ML17164A956

Insp Repts 50-387/98-12 & 50-388/98-12 on 981124-990104. Violations Noted.Major Areas Inspected:Aspects of PP&L Operations,Maint,Engineering & Plant Support at SSES

ML17164A956
Person / Time
Site:	Susquehanna
Issue date:	01/26/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17164A954	List: ML17164A953 ML17164A955 ML17164A956
References
50-387-98-12, 50-388-98-12, NUDOCS 9902090347
Download: ML17164A956 (29)

See also: IR 05000387/1998012

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos:

License Nos:

50-387, 50-388

NPF-14, NPF-22

Report No.

50-387/98-1 2, 50-388/98-1 2

Licensee:

Pennsylvania Power and Light Company

2 North Ninth Street

Allentown, Pennsylvania

19101

Facility:

Susquehanna

Steam Electric Station

Location:

P.O. Box 35

Berwick, PA 18603-0035

Dates:

November 24, 1998 through January 4, 1999

Inspectors:

S. Hansell, Senior Resident Inspector

J. Richmond, Resident Inspector

A. Blarney, Resident Inspector

Approved by:

Clifford Anderson, Chief

Projects Branch 4

Division of Reactor Projects

9902090347 990i26

PDR

ADOCK 05000387

8

POR

EXECUTIVE SUMMARY

Susquehanna

Steam Electric Station (SSES), Units

1 5, 2

NRC Inspection Report 50-387/98-12, 50-388/98-12

This inspection included aspects of Pennsylvania Power and Light Company's (PPSL's)

operations, maintenance,

engineering,

and plant support at SSES.

The report covers a six-

week period of resident inspection.

~Oerations

The operator response to a Unit 1 loss of main condenser offgas system was

excellent.

Timely restoration of the offgas equipment by nuclear plant operators

enabled plant control operators to stabilize the plant in a safe condition.

(Section

01.1)

During a planned plant process computer outage, PPRL removed one of the two

methods being utilized to monitor suppression

pool average water temperature

and

disabled the initial suppression

pool water high temperature control room overhead

annunciator.

PPRL did not recognize that Unit 2 had entered

two limiting

conditions for operations.

This resulted in a violation of minor significance because

suppression

pool bulk temperature

did not exceed 90

F.

(Section 04.1)

In December 1998,'PPRL incorrectly implemented

a complex residual heat removal

service water system Technical Specification Interpretation (TSI). Previous to this

event in October, 1998, PP8cL did not implement this TSI due to a lack of a

reference to the TSI.

In both instances

PPSL returned the equipment to an operable

status within the required time limit specified in the TSI.

PP&L corrective actions

include planned revisions to the TSI and ultimately removal of all TSls.

(Section

03.1)

PPSL identified that channel functional surveillance tests of the source range

monitors did not include the indication portion of the channels

as acceptance

criteria, as required by Technical Specifications.

PPRL's proposed

and completed

corrective actions, including procedure and programmatic actions, were good.

This

non-repetitive, licensee identified and corrected violation is being treated as a non-

cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.

LER

50-387/388/98-017

is closed.

(Section 08.1)

Maintenance

~

Management's

decision to stroke the Unit 1 outboard main steam isolation valve

(MSIV), prior to the required surveillance test, was proactive and resolved a

potential safety problem that could have resulted in a higher than expected pressure

increase during a postulated MSIV closure event.

(Section M1.1)

Executive Summary (cont'd)

The Unit 2 high pressure coolant injection (HPCI) system outage was well planned

and executed.

The pump and turbine equipment areas were maintained as clean

areas which resulted in an excellent work environment.

Excellent coordination of

the HPCI post maintenance test minimized the heat addition to the suppression

pool.

(Section M1.1)

~

.

Instrumentation and control technicians promptly reported an activity that led to the

foreign material addition to the Unit 2 standby liquid control (SLC) tank.

The

technicians, actions were representative of a good safety culture to report work

activity problems.

The shift supervisor's continuous operability assessment

led to

the appropriate SLC pump operability determination and the timely removal of all

foreign material from the SLC tank.

(Section M1.1)

Encnineering

~

PPSL failed to adequately translate the system design, from a modification, into

appropriate specifications, drawings, and procedures,

and on two separate

occasions substituted gasket material without a review for suitability of materials.

The inspectors determined this was an apparent violation of 10 CFR 50 Appendix B,

Criterion III, Design Control. PP5L's initial corrective actions were good.

However,

the proposed final corrective actions, which appeared

reasonable to correct'the

original condition, were not performed in a timely manner.

In addition, PPSL failed

to recognize that SSES design control requirements

had not been followed, when a

different type gasket was installed in the plant.

URI 50-387,388/98-06-03

is

closed. (Section. E8.2)

~

System and maintenance

engineers provided good outage support at the high

pressure coolant injection (HPCI) jobsite.

Also, the HPCI system engineer monitored

the post maintenance

surveillance test and provided timely feedback to the operator

performing the test.

(Section M1.1)

Plant Su

ort

~

The security computer replacement,

in the Security Control Center, was well

controlled and completed with minimal interruptions to the normal plant access

. areas.

A significant improvement was noted for the plant accountability capabilities.

(Section S2)

TABLE OF CONTENTS

EXECUTIVE SUMMARY

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II

TABLE OF CONTENTS

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IV

Summary of Plant Status

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I. Operations

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03

04

08

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Conduct of Operations

01.1

Unit Operations and Operator Activities

01.2

Operational Safety System Alignment

Operations Procedures

and Documentation .............

03.1

Technical Specification Operability Determinations...

Operator Knowledge and Performance

04.1

Suppression

Pool Bulk Water Temperature Monitoring

Miscellaneous Operations Issues

08.1

Licensee Event Report Review ~"................

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I. Maintenance

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M1

Conduct of Maintenance......

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M1.1

Surveillance and Pre-Planned

Maintenance ActivityReview

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III. Engineering .. ~...........................

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Miscellaneous Engineering Issues

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E8.1

Followup of Open Items

E8.2

"A" Emergency Diesel Generator Inoperable due to Heavy Rains ... 9

IV. Plant Support ............

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Status of Security Facilities and Equipment

V. Management Meetings

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Exit Meeting Summary

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1 1

ATTACHMENTS

Attachment

1 - Inspection Procedures

Used

- Items Opened, Closed, and Discussed

- List of Acronyms Used

Re ort Details

Summar

of Plant Status

Susquehanna

Steam Electric Station (SSES) Unit 1 maintained 100% power throughout the

inspection. period, except for the following power reductions.

On November 27, 1998,

power was reduced to 90% for approximately one hour due to electrical grid minimum load

considerations.

On December 11, power was reduced to 72% due to a load center

electrical breaker trip that resulted in an isolation of the main condenser offgas system.

On

December 13, 1998, reactor power was raised to 100% after restoration of the load center

trip and a completion of a control rod pattern sequence

exchange.

The unit remained at

100% for the rest of the inspection-period;

SSES Unit 2 maintained 100% power throughout the inspection period, except for the one

power reduction to 90% for approximately one hour due to electrical grid minimum. load

considerations

on November 27, 1998.

01

Conduct of Operations

'1.1

Unit 0 erations and 0 erator Activities

a.

Ins ection Sco

e 71707

Routine operations activities of plant control operators

(PCOs), nuclear plant

operators

(NPOs), unit supervisors

(USs), and shift supervisors

(SSs) were observed.

b.

Observations

and Findin s

The operator response to a Unit 1 loss of main condenser offgas system was

excellent.

The loss of the offgas system was due to a 480 Volt load center

electrical breaker trip related to the spurious trip of the breaker overcurrent

protection unit. Timely restoration of the offgas equipment by nuclear plant

operators enabled plant control operators to stabilize the plant at 72% reactor

power. After transfer of electrical loads to a backup power supply and completion

of additional planned activities, operators raised reactor power back to 100%.

The inspectors determined routine operator activities were adequately prescribed,

communicated,

and conservatively performed in accordance with SSES operations

department procedures.

Shift turnovers were observed to be detailed and complete.

The inspectors discussed plant conditions with PCOs and USs following shift

turnovers and observed sufficient information and status were transferred to the

oncoming shift to ensure the safe operation of the units.

The licensee was

I

'Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline.

Individual reports are not expected to address all outline topics.

observed to conduct plant operations in accordance with procedures,

and effective

controls were implemented for safe plant operation.

C.

Conclusions

The operator response to a Unit 1 loss of main condenser offgas system was

excellent.

Timely restoration of the offgas equipment by nuclear plant operators

enabled plant control operators to stabilize the plant in a safe condition.

01.2

0 erational Safet

S stem Ali nment

(71707)

During plant tours, the alignment and operability of selected safety systems,

engineered safety features,

and on-site power sources were verified. A partial

walkdown of the following systems was performed:

Unit 2 Standby Liquid Control System

Unit Common Standby Gas Treatment System (SGTS)

Unit 1 Engineered Safety Features Instrument Racks

Emergency Service Water

Residual Heat Removal Service Water

Spent Fuel Pool Cooling Water

Reactor Water Cleanup (RWCU)

Overall equipment operability, material condition, and housekeeping

conditions were

good.

The inspectors identified several minor housekeeping

and material condition

items, including=seismically unrestrained equipment (used for charcoal filter

maintenance)

stored on top of the SGTS filter trains.

The items did not affect

system operability and were resolved satisfactorily.

03

Operations Procedures

and Documentation

03.1

Technical S ecification 0 erabilit

Determinations (71707,40500)

On October 27, 1998, the NRC identified that PP&L had inappropriately entered

a

30 day Limiting Condition for Operation (LCO) for planned maintenance

on the "1A"

residual heat removal service water (RHRSW) pump in accordance with technical

specification (TS) section 3.7.1.

TSs allow a 30 day LCO with one RHRSW

subsystem

inoperable.

Technical Specification Interpretation (TSI) 1-97-007,

reduces the LCO to 7 days because

TSs do not account for potential failures within

the RHRSW subsystem flow paths.

The Unit Supervisor (US) did not review the TSI

prior to implementing the LCO. PPRL exited the LCO within the required seven

days, as delineated by the TSI; initiated condition report (CR) 76161; and improved

the references to active TSls in the applicable TS sections.

This issue was

previously documented

in IR 50-387/98-11, 50-388/98-11.

On December 29, 1998, the NRC identified that PPSL had inappropriately entered

a

30 day LCO for planned maintenance

on the "2A" RHRSW pump in accordance with

TS section 3.7.1, instead of 'the 7 days allowed by TSI 2-97-007.

The US correctly

identified that TSI 1-.97-007 was applicable; however, due to the complexity of this

TSI, the US incorrectly interpreted the TSI.

PP&L exited the LCO within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,

initiated CR 87503, and plans to simplify the TSI.

In conclusion, in December 1998, PP&L incorrectly implemented

a complex residual

heat removal system Technical Specification Interpretation (TSI). Previous to this

event, in October, 1998, PP&L did not implement this TSI, due to a lack of a

reference to the TSI.

In both instances,

PP&L returned the equipment to an

operable status within the required time limit specified in the TSI.

PP&L corrective

actions include planned revisions to the TSI and, ultimately, removal of all TSls.

04

Operator Knowledge and Performance

04.1

Su

ression Pool Bulk Water Tem erature Monitorin

Ins ection Sco

e 71707

40500

The inspectors reviewed PP&L's method of monitoring suppression

pool average

temperature during a planned plant process computer (PICSY)'outage.

b.

Observations

and Findin s

On December 15, 1998, at 5:55 a.m., SSfS Unit 2 removed the PICSY computer

from service for planned maintenance.

This action removed one of two methods

being utilized to monitor suppression

pool average temperature

and disabled the

initial suppression

pool water high temperature control room overhead annunciator.

Suppression'Pool

Average Water Temperature Monitoring Requirements

TS 3.6.2.1 Suppression

Pool Average Water Temperature,

requires suppression

pool

average temperature to be verified less than 90'

once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during

normal operation.

If suppression

pool temperature

exceeds 90', TS 3.6.2.1.A.1

requires the average temperature to be verified less than 110'

hourly. Hourly is

considered

an adequate frequency due to redundant indication and alarms available

to alert the operator to abnormal suppression

pool average temperature conditions.

TS allows three methods for monitoring the suppression

pool average water

temperature.

The methods are (a) Suppression

Pool Temperature Monitoring

System (SPOTMOS), (b) plant process computer system (PICSY) calculation, or (c)

manual calculation, if there is no testing or transient that is adding heat to the

suppression

pool ~

When PP&L removed the PICSY computer from service on December 15, 1998,

SPOTMOS was the only real time indication of suppression

pool average water

temperature.

SPOTMOS indicated 99'

which was greater than the 84'

indicated by the PICSY computer prior to removing the PICSY computer from

service.

The SPOTMOS high temperature indication required the PCOs to monitor

suppression

pool average water temperature hourly, until the temperature was

reduced to less than 90'

(TS 3.6.2.1.A.1).

The Unit 2 US and PCOs did not

monitor the suppression

pool average temperature hourly nor did they perform a

manual calculation.

The inspectors discussed this issue with the Unit 2 US and

PCOs and at 8:40 a.m. operations completed

a manual calculation, allowed by TSs

and confirmed that suppression

pool average bulk water temperature was less than

90'. This calculation was completed in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 45 minutes after the PICSY

computer was removed from service, which exceeded the hourly monitoring

requirements of TS 3.6.2.1.A.1.

Because the suppression

pool average bulk water

temperature

did not exceed 90', this failure constituted

a violation of minor

significance and is not subject to formal enforcement action.

Suppression

Pool First Level High Water Temperature Alarm

The TRM section 3.6.3, Suppression

Pool Alarm Instrumentation, requires that four

levels of alarms be operable to monitor suppression

pool water temperature.

If any

of the alarms becorn'e inoperable TRM 3.6.2.A.1 requires the alarm to be restored in

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The PICSY computer provides the process input for the suppression

pool

first level high water temperature

alarm.

When the PICSY computer was removed

from service the first level alarm became inoperable.

This further degraded

information available to alert the operators of abnormal suppression

pool

temperature conditions.

The Unit 2 US did not identify and document this LCO.

However, this alarm was restored within the allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

C.

Conclusions

During a planned plant process computer outage, PPKL removed one of the two

methods being utilized to monitor suppression

pool average water temperature

and

disabled the initial suppression

pool water high temperature control room overhead

annunciator.

PPRL did not recognize that Unit 2 had entered

two limiting

conditions for operations.

This resulted in a violation of minor significance because

suppression

pool bulk temperature

did not exceed 90 'F.

08

Miscellaneous Operations Issues

08.1

Licensee Event Re ort Review (71707,92700)

CLOSED

LER 50-388 98-009-00

Unit 2 "A" Moisture Se arator Drain Tank Hi h-Hi h Level Scram

On June 29, 1998, Unit 2 was conducting

a plant startup with reactor power at

55% power.

An unexpected

actual "A" moisture separator drain tank high-high

level was sensed

by four instruments in three independent instrument loops.

This

resulted in a main turbine trip and a subsequent

reactor scram.

Prior to the Unit 2

restart, the inspectors reviewed the preliminary root cause investigation, initial

corrective actions taken, condition reports and plant status.

The inspectors in field

review verified that the deficiencies were corrected, and General Operating (GO)

procedure GO-100/200-002 was revised to maintain the steam crossover pipe

drains open until 30% reactor power.

No violations of NRC requirements were

identified. This LER is closed.

Closed

LER 50-387 98-017-00 and LER 50-387 98-017-01

Incomplete Channel Functional Test of Source Range Monitor Channels

PP&L identified that channel functional surveillance testing of the source range

monitors (SRMs) did not include the channel indication acceptance

criteria, as

required by Technical Specifications (TSs).

The condition had existed since initial

plant operation, approximately 15 years.

Based on an in-field review of the issues reported in the licensee event report (LER),

TS, surveillance procedures,

and associated

corrective actions, the inspectors

confirmed that PP&L failed to adequately perform channel functional surveillance

testing of the SRMs, as required by TSs.

Although the SRM channel functional

surveillance tests, performed over an extended period, did not include test

acceptance

criteria for SRM indication, this did not represent

a repetitive condition,

because

it resulted from a single failure to originally establish an adequate

surveillance procedure.

Failure'to perform a channel functional surveillance testing

of the SRMs was of minor safety significance since periodic calibration of the SRMs

performed the same test.

The inspectors determined that PP&L properly identified

and reported this issue, and found PP&L's proposed and completed corrective

actions to be good.

In conclusion, in a Licensee Event Report, PP&L identified that channel functional

surveillance tests of the source range monitors did not include the indication portion

of the channels

as acceptance

criteria, as required by Technical Specifications.

PP&L's proposed and completed corrective actions, including procedure and

programmatic actions, were good.

This non-repetitive, licensee identified and

corrected violation is being treated as a non-cited violation, consistent with Section

VII.B.1 of the NRC Enforcement Policy. This LER is closed.

(NCV 50-387/98-12-

01)

II. Maintenance

M1

Conduct of Maintenance

M1.1

Surveillance and Pre-Planned

Maintenance Activit Review

a.

Ins ection Sco

e 61726 62707

The inspectors observed and reviewed selected portions of pre-planned maintenance

and surveillance activities, to determine whether the activities were conducted

in

accordance with NRC requirements

and SSES procedures.

Observations

and Findin s

Based on the indicated sample of safety related work authorizations and

surveillances, the inspectors found pre-planned maintenance

and surveillance

activities were appropriately conducted and controlled.

The sample included:

Work Authorizations

V82396

V82398

U86624

U66631

S83786

A83521

V82435

IS.C Support for Unit 2 Standby Liquid Control (SLC) Maintenance

Unit 2 SLC Storage Tank Foreign Material Removal

Post Modification Test for Reactor Water Cleanup (RWCU) Vibration

Alarm Removal (DCP 98-9005)

Post Modification Test for Rod Drift Memory Card (DCP 95-9053)

"1B" RHRSW Pump Overhaul

"B" Emergency Diesel Generator Fuel Oil Storage Tank Clean 5

Inspect

ISC Support for the Quarterly Turbine Valve Testing

Surveillances

SO-030-001

SO-030-003

SO-104-001

SO-21 6-003

SO-252-002

SO-293-001

SR-255-004

SO-256-001

TP-024-1 60

CREOASS Monthly Performance Test

Quarterly Control Structure Chilled Water Flow Verification

Monthly Bus 1A201, 1A202, 1A203, 1A204 and OB565 Degraded

Voltage Channel Functional Test

Quarterly RHRSW Flow Verification

Quarterly HPCI Flow Verification

Quarterly Turbine Valve Cycling

Unit 2 Scram Time Testing for Control Rod 30-03

Weekly Control Rod Exercising

"E" Diesel Generator Emergency Test

In addition, selected portions of procedures,

drawings, and vendor technical

manuals, associated with the maintenance

and surveillance activities, were also

reviewed and determined to be acceptable.

In general, maintenance

personnel were

very knowledgeable of their assigned

activities.'B"

Outboard Main Steam Isolation Valve (MSIV) Repair

The previous surveillance test (ST) for the "B" outboard MSIV, HV141F028B, noted

that the stroke time was shorter than previous trend data but within the Technical

Specification (TS) limits of 3 to 5 seconds.

Plant management

made a decision to

stroke the valve before the required quarterly surveillance due to the trend.

During a planned power reduction on December 12, 1998, the valve was tested and

stroked closed in 1.63 seconds.

Operations declared the valve inoperable and

entered the applicable TS limiting condition for operation (LCO). The maintenance

crew found and repaired the cause of the fast stroke time, a leaking oil plug on the

valve dashpot.

After the completed repairs, the valve was stroked close in 4.31

seconds

and declared operable.

Management's

decision to stroke the MSIV, prior to

the required ST, was proactive and resolved

a problem that could have resulted in a

higher than expected pressure

increase during a postulated MSIV closure event.

High Pressure

Coolant Injection (HPCI) System Outage

The Unit 2 high pressure, coolant injection (HPCI) system outage was well planned

and executed.

Maintenance worker performance and knowledge of the HPCI

system corrective and preventive maintenance tasks were good.

The pump and

turbine equipment areas were maintained as clean areas which resulted in an

excellent work environment.

System and component engineers were present at the

jobsite to provide support as needed.

Prior to the HPCI flow test surveillance, the unit supervisor (US) led a detailed pre-

evolution briefing to ensure the post maintenance testing (PMT) was completed as

required.

The briefing included plant operators, health physics, system engineering

and maintenance

personnel involved with the work activities.

An excellent

discussion resulted in a well coordinated plan to ensure all PMT activities were

verified. Plant control operators'est

performance and knowledge of the HPCI

operation were excellent.

Also, the HPCI system engineer monitored the post

maintenance

surveillance test and provided timely feedback to the operator

performing the test. The pump and turbine startup and flow test were controlled and

demonstrated

system operability. The work group's good coordination of the test

minimized the heat addition to the suppression

pool.

Standby Liquid Control'(SLC) Storage Tank Foreign Material Removal

During an Instrument and Control (I&C) monthly preventative maintenance

(PM)

activity, to clean the Unit 2 SLC storage tank level instrument bubbler tube, a

portion of an l&C cleaning tool (a 3 inch long piece of stainless wire) broke off inside

the tank.

The I&C technicians immediately reported the problem to operations.

The operations plant supervisor performed an internal tank visual inspection which

identified additional foreign material inside the tank (a 3 inch by 6 inch piece of cloth

caught on a support bolt for the air sparger).

The initial operability determinatio'n concluded that the foreign material inside the

tank would not float free or, become entrained in a SLC pump suction line.

However, based on a more detailed tank inspection, three days later, operations

concluded that the cloth was not "firmlyattached,"

and declared one train of SLC

inoperable.

The cloth, and the piece of wire, were promptly removed by

maintenance the next day.

The retrieval of the foreign material eliminated all SLC

system operability concerns.

C.

Conclusions

Management's

decision to stroke the MSIV, prior to the required ST, was proactive

and resolved a problem that could have resulted in a greater pressure

increase

during a postulated MSIV closure event.

The Unit 2 high pressure coolant injection (HPCI) system outage was well planned

and executed.

The pump and turbine equipment areas were maintained as clean

areas which resulted in an excellent-work environment.

Excellent coordination of

the HPCI post maintenance test minimized the heat addition to the suppression

pool ~

System and maintenance

engineers provided good outage support at the high

pressure coolant injection (HPCI) jobsite.

Also, the HPCI system engineer monitored

the post maintenance

surveillance test and provided timely feedback to the operator

performing the test.

Instrumentation and control technicians promptly reported an activity that led to the

foreign material addition to the standby liquid control (SLC) tank.

The

technicians'ctions

were representative

of a good safety culture to report work activity

problems.

The shift supervisor's continuous operability assessment

led to the

appropriate SLC pump operability determination and the timely removal of all foreign

material from the SLC tank.

III. En ineerin

E8

Miscellaneous Engineering Issues

E8.1

Followu

of 0 en Items (37551,92903)

Closed

VIO 50-387 388 98-08-02

Emergency Diesel Generator Day Tank Minimum Volume

In 1990 and 1991, PPSL identified that the fuel oil transfer pump automatic start

level switch setpoints for the emergency diesel generator day tanks did not meet the

American National Standards Institute (ANSI) requirements.

The ANSI requirement

to ensure

a day tank minimum fuel oil volume sufficient for 60 minutes of diesel

operation at the level where fuel oil is automatically added to the day tank was not

met.

PP&L documented this non-conforming condition, and implemented

administrative controls as compensatory

measures,

but failed to effect timely

resolution.

The failure to effect timely resolution was cited as a violation.

The inspectors performed an in-field review of PPRL's response to the violation,

Technical Specifications (TSs), and the final safety analysis report (FSAR).

PPRL's

corrective actions included a TS change request, submitted to the NRC on

November 20, 1998, and a design basis change which will resolve the non-

conforming condition.

The inspectors determined that

PPSL's corrective actions

were appropriate.

This violation is closed.

"A" Emer enc

Diesel Generator Ino erable due to Heav

Rains

Closed

URI 50-387 388 98-06-03

Ins ection Sco

e 37551 92903

On June 23, 1998, SSES experienced

heavy rains.

This resulted in water intrusion

into the "A" emergency diesel generator

(EDG) fuel oil storage tank.

This event was

reviewed in detail in NRC Inspection Report 50-387,388/98-06,

and identified as

Unresolved Item (URI) 50-387,388/98-06-03.

The inspectors reviewed PPRL's

corrective actions in response to this event.

Observations

and Findin s

In June, 1998, heavy rains resulted in significant quantities of water entering the

.

"A" emergency diesel generator

(EDG) fuel oil storage tank.

The rain water entered

the storage tank vault area immediately above the tank, in-part, through below

ground level unsealed penetrations into the vault. The vault penetrations were part

of an in progress modification, and had remained unsealed during the installation

work. The vault flooded to a depth of about five feet, and water leaked into the

.storage tank through a loose flange on the tank.

The consequences

of this event

resulted in the "A" EDG being inoperable for a short period of time, and in a

degraded condition for several days, following the event.

PPSL initiallydetermined that no programmatic or proceduie provisions existed to

require interim sealing of penetrations or breaches

into safety related structures or

barriers made during the course of modification or maintenance work, and is

continuing to evaluate foreign material exclusion program requirements.

PPSL

further determined the loose flange appeared to have resulted from gasket

deterioration, due to use of an incorrect gasket material (i.e., a rubber gasket

appeared to have been substituted for a neoprene gasket).

~

The inspectors performed an in-field review of PPSL's corrective actions,

which'ncluded

proposed field inspections of storage tank flange gaskets,

and proposed

procedure and programmatic changes.

PPSL's initial corrective actions were good,

and included immediate water removal from the fuel oil storage tank, inspection of

the other storage tanks and tank flanges, and sealing of the open penetrations into

the tank vault. The inspectors concluded the corrective actions, identified by

condition report (CR) 98-2183, appeared

reasonable to correct the condition and

prevent recurrence.

However, as of December 15, 1998, only one of the five

specified corrective actions had been completed.

Neither the corrective action to

determine the correct gasket material for the tank flanges, due by September 30,

1998, nor the corrective action to inspect all tank flange gaskets, for appropriate

gasket and replace as necessary,

due by October 30, 1998, had started,

as of

December 15, 1998.

The inspectors, therefore, concluded that the corrective

actions were not performed in a timely manner.

10

Confi uration of Fuel Oil Stora

e Tanks

A 1989 modification (PCN 89-9008) installed a different type of level instrument,

and added stilling wells to the storage tanks.

The function of the stilling well was

to provide a foreign material exclusion barrier, similar to a basket, for the level

instrument floats which hung inside the tank.

The stilling well was safety related,

while the instrument and floats were non-safety related.

The instrument/tank flange

is actually an assembly, consisting of three flanges sandwiched together by one set

of bolts (the bolts were designated

as safety related).

The lower gasket is between

the tank flange and the stilling well flange, and the upper gasket is between the

stilling well flange and the instrument flange.

Neoprene was specified for both

gaskets.

The inspectors determined that PPRL failed to revise design drawings (or other

appropriate design basis documents) to incorporate the design changes made by

modification 89-9008.

The unavailability of the design information for the correctly

specified gasket material resulted in the use of incorrect gasket material (i.e., rubber

instead of neoprene), which deteriorated due to exposure to fuel oil, and

subsequently

allowed water intrusion into the fuel oil storage tank on June 24,

'1998.

10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that

measures

be established to ensure that applicable regulatory requirements

and the

design basis are correctly translated into specifications, drawings, procedures

and

instructions.

The failure to adequately translate the system design, from a

modification, into appropriate specifications, drawings, and procedures

is an

example of an apparent violation of Appendix B Design Control requirements.

The inspectors found that on July 1, 1998, SSES maintenance

replaced the

instrument flange gasket, identified as having been deteriorated

and loose, with a

flexitalic gasket (i.e., different type of gasket).

The as-left condition was an upper

flange flexitalic gasket and a lower flange neoprene gasket, with the flange torqued

to the required value for the flexitalic. The applied torque greatly exceeded the

maximum allowed for the lower flange neoprene gasket.

PPRL has subsequently

determined that both the upper and lower gaskets must be of the same type.

As of

January 4, 1999, no operability determination, or condition report interim use-as-is

.or repair disposition had been performed to evaluate the as-left condition. Also, no

approval existed for the use of a flexitalic gasket as an alternate replacement item

for the as-found gasket.

The use of the flexitalic gasket, without the required SSES

evaluations and approvals, was identified by the NRC during the inspectors'eview

of CR 98-2183.

Although the CR did identify that a flexitalic gasket had been

installed by maintenance

in July, the CR did not identify or recognize the gasket

substitution as an action which was not performed in accordance with required

station procedures for operability determinations

and replacement item evaluations.

The NRC further identified that work order S83104, which installed the flexitalic

gasket, was designated

as non-safety related and non-ASME, which would have

allowed the use of non-safety related bolts on the flange.

10 CFR 50, Appendix B,

Criterion III, Design Control, requires, in part, that measures

be established for the

selection and review for suitability of application of materials and parts.

The failure

11

of PPtkL to perform a replacement item evaluation, prior to substituting a flexitalic

gasket for a neoprene gasket is a second example of an apparent violation of

Appendix B Design Control requirements.

This URI is closed.

(VIO 50-387,388/98-

12-02)

c.

Conclusions

PPRL failed to adequately translate

a system design change into appropriate

specifications, drawings, and procedures,

and on two separate

occasions

substituted gasket material without a review for suitability of materials.

PPSL

determined that the use of an incorrect gasket material was a root cause for

significant water intrusion into an emergency diesel fuel oil storage tank on June 24,

1998.

The inspectors determined this was an apparent violation of 10 CFR 50

Appendix B, Criterion III, Design Control.

PP&L's initial corrective actions were

good.

However, the proposed final corrective actions, which appeared

reasonable

to correct the original condition, were not performed in a timely manner.

In

addition, the NRC identified that PPSL failed to recognize that SSES design control

requirements

had not been followed when a different type of gasket was installed

on July 1, 1998.

This URI is closed.

IV. Plant Su

ort

S2

Status of Security Facilities and Equipment

(71750,92904)

The secunty computer replacement,

in the Secunty Control Center, was well

controlled and completed with minimal interruptions to the normal plant access

areas.

The inspectors also verified, through observations

and interviews, that the

computer replacement modification did not interfere with operational activities, or

the execution of the detection, assessment

and response functions.

A significant

improvement was noted for the plant accountability

capabilities.'.

Mana ement Meetln s

Xl

Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management

at the conclusion of the inspection report period on January 11, 1999.

The licensee

acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the

inspection should be considered proprietary.

No proprietary information was

identified.

ATTACHMENT1

INSPECTION PROCEDURES USED

IP 37550

IP 37551

IP 40500

IP 61726

IP 62707

IP 71707

IP 92700

IP 92901

IP 92903

Engineering

Onsite Engineering Observations

Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing

Problems

Surveillance Observations

Maintenance Observations

Plant Operations

On Site Followup of Reports

Followup Plant Operations

Followup Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

~Oeoed

50-387,388/98-1 2-02

VIO

"A" Emergency Diesel Generator Inoperable due to

Heavy Rains (Section E8.1)

50-387/98-1 2-01

I

Closed

50-388/98-009-00

NCV

Incomplete Channel Functional Test of Source Range

Monitor Channels (Section 08.1)

LER

Unit 2 "A" Moisture Separator Drain Tank High-High

Level Scram (Section 08.1)

50-387/98-01 7-00

50-387/98-01 7-01

LER

Incomplete Channel Functional Test of Source Range

Monitor Channels (Section 08.1)

50-387,388/98-08-02

VIO

Emergency Diesel Generator Day Tank Minimum Volume

(Section E8.2)

50-387,388/98-06-03

URI

"A" Emergency Diesel Generator Inoperable due to

Heavy Rains (Section E8.1)

Attachment

1

LIST OF ACRONYMS USED

ANSI

ASME

ASO

BWR

CFR

CR

CREOASS

DCP.

ECCS

EDG

ESW

FPC

FME

FSAR

GDC

gpfn

HPCI

HWC

I&C

IR

IST

ITS

LCO

LER

MSIV

NCV

NOV

NPO

NRC

PCO

RB

RHR

RWCU

SLC

SRO

SS

SSES

STA

TS

TSI

URI

US

VIO

WA

American National Standards

Institute

American Society of Mechanical Engineers

Auxiliary Systems Operator

Boiling Water Reactor

Code of Federal Regulations

Condition Report

Control Room Emergency Outside Air Supply System

Design Change Package

Emergency Core Cooling System

Emergency Diesel Generator

Emergency Service Water

Fuel Pool Cooling

Foreign Material Exclusion

Final Safety Analysis Report

General Design Criteria

gallons per minu'te

,High Pressure

Coolant Injection

Hydrogen Water Chemistry

Instrument and Control

[NRC] Inspection Report

Inservice Testing

Improved Technical Specification

Limiting Condition for Operation

Licensee Event Report

Main Steam Isolation Valves

Non-Cited Violation

Notice of Violation

Nuclear Plant Operator

Nuclear Regulatory Commission

Plant Control Operator

Reactor Building

Residual Heat Removal

Reactor Water Cleanup

Standby Liquid Control System

Senior Reactor Operator

Shift Supervisor

Susquehanna

Steam Electric Station

Shift Technical Advisor

Technical Specification

Technical Specification Interpretation

[NRC] Unresolved Item

Unit Supervisor

Violation

Work Authorization

0