranges of 780 to 900 F on the 2A A2 diesel, 4:nd

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ranges of 540 to 1140 F on the 2A Al diesel.

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At the completion of the two hour 110% post maintenance run, the EDG

exhibited erratic behavior. When the EDG load was decreased to 4.4

megawatts (100%), the EDG governor became unstable and load swings of

about 10% were observed. The EDG was then rapidly unloaded. At no load

conditions, engineering noted that the fuel racks for the 2A A2 EDG were

fully closed indicating a motorized diesel condition. The EDG was then

manually tripped.

During the PMT of the 2A A EDG, the inspector noted various procedural

and operational problems. The observations and findings are listed as

follows:

• After questioning by the inspector, the licensee noted that the

EDG alarm response procedure 0 AR M26-C (B 2), Diesel Generator

2A A Exhaust Temperature Difference, was deficient. The procedure

listed the setpoints for the three alarm conditions as 100 F:

however, subsequent review noted that the actual setaoints were

200 F. Also, the procedure required the diesel to >e declared

inoperable if the local tem)eratures exceeded 100 F differential:

however, the EDG would not aecome inoperable until the

temperatures exceeded 200 F differential . The procedure was

considered to be inadequate due to the improper alarm setpoint

reference and inappropriate exhaust temperature differential

guidance.

e During the EDG post maintenance test, the licensee and the

inspector noted that the EDG alarm response procedure 0-AR M26-C

(B 1), Diesel Generator 2A-A Governor Actuator Difference, was

deficient. The alarm setpoint was listed as 0.04 (4%) difference

between the hydraulic governor scales of the two engines. The 1

local alarm response 3rocedure noted that acceptable operation

would be verified to 3e less than 0.1 (10%) difference between the

governor scales. However, the control room alarm response

procedure incorrectly listed acceptable operation as less than 1.0

(100%) difference between the governor scales. The control room

procedure was considered to be inadequate due to an improper value

listed for the verification of acceptable governor operation. l

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e The alarm response procedures, Diesel Generator 2A A Exhaust l

Temperature Difference and Governor Actuator Difference, both

required the EDG to be declared inoperable if the turbocharger '

inlet temperature exceeded 100 F differential: however, the alarm l

response procedures did not provide guidance or limitations for 1

continuing to operate the EDG with valid alarm conditions. These

procedures were considered to be inadequate in that they did not i

provide sufficient immediate and long range operator actions. i

Technical specification 6.8.1.a requires that procedures shall be

established, implemented, and maintained covering activities recommended I

in Appendix A of Regulatory Guide 1.33. Revision 2, February 1978. i

Appendix A of Regulatory Guide 1.33, Section 5, includes procedures for i

alarm conditions. This section lists the requirements for safety i

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related alarm response procedures which included: (1) the meaning of

the annunciator, (2) the source of the signal (3) the immediate l

automatic action (4) the immediate operation action, and (5) the long  !

range action. The EDG alarm response procedures did not meet the i

requirements as documented in Regulatory Guide 1.33 Section 5 therefore i

the inadequate procedure conditions listed above are considered to be a l

violation (VIO 50 327, 328/97-01 01).

While observing local operation of the EDG, the inspector noted that

Operations was not actively monitoring the EDG although it was being

operated at 110% and was in alarm for high exhaust differential

temperature and high governor actuator differential. In addition, the i

inspector noted that individual exhaust temperatures exceeded the alarm l

response procedure limit of 1050 'F and this condition had not been

identified by Operations. Subsequent review noted that the operators i

were not taking log readings on the EDG. This was discussed with the

shift manager, who noted that normal EDG operating parameters should

have been checked in accordance with Appendix C of operating procedure,

Diesel Generator 2A-A, 0-S0 82-3. However, the trouoleshooting section

of 0-S0 82-3, Section 8.7, which was used to perform the post

maintenance testing, did not require the operatort to perform the

routine checks. Operations' 3rocedure, Diesel Generator 2A A,

0 S0 82 3, was considered to 3e weak in that it did not require the

operators to take log readings in order to monitor ecuipment

performance. This would have identified the high incividual exhaust

temperature condition of the EDG during the post maintenance test. Not

obtaining routine log readings during diesel operation, is considered to

be a weakness.

During the 2A-A EDG post maintenance test on February 13, 1997, the

inspector noted that two of the 2A Al EDG exhaust thermocouples were

reading 400 to 500 F lower than the fifteen other 2A Al EDG exhaust

thermocouples. There was nothing at the local EDG control panel to

indicate that there was a problem with any of the thermocouples. These

thermocouples were later identified as failed. Although a WR had been

written to encompass problems with the entire EDG exhaust thermoccuple

system, the individual failed thermocouples were not identified locally. 1

This limited Operation's ability to evaluate and respond to the actuated

EDG alarms.

Also, the inspector noted that the EDG stator and bearing temperature

recorder was not properly recording any of its assigned points. Further

review by the licensee noted that the recorder was defective: however,

work requests had not been written to identify the deficient condition.

The inspector noted that neither of these conditions affected the

operation of the EDG; however, they would provide valuable information

on the performance of the EDG, and therefore, the licensee's lack of I

pro >er identification of the deficient conditions was considered to be a

wea(ness.

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In addition, the inspector noted that the EDG post maintenance test was

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continued at 110% diesel loading with multi ale alarm conditions in on  ;

the EDG. The inspector briefly discussed tais adverse condition with i'

the shift manager during the PMT The shift manager's decision to

continue to operate the EDG was partially based on

engineering / maintenance input. However, the inspector noted that the

engineering / maintenance inaut was based on local pyrometer readings of

L the EDG exhaust to the turaocharger inlets. These readings were roughly

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300 to 400 degrees lower than the multiple individual EDG exhaust

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thermocouple readings and the two turbocharger inlet thermocouple

readings.

c. Conclusions

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, An inadequate procedure violation with multiple examples was identified

which included inaccurate alarm procedure actuation setpoints,

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1 inadequate alarm procedure immediate operational actions and, inadequate  !

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alarm procedure long range actions. j

A weakness was identified for the licensee's lack of identification of l

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EDG deficient conditions related to a aalfunctioning stator and bearing

temperature recorder and the lack of a WR sticker on a local EDG panel

to identify failed thermocouples.  ;

A weakness was identified for not obtaining routine logs readings during

EDG operation and for not actively monitoring the EDG, although the EDG .

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was being operated at 110% load and was in alarm for high exhaust  !

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differential temperature and high governor actuator differential. ,

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02.3 2A A Diesel Generator Notice of Enforcement Discretion l

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a. Insoection Scope (71707)

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On February 14, 1996, the litensee requested the NRC exercise discretion

, and not enforce compliance with the actions required in Units 1 and 2

, Technical Specification 3.8.1.1. Action b. The request was a result of

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problems encountered during planned testing and maintenance on the 2A A

EDG (initially, an inadequate polarization index level on the 2A-/. EDG

generator C phase winding, followed by an unrelated problem with

degraded performance of the 2A2 engine governor). An additional 48 .

hours was requested in order to complete repair and testing of the EDG.

This discretion was approved by the NRC. and compensatory measures were

implemented by the licensee. (Notice of Enforcement Discretion (N0ED)

97-2 001)

The compensatory measures included: perform TS surveillance

recuirements 4.8.1.1.1.a every four hours (each of the required

incependent circuits between the offsite transmission network and the

onsite Class 1E distribution system shall be determined operable by

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verifying correct breaker alignments and indicated power availability):

perform TS 4.8.1.1.2.a.4 (demonstrate remaining diesel generators

operable); protect the switchyard, B train components and engineered

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safety features equipment while the 2A A EDG was out of service: provide

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refresher training for operators for contingency plans to cross connect

electrical loads during a loss of offsite power emergency; and approval

of the discretion by the licensee's Plant Operations Review Committee

(PCRC).

! b. Observations and Findinas

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The inspectors reviewed completed copies of 0 SI 0PS 082 007.W. AC

Electrical Source 0)erability Verification, Revision 2. This procedure,

which verified breater alignment, was perfcrmed every four hours. The

inspectors reviewed completed ccpies of 0 SI 0PS 082-007.0, Diesel

Generator Operability Verification, Revision 3: 0-S0-82-1. Diesel

Generator 1A A, Revision 1; 0-S0 82-2, Diesel Generator 18 B, Revision

1: 0 S0 82 4, and Diesel Generator 2B B, Revision 2, which were

performed for diesel generators 1A A, 1B B, and 2B B.

The inspectors determined through a review of control room logs that

access to the switchyard was restricted at 10:30 a.m., on February 14.

and that all main control room and plant activities unrelated to the 2A-

A EDG, or were not emergency in nature, were >ut on hold at 1:34 p.m.,

on February 14. An inspector also observed t1e refresher training for

the operators during one of the shift turnovers. The PORC meeting

minutes for February 14, indicated PORC approval for the discretion.

c. Conclusions

The inspectors concluded that the compensatory actions agreed to by the

licensee for the duration of the enforcement discretion were

implemented. Inspector Followup Item 328/97 01-05, Review Root Cause

which led to N0ED on EDG.

02.4 Unit 2 Turbine Runback

a. Inspection ScoDe (71707)

On February 28, 1997, at approximately 6:23 a.m., Unit 2 experienced an

automatic turbine runback to 97% Power from 100% power, due to problems

with the No. 3 heater drain tank level control system. A heater drain

tank level control system runback is designed to reduce load to 80%

power. However, the automatic runback inappropriately terminated and

the operators had to manually reduce load to less than 80%. The

inspectors reviewed the licensee's response to the runback.

b. Observations and Findinas

After the runback the licensee determined that 2 LCV 6 106 A and B had

unexpectedly closed, which reduced the No. 3 heater drain tank flow to

less than 5500 gallons per minute, which initiated the runback. The

licensee investigated several possible causes for the unexpected closure

of these valves. Preliminary licensee findings for the cause of the

runback indicated failure of heater drain tank level controller

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2 LIC 6 106. The controller contains a flapper held in place by spring

tension. The licensee noted that the "as-found" spring tension of the

fla)per was less than expected, and was determined to be the most

pro)able cause of the unexpected closing of 2 LCV 6106 A and B. The

licensee noted that the spring tension is preset at the factory.

The licensee also investigated possible causes for the premature  ;

termination of the runback. Preliminary information indicated that

turbine impulse pressure switches experience pressure set point drifts

after initial installation. Pressure switch 2 PS 47 13D, which

terminated the runback at 97* aower, had been replaced and calibrated in

October 1996. A calibration cleck following the runback determined the

"as found" set point corresponded to 95% power (a drift of approximately

130 pounds per square inch (psi) or approximately 15%). ,

As a result of these findings, the licensee checked the "as found" set

points on the remaining three balance of plant runback pressure switches i

for Unit 2 and all four balance of-plant runback pressure switches on i

Unit 1. Two of the pressure switches on Unit 2 were found 80 psi high,  ;

and one switch was found to be inoperable. All four of these switches  !

had been replaced after an October 1996, water intrusion event.

Subsequently, all of the Unit 1 pressure switches were found within the

allowable "as-found" tolerance.

On March 1 the licensee replaced two of the pressure switches on Unit 2

(2 PS47-13D and the inoperable switch), and reset the set points on all

four switches. On March 2 the licensee checked the calibration set

points and determined that they had drifted -8 to +15 psi. Because of

the drift, instrument maintenance began checking the calibration of the

pressure switches once every 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. .The licensee indicated that

calibration checks will continue until it is certain that a longer .

calibration frequency is warranted. Based on this calibration

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verification frecuency, the unit was returned to 100% power. The cause

of the pressure crift is still under investigation.

In addition to the once per 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> calibration check, the licensee

also implemented the following actions:

e the failed switch was sent to the vendor for diagnosis:

e a vendor engineering re)resentative was scheduled to visit

Sequoyah to assist in tie diagnosis of the pressure switch drift ,

problem:

o performance of an extent of condition review:

e development of a long and short term corrective actions based on

the vendor diagnosis.

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c. Conclusions

The inspectors considered the failures of level controller 2-LIC-6106

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and the turbine impulse pressure switch 2 PS 47 13D, which precipitated

the runback and terminated the runback prematurely, respectively, to be

a negative observation.

The inspectors considered the licensee's extensive root cause

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investigation into the equipment failures associated with the runback to

be a positive observation.

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02.5 Control Room AFlux Recorders I

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a. Insoection Scope (62707)

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During routine observations in the control room, the inspectors noted

j problems with the AFlux recorders on Unit 1. (There are four AFlux

recorders, which record the reactor core upper and lower AFlux as

monitored by nuclear instruments 41, 42, 43 and 44.)

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b. Observations and Conclusions

The inspectors noted that two of the Unit 1 AFlux recorders were out of

chart ) aper. An operator explained that an effort to obtain the chart

paper lad been made, but that none was available in the storehouse. The

operator indicated that a Problem Evaluation Report (PER) had been

written. The inspectors concluded that the unavailability of paper for

the AFlux recorders was a negative observation.

08 Miscellaneous Operations Issues

08.1 Corrective Action Procram Review

a. Insoection Scope (405001

This inspection was conducted to determine the effectiveness and the I

state of completion for specific corrective actions identified by the ,

licensee to correct findings identified in the March 5,1996, j

Reliability Study. The licensee initiated PER No. SQ960393PER to track l'

the corrective action items identified in the Reliability Study.

b. Observations and Findinos

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Actions taken by the licensee on the following corrective actions items, l

identified in PER No. SQ960393PER, were verified by the inspector:  !

e Item #1: Site Vice President, Plant Manger, Engineering and

Materials Manager, and Business and Work Performance Manager  ;

review findings of this report (reliability study) with their line i

supervisors and obtain a personal commitment from each that they  ;

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are personally accountable for the actions of their employees and

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they will be held accountable for their subordinates performance.

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Action taken: Early in 1996, the licensee initiated site

standdown meetings to communicate management expectations for  !

conducting work, enforcing work standards, and ensuring all plant i

personnel were aware of recent plant events and negative trends in

work practices. One such meeting was held on February 22, 1996, i

All managers and supervisors were required to attend the meeting I

and to brief their employees on the meeting and management

expectations. The meeting discussed recent plant issues and ,

events Sequoyah common cause assessments, enforcement of work

standards and accountability as they related to all employees and

to managers and supervisors. The licensee did not keep attendance

rosters for those meetings and did not actually require employees

to sign written commitments that they understood management's l

expectations; however, the resident inspectors attended several

of the standdown meetings and noted that licensee management was

intent upon making expectations known to employees and ensuring i

that employees understood that they would be held accountable to l

those expectations.  ;

e Item #2a: (Part 1) The 0)erations Manager and Operations line

supervisors will ensure tlat Operations personnel, with

demonstrated knowledge and experience, will r iiorm or supervise

the performance of any activity described in the Sensitive

Activities Manual. (Part 2) The Operations Manager will further

ensure that Operations training, retraining, and performance

monitoring programs gain, maintain, and measure knowledge and

experience to reduce knowledge based errors by 70% by the end of

the first quarter of calendar year 1997.

Action taken (Part 1): The Sensitive Activities Manual Sequoyah

Nuclear Plant, Revision 2, dated June 28, 1996, made supervisors

responsible for ensuring that employees possess demonstrated

knowledge and experience in using the proper tools and in the

procedures used to perform unsupervised tasks, and that the

expectations of the performance standards are clearly stated to

the employees just prior to performance of the task.

Action taken (Part 2): The licensee determined that, by the end

of calendar year 1996, knowledge based errors in the 0)erations

organization had been reduced by approximately 58%. T1is

percentage im)rovement was determined by comparing the percentage

of knowledge )ased errors identified in the Reliability Study

(which used 1994 1995 PER data) to the percentage of knowledge

based errors identified in the Common Cause Assessment data for

calendar year 1996. The licensee has established a goal of 70%

reduction of knowledge based errors in the Operations organization

by the end of the first quarter of calendar year 1997.

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e Item #2b: Operations Manager will develop a balance of plant

requalification training program incorporating systems and/or

component engineer utilization.

Action.taken: The licensee has a Curriculum Review Committee

(CRC) which meets at least quarterly to identify the tasks to be

covered during the o>erations requalification training cycle. The -

CRC is also responsi)le for developing a two-year requalification

training schedule. The current requalification training schedule  ;

contains several training classes on balance-of-plant systems.

The chairperson of the CRC is appointed by either the plant  ;

manager or the site vice president and is typically.the senior {

manager in a given program area. In the case of operator 1

training, the Operations Manager acts as the chairman of the CRC.

e Item #2c: Operations Manager will revise SSP-12.63 to incorporate

the Sensitive Activities _ Manual and to focus on unit reliability

improvement and proceduralize supervisor responsibility.

Action taken: SSP-12.63, Sensitive Equipment Control, was revised

July 5,1996 (Revision 2), to ensure consistent guidance with the

Sensitive Activities Manual. Revision 2 also implemented

corrective actions relative to supervisor responsibility and unit

reliability.

e Item #4: Reissue the Sequoyah Personnel Accountability Guidelines

and utilize the Guidelines to hold all' employees and line

supervisors up to and including the department managers

accountable for human performance errors.

Action taken: Revision 1 of the Work Standards Manual was

effective May 30, 1996. The manual served as a centralized source .

of guidance relevant to the conduct of work standards, but it did  !

not replace established procedures and policies. Copies of this

manual were distributed to site employees. Managers and

supervisors were required to discuss with their employees the

expectations discussed in the manual and to stress that employees

will be held accountable to those expectations. l

e Item #5a: Reestablish focus areas and adhere to them.

Action taken: The licensee established six major focus areas in

the Fiscal Year 1997 Business Plan. Each focus area was further

sub divided into smaller areas. The six focus areas were

financial plan, work force plan, health & safety plan,

environmental, nuclear safety, and generation. Each focus and

sub focus area was assigned to a manager who was held responsible

for successful implementation of the plan associated with that

focus area.

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

.

11

e Item Sb: Restructure the PER Review Meeting (PRM) and/or

Management Review Committee (MRC) to evaluate performance in the

'

focus areas.

Action taken: The (MRC) was restructured to focus on the plant

and problems related to plant operations. The plant manager is

the chairman of the HRC and its members are comprised of

department managers. The MRC meets daily and discusses Problem

Evaluation Reports (PER) which are listed on an agenda published

the day before each meeting. Each department head discusses those

PERs which apply to his specific department and the MRC determines

at what level (A, B, C, D, with A being the highest level) the PER

j will be dispositioned.

e Item #6: Reestablish a plan-of-the day type meeting.

Action taken: The licensee has reestablished the plan-of the-day

meeting. The purpose of the meeting is to focus on plant

operations. Items discussed during the meeting include the status

of each unit, engineering issues, sensitive maintenance activities

which could affect the units, material restraint issues,

switchyard issues and chemistry issues. The meeting is chaired by

the on-shift shift manager.

e Item #7: Prioritize the FY 1997 Capital and Operations and

Maintenance (0&M) budget by the focus areas and develop a ,

task based budget to support those priorities. Reflect this '

philosophy in the Sequoyah 1997 Business Plan. Supervisors

should ensure that resources are not expended on any task

that does not support Sequoyah focus areas.

Action taken: The licensee restructured the Capital and 0&M

Project Lists to group work according to the focus areas. The FY-

97 Capital and O&M Dudgets and Business Plan were also built

according to the focus areas. l

e Item #8: Develop a site material condition report which

consolidates prioritized hardware focus areas. Include in the

report maintenance work request (WR) indicators, operator

distractions (e.g., work arounds, lit annunciators) system health,

maintenance rule performance, and unit generator / capacity factor

performance.

Action taken: The licensee's Weekly Business Meeting Report and

meeting addressed the items to be included in the Site Material

Condition Report. Items in the Weekly Business Meeting Report are

discussed weekly at the meeting and include: Work Order (WO)

indicators, operator distractions, system health, maintenance rule

performance, plant generation, and material conditions (including

maintenance backlogs and temporary repairs).

. .

- . . -

,

.

i

, 12

o Item #17

Provide a management training course in implementing

'

change.

Action taken

The licensee instituted a Leadership Development

Program. The schedule provided for ten two week sessions, which

'

started in March 1996 and will end in March 1997. Approximately

224 personnel, encompassing managers at the first line supervisor

)osition and above and representing 18 organizations at Sequoyah,

lave been targeted to receive the training. The course was

desioned from recommendations provided by plant management and

inciuded sessions which discussed change management. The course

is taught by Sequoyah managers.

'

c. Conclusions

I

The inspector determined that the licensee addressed each of the above  ;

, action items related to the March 1996 Reliability Study.

08.2 (Closed) Violation 50 327. 328/96 04-02. Failure to Maintain the

Adecuacy of Procedures 2-SI 0PS 082-26.A and 2 SI-IRT-099 699.A and

Failure to Follow the Reauirements of Procedure 2 PI-0PS 000-038.1.

i The licensee *s response letter, dated July 26, 1996, committed to

reviewing and revising appropriate procedures relative to equipment

alignment and restoration of spent fuel pool (SFP) cooling that resulted

'

l in the violation, and to perform an independent assessment of operator  !

'

watch standing. The inspector verified that the appropriate procedures i

4 were revised to include SFP cooling restoration and to improve operator

rounds relative to recording SFP temperatures.

! Operator watch standing was assessed by the site quality assurance (QA)

1

organization and was documented in Assessment NA SQ 96-014, dated August i

8, 1996. The assessment concluded that: (1) out of-limit readings were l

'

not always identified and/or reported to the Unit Operator or Unit ,

Supervisor, (2) management expectations with respect to rounds sheet I

reviews and reporting out-of-limits data was not consistently adhered to I

or reinforced, and (3) corrective actions for Violation 96 04 02 were '

not totally effective in improving Operations personnel performance. As

a result of these QA findings, a level B PER (SQ962088PER) was initiated

to identify problems found during the evaluation of operator watch

standing. Corrective actions were initiated immediately by the Shift

Managers. The inspector concluded that the corrective actions

associated with the PER were appropriate.

4

i

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

.

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13

.

II. Maintenance

M1 Conduct of Maintenance i

'

M1.1 General Comments (62707)

a. Inspection Scope (61726 & 62707)

The inspectors observed and/or reviewed all or portions of the following l

work activities and/or surveillances:

e WO 96041452 Replace Air Start Pressure Switches on IB Diesel

Generator

e WO-97003251 Test P 4 Permissive for Unit 2 Reactor Trip

Breaker B

e WO 97003408 Diesel Generator 2A A Functional Test

e WO 96000052 Repair of Primary Water Storage Tank Fill Valve -

e WO 96036842 Centrifugal Charging Pump 1A-1 Oil Cooler

Outboard Bearing

e WO 97003212 Centrifugal Charging Pump 1A 1 Speed Increaser

Oil-Cooler  !

l

e 0-SI SXV 032 200.B Train B Auxiliary Air Compressor Cooling Water l

Inlet Valve Operability Test  ;

1

e 0 PI SFT-032 001.B Auxiliary Control Air Operability Test

e 0 PI 0PS 000 032.0 Condensate Demineralizer AU0 Duty Station Shift

Relief and Rounds Sheets

e 0 50 30 8 Containment Pressure Control

e S0I 78.1 Spent Fuel Pit Coolant System

e 0 MIM DG 082 007.0 Four Year Preventive Maintenance (PM) of EDG

e 1 SI TPT 082.102A Functional Test of the DG 1A-A Protection

e CMP 82 0180 1A1 Starting Air Compressor (PM)

e 2 SI EFT-082 001R DG 2A A 18 Month Electrical Inspection

e MI-4.2.3 Monthly PM of Diesel Engines

e 2 PI 0PS-003 001.0 AMSAC Functional Test

. _ . _ _ _ _ _ _ _ .._ __ _ _. _ _ _ _ _ _ _ _ _ .

,

1

4

l 14

b. Observations and Findinas

2

The inspectors noted that the work activities and the performance of

surveillance activities were adequately performed.

M1.2 1A A Diesel Generator Outaae

a. Inspection ScoDe (62707)

The inspectors observed and reviewed activities related to a planned

.

outage of the 1A A EDG.

,

b. Observations and Findinas '

On February 25,1997, at 11:04 p.m., the 1A A EDG was declared

inoperable (Limiting Condition of Operation Action Statement 3.8.1.1.b

was entered) and a 49 hour5.671296e-4 days <br />0.0136 hours <br />8.101852e-5 weeks <br />1.86445e-5 months <br /> planned EDG outage was started. The planned

i' length of the outage was based on maintenance activities associated with

a 24 month preventive maintenance inspection of the EDG. One of those

activities was an inspection of each engine cylinder's piston-to head

clearance. During that inspection it was determined that cylinder #8 on

engine 1A-1 did not meet acceptance criteria and subsecuently the power

pack (the piston and cylinder assembly) for that cylincer was replaced.

The power pack replacement, which required additional post maintenance

testing (PMT) and was not part of the original outage schedule, resulted

in the EDG outage lasting ap3roximately 67.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> out of the total TS

LC0 allow outage time of 72 1ours. The LC0 action was exited on

February 28, 1997, at 6:29 p.m.

c. Conclusions  !

Maintenance exhibited good >erformance during a preventive maintenance ,

outage on the 1A A EDG whic1 included emergent work activities which

extended the original length of the planned outage.

M2.2 Switchyard Activities

a. Insoection Scope (62700. 62706).

Previous problems with equipment reliability in the 500 kV Switchyard

and 161 kV Switchyard at Sequoyah have resulted in numerous online

component failures, plant trips, the potential for injury to personnel,

and challenges to safety related systems and components. The licensee's

switchyard Preventive Maintenance Program was previously identified as a

weakness by the NRC. The license's OA organization also identified the

overall performance in this area as a significant weakness.

Additionally, the license's OA organization identified an adverse trend

associated with switchyard work practices during the fourth quarter of

fiscal year 1996.

. .- - . -- - - --- . . . .

.

.

I

15

i The inspectors reviewed the Sequoyah Switchyard Improvement Project to

determine the status of corrective actions in this area. This review

included a review of planned changes associated with the licensee's new

i

Substation / Switchyard Maintenance and Test Program. Additionally, the

, inspectors reviewed the licensee's disposition of recommended corrective

actions proposed in PTI Report No. R60 96, Critique of Sequoyah 500 kV

,

'

Switchyard, PTI Report No. R60a 96, Critique of Sequoyah 161 kV

Switchyard, PTI Report No. R87a-96 Critique of TVA Nuclear Plant

Switchyard Maintenance Practices, and the Sequoyah Nuclear Plant

Switchyard Design Review Report, dated January 27, 1997. The inspectors

conducted tours of both switchyards, the Sequoyah main control room and

the )lant relay room along with observation of ongoing activities in the

161 (V and 500 kV equipment located in the plant and in the switchyards.

b. Observations and Findinos

Switchyard Imorovement Pro.iect i

The inspectors concluded that the licensee has implemented several ,

changes in this area which were intended to result in significant- l

improvements in the reliability of switchyard equipment at all TVA

nuclear facilities. These included increased manageinent oversight of

Transmission and Power Supply Group (TPS) activities, appointment of a

sanior site manager to oversee switchyard activities, weekly switchyard

improvement status meetings, TPS activities included on the plant's j

daily. activities schedule and 12 week rolling schedule, and TPS O&M 1

Manager attendance at plan of the-day meeting to discuss ongoing

switchyard issues. Additionally, there was limited oversight by site QA

of switchyard activities. Switchyard activities were recently added to

the Sequoyah QA Level 1 Trend Report as a maintenance process. The

inspectors were informed that the designated senior site manager

responsible for overseeing switchyard activities at Sequoyah was the

Site Support Manager.

The inspectors determined that the licensee's TPS has made a significant

reduction in the outstand 1ng backlog of switchyard PM items, performed

various equipment upgrades and in the process of implementing other

changes intended to improve the overall reliability of both switchyards. I

The new TPS Substation / Switchyard Maintenance and Test Program is

scheduled to be implemented on March 31, 1997. The inspectors i

determined that this new program included more stringent expectations

associated with material conditions in the switchyards and the  ;

requirement for management approval of any PM deferrals.  ;

The licensee conducted a design review to evaluate switchyard equipment i

failures at Sequoyah, identify corrective actions, and develop

corrective actions were necessary. The design review report was issued

January 27, 1997. Corrective actions recommended in this report i

included planned modifications to switchyard equipment: inspections of .

current carrying connections and overhead ground wire tie offs in the l

switchyards: completion of ferroresonance calculations on both '

switchyards; and improveinents in communications between TPS, system

-

'

I

I

16

dispatching, and operations personnel. Recommended hardware

modifications included replacement of 500 kV MICAFIL Coupling Capacitor  ;

Voltage Transformers (CCVT) with sulfer hexafluoride (SF6) voltage l

transformers (VT), re)lacement of 500 kV oil filled potential '

transformers (PT) wit 1 SF6 pts, replacement of all oil-filled 500 kV  !

current transformers (CT) with non-oil filled cts, replacement of 161 kV

Breaker 974 and 500 kV Breakers 5054, 5064, and 5048: and disabling of

the redundant trip function of the Bucholz gas operated relays for the

main bank transformers. The inspectors noted that many of these

recommended hardware modifications have been completed with a few still

in progress or planned before the end of 1997.

Preventive Maintenance Proaram i

The licensee used the Substation Maintenance and Routine Test (SMART)

Database to plan and schedule switchyard preventive maintenance items.

The inspectors were informed that many of the previous prcblems with

overdue PM items were associated with the use of the SMART database.

This database was not user friendly and it did not allow early

identification of upcoming PM items that the licensee might want to

perform during short notice switchyard outages. Additionally, the

database was not compatible with the database in use by the )lant to i

track plant PMs. The licensee was developing a new program tlat will

replace the current SMART database. The licensee had planned changes to

the program to provide for full compatibility between the different

programs used by the plant and TPS along with allowing identification of

any upcoming PH items prior to the due date.

The licensee's existing program included oil analysis, temperature I

indications, routine logs, and thermography. The licensee had plans to

develop a computer program for trending of transformer gas-in oil

analysis results.

The licensee appeared to be making excellent use of infrared

thermography in the 500 kV and 161 kV Switchyards. Use of this

technology allowed direct observation of actual temperature conditions

on most switchyard components while those components were under

electrical load. This approach to predictive maintenance has resulted

in identification of several potential problems before actual component '

failure. Examples of problems recently identified through the use of

thermography included excessive temperature on several bus connections

and overheated transformer bushings. These problems were corrected

during a recent switchyard outage prior to failure of the components. )

This imarovement in the Predictive Maintenance Program was considered a

strengt1.

Observation of Switchyard Maintenance Activities

The inspectors observed ongoing work associated with replacement of the

500 kV Breaker 5048. Additionally, the inspectors observed portions of

ongoing calibration checks of the 161 kV Chickamauga No. 2 Line Relays.

This work was performed under WO 97-002836-00. The inspectors noted

1

.

17 l

that the Doble F2200 Test System used for the relay calibration was

within required calibration periodicity. The inspectors also reviewed

completed WO 96 042548 00 which recalibrated the pressure relay for the

intertie transformer. No problems were noted during the inspector's

observation or review of these activities.

Material Condition of Switchyards

The inspectors conducted a tour of both switchyards, the main control

room and the plant relay room. Access control into the switchyards was

adequate with Senior Reactor Operator )ermission recuired prior to

entry. No accumulation of trash or de)ris was notec in either

switchyard. No temporary buildings, trailers, loose boards, plywood, or

other materials that could result in damage to switchyard equipment in

the event of high winds were observed. No unnecessary vehicle traffic

was present in the switchyard. The ins)ectors observed several minor

oil leaks on each the four Unit 1 main aank transformers which indicated

possible gasket problems. Condition of protective coatings on several

transformers were noted to be poor with oxidized or peeling paint.

Additionally, one fan on the Unit 2 B Phase Main Transformer exhibited

excessive noise during operation. The inspectors verified that the fan

problem was documented under WO 97-03139 00 and that the licensee had

already scheduled refurbishment of all four Unit 1 Main Transformers

during the next refueling outage. Correction of all identified oil

leaks was planned during the refurbishment. Several large sections of

unused 161 kV/500 kV bus conductors were stored on the ground in the

switchyard. The inspectors were informed that these sections were

actually removable conductors associated with the Spare Main

Transformers and the 500 kV - 161 kV Intertie Bus. The inspectors noted

that these bus sections were adequately secured to prevent movement.

Isoohase Bus Ducts and Isophase Bus Duct Coolina Systems

The inspectors )erformed a walkdown of selected portions of the Unit 1

and Unit 2 isoplase bus duct and isophase bus duct cooling systems. No

problems were noted during this walkdown. The inspectors noted that

licensee personnel had previously noted a buildup of moisture on the

plexiglass viewing port on the Unit 2 C Phase Isophase Bus Duct on

November 26, 1996. This condition was documented by the licensee under

PER No. 963051PER. The licensee had determined that maintenance

personnel had inadvertently missed the makeup air filter during

performance of PM 05863200 to inspect the cooling system filters. The

filter had subsequently become clogged and a negative pressure condition

resulted in the bus duct. This allowed water intrusion. The filter had

been missed because the craft were not aware that specific filter

existed. As corrective action the licensee initiated a PM revision to

specifically list all filters and locations and to clarify the

requirement that all filters be cleaned or replaced. The inspectors

reviewed PER No. 963051PER and the associated PM Change Recuest and

determined that corrective actions had been adequate to adcress the

problem.

_ _ _ _ _ _ _ . . _ . . _,

,

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,

I

18

Maintenance Rule Activities Associated with the Switchyard

The inspectors reviewed the Maintenance Rule Expert Panel meeting

minutes for panel meetings held on June 5, 1996. September 26, 1996, and

November 4, 1996. Based on information contained in those meeting

minutes the inspectors determined that all equipment in the 500 kV and

161 kV Switchyards for both units at Sequoyah were classified as a(1) )

under the Maintenance Rule. The licensee's Maintenance Rule Program

requires that all switchyard challenges be considered as part of their

program for monitoring switchyard equipment. Switchyard challenges

include any type failure of a switchyard component that affects the  ;

manual or automatic operation of that component. This definition was

more restrictive than used for other plant equiment and has resulted in

counting some failures that might not normally m considered functional

failures under the Maintenance Rule. The licensee had established goals

of no more than four challenges to the switchyards for the first and '

second quarters of Fiscal Year 1997, three challenges for the third

quarter, two challenges for the final quarter of the fiscal year and

only one challenge per quarter after that. These goals had not been l

satisfied during the first quarter of Fiscal Year 1997 since there had I

been a total of five challenges. However, it is expected that the

licensee should be able to meet the established goals as the result of i

switchyard improvements. The inspectors noted that the licensee's

established goals would not allow the switchyards to be removed from

a(1) status any earlier than the second quarter of Fiscal Year 1998.

Review of Selected Corrective Action Documents

The inspectors reviewed several licensee PERs which documented problems '

associated with switchyard equipment. Specific PERs reviewed by the '

.

inspectors included the following:

SQ950768PER Unit 1 Reactor Trip Due to Erroneous Operation .

of Sudden Pressure Relay on 1A Main Transformer  !

SQ961211PER USST 2B Wire Degraded Insulation

SQ961757PER Maintenance Rule Corrective Action

SQ961822PER Unit 1 Reactor Trip Due to Violent Failure of

500 kV Bus 1 MICAFIL CCVT.

SQ962596PER 500 kV Bus 1 Potential Transformer Explosion

SQ962887PER Loose / Damaged Bushing Draw Rod and Loose Objects

Found in Intertie Transformer Bank During i

Transformer Outage  !

'

SQ963051PER Moisture in Unit 2 "C" Phase Isophase Bus Duct

SQ963262PER 500 kV Switchyard Transformer Paint Problems

i

l

.

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

.

.

l 19

SQ963282PER Haintenance Rule Switchyard Challenges

.

SQ963291PER Intertie Transformer Tripped Due to Pressure  !

Relay Actuation j

SQ970135PER Airline Freezing on 500 kV Air Blast Breaker

5018

The inspectors determined that the corrective actions for each of the

above PERs were adequate to resolve the problems identified in the PER.

,

No problems were identified during the inspectors review of these PERs.

c. Conclusions

. The increased management attention associated with the Switchyard

'

Improvement Project has resulted in significant progress in this area.

Additionally, the licensee's use of infrared thermography in the 500 kV

i and 161 kV Switchyards has resulted in identification of potential

.

problems before actual component failure. Management attention being

1

devoted to switchyard problems and the licensee's Predictive Maintenance

"

Program were considered strengths. Although significant improvements  ;

1 have occurred there was still area for improvement. Several 161 kV and i

500 kV breakers were yet to be replaced and some transformers leaked oil

1

and still needed refurbishment. Additionally, the licensee has not meet

their goal for number of switchyard challenges for the most recent

quarter. l

l

4 M4. Maintenance Staff Knowledge and Performance  ;

, M4.1 Reactor Trio Breaker Testina

-

a. Insoection Scope (61726)

Due to previous problems identified with testing of the reactor trip

breakers (Inspection Report 96 13), the ins)ector reviewed the TS

required surveillance testing associated wit 1 the reactor trip breakers,

b. Observations and Findinas

Following maintenance activities on the Unit 2 reactor trip breaker on

September 19, 1996. TS required surveillance testing was performed;

however, the testing did not identify the inoperable P-4 contactor (the

inoperable reactor trip breaker was discussed in Inspection Report (IR)

96 13). Due to the failure of the TS surveillance to identify the

failed reactor trip breaker, the inspectors performed a detailed review

of the a)plicable technical specification surveillances. The following

paragrapls discuss the deficiencies noted with the surveillances and

associated testing procedures.

.

20

During subsequent reviews, it was identified that both Unit 2 reactor

trip breaker P 4 circuits had not been adequately tested. The

inadequate testing involved the testing of two of the P 4 actuation

.

signals, the P 4 main feedwater isolation signal (MFWI) and/or the P 4

turbine trip signal. The inadequate testing was related to the P 4

breaker contacts and/or the P 4 electrical circuit auxiliary contacts

(breaker to cubicle) for one or both of the P 4 signals.

1. On August 29, 1996, the "A" reactor trip breaker was replaced with

'

a refurbished spare breaker. The P-4 turbine trip contacts and

the turbine trip auxiliary contacts (breaker to cubicle) were not

adequately tested. The P 4 main feedwater isolation contacts and

the feedwater isolation auxiliary contacts (breaker to cubicle)

w a also not adequately tested.

Adequate testing of the breaker was subsequently completed as

follows:

On October 22, 1996, the "A" reactor trip breaker (refurbished)

main feedwater isolation P-4 circuit was tested. This included

testing of the P-4 MFWI contacts and the MFWI circuit auxiliary

4

contacts (breaker to cubicle).

On January 18, 1997, the "A" reactor trip breaker (refurbished)

turbine tria P 4 circuit was tested. This included the testing of

the P-4 tur)ine trip breaker contacts and the turbine trip circuit

auxiliary contacts (breaker to cubicle).

2. On September 19, 1996, the "B" reactor trip breaker was replaced

with a refurbished saare breaker. The P-4 turbine tri) breaker

'

contacts and the tur)ine trip auxiliary contacts (brea(er to

cubicle) were not adequately tested. The P 4 main feedwater

isolation breaker contacts and the feedwater isolation auxiliary

. contacts (breaker to cubicle) were also not adequately tested.

Later on September 19, 1996, the refurbished "B" reactor tri)

breaker was replaced with the original "B" rec.ctor trip brea(er,

however, due to an inoperable P 4 function, the refurbished spare

breaker exceeded the LC0 action requirements of TS 4.3.1.1.2,

prior to the original breaker replacement. This was the subject

of escalated enforcement action EA 96 414.

3. On October 16, 1995, the "B" reactor trip breaker was replaced

with a re. furbished spare breaker. The P 4 turbine trip auxiliary

contacts (breaker to cubicle) were not adequately tested.

- - - - . - -

.

1

21

Adequate testing of the breaker was subsequently completed as

follows: i

On February 7, 1997, the "B" reactor trip breaker (refurbished  !

breaker) turbine trip P 4 circuit was tested. This included the

testing of the turbine trip circuit auxiliary contacts (breaker to

cubicle).

The following sections provide additional details of the inspection

activities, observations and findings related to the inadequate '

surveillance activities noted in sections 1, 2, and 3 above:

(1). "A" Reactor Trio Breaker Replacement on Auaust 29. 1996.

The inspectors requested information related to the surveillances

aerformed for testing of the P-4 contacts, and requested the

areaker refurbishment dates. The licensee supplied information i

indicating that the Unit ) reactor trip breakers were refurbished

'

and subsequently tested in November 1995. The licensee supplied ,

information indicated that the Unit 2 reactor trip breakers were i

refurbished in October and November 1996 with the surveillance

testing having been completed in May, August and September 1996.

Because the information was based on the closure dates of the work

recuests, additional information was requested. Further review l

incicated that the Unit I reactor tri) breaker maintenance and  ;

testing was satisfactory. However, t1e inspectors noted that the

Unit 2 data was still insufficient to determine adequate testing.

The inspectors informed the licensee that the reactor trip breaker

surveillance testing appeared to be incomplete and further review

was necessary to resolve the concerns.

Subsequently, the inspectors requested specific testing and

refurbishment dates. During the licensee's review and collection

of requested material, the licensee noted that the "A" reactor

trip breaker had not been adequately tested. On January 17,

1997, the licensee entered Technical Specification 4.0.3 for

failure to perform a surveillance requirement within the allowed

surveillance interval. Subsequent surveillance testing was

adequately performed on January 18, 1997, to meet the surveillance >

requirements of Technical Specification 4.3.1.1.2.

The licensee noted that the cause for the inadequate testing of

the "A" reactor trip breaker P 4 contacts was a faulty process for

documenting test completion dates. The spare "A" reactor trip

breaker had been refurbished and had its contacts tested in May  !

1994. It was then ) laced in standby and subsequently installed on

August 29, 1996. T1e testing section of the refurbishment

procedure was not completed until August 29, 1996, however, it did

not retest the breaker P-4 contacts. Based on the licensee's

process, the breaker contacts were considered to have been tested

on August 29, when the refurbishment procedure was finally

completed. Since the breaker P 4 contacts had not been tested

_. _ _ _ _ _

l

l

22

since May 1994, the breaker was inoperable when it was installed

on August 29, 1996.

During subsequent interviews with the licensee staff and

discussions with licensee management, the inspectors were informed

that surveillance / calibration time clocks occasionally start when

a piece of equipment is installed, regardless of when it may have

been calibrated, tested or adjusted. This could lead to exceeding

surveillance and calibration intervals, as occurred with the "A"

reactor trip breaker on August 29, 1996. The process of using

installation dates versus calibration dates to meet surveillance

start dates will be reviewed and is identified as an inspector

followup item (IFI), (IFI 50-327, 328/97 01 03). ,

(2) "B" Reactor Trio Breaker Reolacement on September 19. 1996.

This event was identified in IR 96 13 and violations were

identified for an inadequate maintenance procedure and failure to

follow the maintenance procedure, which led to the failure to meet  ;

the TS LC0 action statement of TS 4.3.1.1.2. The inspectors

reviewed the associated surveillances and noted that the

(refurbished) "B" reactor trip breaker had not been adequately

tested following installation. It was subsequently removed due to

inconsistent indications and found to have an inoperable P 4

function.

The P-4 auxiliary contacts (breaker to cubicle). for both

actuation signals, were not tested. Testing of these contacts

would be required following installation of the spare refurbished

breaker in order to continue to meet the 18 month TS 4.3.1.1.2

requirements. This issue is included to highlight the need to

'

.

properly test the auxiliary contacts (breaker to cubicle),

following maintenance activities or breaker replacement, which

could result in the auxiliary contacts not properly making up due

'

5

to high resistant (dirty) or misaligned contacts.

The P 4 breaker contacts, for both actuation signals, were not

tested. Pro)er surveillance testing of these contacts would have

-

identified t1e disconnected P 4 contactor linkage and the

ino>erable reactor trip breaker. This issue is included to

hig111ght the inadequate surveillance test procedure.

.

(3) "B" Reactor Trio Breaker Replacement on October 16. 1996.

After the Unit 2 reactor trip on October 11, 1996, the licensee

'

refurbished a spare reactor trip breaker and on October 22,

'

installed the refurbished breaker in the "B" reactor trip breaker

cubicle. On February 10, 1997, the ins >ectors requested

,

'

information concerning the testing of tie "B" reactor trip breaker

P 4 turbine trip auxiliary contacts, following the breaker

replacement on October 16, 1996. During the week of February 3 7,

4

discussions were held with engineering involving testing of the

<

w

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

.

.

l

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23

breaker to cubicle (auxiliary) contacts. Further review of

breaker testing by the licensee noted that the P 4 turbine tri) <

contacts had not been properly tested. On February 7, 1997, tie I

licensee performed testing of the auxiliary contacts for the P 4

. turbine trip circuitry.

, The licensee did not perform adequate testing of the reactor trip

'

breaker P 4 function, which resulted in a failure to meet TS

Surveillance Requirement 4.3.1.1.2. Review of this issue is ongoing by

, the NRC and licensee, and thus this issue will be identified as  !

unresolved item URI 50-328/97 01-02.

During the review of the associated TS surveillances, the inspectors

noted references to previous Westinghouse letters, one dated October 27,

1987, and one dated November 16, 1979. Both letters discussed

" undetectable failures which could exist in.the engineered safety

features actuation system." The 1987 letter noted there was a potential

for an unreviewed safety It also stated that in the case of

an " undetectable failure" question.

. Institute of Electrical and Electronics

Engineers (IEEE) 379 Application of the Single Failure Criterion to

Nuclear Power Generating Station Class 1E Systems, was applicable and

required a test scheme to identify the failure or to redesign the system i

to eliminate the failure.

In the response to the 1979 letter Sequoyah developed procedural

guidance to test the P-4 contacts for the main feedwater isolation

actuation circuitry. In the response to the 1987 letter, Sequoyah did

not adequately develop procedural guidance to test the P 4 contacts for

the turbine trip actuation circuitry.

The inspectors noted that 1, 2 PI-IFT 099 0P4.0, Verification of P4

Interlock Input To SSPS, implemented the required testing for the 1979  ;

Westinghouse letter. Section 1.1, Perpose, stated the following, "This

Instruction is performed to verify the operability of the Reactor Trip

Breaker P 4 contacts. This Instruction satisfies tha commitment

concerning the 1979 Westinghouse letter which requires testing the P-4

contact status following reactor trip breaker operation. This

Instruction can be performed in any mode and must be performed after a

reactor trip, after a breaker closure prior to startup, or whenever a

trip breaker is operated and the Safety Injection System is operable."

The inspectors noted that this procedure verified that the P-4 contact,

for main feedwater isolation, was in the appropriate position when the

reactor trip breaker was opened and closed.

Following maintenance activities'on the Unit 2 "A" reactor trip breaker

on August 29. and the "B" reactor trip breaker on September 19, 1996,

2-PI IFT-099 0P4.0 was not performed. Instead, TS surveillance

requirement procedure 2-SI 90.82, Reactor Trip Instrumentation Monthly

Functional Test (SSPS), was performed. On September 19, the performance

of 2 SI 90.82 did not identify the inoperable P 4 contactor and the "B"

reactor trip breaker was placed in service and subsequently exceeded the

allowable TS Limiting Condition of Operation (see IR 9613 for details

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

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and enforcement). A review of 2-SI-90.82 noted that it did not fully  !

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implement the requirements of 2-PI-IFT-099-0P.0 in that 2-SI 90.82 only

verified the P 4 contact with the reactor trip breaker closed. The

,

!

surveillance instruction (SI) failed to check the status of the P-4

i contact with the reactor trip breaker open. This check would have

identified the failed P 4 contactor.

)

"

The inspectors determined that the Unit I reactor trip breakers were

adequately tested because the 18 month surveillance was completed during

an outage, procedures ctllectively tested all components, and

replacement was not done online.

.

The inspectors noted the licensee did not fully implement the guidance ,

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from the 1979 Westinghouse letter into 1 SI 90.8 and 2-SI-90.82 and the  :

licensee did not adequately implement the guidance from the 1987

< Westinghouse letter for the turbine trip circuitry. When online

4

replacement of breakers was conducted, it may have resulted in the

licensee not meeting the requirements in Institute of Electrical and

Electronics Engineers Standard 379 for single failure criteria with an

undetectable failure. The failure to fully im)lement the

'

recommendations from the 1979 and 1987 Westinglouse letters is

identified as unresolved item URI 50-327, 328/97 01-04.

d  :

, Based in part on the identification of the above issues, the licensee l

conducted extent of condition reviews. On January 25, 1997, the '

licensee determined that surveillance testing of the emergency diesel l

generator start-timer relays, which are contained in the start logic

circuitry, was not being performed as required by TS. TS require two

channels per shutdown board to be demonstrated operable. Surveillance

instruction reviews, which were being performed in accordance with

Generic Letter (GL) 96 01, found that only one channel was being tested.  ;

Licensee reviews determined that redundant timer relays installed in i

parallel for each of the functions of degraded voltage, safety

injection / degraded voltage, and loss of voltage were not overlap tested.

When the deficient surveillance condition was identified, the '

appropriate LC0 action was entered, the sis were revised, and the

testing of the timer relays was performed. The testing determined that

each channel and circuit was acceptable. This event was documented in

LER 50 327/97001. On March 5, 1997, the licensee determined that

surveillance testing of all portions of the VCT to RWST swapover logic

circuitry were not being performed as required by TS. This was

identified as a result of the licensee *s GL 96 01 review. The licensee i

determined they had not independently demonstrated that either LCV 62-

135 or LCV-62-136 (two parallel valves, RWST to CCPs) going fully ,

opened, would close contacts that would allow both LCV-62132 and LCV-  !62-133 (two valves in series, VCT to CCPs) to close. On March 5, the ,

licensee successfully performed STI 155, Chemical Volume and Control l

System Interlock Safety Function Demonstration, Revision 0, and I

determined the circuit logic was operable. This issue was documented in

PER No. SQ970442PER, and will be reported in an LER. j

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25

c. Conclusions

The licensee failed to adequately test the reactor trip breaker P-4

circuitry, which resulted in multiple failures to meet the surveillance

requirements of Technical Specification 4.3.1.1.2. Pending additional

review, this item is identified as an unresolved item.

The licensee failed to implement vendor recommendations and implement

adequate corrective actions for a significant deficiency. Pending

additional review, this item is identified as an unresolved item.

M8 Miscellaneous Maintenance Issues (92902)

M8.1 (Closed) Violation 50-327. 328/96 11-03. Failure to Inst 91 Temocrary

Missile Protection for ERCW Pioina as Reauired by SSP 7.4. The

inspector verified the corrective actions described in the licensee's

response letter, dated December 19, 1996, to be reasonable and complete.

No similar problems were identified.

M8.2 (Closed) Violation 50-327/96 08-02. Failure to Establish Measures to

Assure that Conditions Adverse to Quality Are Promptly Identified.

Corrected and Reported to the Acoropriate Levels of Management. The

inspector verified that corrective actions described in the licensee's

response letter, dated Se)tember 18, 1996, to be reasonable and

complete. No similar proalems were identified. ,

1

M8.3 (Closed) Violation 50 327. 328/93-53-01. A Violation of Technical

Specification 6.8.1 for Failure to Follow Procedures with Multiole

Examoles. During observation of routine licensee activities the

inspectors had identified several examples of the licensee's failure to

follow established procedJres. Examples identified included failure to

remove flammable materiale near hot work areas, improper erection of

scaffolds, and use of non terified vendor drawings.

The inspectors reviewed the licensee's response to the violation and

determined that corrective actions were adequate to address the problems

identified in the violation. Modifications personnel and fire watch

personnel associated with welding, grinding and other hot work

activities were counseled concerning the event. The inspectors reviewed

training attendance records for modifications standdown meetings which

provided additional training to modifications personnel on hot work, '

fire protection and scaffolding erection requirements along with records

to support completion of training on proper use of vendor manual

drawings for maintenance and engineering personnel. Site Procedure,

SSP 2.10. Vendor Manual Control, was revised to include a requirement to

stamp all vendor drawings in vendor manuals to inform personnel that all

drawings be approved before use. The inspectors determined that

corrective actions appeared adequate to preclude recurrence of the

problems described in the violation. This item was closed. j

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III. Enaineerina

E2 Engineering Support of Facilities and Equipment

E2.1 Review of American Society of Mechanical Enaineers (ASME)Section XI

Valve Strokina Documentation

a. Insoection Scope (37551)

ASME Section XI 1989 OMa Part 10, 1988, Inservice Testing of Valves in

Light Water Reactor Power Plants, provides that when valves with

measured stroke times do not meet acceptance criteria, that the valves

shall be immediately retested or declared inoperable. The cause of the

initial deviation shall be analyzed and the results documented in the

record of the tests. The inspector verified that the licensee was

analyzing and documenting those instances when Section XI valves were

stroked more than once during the same surveillance in order to meet

stoke time acceptance criteria.

b. Observations and Findinas

The inspector, through a review of control room log entries, identified

several examples where valves were stroke timed more than once during

Section XI valve testing. The inspector then examined the surveillance

instruction associated with each of the examples and verified that each

stroke time had been recorded and that an analysis had been performed

when acceptance criteria was not initially met. The inspe:: tor also

verified that the Section XI system engineer was tracking the stroke-

times of each of the valves, including those instances when a valve was

stoked more than once during the same surveillance.

c. Conclusions

The inspector determined that the licensee'sSection XI Valve Testing

Program documented and analyzed those instances where valves were

stroked more than once in order to meet stroke time acceptance criteria.

Continued rwiew as to the adequacy of the evaluations in ongoing.

E2.2 Essential Raw Coolina Water (ERCW) Freeze Protection

a. Inspection Scope (37551)

The inspectors reviewed the licensee's corrective action related to ERCW

heat tracing.

b. Observations and Findinas

In February 1996, the licensee initiated PER No. SQ960210PER to address

several identified deficiencies with the freeze protection program. The

PER recommended corrective actions to address those issues. Early in

1997, the inspectors documented in IR 9617 that uncorrected problems

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27

continued to exist with ERCW heat tracing. IR 96-17 identified a

weakness to expedite resolution of ERCW heat trace deficiencies, a

weakness for nuclear engineering to respond to an overdue freeze

protection program corrective action item, and a weakness in the ERCW

freeze protection compensatory actions. Inspection Reports 96 01 and

96 04 also discussed problems related to ERCW heat tracing. i

On January 14, 1997, the licensee's Nuclear Assurance organization )

escalated PER No. SQ960210PER to the Maintenance and Modifications l

Manager. The Escalation Report, a formal process to escalate i

items / issues to the level of management necessary to achieve corrective '

action, stated that the actions identified in the corrective action plan

had not been timely and did not address / resolve long standing issues

with freeze protection. The licensee initiated an extent of condition

investigation of the freeze protection program as a result of tne

escalated PER.

On February 3,1997, the licensee initiated KR No. SQ970251PER, a level

A PER, when the freeze protection system engineer identified that the

FRCW heat tracing system had experienced five functional failures within

a 24 month period which elevated the ERCW heat tracing system into

category (a)(1) of the maintenance rule (10 CFR 50.65). PER No.

SQ970251PER also noted that the licensee conducted a walkdown of the

ERCW heat trace system on January 28, 1997. Several deficiencies were l

observed during the walkdown regarding incorrectly installed ERCW heat l

tracing. The PER recommended both short term and long tern corrective j

actions to address the problems.

On February 24, 1997, the inspector discussed the status of the freeze

protection program with the Mainterr.ce Manager and the team leader of

the freeze protection investigation team. On February 26, 1997, at the

bi-monthly NRC/Sequoyah management meeting held at the Sequoyah Training

Center, the licensee stated that deficiencies in the freeze protection

program would be corrected prior to the winter of 1997/1998.

c. Conclusions

The inspector concluded the licensee is taking appropriate steps to

address long standing problems related to the freeze protection program.

IFI 50 327, 328/96 04-13. Weak Freeze Protection Program, will remain

open pending satisfactory implementation of the licensee's corrective

action plan.

E8 Miscellaneous Engineering Issues (92903)

E8.1 (Closed) Followuo Item 50 327. 328/96 08 05. Review Amendment 12 to

UFSAR Recardina Spent Fuel Pit EvcDoration Rce and Rerack Pro.iect. The

inspector. verified that Section 9.1.3.3 of Amendment 12 to the Updated

Final Safety Analysis Report (UFSAR). dated December 6,1996, reflected

the new SFP rate of evaporation of 103 gallons per minute. Amendment 12

also reflected numerous changes to the UFSAR as a result of the recent

. _ . . _ _ _ __ __ _ _ . _ _ . _ . _ . . _ _ _ _ __ __

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SFP rerack project. Those changes appeared to correctly describe the

SFP as a result of changes made during the rerack project.

E8.2 (00en) Followup Item 50 327. 328/96 02 02. Review Corrective Actions of I

PER No. S0960759PER Recardina CCS Surae Tank Overflow. Technical

. Support was assigned a corrective action item to prepare and submit

design issues to address the Component Cooling System (CCS) surge tanks

i vent piping arrangement and the dry reference leg level indicators. The

Plant Issues Committee (PIC) subsequently approved two issues submitted i

by Technical Su) port which recommended routing a discharge pipe from the '

! vent valve to tie space below the CCS surge tanks and replacing the dry

4

reference legs with wet reference leg level indicators. The licensee

has not established an implementation date for the modifications. This

"

, will remain open pending additional review. l

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R8 Miscellaneous Radiological Protection and Chemistry Issues

l R8.1 Inspection Scope (71750)

' i

During tours of the plant, the inspectors checked a selected sample of

doors required to be locked for the purposes of radiation protection:

checked whether workers, supervisors, and radiation protection personnel

were following the licensee's procedures for radiation protection, and

whether housekeeping in the plant was adequate.

b. Observations and Conclusions

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The inspectors' walkdowns determined: doors required to be locked for  :

the purposes of radiation protection were locked: workers, supervisors, l

and radiation protection personnel were following the licensee's

'

procedures for radiation protection, and housekeeping in the plant was

adequate. No deficiencies were noted.

V. Manaaement Meetinas

X1 Exit Meeting Sununary

,

The inspectors ) resented the inspection results to members of licensee

management at t1e conclusion of the inspection on March 7,1997. The

licensee acknowledged the findings presented. '

The inspectors asked the licensee whether any materials would be

considered proprietary. No proprietary information was identified.

4

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PARTIAL LIST OF PERSONS C0KTACTED i

Licensee

• Adney, R., Site Vice President j

Beasley, J., Acting Site Quality Manager

Bryant, L.. Outage Manager  !

'

Driscoll D., Training Manager l

4 *Fecht, M., Nuclear Assurance & Licensing Manager '

<

Fink, F., Business and Work Performance Manager

• Flippo. T., Site Support Manager

• Herron, J., Plant Manager

'

• Kent, C., Radcon/ Chemistry Manager

• Lagergren, B., Operations Manager

• Rausch, R. Maintenance and Modifications Manager

Reynolds, J., Operations Superintendent

Rupert, J., Engineering and Support Services Manager

• Shell, R , Manager of Licensing and Industry Affairs

Skarzinski, M., Technical Support Manager

Smith, J., Licensing Supervisor ,

Summy, J., Assistant Plant Manager o

Symonds, J., Modifications Manager

• Valente, J , Engineering & Materials Manager

• Attended exit interview

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering .

IP 40500: Effectiveness of Licensee Controls In Identifying, Resolving, & l

Preventing Problems )

IP 61726: Surveillance Observations

IP 62700: Maintenance Implementation

IP 62706: Maintenance Rule  !

IP 62707: Maintenance Observations l

IP 71707: Plant Operations  !

IP 71750: Plant Support Activities

IP 92902: Followup - Maintenance

IP 92903: Followup Engineering '

!

ITEMS OPENED. CLOSED. AND DISCUSSED

Opened

'

Type Item Number Status Descriotion and Reference

VIO 50 327, 328/97-01 01 Open Failure to Maintain Adequate  ;

Emergency Diesel Generator Alarm i

Response Procedures (Section 02.2).

.._h,, .sl. k*4 ,4 __g_.Js .IJ m a _ e -

- J_,. , 4 w a au_ s_ - 4 _.__.4a =mA.m 4_ a.: W. 4_ ,

.

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URI 50 328/97 01 02 Open Review Adequacy of Testing the

Reactor Trip Breaker P 4 Function

(Section M4.1).

IFI 50-327, 328/97-01-03 Open Review the Process of Using

Installation Dates Versus

Calibration Dates to Meet

Surveillance Start Dates (Section

M4.1).

URI 50-327, 328/97-01 04 Open Review Implementation of

Recommendations from the 1979 and

1987 Westinghouse Letters Regarding

Reactor Trip Breaker Testing

(Section M4.1).

IFI 50 328/97 01 05 Open Review Root Cause which led to N0ED

on EDG (Section 02.3).

Closed

Tygg Item Number Status Descriotion and Reference

VIO 50-327, 328/96-04 02 Closed Failure to Maintain the Adequacy of

Procedures 2 SI 0PS-082 26.A and 2-

SI IRT 099 699 A and Failure to

follow the Requirements of Procedure  ;

2-PI 0PS-000 038.1 (Section 08.2). l

VIO 50 327, 328/96 11 03 Closed Failure to Install Tem rary Missile

Protection for ERCW Pi ing as

Required by SSP 7.4 (S ction M8.1).

VIO 50-327/96 08 02 Closed Failure to Establish Measures to

Assure that Conditions Adverse to

Quality Are Promptly Identified,

Corrected and Reported to the

Appropriate Levels of Management 4

(Section M8.2). ]

VIO 50-327, 328/93-54 01 Closed A Violation of TS 6.8.1 for Failure

to Follow Procedures with Multiple

Examples (Section M8.3).

IFI 50 327, 328/96-08 05 Closed Review Amendment 12 to UFSAR

Regarding Spent fuel Pit Evaporation

Rate and Rerack Project (Section

E8.1).

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The following escalated enforcement items (EEI) were reviewed as part of an

enforcement conference with the licensee on December 16, 1996. Subsequent

i enforcement was taken on a number of the issues. Based on the enforcement

conference and violations issued on December 24, 1996, the Eels listed below

I

are closed. Followup of licensee corrective actions for the violations

documented in the December 24, 1996, enforcement action will be conducted as

part of the violation closecut. EEI 50 327, 328/96 13-02, Enforcement Action

(EA) No.96-414, Failure To Implement Adequate Corrective Actions To Prevent

Repetitive Damage To The Main Feed Water Isolation Valve (MFIV) Flexible

Conduits, was reviewed as part of the enforcement issued December 24, 1996,

and determined to not be a violation.

Type Item Number

_ Status Description and Reference

EEI 50 327, 328/96 13-01 Closed Failure To Correct Repetitive

EA. No. 96 414 Problems (Water Intrusion) With The

MFIV #4 MOV Brake Assembly.

EEI 50 327, 328/96-13 02 Closed Failure To Implement Adequate

, EA. No. 96 414 Corrective Actions To Prevent  !

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Repetitive Damage To The MFIV l

Flexible Conduits  !

l

EEI 50 32/, 328/96 13 03 Closed Failure To Implement Adecuate  !

EA. No. 96 414 Corrective Actions To Adcress ASCO <

Solenoid Valve Elastomer Aging l

EEI 50-327, 328/96 13 05 Closed Failure To Perform An Adequate

l EA. No. 96 414 Extent Of Condition Review Required

! By SSP-3.4 For Deluge Event Which l

Resulted In The Impulse Pressure -

Switch Failures. l

l EEI 50 327, 328/96 13-07 Closed Failure To Follow TS 3.3.1.22.G.

l EA. No. 96 414 Action 14. 1

EEI 50-327, 328/96-13 08 Closed Failure To Follow Procedure

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EA. No. 96 414 mil 0.9.1 And Failure To Provide An

Adequate MI-10.9.1 Procedure.

EEI 50 327, 328/96 13-09 Closed Failure To Perform

EA. No.96-414 An Operability /Reportability

Determination

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

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Discussed

IY2e Item Number Status Description and Reference i

l

IFI- 50-327. 328/96 04-13 Open Weak Freeze Protection Program  !

(Section E2.2).  ;

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IFI 50 327, 328/96 02 02 Open Review Corrective Actions of PER No.

SQ960759PER Regarding CCS Surge Tank

Overflow (Section E8.2).

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