ML17157C044

Insp Repts 50-387/92-22 & 50-388/92-22 on 920818-0928. Violations Noted.Major Areas Inspected:Plant Operations, Radiation Protection,Surveillance & Maint & Safety Assessment/Quality Verification

ML17157C044
Person / Time
Site:	Susquehanna
Issue date:	10/21/1992
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17157C042	List: ML17157C041 ML17157C043 ML17157C044
References
50-387-92-22, 50-388-92-22, NUDOCS 9210270109
Download: ML17157C044 (53)

See also: IR 05000387/1992022

Text

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

Inspection

Report Nos.

50-387/92-22; 50-388/92-22

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:

August 18, 1992 - September 28, 1992

Inspectors:

G. S. Barber, Senior Resident Inspector, SSES

D. J. Mannai, Resident Jnspec r~ES

B. C. Westreich, R

or En

ee

Approved By:

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te, Chief

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ctor Projects Section No. 2A,

Date

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during day and backshift hours of station activities including: plant operations; radiation

protection; surveillance and maintenance;

and safety assessment/quality

verification. Three

violations were identified.

One violation involved removal of insulation from safety related

equipment without a documented procedure which is a violation of Technical Specification 6.8.1.

Section 4.4.2 pertains.

Two violations concerning a design change to the Control

Structure Chilled Water System occurred.

One violation concerned failure to perform post

maintenance testing in accordance with PP&L's procedure AD-QA-482. The other violation

concerned

the failure to complete a required 10 CFR 50.59 safety evaluation for a change to

the facility. Subsequently,

the licensee returned the system to the original configuration

(without the orifice) and verified that proper flow was achieved.

Section 7.2.1 pertains.

Findings and conclusions are summarized in the Executive Summary.

Details are provided in

the full inspection report.

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'721027010'P

921022

PDR

ADOCK 05000387

8

PDR

EXECUTIVESUMMARY

Susquehanna

Inspection Reports

50-387/92-22; 50-388/92-22

August 14, 1992

- September 28, 1992

Operations (30702, 71707, 71710)

During the period, a trip of the Unit 1 "B" Reactor Recirculation Pump Occurred.

A

momentary power spike of 108% occurred on the Average Power Range Monitor (APRM)

indications during the first few seconds of the transient.

The licensee determined

a Peak

Core.Thermal Power of 100.2 percent.

The licensee methodology utilized GETARS

simulated thermal power points to determine peak power during transients since APRM

indication overpredicts thermal power increase during overpower events.

During overpower

events neutron flux leads reactor heat flux because of the inherent six second delay in

transferring heat to the coolant.

The inspector determined the licensee's methodology to be

sound.

Section 2.2.1 pertains,

One engineered

safety feature actuation occurred during the period.

A loss of shutdown

cooling occurred when the outboard isolation valve went closed.

Shutdown cooling was

promptly restored.

The licensee did not determine the cause.

Section 1.3 pertains.

Maintenance/Surveillance

(61726, 62703)

During the period, on a routine tour, the inspector identified that insulation was removed

from High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC)

systems with Unit 2 operating at power without a prescribed procedure or operations

authorization.

As a result, equipment in these area was exposed to elevated temperatures.

.Because there was no procedure,

the potential effects of these temperatures

were unanalyzed.

The inspector determined that this uncontrolled maintenance activity on safety related

equipment was a weakness.

This is an apparent violation of Technical Specification 6.8.1.

Section 4.4 pertains.

During the period, the licensee identified potential problems with Resistance Temperature

Detectors (RTDs) used to determine suppression pool temperature.

Five of the fifteen RTDs

exhibited unacceptable drift during in-situ testing during the Unit 1 Refueling Outage in the

Spring of 1992.

The licensee believed moisture entrainment may have caused excessive

buildup of voltage to ground, at the sensing element, resulting in the observed drifting. The

licensee is evaluating reportability per 10 CFR 21.

During the period, the "A" Emergency Switchgear Room Cooling (ESRC) system was

declared inoperable due to inadequate cooling water flow from.the "A" Control Structure

(CS) Chilled Water System.

At the time, the "B" Control Structure Chilled Water System

was out-of-service to install a flow orifice which had been previously installed in the "A"

system.

The "B" train was restored to service prior to exceeding the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Limiting

Condition for Operation (LCO). A design change was performed to install an orifice in a

location that previously had one. The original orifice was removed by a previous design

change.

The new orifice was being installed to allow system flow measurement.

The design change to install the new orifice was performed as resolution of a Noncon-

formance Report (NCR).

This design change altered -system design flow rate.

The orifice

was installed on the "A" CS Chilled Water on August 2 and the system was returned to an

operable status without performing post-maintenance

testing to check system flow rate.

Subsequent

testing revealed flow rates slightly less than the specified design flow. The

licensee failed to perform post-maintenance

testing and a safety evaluation to support the

design change.

Failure to perform the post-maintenance/modification

testing was a procedural violation of

AD-QA-482, Post Maintenance/Modification Test Program.

Failure to perform the safety

evaluation was a violation of 10 CFR 50.59.

Section 7.2.1 pertains.

The licensee discovered that 20 Unit 1 and one Unit 2 solenoid operated valves were rebuilt

using an improper 0-ring lubricant.

Petroleum Jelly was used instead of the preferred Dow

Corning (DC)-55, lubricant.

The performance history for the affected valves showed no

lubricant induced failures, and that all of the suspect valves (except for one) had been rebuilt

since March 1992.

The excepted valve, rebuilt in.early 1984, has been stroked quarterly

with no anomalies.

The licensee is confident the valves willcontinue to operate until they

are all replaced by the next refueling outage in September

1993.

The inspector found the

licensee's actions prompt and comprehensive.

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TABLEOF CONTENTS

EXECUTIVESUMMARY............ ~............... ~...........

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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

Unit 1 Reactor Recirculation Pump Trip

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RADIOLOGICALCONTROLS

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Inspection Activities

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Inspection Findings

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MAINTENANCE/SURVEILLANCE

4.1

Maintenance and Surveillance Inspection Activity

4.2

Maintenance Observations

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Surveillance Observations......... ~..........

4.4

Inspection Findings

4.4.1

Uncontrolled Safety System Insulation Removal ..

4.4.2

Suppression Pool Resistance Temperature Detector

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egradation

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EMERGENCY PREPAREDNESS......,...

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Inspection Activity...... ~........

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Inspection Findings

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6.

SECURITY

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Inspection Activity.....,.......

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Inspection Findings

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Table of Contents (Continued)

7.

ENGINEERING/TECHNICALSUPPORT................

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Inspection Activity........,..........,........

7.2

Inspection Findings

7.2.1

Emergency Switchgear Room Cooler Event

7.2.2

Improper Lubricant Used on Solenoid Operated Valves (SOV)

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8.

SAFETY ASSESSMENT/QUALITYVERIFICATION

8.1

Licensee Event Reports (LER)

8.1.1

Licensee Event Reports...........=.'.

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MANAGEMENTAND EXIT MEETINGS

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Inspections Conducted By Region Based Inspectors

9.3

Management Meeting - Federal Field Exercise 3 (FFE-3)

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Details

1.

SUMMARYOF 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

At the start of the inspection period, Unit 1 was at full power.

On August 20, the Unit 1

"B" Recirculation pump tripped from full power resulting in a reduction to 47% power.

Investigation of the pump trip revealed that lube oil pump problems caused

an increase in

recirculating pump speed and an apparent increase in indicated reactor power to 108%.

Subsequent problems with lube oil resulted in a Reactor Recirculation pump tripping.

Section

2.2 pertains.

Following evaluation of the recirculation pump trip event, at 5:00 a.m., August 21, reactor

power was increased to full power.

At 12:46 p.m., August 21, the "C" Circulating Water

Pump tripped on overcurrent on the "A" phase, causing a recirculation system runback.

The

result was a decrease

to 68% power.

Following evaluation, power was returned to 100%,

with three of four circulating water pumps in service.

On September 5, reactor power was reduced to 68% to repair a loose conduit on the 11 main

turbine control valve.

Upon completion of repairs on September 6, power was returned to

100% and remained at or near full power until the end of the period.

Other significant events which occurred during the period include:

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Both Emergency Switchgear Room Coolers were declared inoperable on August 18 requiring

entry into a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> LCO. The "B" cooler was out of service for maintenance when the "A"

cooler was declared inoperable due to insufficient flow. The "B" cooler was returned to

service prior to exceeding the LCO,

Investigation by the licensee indicated that modifications

to the "A" loop were performed contrary to the licensee's modification process,

and without

the required post-modification system test.

Section 7..2 pertains.

2

In response to NRC Bulletin 92-01 Supplement

1, the licensee declared all remaining

Thermo-Lag installations inoperable on August 31.

The licensee implemented compensatory

measures.

1.3

Susquehanna

Unit 2 Summary

Unit 2 entered the period in coastdown at 96.4% power.

On September 6, at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br />,

reactor power was reduced to 60% for the remainder of the cycle to stay within the license

fuel design window. The fifth refueling outage was commenced on September

12, when the

main generator was taken off-line at 5:30 a.m..

The mode switch was placed in Hot

Shutdown, entering Condition 3, at 7:28 p.m. on September

12 and in Cold Shutdown,

entering Condition 4, at 10:25 p.m. on September

13.

The refueling mode, Condition 5, was

entered on September

15 at 12:05 a.m..

Core offload was complete at 9:10 p.m. on

September 26.

Significant events which occurred during the period include:

At 1:46 p.m., September 26, an ESF actuation occurred when the Shutdown Cooling

(SDC) outboard isolation valve went closed and the "B" RHR pump being used for

SDC tripped.

Licensee review of the computer history and NSSSS isolation

indications revealed no abnormal conditions.

The procedure for loss of SDC was

implemented and all fuel movement was stopped.

Though an investigation was

performed, a-cause could not be determined.

Subsequently,

the NSSSS logic was

reset, the isolation valve opened,

and SDC restored.

The licensee continued to

investigate at the end of the inspection period.

On September

10, insulation was removed from HPCI and RCIC piping in preparation

for outage work. This resulted in elevated equipment room temperatures.

The work

was performed without review by Unit Coordination, and without evaluation by

system engineering to determine the impact on equipment qualification and

operability.

This work was performed without authorization from any responsible

department.

Subsequent

analysis determined that EQ limits were not exceeded.

Section 4.4 pertains.

2.

OPERATIONS

2.1

Inspection Activities

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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 36.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of deep backshift inspections during the period.

These

deep backshift inspections covered licensee activities between 10:00 p.m. and 6:00 a.m. on

weekdays,

and weekends and holidays.

2.2

Inspection Findings and Review of Events

2.2.1

Unit 1 Reactor Recirculation Pump Trip

On August 20, the Unit 1 "B" Reactor Recirculation Pump tripped when the reactor

recirculation pump motor generator (MG) set tripped, following a trip of the "B" 2 lube oil

pump.

The "B" 1 lube oil pump automatically started as designed.

The operators promptly

performed the actions of off-normal procedure ON-164-002, Loss of Reactor Recirculation

Flow.

CRAM rods (pre-defined high reactivity control rods) were inserted following the

recirculation pump trip to reduce power.

Additional rods were inserted to reduce power

below the 80% rod line.

The licensee verified proper core power and flow were achieved for

the condition. 'The licensee was unable to restart the "B" 2 lube oil pump, but since the "B"

1 lube oil pump was already running, the "B" reactor recirculation pump was successfully

restarted.

Following, the licensee performed a transient review and determined no thermal

limits were exceeded.

A review of the General Electric Transient Analysis Recording System (GETARS) Data

indicated that average power range monitor (APRM) indication momentarily increased from

95 to 108% power during the first few seconds of the transient.

Control room operators did

not 'observe any Local Power Range Monitor (LPRM) upscale lights on the full core display.

The licensee determined that peak core thermal power (heatflux) did not exceed 100.2%.

The inspector questioned the licensee on how a peak core thermal power of 100.2% was

determined.

The licensee described an off-normal procedure for reactor power greater than

100% (3293 MWth). The procedure requires the shift technical adviser (STA) to determine

peak core thermal power using GETARS ifit is suspected

that reactor thermal power

exceeded

102% (3358 MWth) of rated thermal power.

Since APRMs indicated 108% the

STA implemented the procedure.

The licensee determined peak thermal power during transients using simulated thermal power.

The simulated thermal power is obtained by using APRM neutron flux signals through a

filtering network with a six second time constant which is representative of fuel

characteristics.

During power increase events neutron flux leads reactor heat flux because of

the fuel time constant.

Thus APRM neutron flux overpredicts thermal power during power

increase events.

This methodology is supported in General Electric Service Information

Letter (GL SIL) No. 158.

This calculation determined that thermal power peaked at 100.2%.

The inspector determined that the licensee's methodology used to ensure compliance with

licensed thermal power appeared

sound.

The inspector observed that the procedure should

contain the steps to determine peak core thermal power rather than simply reference

documents which contain the methodology.

The licensee agreed to a procedure change to

explicitly describe the methodology for determining peak core thermal power in the off-

normal procedure.

The inspector had no further questions.

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.

No

inadequacies

were noted.

4.

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 following 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

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.

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These observations and/or reviews included:

WA 23026, Installation of Vent Tubing on the "A" Emergency Diesel Generator

Injector Drains, dated August 20.

WA 20068, Control Structure Chiller Oil Leak Repair, dated August 22.

WA 13829, Residual Heat Removal PSV Replacement Setpoint Test, dated September

9.

WA 26265, Primary Containment Accident Range Pressure Transmitter internal

wiring inspection, dated September 9.

4.3

Surveillance 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:

SO-156-001, Weekly Exercising Control Rods for Operability, dated August 22.

SO-149-002, Residual Heat Removal (RHR) System Quarterly Flow Surveillance,

dated August 27.

SI-255-302, Eighteen Month Calibration of Control Rod SCRAM Accumulator Leak

Detectors, dated September

14.

4.4

Inspection 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'roperly

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.

Except as noted below, the inspectors had no further questions on

the listed activities.

4.4.1

Uncontrolled Safety System Insulation Removal

On September 9, during a tour of the Unit 2 emergency core cooling pump rooms, the

inspector noted elevated Reactor Core Isolation Cooling (RCIC) and High Pressure Coolant

'njection (HPCI) system room temperatures.

Unit 2 was at 60% power at the time.

The inspector discovered that insulation was being removed from steam piping in preparation

for the upcoming outage starting September

12.

Maintenance personnel had removed and

were removing insulation from HPCI and RCIC steam piping, valve and pumps.

The inspector contacted the system engineer to assess

the licensee's evaluation of the

connection between insulation removal and increased area temperatures.

The system engineer

was not aw'are of any insulation removal from steam piping and other components.

In response to the inspector's questioning, the licensee later determined that insulation was

being removed from safety related equipment by an uncontrolled station work practice that

allowed removal without review or approval by either plant scheduling (unit coordination) or

operations.

The licensee subsequently

documented this undesirable work practice in

Significant Operating Occurrence Report (SOOR) 2-92-087.

Further, no engineering evaluation was requested or performed by systems engineering to

assess

the impact of premature insulation removal on equipment qualifications or system

operability.

To address the potential safety concerns,

the work group reinstalled all removed installation.

The HPCI and RCIC.room coolers were operated to reduce room temperatures.

The licensee

determined that since room temperatures

did not exceed the environmental qualification (EQ)

limit and since the duration of the elevated temperatures

was short, equipment operability was

not affected.

Maxiinum HPCI room temperature reached was 105'F and RCIC room

temperature reached was 114'F.

The HPCI EQ limit was 112'F, while the RCIC EQ limit

was 123'F.

The inspector noted that the work performed was accomplished without the use of an

approved procedure nor was it controlled in accordance with either NDAP-QA-306,

System/Equipment

Release, or AD-QA-502, Work Authorization System.

The inspector

determined that the conduct of maintenance activities that removed insulation required by

design from safety related equipment without an approved procedure or instruction was a

weakness.

Technical 6.8.1 requires that safety related activities be performed in accordance

with approved procedures.

This lack of control of maintenance activities was of particular

concern.

The inspector concluded that the actual safety significance was minimal since

temperatures did not exceed the EQ limit. However, the potential was significant as

uncontrolled maintenance

was performed on safety related equipment. This was a violation of

TS 6.8.1 which requires that instructions or procedures be established for work on safety

related equipment.

(VIO 50-388/92-22-01).

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4.4.2

Suppression Pool Resistance Temperature Detector (RTD) Degradation

On August 25, the licensee informed the inspector of a potential problem with resistance

temperature detectors (RTDs) used for suppression pool temperature.

Five of the fifteen

RTDs exhibited unacceptable drifting during in-situ testing performed during the Spring

1992, Unit 1 refueling outage.

This potentially nonconforming condition was documented in

Nonconformance report (NCR)92-058 on March 19.

This NCR was forwarded for a

reportability evaluation on May 1.

The licensee believed the problem may have been related

to moisture entrainment in the RTD which results in an excessive build-up of voltage to-

ground within the circuitry. This voltage buildup resulted in the observed drifting.

The RTDs are manufactured by Hy-Cal Engineering of El Monte, California. The licensee

believes only one lot is affected, and involves a new design containing an additional layer of

insulation on the RTDs (Model No. RTS-4096-B-A-100-C-290-3-12-XI-M3).

The licensee's

initial testing identified the degradation.

Subsequent

testing by the vendor has shown less of

a voltage buildup to-ground.

The licensee and vendor are considering the collective impact

of their respective testing.

The licensee is also evaluating reportability per 10 CFR 21.

The inspector questioned the licensee on the differences between their results and those of the

vendor.

The licensee stated that entrained moisture within the RTD disassociates

the

magnesium oxide coating and forms an electrolytic cell which acts as an internal battery.

'he removal of the RTD from service allows this effect to dissipate with time.

Thus, the

testing results seen by the vendor and by the licensee are explainably different. After further

discussion the licensee agreed to informally report this nonconforming condition.

The

licensee documented their conclusions in an August 26 submittal (PLA-3842) to the NRC,

and initiated actions to report the event in accordance with 10 CFR 21.

The inspector had no

further questions.

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 significant observations

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 noted.

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 problems

and scheduled modifications and design changes, by the Nuclear Modifications organization

as appropriate, to provide long term problem correction.

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

Emergency Switchgear Room Cooler Event

On August 18, with Unit 1 at 100% power and Unit 2 at 96% power, the "A" Emergency

Switchgear Room Cooling (ESRC) System was declared inoperable due to inadequate flow

through the "A" Control Structure Chilled Water System.

At the time "B" Control Structure

Chilled Water was out-of-service to install a flow orifice which had previously been installed

in the "A" Control Structure Chilled Water System.

As a result, both trains of ESRC were

inoperable which required the licensee to enter a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> LCO. The "B" train was returned

to service prior to exceeding the LCO. With both systems unavailable, this condition could

have prevented the fulfillmentof the affected rooms safety functions for systems needed to

safely shutdown the reactor and maintain it in a safe shutdown condition.

The licensee made

the required NRC notification per 10 CFR 50.72.

The licensee performed an investigation of the, event and determined the following sequence

of events:

~

In July 1991, Operations requested

that Engineering investigate the need to maintain

locked valves in the Control Structure Chilled Water System.

Operations was

interested in reducing the number of locked valves required to be maintained.

To

assist in accomplishing this, Engineering decided to check system flow to verify the

last flow balance.

When attempting to measure flow in the ESRC system, the licensee

discovered that a flow orifice was not installed as indicated on the system drawings.

In August 1991, PP&L determined that a design change initiated in June 1982 by

Bechtel, to remove the orifice had not been fully incorporated into all drawings.

The

design change, Startup Field Request (SFR) 2923, had been issued because

calculations showed the design flow rate of 49 GPM could not be maintained with the

orifice installed,

This explained why the orifice was shown on the system drawing,

but not installed in the system,

In September

1991, the licensee determined that in order to measure system flow, the

orifice should be reinstalled.

Flow measurements

were 34 gpm for the "A" ESRC

and 28.5 gpm for the "B" ESRC.

New calculations were performed which showed

that the system required 29 gpm to perform its cooling function.

Engineering changed

the design flow rate for the Control Structure Chilled Water to the Emergency

Switchgear Room Cooling Coil accordingly.

In November 1991, a Nonconformance Report (NCR) was issued to document the

drawing discrepancies.

The NCR resolution instructed changing all drawings to

reflect that a new orifice was to be installed.

The work was to be controlled by three

work authorizations (WAs): one for fabrication, one for installation, and one for post

installation fiow testing.

The completion of all three Work Authorizations was not

required prior to returning the system to service.

On August 2, 1992 the'newly fabricated orifice was installed in the "A" Control

Structure Chiller System and the system was declared operable.

A post modification

flow test was not performed.

On'ugust 12, 1992 the "B" Control Structure Chiller was taken out of service for

maintenance.

On August 18, the WA for installing the "B" orifice was brought to Unit Coordination

and the lack of a specified retest was questioned.

The system engineer also noted that

the retest WA was not directly tied to the installation WA or operability of the system,

and realized that the retest had not been performed on the "A" Control Structure

Chilled Water system.

Unit coordination and system engineering deemed it necessary

to immediately obtain the flow data for the "A" subtrain.

The flow test subsequently

0

(

0

10

performed measured flow rate at 25.8 gpm.

The required flowrate was 29 gpm.

Consequently,

the "B" Control Structure Chilled Water System was returned to.-service

immediately after the discovery.

The LCO when both systems are inoperable is 12

hours.

Subsequently,

when investigating the low system flow, the orifice was removed from the "A"

system and was determined to be installed backwards.

This was indicative of an installation

error.

Final resolution of the investigation determined that the orifices should remain

removed and all documentation changed to reflect this condition.

No data was taken to

determine the flow of the system with the orifice in the correct orientation.

A minor

modification request was processed for future consideration.

The inspector's reviewed the Event Review Team (ERT) report and LER 92-013-00 and

identified the following:

~

The licensee identified that a Design Change Package (DCP) was required for

modification work instead of the NCR which was used.

Use of the DCP would have

required a 10 CFR 50.59 evaluation and increased

management control and

supervisory oversight of the performance of the modification and retest.

The use of

the NCR as -the controlling document was improper.

No retest was performed on the system prior to declaring it operable.

The licensee

investigation identified that retest requirements are not addressed

adequately on NCRs,

The NCR was reviewed by the system engineer and his supervisor, the compliance

organization, and Quality Control prior to work being performed.

It was not

identified during the review and concurrence process that the more formal DCP

process should have been used for work that involved modification to a safety related

system.

Previous licensee calculations have shown that the Emergency Switchgear would have

continued to perform its safety functions for at least 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> without the ESRC

operable, and with the likelihood of continued operation of up to 100 days.

The actual safety significance of this event was minimized since the system was only slightly

below required flow rates for a short period of time.

Licensee analysis indicated the

emergency switchgear would have continued to operate for an extended period of time with

no cooling.

However, the extent to which levels of protection and procedural controls were

bypassed

to allow this event to occur indicated a significant weakness in management control.

and oversight.

The design change was not recognized

as a modification, and thus, was not reviewed in

detail.

As a result, a required post maintenance/modification

retest was not specified or

completed in accordance with AD-QA-482, Post Maintenance/Modification Test Program.

11

After orifice installation, the system was improperly declared operable on August 2, 1992 and

returned to service without the required retest.

Subsequent post-installation testing identified

that the flow rates were slightly below acceptable levels on August 18, 1992.

This is an apparent violation of AD-QA-482, Post Maintenance/Modification Test Program,

which requires that post maintenance/modification

testing be performed after maintenance or

modifications and prior to returning a safety system to an operable status.

This procedure

provides the controls and appropriate levels of review to ensure that adequate post

modification testing is performed.

(VIO 50-387/92-22-02)

Additionally, during performance of this modification, the licensee failed to perform the '-

required 10 CFR 50.59 evaluation for making changes to the facility as described in the

safety analysis report.

This is an apparent violation of 10 CFR 50.59 which requires that a

safety evaluation be performed whenever there is a change to plant design. (VIO 50-387/92-

22-03)

7.2.2

Improper Lubricant Used on Solenoid Operated Valves (SOV)

I

Circle Seal (a valve manufacturer who supplies several solenoid valves in use at the

Susquehanna

units) was contacted by the licensee on September 2 to discuss the use of

petroleum jelly as an 0-ring lubricant.

This initial contact arose out of the licensee's review

of NRC Generic Letter (GL) 91-15 which endorsed NUREG 1275, Operating Experience

Report Feedback- SOV Problems.

This GL identified the potential effects of using improper

lubricant (such as lubricants containing hydro-carbons) on certain materials used for 0-rings

in solenoid operated valves.

The licensee identified that petroleum jelly was being used as an 0-ring lubricant for

rebuilding certain safety-related SOVs.

On September 9, nonconformance report (NCR) 92-

204 identified that the vendor manual (IOM 239) for safety related Circle Seal SOVs required

the use of petroleum jelly as an 0-ring lubricant,

IOM 239 required that petroleum jelly be

used sparingly on 0-rings when assembling the Circle Seal SOV valve bodies (SV31S-9101-

3, -4).

Electric Power Research Institute (EPRI) report NP-7414 (Pgs. 56 and 57) identified that

petroleum based lubricants (hydrocarbon based materials) should not be used with certain 0-

ring materials because

they cause swelling, softness and deterioration.

This report

documented this degradation in 0-ring materials, such as, ethylene propylene elastomers

(EPR and EPDM).

The licensee determined that, as many as, twenty valves in Unit 1 and one valve in Unit 2

may have been rebuilt with petroleum jelly applied to the 0-rings.

Consequently,

the

licensee was required to perform an operability assessment.

12

In the preliminary operability assessment,

the licensee determined that there were no

identifiable consistent trends, nor any noticeable increase in the frequency of failures, to

indicate that the use of the petroleum jelly had any deleterious effect.

The lubricant was not

required to ensure proper functioning of the valves, but was to be used as an aid for

reassembly.

This lubricant was used to ensure that flexible components would not be

distorted during re-assembly,

and would be properly seated in their respective groove or

holding restraints and be unstressed

when in their fully assembled configuration.

Based on

this assessment,

the licensee concluded that the affected SOVs were operable,

The inspector

noted the low the failure frequency as a sufficient basis for the licensee's preliminary

assessment.

Thus, their preliminary operability evaluation was acceptable.

The licensee completed their final operability assessment

on September

15. All 21 affected

valves were reviewed.

The licensee conducted a search for all available information related

to SOV failures and degradations.

Eight LERs, 50 SOORs, 25 NCRs, and all SOV related

failure WAs were reviewed.

At the conclusion of this review the licensee confirmed that no

failures had occurred at Susquehanna

as a result of improper 0-ring lubrication.

For the

subject valves, no failures have been detected which were traceable to this cause.

Allbut one

of the SOVs had been rebuilt since March 1992.

The remaining valve (rebuilt in March

1984) was stroked quarterly and has operated successfully.

The licensee plans to replace all

affected valves within the next several months.

The last three valves to be replaced are inside

containment and serve only a test function for the wetwell to drywell vacuum breakers.

They

willbe replaced during the Fall 1993 outage.

Allaffected valves are expected to be replaced

by the end of the outage.

The inspector reviewed the licensee's actions and found them to be thorough and

comprehensive.

Their SOV replacement schedule appears consistent with each valves safety

significance.

The inspector had no further questions.

0

13

8.

SAFETY ASSESSMENT/QUALITYVERIFICATION

8.1

Licensee Event Reports (LER)

8.1.1

Licensee Event Reports.

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

were clearly reported, including 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 LER was reviewed:

gott i

92-013-00

Emergency Switchgear Room Cooling Inoperable - Could Prevent Fulfillment

of a safety function.

On August 18, 1992 with both units at full power, the

"A" Emergency Switchgear Room Cooling (ESRC) was declared inoperable

due to Low Cooling Water Flow.

Section 7.2 pertains.

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.

9e2

Inspections Conducted By Region Based Inspectors

~Da e

~Sub'eet

9/21-9/25/92

Outage HP

~ln pettin

~Re

rt No

92-23

~Re ~rtin;

~ln pe~et r

J.'oggle

14

9.3

Management Meeting - Federal Field Exercise 3 (FFE-3)

On September

18, a Management Meeting was held between PP&L and the NRC to discuss

Federal Field Exercise 3 (FFE-3).

The licensee discussed their objectives, their

understanding of the overall Federal objectives and the NRC objectives for FFE-3.

PP&L

also presented their expectations of the exercise.

Attachment 2 lists the meeting attendees.

Attachment 3 is a copy of the PP&L management

presentation.

ATTACHMENT 1

A

reviati n Li t

AD

-A

ADS

- A

ANSI - A

'SME

CAC

- C

CFR

-C

CIG

- C

CRDM

CREOAS

DG

-D

DX

-D

ECCS -E

EDR

- E

EP

-E

EPA

- E

ERT

- E

ESF

- E

ESW -E

EWR - E

FO

-F

FSAR - F

HVAC

ILRT - I

I&C

- I

JIO

- J

LCO

- L

LER

- L

LLRT - Loc

LOCA

LOOP - Lo

MSIV - M

NCR -N

NDI

- N

NPE

- N

NPO -N

NQA - N

NRC

- N

OI

-0

OOS

- 0

PC

-P

PCIS

- P

PMR -P

dministrative Procedure

utomatic Depressurization

System

merican Nuclear Standards Institute

- American Society of Mechanical Engineers

ontainment Atmosphere Control

ode of Federal Regulations

ontainment Instrument Gas

- Control Rod Drive Mechanism

S - Control Room Emergency Outside AirSupply System

iesel Generator

irect Expansion

mergency Core Cooling System

ngineering Discrepancy Report

mergency Preparedness

lectrical Protection Assembly

vent Review Team

ngineered Safety Features

mergency Service Water

ngineering Work Request

uel Oil

inal Safety Analysis Report

- Heating, Ventilation, and Air Conditioning

ntegrated Leak Rate Test

nstrumentation and Control

ustifications for Interim Operation

imiting Condition for Operation

icensee Event Report

al Leak Rate Test

- Loss of Coolant Accident

ss of Offsite Power

ain Steam Isolation Valve

on Conformance Report

uclear Department Instruction

uclear Plant Engineering

uclear Plant Operator

uclear Quality Assurance

uclear Regulatory Commission

pen Item

ut-of-Service

rotective Clothing

rimary Containment Isolation System

lant Modification Request

,h

b

PORC - Plant Operations Review Committee

PSID

- Pounds Per Square Inch Differential

QA

- Quality Assurance

RB

- Reactor Building

RCIC - Reactor Core Isolation

Cooling'G

- Regulatory Guide

RHR

- Residual Heat Removal

RHRSW

- Residual Heat Removal Service Water

RPS

- Reactor Protection System

RWCU

- Reactor Water Cleanup

SGTS - Standby Gas Treatment System

SI

- Surveillance Procedure, Instrumentation and Control

SO

- Surveillance Procedure,

Operations

SOOR - Significant Operating Occurrence Report

SPDS

- Safety Parameter Display System

'PING

- Sample Particulate, Iodine, and Noble Gas

TS

- Technical Specifications

TSC

- Technical Support Center

WA

- Work Authorization

1

FEE-3 MANAGEMENTMEETING

July 30, 1992

A%I'ACHMENT2

Nuclear Regulatory Commission (NRC)

Thomas T. Martin, Regional Administrator, Region I

Richard W. Cooper, Director, DRSS

Charles W. Hehl, Director, DRP

, Charles L. Miller, Director, PD1-2, NRR

G. Scott Barber, NRC, Senior Resident Inspector - SSES

David J. Mannai, NRC Resident Inspector - SSES

James J. Raleigh, NRC Project Manager

Brian J. M'Dermott, Reactor Engineer, DRP

Pennsylvania Power & Light Company (PP&L)

Harry W. Keiser,,Senior Vice President - Nuclear

Robert G. Byram, Vice President - Nuclear Operations

Frederick T. Eisenhuth, Senior Engineer, Nuclear Plant Management

ATTACHMENT 3

FFE-3

MEETING WITH

NRC REGIONAL ADMINISTRATOR .

FRIDAY, SEPTEMBER 18,

1992

KING OF PRUSSIA,

PA

I.

INTRODUCTIONS

II.

FF'E-3

OBJECTIVES

III.

EXPECTATIONS

IV.

FFE-3 SPECIFIC

ITEMS

SUMMARY

HAROLD W. KEISER:

SENIOR VICE PRESIDENT - NUCLEAR

ROBERT G.

BYRAM:

VICE PRESIDENT - NUCLEAR

OPERATIONS

FREDERICK T.

EISENHUTH:

FFE-3

PROJECT

MANAGER

FFE-3

OBJECTIVES

A.

PP&L OVERALL OBJECTIVES

B.

FEDERAL OVERALL OBJECTIVES

C.

SPECIFIC

NRC

REGION I OBJECTIVES

D.

PUBLIC UNDERSTANDING AND CONFIDENCE

~

0

0

PP

L OVERALL OBJECTIVES

FOR FFE-

MONSTRATE

BLIC HEAL

FECTIVE

E

ABILITYTO

PROTECT

TH AND WELFARE THROUGH

MERGENCY RESPONSE

II.

INCREASE UNDERSTANDING OF

FEDERAL

ELEMENTS IN FULL-SCALE RESPONSE

III.

ENHANCE FEDERAL/STATE/LOCAL

RELATIONSHIPS

IV.

IMPROVE EMERGENCY .RESPONSE

V.

OVE

IDE

ARE

IMPR

CONF

PREP

PUBLIC KNOWLEDGE OF

AND

NCE IN EMERGENCY

'NESS

MEASURES

FEDERAL OVERALL OBJECTIVES

DEMONSTRATE THE ACTIVATION OF THE FRERP

INCLUDING THE

TRANSITION OF THE FEDERAL RESPONSE

FROM ONE STAGE

TO

ANOTHER.

2.

DEMONSTRATE THE FEDERAL ONSCENE

OPERATIONS

CENTER FUNCTIONS

SUCH AS INFORMATION COLLECTIONS

PROCESSZNGt

AND

DZSSEMINATION.

THE ONSCENE

OPERATIONS

CENTERS

WOULD INCLUDE

THE FEDERAL RADIOLOGICAL MONITORING ASSESSMENT

CENTER

(fRMAC) t

THE DISASTER FIELD OFFICE

(DFO) t

AND THE MEDIA

OPERATIONS

CENTER

(MOC).

DEMONSTRATE THE TIMELY AND ORDERLY

COLLOCATION OF THE FEDERAL RESPONSE

CENTERS

WHERE

APPROPRIATE.

3.

4.

DEMONSTRATE THE EFFECTIVENESS

OF THE INTERFACES

BETWEEN THE

FEDERAL AGENCIES'FFSZTE

AUTHORITIES (STATE AND LOCAL) AND

THE LZCENSEEg

AS WELL AS THE EFFECTIVENESS

OF COMMUNICATIONS

BETWEEN THESE

GROUPS.

DEMONSTRATE THE SUPPORT

OF

FEDERAL RESPONSE

EFFORTS

FOR

STATE AND LOCAL GOVERNMENTS.

5.

6.

DEMONSTRATE THE ADEQUACY OF

FEDERAL AGENCY PROCEDURES,

TRAINING, AND RESOURCES

IN ADDRESSING STATE AND LOCAL NEEDS.

DEMONSTRATE THE EFFECTIVENESS

OF KEEPING THE WHZTE HOUSE

AND

CONGRESS

INFORMED OF THE SITUATZON AND OF

FEDERAL ACTIONS

ZN

SUPPORT

OF THE STATE AND UTILITY ZN AN ONGOING EVENT.

7.

DOCUMENT THE ACCURACYt CONSISTENCY,

AND TIMELINESS OF THE

RELEASE Of PUBLIC INFORMATZON, AND THE COORDINATION OF

SUCH

INFORMATION AMONG THE FEDERAL AGENCIES'FFSITE

AUTHORITIES'ND

LICENSEE

BOTH AT THEIR ONSCENE

AND HEADQUARTERS

LOCATIONS.

8.

e'EMONSTRATE

THE ADEQUACY OF THE FEDERAL INTERAGENCY PLANS

AND PROCEDURES

fOR PERFORMING

FUNCTIONS AT FEDERAL ONSCENE

OPERATIONS

CENTERS.

THESE

FUNCTIONS INCLUDE:

ALERTING AND

UPDATING AGENCIES'ENERATING ZNZTZAL RESPONSE

DECISIONS'ND

TRACKING INITIAL RESPONSE

DECISIONS.

r

DEMONSTRATE AGENCY"DEVELOPED PLANS AND PROCEDURES

THAT

ADDRESS

THE ISSUES

OF

REENTRY,

RETURNS

RELOCATIONS

AND

RECOVERY PROBLEMS,

DEMONSTRATE THE FORMULATION OF VIABLE

SOLUTIONS.

S

10.

DEMONSTRATE THE ADEQUACY OF

PROCEDURES

FOR AD HOC ADVISORY

GROUPS

AND THEIR ABILITYTO-COORDINATE RECOMMENDATIONS WITH

THE LEAD FEDERAL AGENCY ZN SUPPORT

OF

STATE AND LOCAL

DECISIONS.

11.

DEMONSTRATE THE ABILITY OF

THE AMERICAN NUCLEAR ZNSURERS

(ANZ) TO IMPLEMENT THE PRICE"ANDERSON

LEGZSLATZON BY

ADDRESSING FINANCIAL CONCERNS

ASSOCIATED WITH THE EVENT

RESPONSE.

12."

DEMONSTRATE THE REQUEST

AND APPROVAL PROCESS

OF A

PRESIDENTIAL DECLARATION OF

EMERGENCY UNDER THE STAFFORD

ACT.

13.

DEMONSTRATE RESPONSE

CAPABILITY IMPROVEMENTS WHICH RESULTED

FROM LESSONS 'LEARNED IN EARLIER EXERCISES

OR REAL-WORLD-

EVENTS.

SPECIFIC

NRC

REGION I OBJECTIVES

EFFORTS

TO ENSURE

PUBLIC UNDERSTANDI

G AND

0 FIDE

E

~

PUBLIC AFFAIRS WORK GROUP

~

PPLL PUBLIC INFORMATION PLAN

.

~

STATE PUBLIC INFORMATION EFFORTS

PPS L EXPECTATI N

~

PARTICIPATING FEDERAL AGENCY PERSONNEL

ARE FULLY TRAINED AND QUALIFIED FOR

RESPONSE

ROLES

I

~

JOINT FACILITY FUNCTIONS ARE FORMALIZED

AND WELL UNDERSTOOD

BY RESPONDING

PERSONNEL

~

OVERALL FFE-3

PREPARATIONS

MUST ENSURE

SUCCESS

NMENTS,

OCAL GOVER

~

INTERFACES WITH

STATE,

AND UTIL

MATCH PHILOSOPH

REQUIREMENTS

OF

ORGANIZATIONS I

L

ITY ARE TAILORED TO

IES,

STRUCTURES,

AND

THE PARTICULAR

NVOLVED

~

ALL PARTICIPANTS RECEIVE ORIENTATION IN

EXERCISE

PLAY AND OBJECTIVES

EFE-3 SPECIFIC

ITEMS

A.

ROLE

OF

NRC DIRECTOR OF SITE OPERATIONS

B.

SITE

TEAM PARTICIPATION IN PPRL

PRACTICE DRILLS .

DECEMBER

,

1992

JANUARY 26,

1993

C.

ONSITE SCENARIO

~

PPLL WORKING WITH NRC

CONTRACTOR

~

FULL ONSITE

PLAY DAY 1

~

TSC

CONTROL CELL DAYS 2,3,4

D.

RECOVERY PHASE

EXPECTATIONS

~

FOCUS

OF PLAY AT DFO AND FRMAC

~

LEVEL OF

FEDERAL PLANNING

E.

FEMA INTERFACE

F.

DOE INTERFACE

lt

FFE-3 SPECIFIC

ITEMS

CONT.

G.

NRC CHAIRMAN/COMMISSIONER INVOLVEMENT

~

.

TABLETOP

~

ACTUAL EXERCISE

H.

FFE-3

CONTROL SYSTEM

I.

POST

EXERCISE

REVIEW

SUMMARY

i

~

A SUCCESSFUL

DEMONSTRATION OF

EMERGENCY

RESPONSE

CAPABILITIES IS ESSENTIAL

~

IMPROVED PLANS AND PROCEDURES

IS AN

EXPECTED BENEFIT

AND ENHANCED

~

RELATIONS WITH PUBLIC MUST BE PRESERVED

~

ALL PARTICIPATING ORGANIZATIONS MUST

WORK TO

ENSURE

SUCCESS