ML17157C176

Insp Repts 50-387/92-29 & 50-388/92-29 on 921110-1231.No Violations Noted.Major Areas Inspected:Station Activities, Plant Operations,Radiation Protection,Surveillance & Safety Assessment/Quality Verification

ML17157C176
Person / Time
Site:	Susquehanna
Issue date:	01/27/1993
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17157C175	List: ML17157C174 ML17157C176
References
50-387-92-29, 50-388-92-29, NUDOCS 9302100394
Download: ML17157C176 (44)

See also: IR 05000387/1992029

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

Inspection

Report Nos.

50-387/92-29; 50-388/92-29

License Nos.

NPF-14; NPF-22

Licensee:

Pennsylvania Power and Light Company

.2 North Ninth Street

Allentown, Pennsylvania

. 18101

Facility Name:

Inspection At:

Susquehanna

Steam Electric Station

"

Salem Township, Pennsylvania

Inspection

Conducted:

Inspectors:

Approved By;

November 10, 1992 - December 31, 1992

I

G. S. Barber, Senior Resident Inspector,

SSES

D. J. Mannai, Resident Inspector, SSES,

,i

/r

J. white, Chief

,Reactor Projects Section No. 2A,

ate

Ins ection Summa:

This inspection report documents safety inspections of station activities

including: plant operations; radiation protection; surveillance and maintenance;

and safety

assessment/quality

verification.

Findings and conclusions are summarized in the Executive

Summary.

'3021'00394

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PDR

ADOCK 05000387

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PDR

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EXECUTIVE SUMMARY

Susquehanna

Inspection Reports

~ -50-387/92-29; 50-388/92-29

November 10, 1992

- December 31, 1992

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Operations (30702, 71707, 71710)

A Unit 2 turbine trip/reactor scram occurred at 10:14 a,m., November 12, during a

surveillance on the "A" channel of the feedwater (FW) high level trip switches.

The plant

'as

subsequently

stabilized in hot shutdown.

The turbine trip was caused by an'Agastat

relay failure for the "C" high level trip channel.

Two anomalies were identified by the

licensee,'s post-trip review:

(1) the reactor feed pump (RFP) turbines did not trip as

expected;

(2) two of three non-safety related feedwater heater (FWH) strings isolated due to

excessive flashing in the high'pressure

heaters.

Proper licensee actions'were taken for the

FWH anomalies.

The RFP turbine trip failures were due to inadequate contact makeup of

the "A" trip channel's Agastat (EGP Series) relay.

The licensee is sending this relay off-site

to determine ifthe specific failure mechanism

has generic implications.

The "C" channel's

premature failure was traced back to an early installation error that placed an AC relay in a

DC circuit application.

These issues remain unresolved pending final review by the licensee

and evaluation by the NRC.

Section 2.2.1 pertains.

Because of a continually degrading differential pressure signal, the licensee declared the Unit

2 "B" Reactor Water Cleanup (RWCU) High Flow channel inoperable on November 17, To

prevent the expected

increase in reactor water conductivity which might necessitate

unit

shutdown,'a temporary waiver of compliance was requested for Technical Specification (TS) 3.3.2 to lengthen the time required to isolate the RWCU system. After proper consideration

and evaluation, the NRC granted the temporary waiver of compliance on November 18.

.Over the next several days, the licensee and the NRC held numerous discussions

regarding

the need for further extensions to the original waiver.

Numerous problems were encountered

during these interactions.

The licensee subsequently initiated an Event Review Team (ERT)

to identify and correct the noted deficiencies. NRC review of these concerns willremain

unresolved pending final review by the licensee's ERT.

Section 2.2.4 pertains.

The inspector performed an Engineered

Safety Feature (ESF) walkdown of the Control Room

Emergency Outside Air Supply (CREOASS) system,

The inspector determined the system

was properly aligned and capable of performing its intended safety function.

The system was

maintained in good physical,condition.

However, several minor deficiencies were identified.

The licensee's

actions for these deficiencies was appropriate.

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The inspector reviewed hourly fire watch records for the month of September,

1992.

The

subject watches were performed by site contract personnel.

While no fire watches had been

missed, two individuals failed to properly perform a required fire watch round.

One

individual admitted that he failed to check the 660'levation of the "A" Emergency Diesel

Generator Bay and was suspended

without pay for five days.

The licensee determined that

the other individual lied about surveying the area.

The individual was subsequently

terminated.

The inspector concluded that the licensee's implementation of fire protection

requirements

was effective.

/

Radiological Controls (71707)

The inspector evaluated susceptibility of either Susquehanna

unit to highly concentrated

radiation beams similar to those observed during July 7-9, 1992 at the,Limerick Nuclear

Generating Station (LNGS).

These beams resulted from a highly concentrate'd

neutron

streaming through an instrument penetration that was poorly shielded.

They were detected at

LNGS during drywell entries performed at power to repair a leaky containment isolation.

valve, At Susquehanna,

the licensee, by policy, has not made any at-power entries to either

units'rywell since commercial operation.

To address

this concern further, the licensee

modified the containment entry procedure to prohibit entries at power.

Inspector review of

post shutdown gamma doses showed no unusual streaming.

The inspector found that the

licensee actions in changing the containment entry procedure to be strong and conservative.

Section 3.2.2 pertains.

On November 12, a routine sample of the "B" Auxiliary Boiler identified radioactive gases in

the auxiliary steam system.

The licensee secured the leak by closing and administratively

controlling a manual isolation valve.

The inspector concluded the licensee promptly

identified and determined the cause of the auxiliary boiler contamination.

Radiological

consequences

were conservatively

assessed.

The inspector determined immediate corrective

actions for this contamination event were adequate.

The event resulted in a minor

uncontrolled, unmonitored release that was calculated to be an extremely

small fraction

regulatory limits. However, this was the third radioactive gas leak through the auxiliary

boiler from essentially the same leak path.

The licensee's effectiveness relative to resolving

this type of occurrence remains unresolved.

Section 3.2.1 pertains.

Maintenance/Surveillance

(61726, 62703)

The licensee exercised good control of maintenance

and surveillance activities.

No scrams or

Engineered

Safety Feature (ESF) actuations were attributable to personnel or procedural error

during maintenance or surveillance activities.

A reactor scram occurred during the

performance of a surveillance but was attributed an undetectable Agastat relay failure.

111

Engineering/Technical Support (71707, 92720, 93702)

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The "E" Diesel Generator started unexpectedly in the emer'gency mode on November 13.,

The unexpected

start was attributed to an in-service failure of a normally energized Agastat

relay (4ESS1).

The failed relay was only seven months old.

The licensee plans to submit

the device to an independent laboratory for failure analysis.

Currently, the licensee intends

to replace 183 of the safety related-active and non-safety related-critical (to plant operations)

Agastat relays.

The licensee is tracking completion of this action under their deficiency

resolution program.

Section 7.2.1 pertains.

Safety Assessment/Assurance

of Quality (40500, 90712, 92700, 92701)

The inspector reviewed three Licensee Event Reports during the period.

Section 8.1

pertains.

TABLEOF CONTENTS

EXECUTIVE

SUMMARY'.

SUMMARYOF OPERATIONS...

1.1

Inspection Activities . ~....

1,2

Susquehanna

Unit 1 Summary

'1.3

Susquehanna

Unit 2 Summary

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OPERATIONS

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2.1

Inspection Activities...............................

2.2

Inspection Findings and Review of Events

2.2.1

Reactor Scram/Turbine Trip During Feedwater High Level Trip

Switch Surveillance.......,...................

2.2.2

Engineered

Safety Feature (ESF) System Walkdown - Control

Room Emergency Outside Air Supply System (CREOASS)-

Common

2.2.3

Hourly Fire Watch Records Review

2,2.4

Inoperable "B" High Flow Isolation Channel for the Unit 2

Reactor Water Cleanup System

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RADIOLOGICALCONTROLS

3.1

Inspection Activities....,..........

3.2

Inspection Findings

3.2.1

"B" Auxiliary Boiler Contamination

3.2.2

Highly Concentrated

Radiation Beams

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MAINTENANCE/SURVEILLANCE

4.1

Maintenance'and

Surveillance Inspection Activity.......

4.2

Maintenance Observations ..... ~,... ~......,...

4.3

Surveillance Observations

4.4

Inspection Findings

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EMERGENCY PREPAREDNESS

5.1

Inspection Activity.....

5.2

Inspection Findings

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6.

SECURITY

6.1

Inspection Activity.....

6.2

Inspection Findings

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Table of Contents (Co'ntinued)

7.

ENGINEERING/TECHNICALSUPPORT

7.1

Inspection Activity..................

7.2

Inspection Findings

7.2.1

Diesel Generator Automatic Start Due to

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Failure ..

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8.

SAFETY ASSESSMENT/QUALITY VERIFICATION .

8.1

Licensee Event Reports........ ~.......

8..2

Open Items ........ ~..............

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MANAGEMENTAND EXIT MEETINGS .......

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Resident Exit and Periodic Meetings

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- 'P&LEmergency Protective Guidelines Meeting

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DETAILS

1.

SUFrIMARY OF OPERATIONS

1.1

.Inspection Activities

The purpose of this inspection was to assess

licensee activities at Susquehanna

Steam Electric

Station (SSES) as they related to reactor safety and worker radiation protection.

Within each

inspection area, the inspectors documented

the specific purpose of the area under review, the

scope of inspection activities and findings, along with appropriate conclusions.

This

assessment

is based on actual observation of licensee activities, interviews with licensee

personnel,

measurement of radiation levels, independent calculation, and selective review of

applicable documents.

Abbreviations are used throughout the text.

Attachment

1 provides a listing of these

abbreviations.

1.2

Susquehanna

Unit 1 Summary

Unit 1 began the inspection period at 100% power.

On November 12, an unplanned

Engineered

Safety Feature (ESF) actuation occurred when the reactor scrammed

due to a

main turbine trip. The cause of the main turbine trip was due to a failed Agastat relay in the

"C" Feedwater High Level Turbine Trip Channel coincident with surveillance testing of the

Reactor Feedwater "A" High Level Turbine Trip Channel.

(Section 2.2.1 pertains)

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The

unit was synchronized to the grid on November 14, and reached

100% power on November

16.

On November 12, a routine sample of the "B" auxiliary boiler indicated contamination of the

auxiliary steam system with main steam as evidenced by the presence of nitrogen-13 and

fluorine-18,

The licensee prepared

a safety evaluation to allow temporary operation of the

boiler for the startup of both units.

(Section 3.2.1 pertains).

On November 13, an unplanned ESF actuation occurred when the "E" Emergency Diesel

Generator auto-started in the emergency run mode with no apparent initiation signal present.

The licensee determined

an Agastat relay failure caused

the auto-start of the diesel.

(Section

7.2.1 pertains).

On December 3, power was reduced to 60% to repair "B" and "D" condenser

water box

leaks.

Reactor power was returned to 100% on December 7. Unit 1 finished the inspection

period at 100% power.

1.3

Susquehanna

Unit 2 Summary

Unit 2 entered the inspection period in Condition 4 at the end of a refueling and inspection

outage.

The unit entered Condition

1 on November 13 and was synchronized to the grid.

Power ascension

continued and the unit reached

100% power on November 23.

On November 17, at 11:20 a.m., the "B" Reactor Water Cleanup (RWCU) system high flow

channel was declared inoperable due to the instrument degradation.

The'high flow isolation

was determined to be inoperable and a temporary waiver of compliance was granted to

preclude isolating, the reactor water cleanup system.

(Section 2.2.4 pertains).

The unit

finished the inspection period at 100% power.

2.

OPERATIONS

2.1

Inspection Activities

The inspectors verified that the facility was operated safely and in conformance with

regulatory requirements.

Pennsylvania Power and Light (PP&L) Company management

control was evaluated by direct observation of activities, tours of the facility, interviews and

discussions with personnel,

independent verification of safety system status and Limiting

Conditions for Operation, and review of facility records.

These inspection activities were

conducted in accordance with NRC inspection procedure 71707.

The inspectors performed 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> of deep backshift inspections during the period.

These

deep backshift inspections covered licensee activities on weekdays between

10:00 p.m. and

6:00 a.m., and weekends

and holidays.

2.2

Inspection Findings and Review of Events

2.2.1

Reactor Scram/Turbine Trip During Feedwater High Level Trip Switch

Surveillance

At 10:14 a.m., November 12, a turbine trip occurred during a surveillance on the feedwater

high level trip switches.

A reactor scram ensued with all control rods fully inserting.

Two

safety relief valves (SRVs) opened and reseated

to compensate for the load rejection.

Reactor water level decreased

to slightly less than the Level 3 setpoint (+10") which caused

certain expected isolations and actuations to occur.

Both reactor recirculation (recirc) pumps

tripped, as expected,

and two of three feedwater heater strings isolated.

The reactor recirc

pumps were subsequently

restarted and reactor water level was restored to normal. All

systems were restored to normal.

The licensee reported the event per 10 CFR 50.72.

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The scram occurred during the performance of a surveillance (SI-145-201) on the feedwater

high water level trip switches,

Unbeknownst to the instrument (1&C) technicians,

at some

time prior to the surveillance, the "C" feedwater high level trip switch had failed in the trip

state.

Thus, when the +54" high level setpoint was exceeded

as a normal course of the

'urveillance

on "A" feedwater channel, a turbine trip occurred since the two-out-of-three

logic was satisfied.

The resultant turbine control valve fast closure resulted in a reactor

scram since power was above 24%.

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Two anomalies were detected on post-trip review:

(1)

Failure of the reactor feed pump (RFP) turbines to trip on the apparent high level trip

'signal.

This was attributed to inadequate contact make-up internal to the Agastat

relay (EGP Series) that performed the trip function.

Upon examination, the contacts

for the turbine trip function were found closed, where as the RFP contacts were'open.

The licensee attributed the RFP turbine trip failure to a design misapplication error.

The failed relay was designed for AC circuit use, but it was erroneously installed in a

DC circuit. This r'esulted in accelerated

thermal aging and premature failure.

The

licensee found the same error in all Unit I feedwater high level switches.

Allof

these relays were replaced with Agastat relays rated for DC voltages.

Following

these replacements,

surveillance testing of all channels was successfully completed.

Similar Unit 2 relays were checked with no misapplication errors detected.

In other systems,

the licensee reviewed all Agastat EGP. series relays having a safety

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related function but no other deficiencies were noted.

Allother non-safety related

Agastat EGP series relays with functions that have possible operational impact (i.e.

turbine trip) were also reviewed.

No incorrect installations were found.

Also

considered

was circuits in which non-safety related.Agastats

shared power supplies

with relays having safety related or operational impact functions.

This was done to

preclude a non-safety related relay failure from affecting the combined power supply

for the circuit. The licensee did not discover any installation errors.

However, some

electrical drawings were found to be in error, and were subsequently

corrected.

(2)

.Unexpected isolation of two non-safety related feedwater heater (FWH) strings.

FWH level instrumentation was checked for all three heater strings following the

event. The licensee believed that the isolations occurred when the FWH level

instrumentation

sensed

flashing in the high pressure FWHs.

Flashing was also

detected in the third string.

However, it was not enough to trip its isolation logic.

Additional minor problems were identified and corrected by the licensee.

No direct

cause for the isolations was found.

The flashing itself was expected.

However, its

magnitude was greater than anticipated.

The inspector responded

to the control room immediately after the scram and observed

operators using procedures

to stabilize the plant in hot shutdown.

Operator response

to the

transient was good. Procedures

were followed and post scram actions were directed. at

stabilizing the plant in hot shutdown.

After the plant was stable, the inspector questioned the

operators about indications they observed during the transient.

In addition, the sequence of

events log generated by the Shift Technical Advisor (STA) was also reviewed.

The inspector

also attended the startup plant operations review committee (PORC) on the following day.

The inspector noted generally good review of the transient by PORC. '

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The inspector questioned various aspects of the event during and after the post scram review,

including the installation error that resulted in an AC relay being installed in a DC circuit.

The licensee was unable to determine the exact cause of the error, but it appeared

to date

from 1982 which was the final licensing phase for Unit 1 and the construction phase for Unit

2.

The inspector considered, this error significant because of its potential generic

implications, along with its long standing nature.

Of particular concern, was the licensee's

apparent inability to detect such an error during-original installation and their continued

inability. to detect this error until it revealed itself during the post scram investigation.

The

inspector noted that the relay nameplate data indicates "120 V 60 Hz" which is clearly for an

AC installation only. The licensee controls implemented to preclude incorrect part

installation were inadequate

since an Agastat relay designed for AC circuit applications was

erroneously installed in a DC circuit. This issue will remain unresolved pending final review

by the licensee and evaluation by the NRC.

(URI 50-387/92-29-01 (Common))

The inspector also noted problems with the feedwater systems response

to an apparent high

level signal.

Technical Specification 3,3.9 requires that all three channels of the

feedwater/main turbine trip system be operable'whenever

the unit is in Operational Condition

1. Two out of three trip systems are needed

to trip the main turbine and the reactor feed

pump turbines whenever reactor water level exceeds +54 inches.

Since the RFP turbines"

failed to trip in response

to an apparent high level signal, their trip system's isolation

function was inoperable.

This isolation failure was caused by incomplete internal contact in

the Agastat relay for "A" FW high level trip function.

The licensee is sending the."A"

Agastat relay off-site for failure analysis. 'The generic implications of the root cause of this

relay failure (RFP trip contacts did not close) will remain unresolved pending evaluation by

the licensee,

and subsequent

review by the NRC.

(URI 50-387/92-29-02 (Common))

2.2.2

Engineered Safety Feature (ESF) System Walkdown - Control Room Emergency

Outside AirSupply System (CREOASS) - Common

The inspector performed an ESF walkdown of the Control Room Emergency Outside Air

Supply System (CREOASS) to independently verify the status of the system.

The inspector

did not identify any major deficiencies during the walkdown. However, the inspector notified

the licensee of deficiencies that required corrective actions.The licensee promptly took or

planned corrective action.

The inspector identified the following deficiencies:

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Several CREOASS filter inspection light bulbs burned out for both A and B filter

trains.

The licensee has written a Work Authorization to correct the deficien'cy.

Loose dog on door to "B" CREOASS filter train charcoal filter.

The licenseo has corrected the deficiency,

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Duct work has holes on either side of A & B CREOASS filter train recirculation air

isolation dampers.

The licensee determined these holes existed to allow boroscopic inspection of the

system.

The licensee decided that these holes did not have a significant detrimental

effect on the system, but, the holes would be plugged.

System engineering found

some additional holes in the CREOASS duct work. The licensee promptly plugged all

the holes with test plugs.

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Dog on a door to CREOASS fan "A" flow control damper not working.

'The licensee has corrected the deficiency.

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Drain valves 083019/083013 packing gland nuts were loose.

The inspector determined the CREOASS system to be properly ahgned m the standby mode

in accordance with appropriate procedures

and able to perform its intended safety function.

Excepting the deficiencies noted, the inspector concluded the licensee maintained the system

in good condition.

2.2.3

Hourly Fire Watch Records Review

The inspector reviewed hourly fire watch records for the month of September

1992.

Site

contract personnel perform the subject roving fire watch rounds.

Contract personnel

completed all fire watch rounds for the month of September.

The inspector found that no

hourly fire watches were missed, but noted that two individuals failed to perform a round

properly.

The contractor supervisor and foremen routinely perform random field observations of fire

watches to ensure proper performance of fire watch rounds.

On September

10, fire watch

supervisors,

on separate

occasions,

observed two individuals improperly performing fire

watch rounds in the "A" Emergency Diesel Generator Bay. Allelevations in the diesel

generator bay are considered within the fire zone.

Accordingly, fire watches are required to

physically check the lower 660'levation.

This expectation was clearly and accurately

communicated to fire watch personnel through training, the fire watch bulletin board and

shift turnover.

During September,

contractor supervision observed that both the individuals failed to

physically inspect the 660'levation.

Supervisors later questioned

the individuals on whether

they completed the round, specifically the 660'levation.

One individual admitted he did not

go down to the 660'levation and received a five day suspension without pay.

The

other'ndividual

maintained that he completed the round even after repeated questioning.

The

'ndividual was subsequently

terminated.

The supervisors

descended

to the 660'levation and

performed the required check after they noted that each fire watch missed it.

Contract supervision convened a Review Board Assembly to review all the circumstances

concerning the performance of the particular round.

PP&L supervision and one of the

individuals participated in the meeting.

Following the review board, the site supervisor

decided that the employee would be terminated based on the employee lying about

completing a round.

PP&L supervisors present at the Review Board Assembly endorsed

the

'decision.

The inspector concluded that based on a review of records and discussions

that the licensee

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. did not miss any required fire watch.

The contractor's disciplinary action concerning the

individuals appeared

commensurate

to the circumstances.

The inspector had no further

questions.

2.2.4

Inoperable "B" High Flow Isolation Channel for the Unit 2 Reactor Water

Cleanup System

On November 15; 1992, operators noted a significant decrease

in the reading of the "B"

Reactor Water Cleanup (RWCU) High Flow channel during a routine surveillance.

Although

the associated

instrument (PDIS-G33-2N044B) met the channel check acceptance

criteria, the

licensee initiated an investigation.

At 11:20 a.m., November 17, the channel was taken out

of service to determine the cause of the apparent flow reduction and Technical Specification (TS) 3.3.2 was entered.

At 1:10 p.m,, the channel was confirmed to be inoperable and the

licensee concluded that the instrument could not be repaired in the time allotted by TS 3.3,2.

Therefore, the RWCU system was shutdown and isolated.

The licensee requested

a

temporary waiver of compliance to permit operation of the RWCU system for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to

allow time to troubleshoot and repair the defective high flow instrument.

The licensee

proposed that continued operation was safe and justifiable due to the operability of the "A"

RWCU High Flow isolation instrument,

as well as the other diverse and redundant RWCU

line break detection logic required by Technical Specification 3.3.2.

The NRC subsequently

approved the waiver on November 18.

The licensee performed troubleshooting over the next three days but was unable to identify

the cause of failure.

Because of the lack of a clearly identifiable cause,

an extension of the

original waiver was requested.

The NRC questioned the licensee on their intentions, since,

ifthis extension were to expire without a root cause being determined,

an additional (third)

extension would be required.

After further consideration,

the licensee modified their request

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to seek NRC approval to operate for the remainder of the fuel cycle with "B" RWCU high

flow channel inoperable but with a full set of compensatory

measures

in place.

The modified

waiver request was submitted on November 20.

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During continued licensee review and discussion with the NRC, a vulnerability was

discovered in the licensee's compensatory

measures.

Piping that runs from the containment

wall through. the pipe routing areas to the RWCU rooms was not adequately monitored for

line break, nor was the deficiency identified in the licensee's November 20 submittal.

Accordingly, NRC determined that the basis of the waiver request was insufficient.

Subsequently,

the licensee reentered TS 3.3.2 and began to make plans to isolate RWCU.

The licensee subsequently

determined that the RWCU high demineralizer temperature

'instrument could be used as an alternative line-break detector device.

The licensee noted that

a leak in the pipe routing area would cause a flow increase that would exceed the various

RWCU heat exchangers

ability to remove an adequate amount of sensible heat from the

'rocess

fluid. This would result in a system isolation on high temperature.

The licensee

determined that-this instrument, altho'ugh not part of the isolation logic, but powered from a

safety grade power supply, would provide an acceptable alternative for the inoperable high

flow channel.

Accordingly, the

licensee reinitiated their waiver request to effectively substitute the RWCU

high temperature isolation function in place of the "B" High Flow Channel isolation function.

The NRC agreed with this approach in a November 25 response

to the licensee,

as long as,

all TS 3.3.2 requirements

(surveillance, operability, action times, etc.) were applied.

The

licensee agreed to these restrictions, and to submit a formal TS amendment

request on/or

before November 30 to reflect these limitations and conditions for the remainder of the

operating cycle.

The.licensee's

submittal is currently being reviewed by NRC.

The inspector noted a number of weaknesses

relative to this matter.

Specifically, it appeared

, that'the licensee did not fully review all aspects of the RWCU leak detection system design

and consider them in their formal requests.

The licensee has also recognized weakness with.

their interaction with NRC on this matter and has formed an Event Review Team (ERT) to

fully evaluate their performance.

NRC findings on this matter will remain unresolved

pending ERT review and NRC evaluation of their findings.

(URI 50-387/92-29-03)

3.

RADIOLOGICALCONTROLS

3.1

Inspection Activities

PP&L's compliance with the radiological protection program was verified on a periodic

basis.

These inspection activities were conducted in accordance with NRC inspection

procedure 71707.

3.2

Inspection Findings

Observations of radiological controls during maintenance activities and plant tours indicated

that workers generally obeyed postings and Radiation Work Permit requirements.

Findings

are discussed

in the following sections.

3.2.1

"B" AuxiliaryBoiler Contamination

On November 12, a routine effluent sample of the "B" auxiliary boiler showed contamination

of the auxiliary steam.

The sample contained nitrogen-13 and fluorine-18.

This combined

with the absence of activation products such as cobalt-60 and manganese-54

indicated

contammation of the auxiliary steam system with main steam.

Following the identification of

contamination, Unit 1 scrammed

due to a failed Agastat relay.

At the time, Unit 2 was in

cold shutdown and Unit 1 was operating.

The licensee documented

this occurrence in SOOR

1-92-352.

Since Unit 2 was shutdown at the time and Unit 1 had scrammed,

the source of contaminated

steam was removed.

A chemistry sample showed decreasing activity on November 13.

A

sample from the auxiliary boiler deaerator vent on the radwaste building roof indicated

xenon-135 activity. The samples from the boiler and the deaerator vent indicated that the

'ormally

uncontaminated

auxiliary boiler system was subjected to leakage from the main

steam system resulting in a small but uncontrolled and unmonitored release of noble gas.

PP&L prepared

a Plant Operations Review Committee (PORC) approved safety evaluation to

allow temporary operation of the auxiliary boiler as allowed by guidance set forth in NRC

I&EBulletin 80-10, "Contamination of Non-radioactive Systems and resulting Potential

Unmonitored, Uncontrolled Release to the Environment".

Plant management

decided to

operate with.contamination to allow the start up of both units, as well as to facilitate location

. of the exact source of the leak.

The safety evaluation determined that no unreviewed safety

question existed and required no change to Technical Specifications.

The chemistry

department concluded that since the deaerator removes air and non-condensible

gasses

(air,

oxygen, xenons, kryptons) and discharges

them through the vent, the fission product gasses

from the discharged

steam would be released via the vent.

Using conservative as'sumptions,

the licensee calculated the release rate from the vent to be 7.37 E-3 microcuries/second.

Typical Lower Limitof detection (LLD) release rates from the five normally monitored vents

are 50-70'microcuries/second.

This represents

a small fraction of the value where any

routine releases

above the minimum detection level would be reported.

The licensee also calculated the maximum total body dose measured

at the site boundary for

the given noble gas source to 2.12 E-5 mrad based on dose due to noble gases

released

as

gaseous effluents.

The Technical Specification

quarterly limitfor gamma radiation due to

noble gases released in gaseous

effluents is 5 mrad.

To further ensure minimal doses,

the

licensee safety evaluation required shutdown and cooldown of the auxiliary boiler ifthe

offgas pretreatment rate exceeded

1000 uci/sec.

The licensee performed an investigation to find the source of leakage.

System engineering

determined that the source was Unit 1 main steam supply to the steam jet air ejector (SJAE).

Steam was leaking past motor operated valve HV10752, which was closed, and check valve

107027.

The remaining flow path contained steam trap ST10702, which drains to the

Auxiliary Boiler Deaerator.

The licensee secured

the leak by closing and administratively controlling manual valve

HV107077.

The leak was verified to have stopped based on a drop in pipe temperature.

Following the start up of both units the licensee issued work authorizations to inspect/repair

the leaky valves.

The licensee has preliminary determined that actions to prevent recurrence

include revising the system check list and operating procedure to have manual HV107077

closed unless auxiliary steam is required to supply SJAE.

System engmeering has,proposed

an enhancement

to route steam trap ST10702 drains to the main condenser

instead of the

auxiliary boiler deaerator.

PP&L willinclude the activities of released

radionuclides in the

next Semi-Annual Effluents Report.

The inspector concluded that the licensee promptly identified and adequately determined the

cause of the auxiliary boiler contamination.

The sampling that promptly identified the

contamination was part of sampling program that was established in response

to NRC I&E-

Bulletin 80-10 "Contamination of Non-radioactive Systems and Resulting Potential

Unmonitored, Uncontrolled Release to the Environment".

The licensee properly performed a

safety evaluation to allow continued operation of the system in accordance with the guidance

set forth in the Bulletin 80-10.

Radiological consequences

were properly and conservatively

assessed.

The inspector determined that the short-term corrective actions were prompt and

adequate.

The long-term corrective actions are still in the planning stage and not yet

finalized.

Licensee immediate response

to this event was considered

adequate,

however, this

was the third such occurrence of auxiliary boiler contamination from the same source.

SOOR's 1-88-158 (dated May 23, 1988) and 1-89-370 (dated December

12, 1989)

documented two previous occurrences.

All three auxiliary boiler contaminations were from

essentially the same backleakage path.

Following the 1988 contamination, maintenance

repaired the leaky valves in January

1989:

The same valves leaked again by December

1989, and maintenance

once again repaired the valves.

Subsequently,

the valves leaked

again in November 1992, resulting in this most recent contamination of the auxiliary boiler.

The licensee resolution of the event was still in progress at the end of the period.

This item

will remain unresolved pending further review and determination of adequacy by the

inspector regarding final corrective actions.

(URI 92-29-04)

3.2.2

Highly Concentrated Radiation Beams in the Drywell

The inspector performed a follow up inspection on the susceptibility of either Susquehanna

unit to highly concentrated

radiation beams similar to those observed at the Limerick Nuclear

Generating Station (LNGS). During July 7-9, 1992, at LNGS, various workers made a

number of entries into the drywell to repair a damaged

main steam sample valve.

The repair

10

attempts were made to restore the valve to an operable status as a containment isolation

valve.

After the entries were completed,

a highly concentrated

radioactive beam was

discovered in an adjacent area where work was performed.

The pre-defined work area was

well surveyed.

However, an adjacent work area that was accessed

by climbing over a

handrail and other equipment was not adequately

surveyed prior to work. The work

performed at the LNGS was performed with reactor operating at a low power (5-8%).

The inspector questioned

the licensee on their potential susceptibility to these beams and their

likelihood of making containment entries at power.

The licensee stated that no entries have

been made into either drywell since each unit went into commercial operation (Unit 1, 1982;

Unit 2, 1985).

Certain low power entries were made during pre-operational

testing to

perform required neutron surveys.

These entries were strictly controlled.

The licensee

intends to delete a provision in AD-QA-309, the Primary Containment Access and Control

procedure that currently permits power entries with superintendent

approval (PCAF 1-92-

1294).

This change also added a requirement to ensure that the reactor was shutdown prior

to initial entry.

To compare shielding configurations between LNGS and SSES, the inspector reviewed the

results of radiation surveys taken approximately one month into the fall 1992 Unit 2 refueling

outage.

The highest gamma radiation levels were inside the biological shield at 12 R/hr on

contact with the bottom of the N-16 nozzle.

General area radiation levels at the biological

shield were 100 mR/hr.

No high dose rate streaming was detected.

Neutron surveys were

not performed since the reactor was shut down.

The inspector compared surveys performed

on October 7 and 8, 1992 and noted good correlation between the results.

The inspector found that the licensee actions in changing the containment entry procedure to

be strong and conservative.

In addition, recent surveys showed no unusual radiation

streaming.

4.

MAINTENANCE/SURVEILLANCE

4.1

Maintenance and Surveillance Inspection Activity

On a sampling basis, the inspector observed and/or reviewed selected surveillance and

maintenance activities to ensure that specific programmatic elements described below were

being met.

Details of this review are documented in the follow'ing sections.

4.2

Maintenance Observations

The inspector observed and/or reviewed selected maintenance activities to determine that the

work was conducted in accordance with approved procedures,

regulatory guides, Technical

Specifications,

and industry codes or standards.

The following items were considered,

as

applicable, during this review:

Limiting Conditions for Operation were met while

components or systems were removed from service; required administrative approvals were

0

11

obtained prior to initiating the work; activities were accomplished

using approved procedures

and quality control hold points were established

where required; functional testing was

performed'prior to declaring the'involved component(s) operable; activities were

accomplished by qualified personnel; radiological controls were implemented; fire protection

controls were implemented; and the equipment was verified to be properly returned to

service.

These observations and/or reviews included:

WA 24798, Fuel Oil.Investigation on "A" Emergency Diesel Generator,

dated

November 23.

WA 27645, Suppression

Chamber Atmospheric Temperature Indication Division 2

Investigation, dated December 3.

WA 26909,

Reactor Core Isolation Cooling Barometric Condenser High Level

Switch Replacement,

dated December 22.

WA 20297,'Standby Liquid Control Nitrogen Accumulator Pressure

Check, dated

December'22.

4.3

SurveBlance Observations

The inspector observed and/or reviewed the following surveillance tests to determine that the

following criteria, ifapplicable to the specific test, were met:

the test conformed to

Technical Specification requirements;

administrative approvals and tagouts were obtained

before initiating the surveillance; testing 'was accomplished by qualified personnel in

accordance with an approved procedure;

test instrumentation was calibrated; Limiting

Conditions for Operations were met; test data was accurate and complete; removal and

restoration of the affected components

was properly accomplished;

test results met Technical

Specification and procedural requirements;

deficiencies noted were reviewed and

appropriately resolved; and the surveillance was completed at the required frequency.

These observations and/or reviews included:

SI-258-301, Quantity Calibration of Drywell Pressure (Primary Containment) High

Pressure

Channels PSH-C72-2N002 A, B, C, D, dated December

16, 1992.

SI-156-203, Channel Functional Test of SCRAM DISC Volume (SDV) High-Water

Level Channels LSH-C12-IN013 E & G, dated December

18, 1992.

SO-024-001A, Monthly Operability Test of the "A" Emergency Diesel- Generator,

dated December 21, 1992.

'2

4.4'nspection

Findings

The inspector reviewed the listed maintenance

and surveillance activities.

The review noted

that work was properly released before its commencement;

that systems and components

were properly tested before being returned to service and that surveillance and maintenance

activities were conducted properly by qualified personnel.

'Where questionable

issues arose,

the inspector verified that the licensee took the appropriate action before system/component

operability was declared.

The inspectors had no further questions on the listed activities.

5.

EMERGENCY PREPAREDNESS

5;1

Inspection Activity

The inspector reviewed licensee event notifications and reporting requirements for events that

could have required entry into the emergency plan.

5.2

Inspection Findings

No events were identified that required emergency plan entry. No inadequacies

were

identified.

6.

SECURITY

6.1

Inspection Activity

PP&L's implementation of the physical security program was verified on a periodic basis,

including the adequacy of staffing, entry control, alarm stations,

and physical boundaries.

These inspection activities were conducted in accordance with NRC inspection procedure

71707.

6.2

Inspection Findings

The inspector reviewed access

and egress controls throughout the period.

No significant

observations were made.

7.

ENGINEERING/TECHNICALSUPPORT

7.1

Inspection Activity

The inspector periodically reviewed engineering and technical support activities during this

inspection period.

The. on-site Nuclear Systems Engineering (NSE) organization, along with

Nuclear Technology (NPE) in Allentown, provided engineering resolution for problems

during the inspection period.

NSE generally addressed

the short-term resolution of

engineering problems; and interfaced with the Nuclear Modifications organization to schedule

13

modifications and design changes,

as appropriate,

to provide long-term corrective action.

The inspector verified that problem resolutions were thorough and directed at preventing

recurrences,

In,addition, the inspector reviewed short-term actions to ensure that they

provided reasonable

assurance

that safe operation could be maintained.

7.2

Inspection Findings

7.2.1

Diesel Generator Automatic Start Due to Agastat Relay Failure

On November 13, at 11:35 a.m., the "E" Diesel Generator (DG) automatically started in the

emergency run mode.

No testing or maintenance

was being performed at the time.

The "E"

DG had been previously substituted for the "A" DG.

The licensee investigated and verified

that no valid automatic (auto) start condition existed.

The "E" DG was then shutdown.

The

DG auto start was reported,

as required, as an ESF actuation.

The licensee investigated and found that a normally energized Agastat (EGP series) relay

deenergized

causing the "E" DG auto start,

This relay (4ESS1) and its Unit 2 counterpart

(4ESS2) were replaced.

Post-maintenance

testing and an operability run was satisfactorily

performed.

The "E" DG was then returned to an operable status in its standby condition.

The inspector observed portions of the replacement relay installation and questioned various

licensee personnel on the event.

The inspector observed maintenance

personnel bench test

the replacement relay.

The licensee tested all of the contacts to verify less than one ohm

resistance

between them.

Some of the contacts exhibited higher than expected resistance

(20-

70 ohms) which indicate the contact faces had oxidized.

To remove the oxidation, these high

resistance

contacts were first electrically burnished,

and, ifnecessary,

mechanically

burnished to achieve the one ohm target.

The relay was then installed into the "E" DG.

The

failed relay was removed and held pending shipment offsite for failure analysis.

The

inspector noted that the maintenance

personnel were very knowledgeable and followed their

work plan.

The failed Agastat was approximately seven months old at the time of failure.

The licensee is planning on sending the failed relay to an independent laboratory to determine

the specific failure mechanism.

The inspector reviewed the licensee's preventative maintenance program for periodic Agastat

relay replacement

and found that it only specifically addressed

safety-related relays in a harsh

environment as a part of their equipment qualification (EQ) program,

Non-EQ safety-related

relays had no periodic replacement interval.

The inspector questioned

the licensee on their

review of NRC Information Notice (IN) 84-20, Service Life of Relays in Safety-Related

Systems since it recommended

Agastat relay replacement on definite intervals.

This IN was

issued to inform industry of earlier than anticipated end-of-service-life failures for Agastat

relays at the Grand Gulf Nuclear Station.

As a result of these failures, Amerace (the parent

company of Agastat relays) and General Electric (GE), performed additional testing and

concluded that the qualified life for all Agastat GP series relays (GP, FGP and EGPD

series), that are operated in a normally energized

state was 4.5 years.

Normally deenergized

14

V

relays were to have a 10 year lifetime. In the licensee's review of this IN, they disagreed.

with the 4.5 year lifetime since they believed it was based on an interpolation of an

~ Underwriter's Lab (UL) non-test based lifetime while their lifetime figures were based on

extrapolation of testing on melamine breaker material.

Thus, they established

a 10 year

lifetime for all Agastat GP relays not addressed

by their EQ program.

Recently, the'licensee

changed their service life to 4.5 years as a result of degradations

seen due to thermal aging.

'n

addition, in a November 9, 1992 memoranda (PLI-72840), an Agastat replacement

program was initiated.

The licensee identified the need to replace 183 Agastat relays for

safety related-active and nonsafety related-critical (to plant operations) applications.

This

replacement

schedule omitted diesel generators

Agastats which willbe addressed

separately.

The inspector noted that the licensee recently established

service lifetimes for certain non-EQ

safety related Agastats.

However, the inspector questioned the licensee's delay in

recognizing the need for such a program when it was clearly an identified priority in IE

Bulletin 84-02, HFA Relays, and Information Notice 84-20, Service Life for Safety Related

Relays.

Over the past nine years, since issuance of the IN, there have been numerous

Agastat relay failures due to thermal aging.

For the most part, the licensee has treated these

failures as isolated occurrences.

These generic communications emphasized

the need for the

licensee to establish service lifetimes for various safety related relays.

The licensee has

agreed to track replacement of the 183 safety related relays (SOOR 1-92-345) and will

review the need for the establishment of additional service lifetimes for other safety related

relays.

The inspector willcontinue to monitor the licensee's relay replacement activities.

The inspector had no further questions at this time.

8.

SAFETY ASSESSMENT/QUALITY VERIFICATION

8.1

Licensee Event Reports

The inspector reviewed LERs submitted to the NRC office to verify that details of the event

were clearly reported, inclu'ding the accuracy of the description of the cause and the

adequacy of corrective action.

The inspector determined whether further information was

required from the licensee, whether generic implications were involved, and whether the

event warranted onsite followup. The following LERs were reviewed:

.@nit

1

92-017-00

"Reactor Scram When Main Turbine Tripped Due to Failed Relay in

Feedwater High Level Trip Logic"

On November 12, 1992, with Unit 1 operating at 100%, a reactor protection system

actuation occurred when the main turbine tripped during surveillance testing on the feedwater

control system.

The turbine control valves closed and automatic reactor scram occurred per

'15

design.

The licensee determined the turbine trip was caused by a failed AGASTAT relay in

the Feedwater "C" High Level Turbine Trip Channel coincident with surveillance testing of

the Reactor Feedwater "A" High Level Turbine Trip Channel.

Section 2.2.1 pertains.

r

92-048-00-

"Unplanned ESF Actuations - "E" Diesel Generator Automatic Start"

On November 12, 1992, an unplanned ESF actuation o'ccurred when the "E" Emergency

Diesel Generator (EDG) automatically started in the emergency run mode.

The

licensee'etermined

the cause was failure of a normally energized AGASTAT relay in EDG's

emergency start circuit.

Section 7.2.1 pertains.

Unit 2

92-005-00

"Residual Heat Removal Shutdown Cooling Isolation - Unplanned ESF

Actuation"

On October 26, 1992, at 10:50 a.m., with Unit 2 in Condition 4, an unplanned ESF

actuation occurred during modificatio'n and testing of the containment isolation system.

The

unplanned ESF actuation occurred while a technician was attempting to land a lead in the

containment isolation logic with adjacent portions of the system energized.

The lead was

inadvertently grounded when it slipped out of the technicians hand which resulted in blowing

a fuse in the logic scheme.

The loss of logic power deenergized

a relay which caused RHR

shutdown cooling inboard isolation valve and the RHR injection valve to close causing the

RHR pump to trip.

Operations personnel followed the procedure for Loss of Shutdown

Cooling.

The subject lead was landed and the blown fuse replaced.

The licensee restored

shutdown cooling at 11:40 a.m..

Reactor'oolant temperature

increased 5'F while shutdown

cooling was lost.

The licensee deter'mined the cause of the event was inadequate accessibility

making the task physically difficultto perform.

The licensee is evaluating the work

authorization program with regard to, working energized

schemes

in certain plant systems

depending on specific plant conditions.

No significant observations

were made.

8.2

.Open Items

8.2.1

(Closed) NC4 50-387/90-08-01, Inadequate Corrective Actions To Prevent

Recurring Late. Event NotiTications To The NRC

On April 17, 1990 the control room indication for HD-17502A, a secondary containment

heating, air conditioning, and ventilation (HVAC) isolation damper was lost.

The operators

decided that ifthe damper was inoperable, it would be a degradation in secondary

containment integrity and therefore entered the applicable 4-hour LCO.

Personnel

dispatched

to investigate found that the normally open damper had cycled to its closed position.

16

Instrumentation and Control (1&C) technicians were called to trouble shoot and repair the

damper.. After one failed repair attempt, the damper was successfully returned to service on

April 18.

During a post event review on April23, the licensee determined the HVAC isolation damper

cycling closed constituted an ESF actuation.

PP&L then made a "4-hour" NRC notification

for the ESF actuation,"5 days and 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after the event.

This was the third instance of

late licensee identification and NRC notification of ESF actuations in eight months.

The

licensee's corrective actions following late notifications in August and September

1989 were

not effective and did not preclude the third instance of late NRC notification. The NRC

documented

this violation in Inspection Report 50-387/90-08.

f

The licensee's

response

to the violation admitted the three ESF actuations were not reported

within the time frame required by 10 CFR 50.72(b)(2)(ii). However, PP&L stated their

methodology for classifying a failure that cycles an ESF component,

as a reportable ESF

actuation, is extremely conservative.

The HVAC damper closed because of a component

failure (the damper's solenoid valve) and not because of a valid logic signal.

The licensee

also stated that inconsistent application of their methodology for classifying failures was the

reason for the violation. As corrective action PP&L developed formal guidance to assist

~

~

operators in evaluating events for reportability as unplanned ESF actuations.

In addition,

'

licensee personnel have received training on the use of this guidance.

F

The inspector reviewed the licensee's

response

to the violation and the ESF actuation

reportability guidelines which the licensee approved on August 21, 1990.

The inspector

identified no problems with either the response or the guidelines.

The inspector noted that

since PP&L started using the reportability guidelines, they have become more consistent in

reporting ESF actuations.

The inspector concluded that the licensee has taken appropriate

actions in response

to the violation and that this item is closed.

9.

MANAGEMENTAND EXIT MEETINGS

9.1

Resident Exit and Periodic Meetings

The inspector discussed

the findings of this inspection with station management

throughout

and at the conclusion of the inspection period.

Based on NRC Region I review of this report

and discussions

held with licensee representatives,

it was determined that this report does not

contain information subject to 10 CFR 2.790 restrictions.

17

9.2

PP&L Emergency Protective Guidelines Meeting

On December

18, 1992, PP&L and NRC management

met in the NRC Region I office to

discuss differences between PP&L's latest revision of emergency operating procedures

(EOPs) and the BWR owners group (BWROG) Emergency Protective Guidelines (EPG),

Revision 4.

Attachment 2 is the list of meeting attendees

and Attachment 3 is a copy of the

slides used by PP&L during the meeting.

PP&L plans to implement their new EOPs on December 31, 1992.

The latest revisions are

based on the BWROG EPG, Revision 4, and the Susquehanna

Individual Plant Evaluation.

18

ATTACHMENT'1

Ab reviation List

AD

ADS

ANSI

ASME

CAC

CFR

CIG

CRDM

CREOASS

DG

DX

ECCS

EDR

EP

EPA

EQ

ERT

ESF

ESW

EWR

FO

FSAR

HVAC

IERP

ILRT

I&C

JIO

LCO

LER

LLRT

LOCA

-LOOP

MSIV

NCR

NDI

NPO

NQA

NRC

NSE

- Administrative Procedure

- Automatic Depressurization

System

- American Nuclear Standards Institute

- American Society of Mechanical Engineers

- Containment Atmosphere Control

- Code of Federal Regulations

- Containment Instrument Gas

- Control Rod Drive Mechanism

- Control Room Emergency Outside Air Supply System

- Diesel Generator

- Direct Expansion

- Emergency Core Cooling System

- Engineering Discrepancy Report

- Emergency Preparedness

- Electrical Protection Assembly

- Environmental Qualification

- Event Review Team

- Engineered

Safety Features

- Emergency Service Water

- Engineering Work Request

- Fuel Oil

- Final Safety Analysis Report

- Heating, Ventilation, and Air Conditioning

- Industry Event Review Program

- Integrated Leak Rate Test

- Instrumentation and Control

- Justifications for Interim Operation

- Limiting Condition for Operation

- Licensee Event Report

- Local Leak Rate Test

- Loss of Coolant Accident

- Loss of Offsite Power

- Main Steam Isolation Valve

- Non Conformance Report

- Nuclear Department Instruction

- Nuclear Plant Engineering

- Nuclear Plant Operator

- Nuclear Quality Assurance

- Nuclear Regulatory Commission

- Nuclear Systems Engineering

19

OI

OOS

PC

'CIS

PMR

PORC

PSID

QA

~

RBCCW

RCIC

RG

RHR

RHRSW

RPS

RWCU

'SGTS

SI

SJAE

SO

SOOR

SPDS

SPING

TS

TSC

WA

- Open Item

- Out-of-Service

- Protective Clothing

- Primary Containment Isolation System

- Plant Modification Request

- Plant Operations Review Committee

- Pounds Per Square Inch Differential

- Quality Assurance

- Reactor Building

- Reactor Building Closed Cooling Water

- Reactor Core Isolation Cooling

- Regulatory Guide

- Residual Heat Removal

- Residual Heat Removal Service Water

- Reactor Protection System

- Reactor Water Cleanup

- Standby Gas Treatment System

- Surveillance Procedure,

Instrumentation and Control

- Steam Jet Air Ejector-

- Surveillance Procedure,

Operations

- Significant Operating Occurrence Report

- Safety Parameter Display System

- Sample Particulate, Iodine, and Noble Gas

- Technical Specifications

-- Technical Support Center

- Work Authorization

20

ATl'ACHMENT2

MANAGEMENTMEETING TO DISCUSS SUSQUEHANNA

DIFFERENCES RELATIVETHE BWROG EPG, REVISION 4

Attendees on December

18, 1992

Penns

lvania Power and Li ht

m an

G. Stanley, Superintendent of Plant

G. Jones, Manager, Nuclear Engineering

J. Kenny, Supervisor, Nuclear Licensing

R. Peal, Supervisor, Nuclear Compliance

G. Butler, Supervisor,

Systems Analysis

A. Fitch, Supervisor,

Operations Training

R. Wehry, Compliance Engineer

R. Lemgel, System Engineer

M. Chaiko, Project Engineer

C. Kickielka, Senior Project Engineer

Nuclear Re ulato

Commission

L. Bettenhausen,

Chief, Operations Branch, Division of Reactor Safety (DRS)

E, Wenzinger, Chief, Reactor Projects Branch 2, Division of Reactor Projects (DRP)

C. Miller, Project Director, PD I-2, Office of Nuclear Reactor Regulation (NRR)

J. White, Chief, Reactor Projects Section 2A, DRP

R. Conte, Chief, BWR Section, DRS

T. Walker, Senior Operations Engineer, DRS

D. Florek, Senior Operations Engineer, DRS

C. Sisco, Operations Engineer, DRS

B. McDermott, Reactor Engineer, DRP

Qther

D. Ney, State of Pennsylvania,

DER, Nuclear Engineer

ATTACHMENT 3

INTRODUCTION

WHY WE'E HERE - EOP'S.

HISTORY OF EOP'S AT SSES.

II ~

HOW WE DEVELOP EOP'S

III. HOW WE ARE IMPLEMENTINGREV 4 EOPS.

DIFFERENCES BETWEEN SSES AND OTHER

SITES.

HISTORY

FIRST EOPS

PROSE.

AUGUST, '1985

REV 3 FLOWCHARTS

DECEMBER, t 992

REV 4 FLOWCHARTS

OPERATOR

BWROG

SSES

REV.

3

EOP'S

SSES

'IPE

SSES

DESIGN

INP UTS

SYSTEM

ENGINEERS

AN ALYZE

8c

IDENTIFY RISKS

OPTIONS

TO

MINlMl2 E

R ISKS

EOP'S

STRATEGY

TRAINING

PLANT

MODS

EQUIP MENT

OUTAGES

WRITE PROCEDURES

REV,IEW

TRAINING

VALIDATION

REVISION

IMPLEMENT

IMPLEMENTATlON

SCHEDULE

1 2/31/92

DEVlATlONS

1 PERFORMANCE

4 CONTENT

PERFORMANCE

PPSL'S APPROACH IS DELIBERATE,

METHODICALADHERENCE TO EOP

FLOWCHARTS

ENHANCES PROBABILITY FOR, ERROR-FREE

PERFORMANCE

REDUCES NEED TO RECOVER FROM

PERFORMANCE ERRORS

TIME CRITICAL

VS

OBSERVED PARAMETERS

EOP'S ARE PART OF RISK MANAGEMENT

~

BASED ON BWROG EPG REV 4 AND OUR IPE

REV 4 EOPS

1 2/31/92

REVIEWED.

TRAINED

VALIDATED

e

DEVIATIONS

FEW

MINOR IN NATURE

IIVlPROVE OUR PLANT SPECIFIC RISK

PROFILE

PPRL EOP PROGRAM

SUSQUEHANNA SPECIFIC STRATEGY

~

RISK ASSESSMENT INFLUENCED EOPS

4

REVIEWS CONDUCTED IN TWO PROGRAMS:

EOP PREPARATION

IPE REVIEWS

~

ATWS EVENT STUDY GENERATED

DIFFERENCES:

SSES ANALYSES SHOW POOR REA'CTOR

BEHAVIOR FOR:

LOW WATER I EVEL OPERATION

LOW PRESSURE OPERATION

PPRL EOP PROGRAM

SSES'SPECIFIC

EOP DIFFERENCES

4

USE OF HPCI DURING DEPRESSURIZATION

REDUCED OPERATOR CHALLENGE

IMP ROVED H PC I RELIABILITYTHRO UG H

TRANS lENT

PREFERRED SOURCE OF MAKEUP

MINIMALINCREASE IN CONTAINMENT

HEATING

J

ATWS STRATEGY

PPRL EOP PROGRAIVI

SPECIFIC EOP DIFFERENCES

0

REACTOR WATER LEVEL MAINTAINED

BETWEEN -110" AND -80" (TAFI -161")

QUESTIONABLE STABILITYREGION-

AVOIDED

WATER LEVEL CONTROL IMPROVED

ENHANCED BORON MIXING

ENHANCED WATER LEVEL INDICATION

IN CR

CONSISTENT DIRECTION

INCREASED CONTAINMENTHEAT

LOADS

ATWS STRATEGY

PPRL EOP PROGRAIVl

SPECIFIC EOP DIFFERENCES

RPV DEPRESSURIZATION NOT FORCED BY

HEAT CAPACITY TEMPERATURE LIMIT

(HCTL) APPROACH

AVOIDS LOW PRESSURE REGION

REDUCED CONTAINMENTTHREAT FOR

MOST SCENARIOS

INCREASED CONTAINMENTTHREAT FOR

ONE SCENARIO

ATWS STRATEGY

ppg L Eap PROGRAlvl

SPECIFIC EOP DIFFERENCES

4,

HCTL IS NOT RESTRAINED BY SUPPRESSION

POOL DESIGN TEMPERATURE

HIGHER TEMPERATURE LIMITS REFLECT

LIMITINGCONTAINMENTPRESSURE AT

'ND

OF DEPRESSURIZATION.

SRV QUENCHER LOADS HAVE BEEN

FOUND TO ACTUALLYDECREASE WITH

INCREASING POOL TEMPERATURE.

PPRL EOP PROGRAM

SUMMARY

~

GENERALL'Y CONSISTENT WITH EPG REV 4

LIMITEDAREAS OF DIFFERENCE

ATWS STRATEGY

HCTL BASIS

~

EACH DIFFERENCE THOROUGHLY ANALYZED

~

PPBcL CONTINUES TO IMPROVE ITS EOP'S

SUIVllVIARY

1

t

~

EOP'S ARE PART OF RISK.MANAGEMENT

t

e

BASED ON BWROG EPG'REV 4 AND OUR IPE

9

REV 4 EOPS

1 2/31/92

REVIEWED

TRAINED

VALIDATED

DEVIATIONS

FEW

MINOR IN NATURE

IMPROVE OUR PLANT SPECIFIC RISK

PROFILE