ML17158B940

Insp Repts 50-387/96-13 & 50-388/96-13 on 961203-970113. Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support

ML17158B940
Person / Time
Site:	Susquehanna
Issue date:	01/29/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17158B938	List: ML17158B937 ML17158B939 ML17158B940
References
50-387-96-13, 50-388-96-13, NUDOCS 9702100146
Download: ML17158B940 (69)

See also: IR 05000387/1996013

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION

I

Docket Nos:

License Nos:

50-387, 50-388

NPF-14, NPF-22

Report No.

50-387/96-1 3, 50-388/96-1 3

Licensee:

Pennsylvania

Power and Light Company

2 North Ninth Street

Allentown, Pennsylvania

19,101

Facility:

Susquehanna

Steam Electric Station (SSES)

Location:

P.O. Box 35

Berwick, PA 18603-0035

Dates:

December 3, 1996 through January 13, 1997

Inspectors:

K. Jenison,

Senior Resident Inspector

B. McDermott, Resident Inspector

K. Kolaczyk, Reactor Engineer,

DRS

Approved by:

Walter J. Pasciak, Chief

Projects Branch 4

Division of Reactor Projects

9702i00i46 970i29

PDR

ADGCK 05000387

8

PDR

EXECUTIVE SUMMARY

Sus'quehanna

Steam Electric Station, Units

1 & 2

NRC Inspection Report 50-387/96-13, 50-388/96-13

This integrated inspection included aspects of licensee operations,

engineering,

maintenance,

and plant support.

The report covers

a 6-week period of resident inspection;

in addition, it includes the results of an announced

inspection by a regional inspector.

~Oerations

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The activities performed by the operators during this inspection period were

determined to be conservative,

in accordance

with the applicable SSES procedures,

and in compliance with applicable technical specifications

(TSs).

Licensed plant

. '- control operators

(PCOs) were well able to,communicate the status of their Unit and

the rational for planned and completed actions.

One instance of excellent and two instances of weak nuclear plant operator

performance were observed/reviewed

during this inspection period.

One

performance error involved the mis-alignment of nonsafety related equipment with

the potential to impact the stable operation of Unit 2. The second issue involved

the improper coordination of a valve alignment for Unit 2 safety related equipment.

Licensee corrective actions included positive behavior modification and the

communication of the performance issues to other operating shift personnel.

The

root cause and corrective action efforts of the Operations Department employed

diverse diagnostic methods, were aggressively performed and were professionally

executed.

The interaction between PPSL management

and staff at a PORC meeting on

January 2, 1997, was viewed as constructive by the inspector.

Of import, the

interaction led to the discussion of a generic issue concerning the control of doors

for station equipment and plant areas.

Although PORC's activities were considered

positive, the inspector viewed the absence

of generic consideration for the blocked

open cabinet door in the Condition Report (CR) resolution to be a weakness

in

implementation of the corrective action process.

A conversion constant affecting the reactor water cleanup system flow value used

to calculate the average core thermal power (CTP) was not correct.

The error is

thought to have existed since initial startup of both Susquehanna

Units and results

'n

the indicated CTP being one mega-watt thermal greater than actual.

This error is

considered to be of low safety significance when compared to the licensed CTP of

3441 MW~, even when combined with other CTP calculational problems identified

in the last two years.

Exceeding the licensed CTP by a small amount was treated

as a non-cited violation.

The licensee failed to control the placement of equipment near safety related

equipment (4.16 kV switchgear) in accordance

with plant procedures.

Adequate

corrective actions were undertaken

by the licensee after the issue was identified to

them.

This constitutes

a minor violation and was treated as a non-cited violation.

Maintenance

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Hydrogen/oxygen

analyzer maintenance

activities did not completely document the

as-left condition of the equipment.

Therefore, it was not possible to determine post

maintenance

operability of the equipment without supporting discussions with the

SSES maintenance

and nuclear system engineering

personnel.

The failure to

adequately document the performance of safety related maintenance

and the basis

of equipment operability constitute

a minor violation and was treated as a non-cited

violation.

k

PP&L has a preventive maintenance

backlog reduction plan in place that is being

monitored by SSES Plant Management.

Based on a sample review of the backlog,

the inspector independently

verified the licensee's determination that no overdue

activities affect the environmental qualification of the equipment.

An undocumented

modification/replacement

of a Unit 2 standby liquid control pump

accumulator was identified by the inspector.

The licensee's

response to the

technical issue was quick and complete.

The safety impact of the identified

replacement was low because the capacity of the accumulator met its system

design requirements.

PP&L's repeated failure to provide adequate

control for high energy line break room

doors, blocked open in support of maintenance,

was considered

a violation of

10 CFR 50 Appendix B, Criterion XVI, Corrective Action.

During the performance of standby gas treatment system maintenance,

power was

returned inside a blocking permit boundary without meeting the requirements of the

licensee's tagging and permit procedures.

Although no personnel injury or

equipment damage occurred, this is considered

a violation of TS 6.8.1,

"Procedures".

~En ineerin

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Standby liquid control pump flow calibrations use unborated water as a medium.

The calibration water is discharged through a recirculation flow path. At the

completion of the test, the normal discharge flow path into the vessel is left filled

with the unborated water.

The licensee was able to produce design basis

documentation that takes into account

a 30 second delay from the time of boron

injection initiation to the time that boron actually enters the core.

These

calculations conservatively account for the unborated water left in the injection line

following the surveillance flow testing.

~

The licensee responded to a violation involving control rod drive mechanism

replacement

in a aggressive

manner.

The licensee's root cause evaluation was

aggressive

'and insightful in that it identified a number of subtle contributions to the

event, was quick in its evaluation of the event, involved a large cross section of

SSES technical expertise and was subjected to the routine high standards

of the

SSES PORC.

~

Pennsylvania

Power 5 Light (PPRL) established

a motor-operated

valve (MOV)

program that met their commitments to Generic Letter (GL) 89-10 "Safety-Related

Motor-Operated Valve Testing and Surveillance."

~

The design basis capability of MOVs was adequately

established

through the

performance of in-situ testing, analysis and most notably through use of the Electric

Power Research Institute (EPRI) Performance

Prediction Model (PPM) software.

PPSL established

a large data base of MOV performance characteristics

in tracking

and trending programs and used the information to improve MOV performance

and

detect degradation.

~

Although PP5L demonstrated

safety-related

MOVs had adequate

design margin, the

methodology PPSL used to account for the effects of load sensitive behavior (LSB)

was inconsistent with the general understanding

of the phenomenon.

Specifically,

PPRL assumed

LSB was a random occurrence when developing the switch settings

for MOVs. It is the NRC's position that industry testing has revealed LSB tends to

reduce motor actuator thrust output under dynamic conditions as a result of

increased

stem friction and, therefore, is a predictable occurrence which is valve-

specific.

~

When developing valve factors for 42 untested Anchor Darling gate valves, PPSL

used data obtained from the EPRI flow loop test program that may not be applicable

to Susquehanna.

However, re-evaluation of available valve factor showed adequate

margin.

~

The analytical approach

used to reduce the number of installed mechanical snubbers

was thorough; the design guide used was comprehensive

and provided detailed

criteria for pipe support analysis.

~

The licensee failed to adequately control health physics technician overtime during

the most recent Unit 1 outage.

In approximately 60 cases the licensee did not meet

the guidelines in Technical Specification 6.2.2, "Unit Staff." This licensee identified

and corrected violation was treated as a non-cited violation.

TABLE OF CONTENTS

EXECUTIVE

UMMARY

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TABLE OF CONTENTS';......... ~......

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I. Operations

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Conduct of Operations .................... ~............

01.1

Operator's

Response

to Transient Conditions

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01.2

Non-Licensed Nuclear Plant Operator Field Performance

01.3

Effectivene'ss of Licensee Controls in Problem Resolution

Operational Status of Facilities and Equipment ................

02.1

Core Thermal Power Calculation Errors

02.2

Storage of Transient Equipment Located Near Safety Related

Equipment

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Operations

Pi'ocedures

and Documentation

03.1

Posting of Notices to Workers

Quality Assurance

in Operations ..

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07.1

Review of Third Party Audits

Miscellaneous Operations Issues..........................

08.1

Control Rod Scram Accumulator Alarm

08.2

(Closed) LER 50-387/96-17: Non-Conservatism

in Heat

Balance Calculation

08.3

(Closed) IFI 50-387/94-19-01: Licensee's Abilityto Activate

the Backup Emergency Operating Facility (EOF)

08.4

(Closed) IFI 50-387/95-16-01: Emergency Preparedness

Training

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(Closed) LER 50-387/96-10: Main Steam Line Penetration

Leakage Rate Exceeded Technical Specification Limit ......

08.6

(Closed) LER 50-387/96-11: Secondary Containment Bypass

Leakage Rate Exceeded Technical Specification Limit ......

08.7

(Closed) LER 50-387/96-12: Missed Firewatch...........

08.8

(Update) LER 50-387/96-13: Reactor Condition Change

08.9

(Update) LER 50-388/96-09: 'D'HR Pump Failure

To Start

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M1

Conduct of Maintenance

M1.1

Review/Observation

of Maintenance Activities

IVI1.2 Surveillance Test ActivitySample Reviews

M1.3

Review of Ongoing and/or Emergent Maintenance Activities-

Unit 1 Hydrogen/ Oxygen Analyzer ............

M1.4 Observation of Major Surveillance Testing

- HPCI Quarterly

Flow Surveillance

M1.5

Review of Preventive Maintenance

Backlog .......

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Unit 2 Standby Liquid Control Pump Discharge Accumulator

M1.7

Effectiveness of Licensee Controls for Maintenance

M1.8

Effectiveness of Licensee Controls for Maintenance

I. Maintenance

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TABLE OF CONTENTS (Continued)

M2

M3

Maintenance

and Material Condition of Facilities

M2.1

Maintenance

and Material Condition of Facilities

Maintenance

Procedures

and Documentation .......

lVI3.1

Unit 2 Reactor Building, Elevation 766, Access

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Maintenance

Issues

M8.1

(Closed) Violation 50-387/96-10-02 Control Rod

Mechanism Replacement

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Drive

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E8,4

E8.5

II. Engineering

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Conduct of Engineering

E1.1

Engineering Problem Resolution

E3

Engineering Procedures

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

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Unit 2 Standby Liquid Control Pump Discharge Flow Design

Basis

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E3.2

Replacement

Item Evaluation

(RIE)

E8

Miscellaneous

Engineering Issues

E8.1

Review of the Updated Final Safety Analysis Report (UFSAR)

E8.2

(Closed) URI 50-388/95-20-01: Standby Liquid Control IST

Instrumentation

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(Update) Unresolved Item 50-387/94-14-01, 50-388/94-15-

01: pressure

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Motor-Operated Valve Program Review

Design Modification Process

and Implementation

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Radiological Protection and Chemistry (RPRC) Controls.........

R6

RP&C Organization and Administration

R6.1

Administrative Requirements for Workers Involved in Safety

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Exit Meeting Summary............

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39

Re ort Details

Summar

of Plant'Status

Both SSES Units operated at 100% power throughout this inspection period, with a few

exceptions.

Short periods of reduced power operation were made to support maintenance

and equipment related activities, and to support minimum power generation conditions on

the Pennsylvania,

New Jersey,

Maryland electrical distribution system.

I. 0 erations

01

Conduct of

Operations'1.1

0 erator's

Res

onse to Transient Conditions

a.

Ins ection Sco

e 71707

The inspector observed

and/or reviewed licensed plant control operator (PCO)

response to the following abnormal conditions:

AR 214-001, l.IPCI Barometric Condenser

Level

AR 015-001, Sodium Particulate Iodine Gas Monitor

In addition, the PCOs'esponse

to routine, immediate conditions were also

observed/reviewed.

b.

Observations

and Conclusions

The activities performed by the PCOs in the control room during this inspection

period were determined to be conservative,

in accordance

with the applicable SSES

procedures,

and in compliance with applicable Technical Specifications (TSs).

The

PCOs were well able to communicate the status of their unit and the rational for

planned and completed actions.

01.2

Non-Licensed Nuclear Plant 0 erator Field Performance

a.

Ins ection Sco

e 71707

The inspector reviewed selected aspects of nuclear plant operator (NPO)

performance during routine activities.

~'Topical headings such as 01, MS, etc., are used in accordance with the NRC standardized

v

reactor inspection report outline.

Individual reports are not expected to address

all outline

topics.

b.

Observations

and Findin s

On December 10, 1996, in support of a high pressure

coolant injection

(HPCI) system draining operation, Drain Recommendation

(DR) 252-001,

HPCI, was performed.

Step 3.4.12 was the responsibility of the PCO to

perfor'm from the control room and steps 3.4.13 and 3.4.14 were the

responsibility of the NPO to perform in the field. The NPO did not ascertain

whether step 3.4.12 was completed prior to performing steps 3.4.13 and

3.4.14.

Consequently,

the NPO performed his steps out of sequence.

This

error resulted in an abnormal alignment of the cooling water to the HPCI

barometric condenser,

a high level in the barometric condenser

vacuum tank,

and a high level alarm.

Performance of step 3.4.12 at the proper time would

have isolated the abnormal flow path by shutting valve HV-256-F059.

The

PCO took the appropriate steps in response

tc; the alarmed condition, and

Condition Report (CR) 96-2197 was issued to document the issue.

The

quick action taken by the PCO limited the safety impact of the personnel

error and did not delay the HPCI pump return to service.

The corrective

actions and root cause evaluation identified in the CR were evaluated by the

inspector and determined to be excellent.

'he

failure to control the alignment of safety related equipment in

accordance

with plant procedures

constitutes

a violation of minor

consequence

and is being treated as a non-cited violation consistent with

Section IV of the NRC Enforcement Policy. This issue is closed.

2.

On December 8, 1996, an NPO attempted to isolate the Unit 2, 'C'ervice

water pump suction valve in order to support scheduled

maintenance.

The

operator incorrectly initiqted the isolation of the Unit 2 'B'ervice water

pump.

When the 'B'uction valve came off of its open seat the control

room received an alarm "B SW PP SUCT VLVNOT FULL OPEN". The PCO

took immediate action to return the 'B'uction valve to its open seat.

The licensee determined that there was no impact on operating equipment

but, classified the event as a "near miss with potentially significant impact to

the Unit." A-human performance causal review and a root cause evaluation

were performed.

In addition, the licensee issued CR-96-2183 to affect

corrective actions.

Because of the potential safety impact from a loss of service water flow

(turbine trip, reactor trip); the inspector reviewed the event, interviewed

selected operators,

and monitored the licensee's corrective actions and root

cause evaluations.

The response

of Operations management

was quick and

extensive.

A root cause of personnel error (failure to implement the

self-checking process) was established

using two different diagnostic

methods.

=Operations management

approached

the corrective action issues

in a responsive

and professional manner.

The corrective actions, which

included positive behavior modification, were well communicated to other

Operations personnel

and were designed to prevent recurrence.

3.

On December 17, 1996, the inspector observed portions of a routine NPO

round in the Unit 2 reactor building.

The NPO performed the tasks required

by his round'sheet.

The inspector noted that the NPO verified the proper

configuration/indication

on a number of additional pieces of equipment that

did not appear on the required round sheet.

The NPO also verified the proper

operation of all fire doors traversed during the tour.

Based on observations

of this NPO tour, the inspector concluded that the NPO demonstrated

an

excellent knowledge of his responsibilities and was very observant of general

equipment conditions.

c.

Conclusions

One instance of excellent and two instances of weak nuclear plant operator

performance were observed/reviewed

during this inspectjon period.

One

performance error involved nonsafety related equipment with the potential to impact

the stable operation of Unit 2. The second issue involved the improper coordination

of a valve alignment for Unit 2 safety related equipment.

Licensee corrective

actions included positive behavior modification and the communication of the

performance

issues to other operating shift personnel.

The root cause and

corrective action efforts of the Operations Department employed diverse diagnostic

methods, were aggressively performed, and were professionally executed.

01.3

Effectiveness of Licensee Controls in Problem Resolution

~ 1

a.

Ins ection Sco

e 71707

The effectiveness of the licensee's controls in identifying, resolving, and preventing

a problem was evaluated during observation of a plant operations review committee

(PORC) meeting for approval of CR 96-2170 on January 2, 1997.

Additional

discussion

regarding PP&L's controls for problem resolution are contained

in Section

E1.1 of this report.

b.

Observations

and Findin s

PORC meeting 97-01-02B was held to review the corrective actions taken and

planned in response to PP&L's discovery (CR 96-2170) that the ground/test devices

for the 4.16 kV emergency safeguard

system

(ESS) switchgear were not considered

in the switchgear's original seismic analysis.

This issue was identified during initial

followup actions for PP&L's discovery that the 4.16 kV switchgear seismic analysis

did not assume

any breakers would be in their racked out or test positions (see

LER 50-387/96-15).

PP&L's review of how the ground/test device is used also

identified that the switchgear cubicle door can not be fully closed and latched (as

per the seismic analysis) with the device's external ground wire in use.

During the PORC review of the CR resolution, the committee raised good technical

and CR process related questions.

The blocked open switchgear cubicle door

aspect of the issue was initiallyof low visibility, however it gained significant

attention after a system engineer questioned the effectiveness of past corrective

-=

actions for similar problems.

The corrective actions proposed

in the CR 96-2170

resolution did not address whether these similar problems had been evaluated.

Plant management

recognized that the corrective action process

had not captured

several previous events related to blocked open equipment doors.

This

development was well received by plant management

and PORC's consensus

was

that additional work was required in this area.

Approval of the CR resolution was

deferred pending the resolution of PORC comments.

The inspector noted that NRC unresolved

item URI 50-387,388/95-24-01

identified

a similar problem with a blocked open cabinet door that occurred when temporary

monitoring equipment was installed on an emergency diesel generator control panel

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The report discussion noted that certain aspects of temporary equipment

installations, such as electrical separation,

seismic considerations,

and fire

protection, were not being adequately considered.

A related issue concerning

environmental qualification and the control of doors for rooms with high energy line

break (HELB) protection are discussed

in Section E2.1 of this report.

PPRL's

followup of the generic door control issue will be reviewed along with their response

to-the corrective action violation discussed

in section M1.7 of this report.

C.

Conclusions

The interaction between PPSL management

and staff at the PORC meeting on

January 2, 1997, was viewed as constructive by the inspector.

The interaction led

to reconsideration

of corrective actions for a generic issue concerning the control of

all types of doors.

Although PORC's activities were considered

positive, the

inspector viewed the absence of generic consideration for the blocked open cabinet

door in the CR resolution to be a weakness

in implementation of the corrective

action process.

02

Operational Status of Facilities and Equipment

02.1

Core Thermal Power Calculation Errors

aO

Ins ection Sco

e 71707

On December 3, 1996, PPSL identified that an analog computer point affecting the

core thermal power (CTP) calculation was indicating a lower mass flow rate than

expected.

PPS.L calculated that as a result, the CTP may be greater than expected-

by approximately 0.8 mega-watt thermal (MW~) and reported to the NRC that both

SSES Units may have exceeded their licensed CTP limits at some time since initial

startup (Reference EN¹ 31404).

The inspector reviewed this non-conservatism

in

the CTP calculation and reexamined other similar conditions reported by PPSL over

the last two years.

b.

Observations

and Findin s

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Three previous reports of errors in the calculated core thermal power were

reexamined:,

In February 1995, PP&L discovered that inaccuracies

in the Unit 2 feedwater

flow (FW) instrumentation

had resulted in a 0.8 MW error in the calculated

CTP and that on several occasions the eight hour shift average

CTP had

exceeded

the license limit of 3441 MW~. PP&L determined the cause of this

event to be errors in original instrumentation drawings that incorrectly

depicted the location of certain instrument taps.

To bound this inaccuracy

PP&L administratively restricted CTP on Unit 2 to 3440 MW . Unit 1 was

not affected by this problem.

The drawings were corrected and the FW flow

instrument was recalibrated.

In June 1995, PP&L's review of a Unit 2 failed instrument transmitter

identified that the instrument drift which preceded the failure caused

a non-

conservative

influence on the calculated CTP.

Initial follow up to this

discovery found that the 'A'eactor Recirculation (RR) pump indicated

power was higher than expected

and the reactor water cleanup (RWCU) inlet

temperature was indicating low. To bound these instrumentation accuracy

problems PP&L administratively restricted Unit 2 operation to below an

indicated CTP of 3437 MW . These issues were.subsequently

resolved.

In December 1995, PP&L's review of an industry event found that seal purge

flow entering the reactor coolant system from RR and RWCU pumps affected

the CTP and were not accounted for in the CTP calculation.

An

administrative limit of 3439 MW~ was placed on both SSES Units pending

corrective actions.

Corrective actions included development of a design

basis document for the CTP calculation and subsequent

revision of the

calculation determined that the actual CTP output was less than had been

originally calculated.

PP&L retracted their original report of exceeding the

licensed CTP in LER 50-387/95-15-01.

Most recently, on December 4, 1996, PP&L made a 24-hour notification to the NRC

when they determined that the flow conversion constant for RWCU was not correct

and had a non-conservative

impact on the calculated CTP for both SSES Units.

PP&L determined it was likely that both Units had exceeded their licensed thermal

power limit at some time since initial startup due to this error.

Upon identification,

PP&L established

interim administrative controls to reduce the CTP limit by

1 MW

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pending correction of the conversion constant.

PP&L found that an instrument which provides inputs to both the RWCU leak

detection system and the CTP calculation was not providing the CTP calculation an

accurate mass flow rate.

The instrument's output is normalized to standard

temperature

and pressure to facilitate comparison of RWCU inlet and outlet flow

rates for leak detection.

However,- due to the conversion constant error the CTP

'alculation

did not account for the fact that the indicated flow rate provided to it

had been normalized.

Typical RWCU system pressure

and temperature were

assumed

in the CTP calculation.

The difference in conversion constant resulted in

the mass flow rate being approximately 40,000 Ibm/hr lower than actual flow rate.

PPKL'elieves this conversion constant

is the original one supplied by General

Electric and plans to inform other utilities of the potential generic issue via the

Nuclear Network.

The errors in CTP. calculations reported by PP5L over the last two years appear to

be of two types.

The first three errors resulted from instrumentation inaccuracies

caused by errors in their calibration or component failures.

The two most recent

issues resulted from original design errors and may be generic to other boiling water

reactors.

In order to assess

the safety impact, the inspector postulated that these errors were

simultaneously present and assumed

a bounding error of 6.0 MW~ based on the

Unit 2 errors discussed

above.

Relative to the Unit 2 licensed CTP limit of 3441

MW~ the combination of these errors would result the indicated CTP being 0.17%

greater than actual.

This error is significantly less than the 2,0% error assumed

by

PP&L in the FSAR and subsequent

Core Operating Limit Report transient analyses.

The inspector discussed

the potential generic aspect of the conversion factor, and

the results of PP5L's design basis effort for CTP, with the NRR Project Manager and

Technical Staff. This issue is under consideration for generic applicability and

communication to the industry.

The violation of the CTP limit is further discussed

in Section 08.2 of this report

under LER 50-387,388/96-17.

Conclusions

A conversion constant affecting the reactor water cleanup system flow value used

to calculate the average core thermal power was not correct.

The condition is

thought to have existed since initial startup of both Susquehanna

units and resulted

in the indicated CTP being one mega-watt thermal greater than actual.

This error is

considered to be of low safety consequence

when compared to the licensed CTP of

3441 MW~, even when combined with other CTP calculational problems identified

in the last two years.

Stora

e of Transient

E ui ment Located Near Safet

Related

E ui ment

Ins ection Sco

e 71707

During the performance of a plant tour the inspector identified a 4.16 kV circuit

breaker that was stored outside of a designated

area in a Unit 1, 4.16 kV

switchgear room.

The circuit breaker had its wheels locked but was next to the

switchgear and could have impacted it if the breaker fell over.

b.

Observations

and Findin s

The Shift Supervisor was notified of the breaker placement issue and it was

immediately removed.

The inspector determined that the breaker storage.was

not

in compliance with licensee procedure NDAP-QA-0552, Transient Equipment

Controls, in that it was not in an approved

area and it was within a topple distance

of the distribution board.

In NRC Inspection Report 387,388/96-10, Section 02.3, Transient Material Storage

in the Unit 1 and 2 Reactor Buildings, the storage of material in designated

areas

was inspected.

The areas identified in NDAP-QA-0552 were originally supported

with an engineering evaluation and an expectation of what type of material was to

be stored in each of the areas.

However, the licensee had failed to carefully control

the types of material placed in these areas.

In this case, the breaker was stored

outside of approved storage areas.

C.

Conclusions

The licensee failed to control the placement of equipment near safety related

equipment (4.16 kV switchgear) in accordance with plant procedures.

Ad 'quate

corrective actions were undertaken

by the licensee after the issue was identified to

them.

This constitutes

a violation of minor consequence

and is being treated as a

non-cited violation consistent with Section IV of the NRC Enforcement Policy.

03

Operations Procedures

and Documentation

03.1

Postin

of Notices to Workers 71707

Notices to workers required by '10 CFR 19.11 were inspected to determine whether

the required information was appropriately and conspicuously

posted.

The inspector observed the NRC required postings at the North and South

Gatehouses,

and the Control Structure access.

The required information was found

to be appropriately posted, including a notice describing where documents not

practicable to post may be examined.

07

Quality Assurance

In Operations

07.1

Review of Third Part

Audits 71707

The inspector reviewed two Institute of Nuclear Power Operations

(INPO) reports, in

the offices of PP&L, that described conclusions from the SSES Plant Evaluation

conducted

in July 1996 and the Technical Training Program Accreditation

performed in September

1996.

No additional NRC regional followup is required

other than the routine planned inspection of the licensee's corrective action program

(CR process).

08

Miscellaneous Operations Issues (92700)

08.1

Control Rod Scram Accumulator Alarm

NRC Inspection Report 50-387,388/96-11,

Section 0.4, addressed

the actions of

operators

in response to the loss of all scram accumulator alarms and the

applicability of TS 3.1.3.5 and TS 3.1.3.1.

TS 3.1.3.1 included an "otherwise"

clause which directed certain activities be taken by the operators.

The inspector

determined that the "otherwise clause" was applicable to the plant condition.

The

NRC inspection report states that:

"The inspector determined that the otherwise clause of TS 3.1.3.1 Action b.1

would be applicable and directed operators to insert the inoperable withdrawn

control rods and disarm the associated

directional control valves.

This action was

not implemented by the operators."

To prevent an improper interpretation of the above paragraph,

it would have been

more clear to have stated:

"The inspector determined that the 'otherwise clause'f TS 3.1.3.1 Action b.1

would be applicable.

This TS directs operators to insert the inoperable withdrawn

control rods and disarm the associated

directional control valves.

These TS required

actions had not been implemented by the operators."

At no time did the inspector direct the actions of licensed operators.

08.2

Closed

LER 50-387 96-17: Non-Conservatism

in Heat Balance Calculation

On December 3, 1996, PP&L identified that a conversion constant used to

determine the mass flow rate for Reactor Water Cleanup system flow in the reactor

heat balance calculation was incorrect.

Consequently,

the indicated CTP was lower

than the actual value by approximately 1.0 MW~. As reported by PP&L in the LER,

it is likely that at some time both SSES units exceeded

their licensed CTP limit when

averaged

over an eight hour shift (reference August 22, 1980 Memorandum from E.

L. Jordan,

Discussion of Licensed Power Level). As discussed

in Section 02.1 of

this report, exceeding the licensed CTP by

1 MW~ (or -0.03/o of the original

licensed CTP) is a licensee identified and corrected violation and is being treated as

a non-cited violation consistent with Section VII.B1 of the NRC Enforcement Policy.

08.3

Closed

IFI 50-387 94-19-01: Licensee's Abilit to Activate the Backu

Emer enc

0 cretin

Facilit

EOF

The purpose of this IFI was to evaluate the ability of the licensee to establish

a

backup EOF near Hazleton, PA. Subsequent

to this IFI being written, the licensee

established

an EOF at the East Mountain Business Center near Wilkes-Barre, PA.

The establishment of this new facility eliminated the need to ensure that the backup

EOF was functional.

The new EOF was activated and performed adequately during

the July 1996 emergency exercise.

This issue is closed.

08.4

Closed

IFI 50-387 95-16-01: Emer enc

Pre

aredness

Trainin

The purpose of this IFI was to evaluate the licensee's training of emergency

preparedness

personnel

in a computer program (MIDAS). The inspector verified that

training was completed prior to the 1996 full-scale emergency exercise and the

skills acquired during the training were adequately demonstrated

during the 1996

emergency exercise.

This issue is closed.

I

08.5

Closed

LER 50-387 96-10: Main Steam Line Penetration

Leaka

e Rate Exceeded

Technical S ecification Limit

With Unit 1 shutdown on September

15, 1996, PP&L identified that the "as found"

leakage through both inboard and outboard main steam isolation valves exceeded

the requirements

of TS 3.6.1.2c.

The licensee further determined that the off site

dose rate using "realistic assumptions" for a loss of coolant accident would be

below the current licensing basis analysis.

The inspector reviewed the data discussed

in the LER and identified no problems

additional to the one that the licensee reported under 10 CFR 50.73.

As such, the

issue, identified and properly reported by the licensee, was a failure to meet NRC

requirements.

Adequate corrective actions were undertaken

by the licensee when

the issue was identified by them.

This constitutes

a licensee identified and

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

Section VII.B.1 of the NRC Enforcement Policy.

08.6

Closed

LER 50-387 96-11: Secondar

Containment

B

ass Leaka

e Rate

Exceeded Technical S ecification Limit

With Unit 1 shutdown on September

18, 1996, PPSL identified that the "as found"

leakage through both inboard and outboard high pressure coolant injection

containment isolation valves exceeded

the design basis requirements of 9.0

standard cubic feet per hour.

The licensee further determined that the off site dose

rate using "realistic assumptions" for a loss of coolant accident would be below the

current licensing basis analysis.

The inspector reviewed the data discussed

in the LER and identified no problems

additional to the one that the li'censee reported under 10 CFR 50.73 and the current

secondary containment bypass leakage licensing issue being analyzed by NRC under

a Task Action. As such, the issue identified and properly reported by the licensee

was a failure to meet NRC requirements.

Adequate corrective actions were

undertaken

by the licensee when the issue was identified by them.

This constitutes

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

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

10

08.7

Closed

LER 50-387 96-12: Missed Firewatch

With Unit

1 shutdown on September

15, 1996, PP&L identified that the

compensatory

fire watch required by TS 3.7.7, was not established for fire

zone 1-5B.

The inspector reviewed the corrective actions performed by the licensee which

included training and counseling of personnel

and a limited analysis of the impact of

the missed firewatch.

The impact of the missed firewatch was determined

by the

inspector to be of minor consequence

and the corrective actions were determined to

be adequate.

The issue, identified and properly reported by the licensee, was a

failure to meet NRC requirements.

Therefore, it constitutes

a licensee identified and

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

Section VII.B.1 of the NRC Enforcement Policy.

08.8

U date

LER 50-387 96-13: Reactor Condition Chan

e

During the Unit 1 startup on October 18, 1996, a mode change to Condition 2

(Startup) was made without the 'B'oop of the Residual Heat Removal s'stem being

operable for its Low Pressure

Coolant Injection (LPCI) function.

Both LPCI

subsystems

are required to be operable

in Condition 2 by TS 3.5.1.

This condition

was identified by the licensee and corrected within 44 minutes of taking the mode

switch to the Startup position.

The inspector reviewed the corrective actions performed by the licensee, which

included training and counseling of personnel

and system realignment, for

immediate safety impact.

The licensee's immediate corrective actions were

determined to be adequate.

The issue was identified and properly reported by the

licensee,

and it was a failure to meet NRC requirements.

This issue will be

reviewed further to determine its safety significance and will remain open.

08.9

U date

LER 50-388 96-09: 'O'HR Pum

Failure To Start

On November 21, 1996, with Unit 2 in Condition 1, the 'D'HR pump failed to

start when it was aligned for suppression

pool cooling.

The cause of the start

failure was determined to be a limit switch for the pump's suction valve that did not

provide the RHR logic a full open indication.

The lack of open indication from the

suction valve (i.e., no suction path) results in an RHR pump trip. PPBcL had

determined that the limit switch problem occurred on November 14, 1996, and

TS 3.5.1 Action b.1 allows a seven day outage time for one RHR pump.

However,

PPRL was not aware the pump was inoperable until November 21 when the

problem was identified and corrected.

Immediate licensee actions to verify operability of the all RHR pumps on both Units

were reviewed by the inspector and found to be thorough.

This issue will be

reviewed further to determine its safety significance and will remain open.

11

II. IVlaintenance

NI1

Conduct of Maintenance

M1 ~ 1

Review Observation of Maintenance Activities

a.

Ins ection Sco

e 62707

A review/inspection of the following maintenance

activities was performed,

including an evaluation of the return to service condition of the equipment.

In

.

addition, a sample of'the equipment permits (tagouts), drawings, and procedures

were evaluated.

., WA P61355

SLC 3-Year Preventive Maintenance for Pump 2P208A

WA V60315 Investigation of Breaker 2A203-04 Control Circuit Ground,

December 13, 1996.

TP-150-018

RCIC Drain Pot Flushing, December 6, 1996.

WA P62210

RHR 1A Service Water Pump Discharge Check Valve Repair

WA P61008

RHR 1A Service Water Motor Doble Test

WA V66783

HPCI Cables

WA V63734 Graphite Packing

b.

Observations

and Conclusions

The inspector determined by observing/reviewing the above listed maintenance

activities and interviewing maintenance

personnel that the activity were performed

in accordance with the licensee's procedures

and regulatory requirements, that

personnel were appropriately trained and qualified, and that appropriate radiological

controls were followed.

M1.2

Surveillance Test Activit Sam

le Reviews

aO

Ins ection Sco

e 61726

The following selected surveillance tests were reviewed to ensure that TS

requirements were met, test equipment was calibrated, test data was accurately

recorded and complete, and that the system was adequately

returned to service.

SO 259-011

Suppression

Pool Level and Temperature,

Unit 2

SO 024-001

'A'mergency Diesel Monthly

SO 024-001

'C'mergency

Diesel Monthly

SE-030-A09

'A'REOASS charcoal and HEPA Bypass Testing,

December 18, 1996

Sl-254-001

Rod Exercising, Unit 2

SE-104-103, Degraded

Grid

12

b.

Observations

and Conclusions

The inspector determined that testing was accomplished

by qualified personnel

in

accordance

with approved test procedures.

Test results met TS requirements

and

any test discrepancies

were rectified.

M1.3

Review of On oin

and or Emer ent Maintenance Activities - Unit 1 H dro en

Ox

en Anal zer

a.

Ins ection Sco

e 62707

A review/inspection of corrective maintenance

associated

with the Unit 1 Hydrogen/

Oxygen analyzer was performed.

b.

Observations

and Findin s

The inspector performed

a walkdown of a portion of the system, and

reviewed/inspected

the following material associated

with the corrective

maintenance

conducted between October 17 and 24, 1996:

WA V66750, H,$0, Analyzer

WA S67431, H,>0, Analyzer

NDAP-QA-502, Work Authorization System

IOM 522, Instrument and Operations Manual, Comsip Hydrogen/Oxygen

Analyzer

In addition, the inspector discussed

the maintenance

activities with SSES

maintenance

personnel,

reviewed the need for permits (tagouts) and evaluated the

vendor technical manual for impact on the design basis functions associated with

selected components

of the analyzer.

The corrective maintenance

was conducted

as minor maintenance,

in accordance

with SSES procedure MT-AD-509-1, Minor

Maintenance.

'

The inspector determined that the documentation

included in the indicated WA

packages

did not include acceptance

criteria for calibration response,

acceptance

criteria for gas volumetric flow rates, or an operability determination to account for

as-found gas flow rates lower than the manufacturer expected value.

In one

instance TS related Channel Check, SO-100-002, was performed and in the other

instance it was not.

In neither case was the instrument calibration performed

following corrective maintenance.

The inspector was not able to determine from

the documentation

alone what criteria was used by the Operations Shift Supervisor

to determine the operability of the

Unit 1 Hydrogen/Oxygen

Analyzer upon return

to service.

The inspector discussed

the subject maintenance

activities with Maintenance

Department first line supervision,

and the Nuclear System Engineering and

determined that the actual maintenance

was adequately performed and that the

13

C.

equipment was operable.

It was not possible to determine operability of the

equipment without the supporting discussions

with the SSES personnel.

. ~

Conclusions

Hydrogen/Oxygen

analyzer maintenance

activities did not completely document the

as-left condition of the equipment.

Therefore, it was not possible to determine post

maintenance

operability of the equipment without supporting discussions with the

SSES maintenance

and NSE personnel.

The failure to adequately document the

performance of safety related maintenance

and the basis of equipment operability

constitutes

a violation of minor consequence

and is being treated as a non-cited

violation consistent with Section IV of the NRC Enforcement Policy. This issue is

closed.

M1.4 Observation of Ma'or Surveillance Testin

- HPCI Quarterl

Flow Surveillance

80

Ins ection Sco

e 61726

Portions of two performances of surveillance SO-252-002,

HPCI Quarterly Flow

~ Surveillance, were observed/reviewed

to determine compliance with TS

requirements,

verify proper licensee review/approval, evaluate the adequacy of

equipment permits (tagouts), verify the adequacy of operating system and test

instrumentation,

and verify the restoration of the portions of the HPCI system to

serwce.

b.

Observations

and Findin s

SO-252-002 was performed on the HPCI system twice during this inspection period.

On the initial performance of the surveillance,

a short loud, noise resulted.

The

noise was heard at the HPCI pump station and in the control room.

The noise

resulted from a water hammer in the HPCI normal injection line and the HPCI test

recirculation line. The water hammer resulted from a mis-coordination of steps

6.4.12 and 6.4.13 of the procedure.

Step 6.4.12 initiates HPCI and step 6A.13

has the operator open the HPCI test line to the condensate

storage tank by opening

isolation valve HV-255-F011.

The intent of step 6A.13 was to open the test line at

an appropriate time in order to prevent piping draindown, and at the same time, to

prevent the differential pressure

on the test isolation. valve from exceeding that

which the valve operator could overcome.

The impact of the water hammer on the operability of the system was evaluated by

the inspector.

Folio(wing discussions with the NSE system engineer and a review of

CR-96-2203, CR-96-1364, inservice testing results, periodic testing results,

previous water hammer incidents, and a detailed equipment walkdown performed by

the licensee, the inspector determined that the water hammer incident that occurred

during this inspection period had no identified impact on HPCI operability.

14

c.

Conclusions

During one of the performances

of SO-252-002,

HPCI, Quarterly Flow Surveillance,

a short loud, noise resulted from a water hammer.

The water hammer was caused

by the test configuration but also impacted the injection line. The impact of the

water hammer on the operability of the system was determined to be non-

consequential

in nature and the licensee took adequate

corrective action to prevent

further HPCI water hammer events.

No violation of NRC requirements was

identified.

I

M1.5

Review of Preventive Maintenance

Backlo

The inspector performed

a review for outstanding work authorizations

(WAs) to

assess

whether the backlog of safety related preventive maintenance

is being

appropriately managed

by PP&L.

b.

Observations

and Findin s

On November 25, 1996, the inspector requested

a printout of the preventive

maintenance

WAs that had reached

PP&Ls "violation" date (i.e., scheduled

due date

plus 25% grace period).

There were no WAs found in this overdue category.

The inspector also examined

a listing of WAs that were waived and therefore

deferred until their next regularly scheduled

occurrence.

In all cases examined, the

waived PMs were due to an adjustment in schedule

based

on past performance

and

the cognizant licensee personnel were able to provide reasonable

background

information.

On January

10, 1997, the inspector discussed

the PM backlog with SSES

Maintenance

Supervision.

The licensee has a plan in place to eliminate the backlog

of 135 activities by March 1997, and has determined that no PMs required for the

environmental qualification of safety related equipment are in the existing backlog.

The inspector reviewed a sample of items from a computer printout of PM backlog

and did not identify any examples of maintenance

activities affecting equipment

environmental qualification.

C.

Conclusion

PP&L has a preventive maintenance

backlog reduction plan in place that is being

monitored by SSES Plant Management.

Based on a sample review of the backlog,

the inspector independently verified the licensee's determination that no overdue

activities affect the environmental qualification of the equipment.

15

M1.6

Unit 2 Standb

Li uid Control Pum

Dischar

e Accumulator

a.

Ins ection Sco

e 71707

During a plant tour the inspector identified that the Unit 2, 'A'tandby liquid control

(SBLC) pump accumulator (2T207A) appeared

to have been replaced, because it

was a different size than the SLBC Unit 2, 'B'ump

accumulator.

The inspector

pursued what appeared to be an undocumented

modification of a safety related

system.

b.

Observations

and Findin s

Following discussions with the licensee, the inspector determined that the

accumulator on the A pump was not the one identified in drawing SP-DCB-201-6

nor was it supported

by seismic calculation SR-2877.

Although the capacity of the

modified accumulator met the original design capacity, the modified accumulator

differed from the original in weight (67 pounds vice 187 pounds)

and

shape.

The licensee wrote CR 96-2233 in response to this issue and performed an

operability determination.

The licensee concluded that the stresses

for the modified

accumulator were less that 30 percent of the SLC system allowable stresses

and

therefore do not impact the operability of the SLC system.

The licensee was not able to precisely determine under what process or at what

time during or since construction the accumulator had been replaced.

However, it

is believed to have been

a construction error.

The failure to control the replacement of safety related equipment in accordance

with plant procedures

constitutes

a violation of minor consequence

and is being

treated as a non-cited violation consistent with Section IV of the NRC Enforcement

Policy. This issue is closed.

C.

Conclusions

An undocumented

replacement of a Unit 2 standby liquid control pump accumulator

was identified by the inspector.

The licensee's

response to the technical issue was

quick and complete.

The safety impact of the identified replacement was low

because the capacity of the accumulator met its system design requirements.

M1.7

Effectiveness of Licensee Controls for Maintenance

a.

Ins ection Sco

e 62707

The inspector reviewed HPCI on line maintenance

activities to assess

the

effectiveness of corrective actions for previously identified issues regarding the

operability of HELB protective features.

16

b.

Observations

and Findin s

NRC Inspection Report 50-387/96-08 discussed

a finding from June 19, 1996,

regarding the operability of RCIC room HELB protective features when barriers, such

as doors or floor plugs, are blocked opened during power operation.

Unresolved

item (URI) 387, 388/96-08-06 was opened pending

a PP&L engineering evaluation

to assess

this configuration relative to the plant's design basis and to determine its

safety significance.

The report also discussed

a finding that the corrective actions

from the June '19 CR were not adequate to prevent a similar finding with a Unit 1

reactor water cleanup room on July 10, 1996.

During the HPCI on line maintenance

conducted

during the week of December 9,

the licensee again failed to provide adequate

control over a HPCI room door that is

assumed to be closed by the HELB analysis.

Altl>ough the significance of the

missing HELB room barrier has not yet been evaluated

by PP&L, the failure to

control the condition in the interim is considered

ineffective corrective action.

PP&L's failure to provide adequate

control to prevent the two recurrences

of

blocked open HELB room doors, after being identified by the corrective action

process,

is considered

a violation of 10 CFR 50 Appendix B, Criterion XVI,

"Corrective Action." (VIO 50-387, 388/96-13-01)

C.

Conclusions

PP&L's repeated failure to provide adequate

control for high energy line break room

doors, blocked open in support of maintenance,

is considered

a violation of

10 CFR 50 Appendix B, Criterion XVI, "Corrective Action." The ability of the plant

to meet its design basis in this configuration is still under review and is being

tracked by NRC unresolved item URI 50-387/96-08-06.

M1.8

Effectiveness of Licensee Controls for Maintenance

aO

Ins ection Sco

e 62707

The inspector observed

a portion of the performance of Standby Gas Treatment

System (SGTS) maintenance,

WA S60439, MT-GE-038 Hydrometer Overhaul

~

b.

Observations

and Findin s

During the performance of this maintenance,

power was removed from the 07553A

damper actuator under red tag permit 1961264.

Following changeout of the

damper actuator, the maintenance

technicians energized the actuator inside a

blocking permit boundary in order to stroke the actuator.

SSES NDAP-QA-322,

Permit and Tag, implements the tagging process at SSES.

Section 5.5 of NDAP-

QA-322 defines a foreign potential as an energy source applied within the boundary

of a blocked out system.

Section 6.2.3 states that the system operating

(SO)

representative,

system permit supervisor and all sign-ons shall be notified by the

person performing a foreign potential test and give their approval prior to application

of the foreign potential.

It further states that proper documentation

shall be noted

0

17

on the Permit Status Change Log, form NDAP-QA-0322-6. TS 6.8.1 requires that

written procedures

shall be established

and implemented for applicable procedures

recommended

in Appendix 'A'fRegulatory Guide 1.33, Revision 2, February

1978.

Regulatory Guide 1.33 requires procedures for the control of maintenance

repair and replacement of safety related equipment including a method for obtaining

permission and clearance for operations personnel to work, and for logging such

work. Contrary to the NDAP requirements,

110 Vac power (a foreign potential)

was brought inside the permit boundary without the proper approvals, or

documentation.

(VIO 50-387, 388/96-13-02)

No personnel

injury or equipment damage occurred as a result of the procedural

violation. The licensee issued

CR 96-2095 to affect corrective actions for the

above stated issue.

c.

Conclusions

During the performance of standby gas treatment system maintenance,

power was

returned inside a blocking permit boundary without meeting the requirements of the

licensee's tagging and permit procedure.

Although no personnel injury or equipment

damage occurred, this is considered

a violation of TS 6.8.1.

M2

Maintenance and Material Condition of Facilities

M2.1

Maintenance

and Material Condition of Facilities

During this inspection period, Unit 1 equipment experienced

several minor incidents

of transient behavior.

These included vibrations on a recirculation pump, reactor

water level spikes, and voltage oscillations on the main generator exciter.

Operators responded

well to the incidents, initial corrective actions were adequately

initiated and licensee management

established

good root cause

and diagnostic

actions.

Maintenance activities were adequately performed and the long term

availability of the equipment in each case was restored;

M3

Maintenance Procedures

and Documentation

M3.1

Unit 2 Reactor Buildin

Elevation 766 Access 0 enin

a.

Ins ection Sco

e 62707

During a plant tour the inspector identified an access

opening that was cut into the

grating above residual heat removal (RHR) containment spray (CS) vent valve

251029.

b.

Observations

and Findin s

The inspector determined that there was an approximately 18" square hole in the

grating, that was covered with a removable plate.

Based on licensee provided

information the opening and plate do not appear on the platform and grating

18

drawings for the valve access

area and as such constitute an undocumented

modification.

In addition, adjacent grating locations did not possess

the proper hold

down clips and studs.

The licensee conducted

a safety impact review (MFP-QA-2200), reinstalled the

missing grating clips under WA V63836, and documented

the condition in CR 96-

2268. Activities as a result of the CR identified two additional grating modifications

of the same sort identified by the inspector.

The conclusion of the nuclear safety impact sheet was that the grating was not

safety related, would not affect safety related equipment and even though the

modifications were not documented,

they met the current SSES seismic two over

one requirements,

C.

Conclusions

The licensee's

response to the undocumented

modification of grating near safety

related equipment was adequate.

PP&L determined that there was no safety impact

resulting from the modification.

The inspector agreed that because

the modification

was on nonsafety related equipment and was determined to meet the licensee's

current seismic two over one process, there was no impact on safety related

equipment.

M8

Miscellaneous Maintenance Issues (92902)

IVI8.1

Closed

Violation 50-387 96-10-02 Control Rod Drive Mechanism

Re lacement

a.

Ins ection Sco

e 62707

A review of the licensee's corrective actions and root cause evaluation for the

above stated violation was performed by the inspector.

b.

Observations

and Findin s

The licensee responded to the above stated violation in a letter (Byram/Pasciak)

dated December 17, 1996.

In that response

the licensee identified a clerical error in

the violation which identified the cited procedure

as MT-055-001 vice the correct

MT-055-015. The error was not substantive

and the licensee's

response,

and

corrective actions were adequate.

The licensee's root cause evaluation was

aggressive

and insightful in that it identified a number of subtle contributions to the

event, was quick in its evaluation of the event, involved a large cross section of

SSES technical expertise and was subjected to the routine high standards

of the

SSES PORC.

19

C.

Conclusions

The failure to perform an adequate

control rod drive mechanism replacement was

adequately

responded to and corrected by the licensee.

The licensee's root cause

evaluation was aggressive

and insightful. This violation is closed.

III. En ineerin

E1

Conduct of Engineering

E1.1

En ineerin

Problem Resolution

a.

Ins ection Sco

e 37551

The inspector reviewed a selection of approximately 40 CR issues which involved

the resolution of engineering related problems and/or incidents.

b.

Observations

and Conclusions

The inspector determined that the licensee adequately identified the root causes of

the selected engineering problems, during this inspection period.

The licensee

implemented an effective process of identifying, resolving, and preventing problems.

In addition the aggressive,

questioning efforts of PORC strengthened

the area of

engineering

and the performance of safety related systems.

E3

Engineering Procedures

and Documentation

E3.1

Unit 2 Standb

Li uid Control Pum

Dischar

e Flow Desi

n Basis

a.

Ins ection Sco

e 37551

During a plant tour the inspector observed that the Unit 2, SLC pump flow

calibrations use pure water as a medium, which discharges through a recirculation

flow path.

The scope of this inspection was to evaluate whether or not the water

remaining in the SLC injection line at the completion of the surveillance test was

accounted for in the design basis of the plant.

b.

Observations

and Findin s

The inspector reviewed the following engineering

design documents:

Calculation EC-ATWS-0505, SABRE Computer Code for Simulation of Boiling

Water Reactor Dynamics Under Failure to Scram Conditions.

Calculation EC-ATWS-1001, Calculation of Unit 2 cycle 9 Peak Suppression

Pool Temperature for ATWS Conditions.

'

20

GE Proprietary Report GENE-637-024-0893,

Evaluation of Susquehanna

ATWS Performance for Power Uprate Conditions.

Note: This document was

returned to the licensee upon the completion of the review.

The calculations assume

a delay of approximately 95 seconds for operator action

(injection initiation), and a 30 second delay from the initiation of boron injection to

the time that boron enters the core.

The 30 second delay accounts for actuation

times of switch positions, motor starting, squib valve actuation, and a volume of

unborated water to be discharged

into the core prior to the boron injection.

The

calculations appear to be conservative

and represent the delay in boron injection

accurately.

C.

Conclusions

Standby liquid control pump flow calibrations use unborated water as a medium and

discharge through a recirculation flow path. At the completion of the test the

normal discharge/injection flow path into the vessel is left filled with unborated

water.

The licensee was able to produce design basis documentation that takes

into account a 30 second delay from the time of boron initiation to the time that

boron actually enters the core.

These calculations conservatively account for the

unborated water left in the injection line following the surveillance flow testing.

This issue is closed.

E3.2

Re Iacement Item Evaluation

RIE

a.

Ins ection Sco

e 37551

During a plant tour the inspector observed the replacement of an ITT General

Controls NH-90 Series model b Hydrometer actuator.

The replacement involved the

use of an improved model b-1 actuator, of a slightly different design.

The new

model was accepted

under the SSES RIE program.

The adequacy of the actuator

replacement under this program was reviewed by the inspector.

b.

Observations

and Findin s

The inspector reviewed the following engineering design documents:

Environmental Qualification (EQ) Assessment

Report - EQ Binder EQAR-074

ITT General Controls Report 730.1.140

ITT Barton Confidential System Engineering Report, R3-EQ-16.

Note: This

report was treated as a proprietary item and returned to the licensee

following its review.

NP-QA-301, Preparation of Replacement

Item Evaluations

21

Based on a'review of the documents

listed above, and a field inspection, the

inspector agreed with PP5L's conclusion that'the form, fit and function of the

replacement

ITT actuators were consistent with the original component design

requirements.

C.

Conclusions

The replacement of ITT General Controls 90 model b Series Hydrometer actuators

with an improved model b-1 series of a slightly different design was adequately

addressed

by the licensee's

RIE program.

E8

Miscellaneous Engineering Issues (92902, 2515/109)

E8.1

Review of the U dated Final Safet

Anal sis Re ort UFSAR

A recent discovery of a licensee operating their facility in a manner contrary to the

Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a

special focused review that compares plant practices, procedures

and/or parameters

to the UFSAR descriptions.

The inspectors compared the MOV design assumptions

for the Reactor Core Isolation Cooling (RCIC) steam isolation valve (HV-249F007),

and the Reactor Water Cleanup (RWCU) system isolation valve (HV-244F001) to

design parameters

contained in the susquehanna

UFSAR.

Engineering study VALV-

0508 assessed

how elevated ambient temperatures

would impact GL 89-10 MOVs.

Section 6.2.3 of the Susquehanna

UFSAR contained the drywell and suppression

pool peak accident temperatures

and pressures.

The inspector verified the design

calculations considered

in EC-VALV-0508 for valves HV-249F007 and HV244F001

were identical to the drywell peak accident temperature

limits listed in section 6.2.3

of the Susquehanna

UFSAR.

PPS.L had appropriately incorporated the temperature

design parameters

contained in the UFSAR when developing MOV design

assumptions

for valves HV-249F007 and HV-244F001.

While performing the

inspections discussed

in Section E3.1 of this report, the inspectors reviewed the

applicable portions of the UFSAR. The inspectors verified that the UFSAR wording

was consistent with the observed plant practices, procedures

and/or parameters.

E8.2

Closed

URI 50-388 95-20-01: Standby Liquid Control IST Instrumentation

This item was opened pending the results of a rotameter flow Instrument

calibration/investigation

and PPRL's final evaluation regarding the method of

calibration for ultrasonic flow transducers.

The vendor calibration of both rotameters involved in a prior failed surveillance were

found to be within 1% accuracy.

During further investigation by PPSL, including

discussion with the rotameter vendor, it was identified that the PPRL installation

procedure did not follow the vendor's installation instruction to null the rotameter

after installation.

Based on review of the test results, and this new information,

PPSL concluded that the failure to null the rotameter was the most probable cause

of the apparent flow degradation

on July 25, 1995.

22

Since this occurrence,

PP&L has had the ultrasonic flow transducers

for each Unit's

SLC system calibrated by the vendor on a flow loop.

The inspector noted that

calibration of this type is consistent with industry practice (reference

NUREG 1482,

Response

5.5-7),

PP&L does not currently plan to perform periodic calibration of

the ultrasonic transducers

since the rotameter flow instrument will be used for

inservice testing in the future.

The failure to provide adequate

procedures for installation and calibration of the test

device for SLC flow (rotameter) led to erroneous

indication during a surveillance test

required by TS. This failure to provide adequate

procedures for control of

measuring

and test equipment constitutes

a violation of minor consequence

and is

being treated as a Non-Cited Violation consistent with Section IV of the NRC

Enforcement Policy.

URI 50-388/95-20-01

is closed.

E8.3

U date

Unresolved Item 50-387 94-14-01

50-388 94-15-01:

pressure

locking

and thermal binding of gate valves.

The inspectors reviewed the status of PP&L's program for assessing

the

susceptibility of motor-operated

gate valves to pressure

locking or thermal binding

(PLTB). Generic Letter 95-07, "Pressure Locking/Thermal Binding of Safety-Relateo

Power-Operated

Gate Valves," requested

the licensee to identify safety-related

power-operated

gate valves that may be susceptible to PLTB phenomena

and take

appropriate compensatory

actions.

In a February 13, 1996, submittal to the NRC,

PP&L identified eighteen valves that were susceptible to PLTB. PP&L indicated that

the corrective actions for the 18 valves, which may be susceptible to pressure

locking, are scheduled to be completed before the startup following the Unit 2 8th

refueling outage, which is presently scheduled for April 1997.

PP&L had performed

an operability determination on the valves and concluded they were operable.

In a

letter dated June 10, 1996, the NRC asked PP&L to supply additional information

concerning its submittal.

The inspectors reviewed PP&L's February 13, 1996,

submittal and did not find any immediate safety or operability concerns regarding

the eighteen valves.

However, this item remains open pending NRR review of the

February 13, 1996, PP&L pressure locking analysis.

E8A

Motor-Operated Valve Program Review

E8.4.1

Motor-0 crated Valve Pro ram Review

On June 28, 1989, the NRC issued Generic Letter (GL) 89-10, "Safety-Related

Motor-Operated Valve Testing and Surveillance," requesting

licensees to establish

a

program to ensure that switch settings for safety-related

motor-operated

valves

(MOVs) were selected, set, and maintained properly.

Seven supplements to the GL

have been issued to clarify the NRC request.

NRC inspections of Pennsylvania

Power and Light's (PP&L's) actions have been conducted

based on guidance

contained

in NRC Temporary Instruction (Tl) 2515/109, "Inspection Requirements

for Generic Letter 89-10."

23

On February 2, 1996, PP&L notified the NRC that the GL 89-10 program was

complete.

The purpose of the current (fourth) inspection was to perform a closeout

review of the Susquehanna

Steam and Electric Station (SSES) GL 89-10 program.

The NRC had previously conducted the initial Part

1 program inspection at SSES in

September

1991, as documented

in Inspection Report (IR) 91-80.

A followup

inspection

(IR 93-08) was performed in August 1993 to assess

how SSES had

addressed

the issues identified in the Part

1 inspection.

During October 1994, the

NRC performed

a Part 2 inspection at the PP&L corporate office as documented

in

IR 94-14/15.

As outlined in the following sections of this report, the inspectors concluded

PP&L

had used inadequate

methodologies to account for the effects of load sensitive

behavior (LSB) and establishing valve factors for some untested valves.

However,

based upon a review of valve design margin, test results and MOV guidance

documents

and procedures,

the inspectors concluded MOV switch settings were

acceptable.

Therefore, PP&L had implemented

a program that met the intent of

Generic Letter 89-10 "Safety-Related Motor-Operated Valve Testing and

Surveillance."

S

E8A.2

Summa

Status of Generic Letter 89-10 Motor-0 crated Valves

The inspectors reviewed procedures, test data, and design guides which

documented

PP&L's GL 89-10 program at SSES.

There are 206 MOVs in the

program.

PP&L verified the design margins of 39 valves by performing dynamic

tests under differential pressure

(DP) conditions with diagnostic equipment.

PP&L

used the dynamic test results to establish the logic settings for 21 butterfly and-

globe valves.

Using dynamic test results obtained from in-plant testing and tests

performed by the Electric Power Research Institute (EPRI), PP&L established

control

logic settings for 42 Anchor Darling gate valves.

PP&L verified the design margins of 32 valves by using the EPRI MOV Performance

Prediction IVlodel (PPM) software.

The control logic settings of 58 valves were

found acceptable

by PP&L based upon excess design margin, or their location in low

DP systems or flow assist-to-close

applications.

Fourteen valves had recently been

added to the MOV program.

PP&L ensured the design margins of those valves were

adequate

by grouping them with valves tested under dynamic or static conditions.

PP&L's methods for demonstrating

MOV design-basis

capability included:

1)

valve-'pecific

dynamic tests at, or near, design-basis

conditions; 2) valve-specific tests,

linearly extrapolated to design-basis

conditions; 3) valve grouping; 4) valves with

little or no DP requirement deemed capable based

on available margin; 5) valves

deemed

capable based

on available or excess margin or in flow-assist-to-close

applications;

6) statistical analysis and application of EPRI and in-plant test data;

and 7) use of the EPRI MOV PPM software model.

To review the seven analysis methodologies,

one valve out of each group was

selected for review. The inspectors reviewed test results and engineering

'valuations

in detail for the following MOVs:

24

HV-1 56F059

HV-1 55F002

HV-1 55F003

HV-1 51 F004

HV-1 49F007

HV-143F031A

HV-1 1 21 OA

HPCI Lube Oil Cooler Supply Valve

HPCI Steam Supply Inboard Containment

Isolation

HPCI Steam Supply Outboard Containment Isolation

RHR Suppression

Pool Suction

RCIC Steam Supply Inboard Containment Isolation

Recirculation System Discharge valve

Service Water Supply to RHR

E8.4.2.1

MOV Sizin

and Switch Settin

s

aO

Ins ection Sco

e

The inspectors reviewed the following: Engineering Calculation Valve (EC VALV)

study 1020, "SSES MOV Program Design Philosophy Study," study EC-VALV-

1008, "Combination of Inaccuracies,

Repeatabilities,

and Margins Associated with

MOV Diagnostic Testing,"

Mechanical Design Standard

(MDS) 04, "Design

Standard

For Motor-Operated Valve Program Engineering Requirements,"

and MDS-

06, "Design Standard

For Verification of Motor-Operated Valve Functionality."

The

inspectors focused upon how PP&L developed

and controlled MOV sizing and

control logic switch settings.

Design Standards

MDS-04 and MDS-06 outline the methodology used to evaluate

the ability of an MOV to function under design-basis

conditions, as well as the

process

used to establish the required MOV switch settings.

The methodologies

outlined in MDS-04 and MDS-06 were based upon a series of studies, that PP&L had

conducted

on MOVs. Studies EC-VALV-1008 and EC-VALV-1020 strongly

influenced the development of PP&L's MOV sizing and switch setting process.

b.

Observations

and Findin s

PP&L used the standard industry equations for MOV sizing and switch settings.

For

gate and globe valves with a safety-related

close function, the torque switch is

bypassed

for 97% of valve stroke.

The torque switch for butterfly valves with a

safety-related

close function is bypassed for 100% of valve travel.

PP&L assumed

a stem friction coefficient of 0.15 to convert torque to thrust when establishing the

initial closing thrust values for Anchor Darling valves.

For other valve types, and

when calculating the required opening thrust for Anchor Darling valves, a stem

friction coefficient of 0.20 was used.

During the initial MOV control logic switch setup,

a valve factor of 0.50 was used

for gate valves and 1.1 for globe valves.

The MOV program required adjustment of

the valve factors and the minimum required thrust if the results of in-situ testing

dictated that a larger value was required.

When establishing the initial MOV switch

settings for gate and globe valves with a safety function to close, PP&L

incorporated

a 10 percent design margin (DM) into the minimum required static

thrust/torque criteria. The DM was intended to account for the effects of load

sensitive behavior, stem lubricant, and valve seat degradation.

25

Following dynamic testing, if the 10% DM did not bound the observed

LSB effects,

a new DM was calculated that would bound LSB.

For gate and globe valves that

were not dynamically tested,

PPSL ensured the DM thrust bounded

LSB and other

uncertainties

including equipment errors, such as torque switch repeatability and

diagnostic system accuracies.

PPSL combined these errors in a "square root sum-

of-the-squares"

(SRSS) methodology to develop

a minimum required thrust.

If the

DM thrust did not bound the errors, a new value was calculated.

The inspectors

~ concluded that this treatment of LSB as a random error was incorrect, however, for

the reasons

outlined in Section E8.4.2.3, the error was not significant.

Some MOVs

were classified as marginal (i.e., less than 10% DM), and became candidates for

increased monitoring or modification.

1

For gate and globe valves with an open safety function, PPSL did not provide a

specified DM to account for LSB effects or valve degradation.

However, PPRL did

adjust the open thrust limitto account for diagnostic system error.

The lack of a

LSB margin in the open direction was not significant since the valves had adequate

margin.

For butterfly valves, allowances for torque switch repeatability and.diagnostic

system errors were applied directly to the minimum required closing torque.

A 10%

DM was then added to the minimum required torque to account for seat

degradation.

C.

Conclusions

PPSL appropriately considered the effects of torque switch repeatability and

diagnostic s'stem inaccuracy.

Additionally, GL 89-10 MOV's were demonstrated

to

have adequate

margin.

However, as outlined in the following sections of this

report, the methods used inadequate

assumptions to develop valve factors for some

valves and to account for the effects of LSB.

E8.4.2.2 'alve Factor and Grou in

aO

Ins ection Sco

e

The inspectors reviewed MOV guidance documents

MDS-04 and MDS-06, and

engineering study EC-VALV-0535 "Motor-Operated Valve Program Valve Factor

Justification" to determine how PPRL developed the valve factors and grouping

.

methodologies

used in the MOV program.

The inspectors also reviewed engineering

study.EC-VALV-1054, "Documentation of the Basis for the Use of the Statistical

Approach for Evaluating the Functionality of Certain Non-Testable

MOVs at SSES,"

which compared the methodology PPSL had used to develop valve factors for non-

dynamically tested Anchor Darling valves to methodologies that were more

commonly used in the nuclear industry.

A

26

Observations

and Findin s

PP&L had placed valves that were not dynamically tested into six categories for

analysis purposes.

These categories were based upon the following criteria:

1)

valve manufacturer;

2) application; 3) similarity to valves that had received dynamic

tests; 4) excess design margin; 5) valves that used the EPRI'PPM software program;

and 6) valves in flow-assist-to-close

applications.

PP&L considered

only the valves

that were categorized

based upon their similarity to valves that had received

a

dynamic test as "grouped" valves per the criteria of GL 89-10 supplement

6.

Valves Grou

ed b

Manufacturer

PP&L had placed 42 Anchor-Darling flex-wedge gate valves in one group.

The valve

switch settings were originally established

using a valve factor of 0.5. To validate

the valve factors, PP&L performed an analysis of dynamic test results conducted at

SSES and EPRI.

PP&L selected valves from the EPRI test program based upon their

similarity, (e.g., same size, type, flow conditions) to SSES valves.

Based on their review of the data for valves that had an open safety function, PP&L

used a valve factor (approximately 0.6) which encompassed

95% of the test data.

For valves that had a close safety function, PP&L established

the required thrust by

using the mean valve factor value and combining the random valve factor term with

allowances for torque switch repeatability, LSB and other terms using a SRSS

methodology.

PP&L assumed

a design margin of 17.01% to account for LSB. If >he

calculated thrust exceeded the initial set up thrust required by the 0.5 valve factor,

the valve switch settings were placed at the new value.

PP&L did not decrease

any

thrust settings below a 0.5 valve factor.

The EPRI data did not represent

a statistically valid test program because

only a few

MOV's of various type and manufacture were tested; also, some valves were not

preconditioned

and revealed low thrust requirements that are not reliable for plant-

specific requirements.

Therefore, the inspectors did not agree with the PP&L

statistical approach to valve factor calculation or the methodology used to develop

a

required valve thrust.

In response,

PP&L calculated "available" valve factors based

upon the "as-measured"

thrust requirements.

PP&L outlined the results in study

EC-VALV-1054. PP&L's data indicated the majority of the valves had adequate

margin with available valve factors greater than 0.6. Two valves that had valve

factors'less than 0.6 had already been identified as marginal by PP&L and were

subject to increased monitoring.

The inspectors reviewed the SSES test data and independently

performed a

statistical analysis resulting in a valve factor of 0.501 at the 95% confidence level

for the close direction.

Using PP&L's assumptions for LSB and torque switch

repeatability, the inspectors calculated

a required thrust for a sample of four gate

valves (HV-155F006, HV-15766, HV-21313, and HV-251F004).

This

independently

calculated thrust was then compared to the present MOV switch

setting, and ultimately found to be adequate.

Although the method PP&L'used to

develop the valve factors for Anchor Darling gate valves was not acceptable,

the

27

inspectors

did not identify any operability concerns.

Therefore, based upon the

available margin for the Anchor Darling valves, the inspectors considered the valve

switch settings to be acceptable.

Valves Grou ed b

A

lication

Twenty-four gate valves in 0 psid applications were grouped together.

The valve

switch settings were set up during static testing based

on a valve factor of 0.50

and an added design margin of 10%.

The 10% margin was used to accommodate

LSB effects and valve degradation.

The inspectors performed

a qualitative review of the valve switch settings and

grouping methodology.

Based upon the low DP and large valve factors, the

inspectors determined the grouping and valve switch settings were acceptable.

Valves Grou ed b

Similarit to D namicall

Tested Valves

Gate and Globe Valves

PPSL had four gate and five globe valves which were grouped with other

dynamically tested valves.

Two of the four gate valves were grouped with other in-

plant tested valves (four valves total in the group).

Two of the five globe valves

were grouped with other in-plant tested valves (four valves total in the group).

However, the remaining five valves were not grouped per the recommendations

of

GL 89-10, Supplement

6. Specifically, the three globe valves were placed in groups

of two with only one SSES valve tested per group.

The remaining two gate valves

were grouped using an EPRI tested valve.

The inspectors reviewed the switch settings and grouping methodology for the gate

and globe valves.

The inspectors determined the switch settings for the valves

(grouped per the recommendations

of GL 89-10, Supplement

6) were adequate.

However, since only one valve was tested in some groups, the inspectors could not

determine if the tested valve's performance characteristics

represented

the group

population.

Despite the minimal test data, the inspectors noted the switch settings

for the grouped valves appeared to have adequate

design margin.

Butterfl

Valves

PPSL had six groups of butterfly valves.

One group consisted of four Posi-Seal

valves which had a design-basis

DP of zero psid.

A second group consisted of four

Contromatic valves where two of the four valves were dynamically tested using

diagnostic equipment.

There were four groups of Jamesbury butterfly valves which

consisted of one group of eight valves and three groups with two valves in each

group.

Only one valve in each group of the Jamesbury butterfly valves'had

been

dynamically tested using diagnostic equipment.

The remaining valves in the groups

had received dynamic tests'without diagnostics.

The valve switch settings were

established with a design margin of 10% to account for valve seat degradation.

28

Butterfly valve diagnostic testing revealed that the vendor-recommended

switch

settings were not conservative; therefore, PP&L established

settings based upon

their own diagnostic test results.

The PP&L methodology for establishing switch

settings for Contromatic valves was based upon sound statistical analysis in that

two valves per group were diagnostically tested.

The inspectors reviewed the

switch settings for'these valves and determined they were acceptable.

Due to the lack of Jamesbury

diagnostic test data, the inspectors were concerned

about the reliability of the switch settings for those valves.

Specifically, since only

one valve per group was tested,

PP&L could not determine if the tested valves

performance ch'aracteristics

adequately

represented

the valve population. However,

the inspectors noted that the Jamesbury

valves had considerable

available margin,

and as part of the GL 96-05 periodic verification effort, the licensee will be

expected to~validate its torque requirement predictions.

Valves Grou ed b

Desi

n Mar in

PP&L had placed 32 MOVs, (12 gate valves and 20 globe valves), in one group

based upon excess design margin.

The gate valves switch settings were

established

using a valve factor of 1.0.

The switch settings for the globe valves

used

a valve factor of 2.0.

PP&L assumed

a 10% design margin to account for

load sensitive behavior.

Most of the 32 MOVs in this group had thrust margins of

at least 100%; therefore, the inspectors considered the valve switch settings in this

group acceptable.

EPRI PPM Valves

PP&L analyzed 32 MOVs using the EPRI Performance

Prediction Model (PPM)

software program.

For non-blowdown valves, PP&L assumed

a 17% design margin

for LSB. For valves in systems that may be subject to blowdown conditions, PP&L

assumed

a design margin of 8%.

PP&L had reviewed the NRC's safety evaluation report (SER) on the PPM, and used

the software according to the EPRI manuals and the NRC SER with two notable

exceptions.

First, PP&L had used the program on four 28-inch Lunkenheimer

recirculation system discharge gate valves.

However, the EPRI PPM was not

validated using Lunkenheimer valves.

Therefore, the software may not accurately

predict the performance of these valves.

PP&L stated the EPRI PPM program was

.

used on the Lunkenheimer valves since the valves could not easily be dynamically

tested and industry test data was not available.

The required thrust predicted by the EPRI PPM for the Lunkenheimer valves was

equivalent to using a valve factor of 0.6 with a design basis DP of 200 psid.

The

inspectors noted the SSES Lunkenheimer valve factor was comparable to the

assumptions

the industry had used for similar large bore gate valves.

Because

no

SSES or indust'ry Lunkenheimer dynamic test data was available from which

adequate

comparison could be drawn, the inspectors determined PP&L's alternative

approach for the Lunkenheimer valves acceptable

on an interim basis.

However,

29

since these valves were outside the scope of the EPRI PPM, the licensee will be

expected to validate its thrust predictions as industry information becomes

available.

ll

Second, when the EPRI PPM was run on several valves in the Residual Heat

Removal (RHR), Reactor Water Cleanup (RWCU), and High Pressure

Coolant

Injection (HPCI) systems, the EPRI PPM reported the valve thrust as

"unpredictable."

However, PPSL still used estimated thrust numbers predicted by

the EPRI PPM to verify the valves were operable.

The inspectors reviewed the

calculations for two of the valves in the HPCI system (HV-155F002 and HV-

155F003) for which the EPRI PPM program predicted unpredictable thrust

requirements.

Since PPSL was not aware of internal valve measurements,

worst

case valve dimensions were used, and the program was unable to accurately predict

a required valve thrust during portions of the valve stroke.

To obtain the necessary

internal dimensions,

PPtkL had developed

plans to disassemble

the low margin

valves in the HPCI system and measure

and modify, specific internal dimensions.

Although the EPRI program could not accurately predict the required valve thrust

throughout the range of the valve stroke, the PPM program did produce estimated

thrust in ".he "unpredictable" region.

PPRL considered the valves operable since the

MOVs produced considerably greater thrust than the EPRI program had predicted.

PPSL calculated available valve factors for the twelve valves that EPRI PPM had

determined were "unpredictable."

The valve factors ranged from 0.9 to 1.0 at

seating, and greater in the flow region where DP was lower.

At the time of the inspection, Unit 1 was in a refueling outage and PPSL was

obtaining the required measurements

for valves in the Unit 1 HPCI system.

PP5L

indicated similar measurements

would be performed on the Unit 2 valves during an

upcoming refuel outage.

To reduce radiation exposure,

PP&L indicated the valves in

the RWCU system on both units would not be disassembled

for the sole purpose of

obtaining data to run the EPRI PPM program.

PPS.L however stated that, if

subsequent

industry testing revealed the current setup to be not conservative, they

would reevaluate their course of action.

The inspectors considered

PPSL's actions concerning the valves identified as

unpredictable to be acceptable

(in the short term), based upon the high available

valve factors and the fact that the valve torque switches are bypassed

during 97%

of the valve's stroke.

However, ALARAshould not be used as a sole basis for

deferring actions to address

a potential safety concern.

Flow-Assist-to-Close Valves

SSES had four globe valves which were in applications wherein flow assisted

in

closing.

The valves were grouped in accordance

with the criteria outlined in

GL 89-10,

Supplement

6. The inspectors reviewed the valve thrust calculations

and the grouping criteria and determined the valve grouping, torque switch settings

and thrust margins were adequate.

30

C.

Conclusions

PP&L's mhthodology for developing valve factors for untested Anchor Darling

valves was not acceptable.

However, based upon the current valve switch

settings,'the

inspectors agreed with the licensee's conclusion that the valves had

design basis capability.

The inspectors noted PP&L was in the process of

evaluating industry information (e.g., EPRI guidelines for LSB assumptions)

for

inclusion into the SSES MOV program to ensure potentially non-conservative

assumptions

were removed.

E8.4.2.3

'Load-Sensitive

Behavior

a.

Ins ection Sco

e

Load sensitive behavior (LSB) is a change

in MOV output thrust due to a change

in

internal friction forces under dynamic conditions.

The inspectors reviewed the

following MOV studies to assess

how PP&L accounted for LSB: EC-VALV-0538,

"MOV Rate of Loading," EC-VALV-1008, "Combination of Inaccuracies,

Repeatabilities,

and Margins Associated with MOV Diagnostic Testing," and EC-

VALV-1025, "Determine Acceptability of Current Use of Design Margin to Account

for Rate of Loading and Determine Appropriate Value of Design Margin to be Used

for Non-Testable MOVs."

b.

Observations

and Findin s

To account for the effects of LSB, PP&L used data obtained from in-situ

Susquehanna

tests as well as industry tests performed by EPRI.

The data was

separated

by valve type and analyzed statistically to establish upper and lower

limits. The gate valve analysis consisted of 28 valves with a sample mean of

0.92% and a 95% confidence interval that 90% of the data was between -15.16%

and 17.01%.

Based upon the statistical analysis, PP&L used 17.01% as an

assumed

value for LSB for gate valves.

PP&L determined that an analysis of the globe valve data could not be performed

since the sample size (7 MOVs) was too small. Although LSB for the seven globe

valves ranged from -17.8% to 31.8%, PP&L assumed

a 25% margin to account for

the effects of LSB was acceptable.

This margin was based upon an evaluation of

test results performed on similar valves in the industry.

PP&L accounted for the effects of LSB by combining the LSB assumption with other

variables such as torque switch repeatability and diagnostic system errors in a SRSS

methodology.

These errors were converted into a design margin (DM) multiplier,

=

and applied to all non-testable

MOVs to adjust the required thrust in the closed

direction.

The inspectors

had three concerns regarding PP&L's assumptions

which tend to

underpredict

LSB:

31

1.

Eleven data points were obtained from the EPRI test program but, the

environmental test conditions may not be identical to those at SSES;

2.

When developing

a margin to account for LSB, PP&L considered

LSB effects

to be a random variable that could be combined with other errors such as

torque switch repeatability and diagnostic system error.

The NRC position is

that industry test data has shown that LSB is caused

by an increase

in stem

friction under dynamic conditions and that most valves exhibit some LSB.

Therefore, LSB is considered

as a bias or bias)random

error rather than pure

random error; and

3.

PP&L did not include a DM to account for LSB for valves that had a safety

function to open.

LSB could reduce thrust in the open direction.

Using the SSES dynamic test results and treating LSB as a biased rather than

random error, the inspectors recalculated the thrust requirements for gate valve

HV-151F004D, since it had low margin.

The predicted thrust requirement was then

compared to the PP&L calculated numbers to determine if original (viz. random) LSB

assumptions

were bounded by the test data.

Assuming the mean value (3.9%) was

a bias error, and the upper confidence limit was a random error, the inspectors then

independently

recalculated the thrust for valve HV-151F004D using a valve factor

of .62. the predicted thrust was less than the PP&L predicted values, therefore, the

assumption was conservative for this valve.

c.

Conclusions

Although PP&L's methodology for calculating LSB was inconsistent with the general

understanding

of the phenomenon,

an acceptable

margin accounted for the effects

of LSB when establishing switch settings.

Although PP&L did not assume

a specific

value for LSB in the open direction, the SSES MOV program required valves to have

a DM, based on motor capability, of at least 10 percent.

MOVs that had less than

10 percent margin required increased monitoring or modification.

The inspectors

concluded the MOVs had sufficient DM to accommodate

the effects of LSB in the

open direction.

E8.4.2.4

Stem Friction Coefficient

a e

Ins ection Sco

e

The inspectors reviewed MOV guidance documents

MDS-04, MDS-06, and

engineering studies EC-VALV-0536 "MOVStem to Stem-Nut Coefficient of Friction"

and EC-VALV-1007, "Evaluation of Motor Capability and Maximum Allowable Open

Thrust for GL 89-10 MOVs Assuming a Stem/Stem Nut Coefficient of Friction of

0.20," to determine how initial MOV stem friction coefficient assumptions

were

established.

32

To assess

how stem friction coefficient test results were used to determine MOV

design margin, the inspectors reviewed engineering study EC-VALV-1022, "Generic Letter 89-10 Periodic Verification Method Evaluation."

b.

Observations

and Findin s

PP&L assumed

a stem friction coefficient of 0.15 to convert torque to thrust when

establishing the initial closing thrust values for Anchor Darling valves.

For other

valve types, and when calculating the required opening thrust for Anchor Darling

valves,

a stem friction coefficient of 0.20 was used.

PP&L did not provide an

allowance for changes

in the stem friction coefficient due to lubricant

degradation'ince

tests conducted

between 18-month operating cycles revealed lubricant

degradation

did not occur.

EC-VALV-0536 contained the results of stem, friction coefficients measured

during

in-situ plant testing..The test results confirmed the 0.20 stem friction coefficient

assumption was conservative.

Specifically, a PP&L statistical analysis of measured

stem- to-stem nut coefficients of friction for SSES MOVs indicated

a mean of 0.12

for static conditions with a 95% confidence range of 0.05 to 0.18.

Dynamic test

results revealed

a mean of 0.13 with a 9" % confidence range of 0.07 to 0.18.

Although the test data revealed the initial 0.15 stem friction assumption was not

conservative for some Anchor Darling MOVS, PP&L's methodology for calculating

MOV design margin ensured non-conservative

changes

in stem friction coefficient

were evaluated.

Specifically, when MOV design margins were calculated, PP&L

used the stem friction coefficient measured

during dynamic testing.

If an MOV did

not receive a dynamic test, PP&L used the static stem friction coefficient measured

during testing with an additional bias to account for load sensitive behavior.

MOVs

that had less than a 10% design margin required modification or increased

monitoring.

C.

Conclusions

PP&L's test data confirmed the validity of the assumed

stem friction coefficients.

E8.4.2.5

Linear Extra olation.

a 0

Ins ection Sco

e

The inspectors reviewed PP&L's methodology for extrapolating test data contained

in engineering study EC-VALV-1023, "Justification for Linear Extrapolation of

Thrust."

b.

Observations

and Findin s

PP&L required MOV dynamic tests to be performed at a minimum of 50% of design-

basis DP before linearly extrapolating test data.

The inspectors reviewed test data

33

and found the lowest case in which results were extrapolated was from 79% of

normal operating pressure

(valve HV-250F045).

Although the SSES extrapolations were performed at large DPs, the inspectors did

not find a requirement in SSES's

MOV procedures that outlined a minimum DP

below which no extrapolation was valid (e.g., 50 psi).

Industry experience

has

shown extrapolating test results at low DPs may produce nonconservative

test

results because

of data scatter at low pressures.

PP&L corrected this deficiency by

revising their MOV program during the inspection to require MOV engineers to

review the DP to be extrapolated for appropriateness.

The inspectors considered

this change acceptable.

c.

Conclusions

The inspectors considered

PP&L's methodology of linear extrapolation to design-

basis conditions acceptable.

E8.4.2.6

D namicall

Tested Valves

a.

Ins ection Sco

e

The inspectors reviewed MOV guidance document MDS-06, maintenance

procedures

M-1503, "Verifying Motor Operated Valves Abilityto Function,"

MT-EO-021, "Votes - MOV Diagnostic Test," valve matrix sheets containing open

and close valve limitations and margins, and diagnostic test documents for the

selected MOVs.

b.

Observations

and Findin s

PP&L had 206 IVIOVs in their program of which 39 MOVs were dynamically tested

using diagnostics.

This amounted to 19% of the MOV population receiving a

dynamic test.

Since PP&L did not utilize industry test data from other plants, a

significant amount of statistical analysis was performed to verify MOV design basis

capabilities.

The analysis methodology was discussed

in section E8.4.2.2 of this

report.

PP&L used Liberty Technologies'OTES

diagnostic equipment to test their MOVs.

The inspectors reviewed test data from MOVs that had received dynamic tests, and

verified PP&L had applied the diagnostic system inaccuracies to their MOV settings

when determining MOV thrust requirements.

c.

Conclusions

The inspectors considered

PP&L's verification of design-basis

capability for MOVs

that were dynamically tested to be adequate.

34

E8.4.2.7

Trackin

and Trendin

aO

Ins ection Sco

e

Item (h) of GL 89-10 requested

licensees to establish,

in part, a monitoring and

feedback effort to establish trends in MOV operability.

The inspectors interviewed

SSES MOV personnel to determine how PP&L tracked and trended MOV

performance.

PP&L described the tracking and trending process

in NDAP-QA-0017,

"Motor-Operated Valve Program."

The inspectors reviewed 15 condition reports

(CRs) that reported MOV deficiencies to evaluate the PP&L corrective actions.

b.

Observations

and Findin s

PP&L had established

a substantial amount of MOV performance data.

The data

bases were in the process of being consolidated

into one program, entitled the

Nuclear Information Management

System (NIMS) data base.

PP&L tracked several

MOV parameters

including thrust, torque and stem factor.

Once each operating

cycle, maintenance

technology was tasked with reviewing MOV performance.

The

review required analyzing the information contained

in the data bases to identify

MOV degradation

and the need for additional testing or maintenance.

The inspectors reviewed the MOV data bases

and concluded the information would

be useful to assess

MOV performance changes.

The inspectors noted PP&L had

already used the information to diagnose

MOV performance deficiencies.

The

inspectors performed a summary review of CRs that documented

MOV performance

deficiencies.

The inspectors verified each deficiency had been evaluated for

reportability and operability.

C.

Conclusions

PP&L had developed

an adequate

trending program.

The program systematically

trended valve failures and provided a method to detect degrading MOV

performance.

MOV performance deficiencies had been adequately documented

via

the CR system.

E8.4.2.8

Periodic Verification

Ins ection Sco

e

The inspectors interviewed personnel

assigned to the MOV Program regarding "as-

found" testing of MOVs to assess

how PP&L willtrack potential degradation of

stem lubrication and changes

in valve factor.

Further, the inspectors reviewed the

periodic verification program guidance document Mechanical Design Standard

(MDS) procedure 08, "Periodic Performance Assessment

of SSES Motor-Operated

Valves" and study EC-VALV-1022 "Generic Letter 89-10 Periodic Verification

Method Evaluation" to assess

how PP&L will monitor MOV performance.

35

Observations

and Findin s

MDS-08 was the guidance document that outlined the responsibilities of the

engineering department concerning the MOV periodic verification program.

Contained in the document were the MOV performance characteristics that should

be monitored, how they should be monitored, and how changes

in MOV

performance should be assessed.

To monitor the performance of gate and globe

valves, PPRL will perform static and dynamic tests with diagnostic equipment.

Butterfly valves would primarily receive dynamic tests without diagnostic

equipment.

MDS-08 required variations in MOV performance characteristics

be documented

in

an annual report.

Performance characteristics that would be monitored included

changes

in stem factor, motor capability margin, and torque in the close direction.

The criteria used to determine the test frequency for rising stem valves included

percent excess motor capability, risk significance, potential for aging and thrust

margin.

Based upon the criteria, a rising stem valve could receive a retest at 2, 5 or

10-year intervals.

Currently, PPS.L intends to perform dynamic tests with

diagnostics

on six gate and globe valves.

PPSL was revising the MOV program

procedures to ensure the periodic diagnostic tests are performed before preventive

maintenance

activities.

These "as found tests" would ensure

PPRL could detect

changes

in valve performance that occurred between preventive maintenance

intervals.

PPSL had scheduled

dynamic tests for four butterfly valves with diagnostics for a 5-

year period.

The remaining butterfly valves would receive dynamic tests without

diagnostic equipment.

PPSL selected the four butterfly valves for dynamic

diagnostic testing based,

in part, on the potential for those valves to be

overstressed

because

of torque switch degradation.

As discussed

in sections E8.4.2.2 and EBA.2.3 of this report, PP5L had performed

only limited diagnostic testing of butterfly valves and did not provide an allowance

for stem lubricant degradation.

The inspectors noted PPSL's periodic verification

program would validate the basis for those assumptions.

Conclusions

The PPS.L periodic verification program will be reviewed in greater detail as part of

PPSL's response to GL 96-05.

Desi

n Modification Process

and Im lementation

Ins ection Sco

e 37550

The scope of this inspection was focused on:

(1) the design modification process,

(2) engineering involvement in the resolution of technical issues,

and (3) the

36

Susquehanna

snubber reduction program.

The inspectors reviewed and verified the

implementation of procedures for engineering design modifications.

Observations

The Desi

n Modification Process

The licensee conducted

Individual Plant Examination for External Events

(IPEEE)

walkdowns to ensure compliance with seismic qualification requirements

and to

identify vulnerabilities for the plant.

During these walkdowns, the licensee noted

excessive

gaps between adjacent cabinets/panels

that were not fastened together.

This condition was noted at several locations in the control room and in the upper

and lower relay rooms.

The NRC inspector reviewed the corrective action which consisted of joining these

cabinets/panels

to adjacent cabinet/panels

through bolting. This corrective action

was implemented through modification package

Nos. DCP-95-9047 and -9048.

The

shop drawings in the package illustrating the details of the connections

were clear

and had sufficient detail for assembly.

The package was prepared

in accordance

with design procedures.

Another Modification No. 95-3014F installed condensate

supply and return piping

associated

with the condensate

filtration project.

The inspectors verified that the

provision of ANSI B31.1 were met by performing the prescribed inservice leak test

(ISLT). In addition, the licensee performed nondestructive

examination; however,

the package stated that the provisions of ASME Section IX Code Case N-416-1 =in

conjunction with the supplemental

requirements

per NRC safety evaluation for relief

request

RRPT-1 be met.

This statement was incorrect since the design basis for

this piping system was not ASME Section III, Class 3 piping.

The licensee reviewed

other packages to ensure that this error was not generic.

PPS,L subsequently

determined the error was an isolated case.

En ineerin

Involvement with the Resolution of Technical Issues

When reviewing DCP-95-9047 and 9048, the inspectors noted the licensee did not

perform an operability determination that had addressed

the acceptability of the

current plant configuration.

In response to the inspector's observation, the licensee

performed an operability determination.

The inspectors reviewed the operability determination and noted the licensee had

previously developed

a detailed finite element seismic analysis model of the

cabinet/panels.

The licensee model of the maximum safe shutdown earthquake

(SSE) displacements

of the cabinet/panels

due to front-to-back and side-to-side

excitation, concluded very low displacements.

These low displacements

yielded

low dynamic impact loads on the cabinets/panels

enclosures,

and to the safety-

related components

within. Therefore, the panels were operable based upon their

as-found condition.

0

37

Sus

uehanna

Snubber Reduction Pro ram

Susquehanna

Steam Electric Station (SSES) Units

1 and 2 utilize mechanical

snubbers

as seismic and dynamic supports of nuclear piping systems.

Operating

experience

on both units indicates the existence of snubber performance difficulties.

The licensee has initiated a snubber reduction and replacement program.

The

program aimed at eliminating the largest possible number of snubbers through pipe

stress analysis using the provisions of the American Society of Mechanical

Engineers

(ASME) Code,Section III, basic code cases, Welding Research

Council

(WRC) Bulletin 300, and by appropriate replacement with more reliable supports

(e.g. struts).

NRC Regulatory Guide 1.84, revision 24, accepted the basic code

cases used by this licensee in this application with certain conditions.

Since the

initiation of the snubber reduction program, the licensee has eliminated 1,618

snubbers from Unit 1 and 752 snubbers from Unit 2. At the close of the inspection

report period, there were 578 remaining snubbers

in Unit 1 and 487 in Unit 2.

The NRC inspector verified that ASME Code requirements were properly applied in

the snubber reduction program, including the fulfillment of the conditions stated in

the NRC Regulatory Guide 1.84, rev. 24.

Specifically, the inspector verified that

the stress analysis for the nuclear class

1 core spray (CS) piping from containment

penetration X-16A to the reactor pressurized

vessel (RPV) nozzle N-5A was

performed in accordance

with the rules of the code of record (Article NB-3600 of

the ASIVIE Section III Boiler and Pressure

Vessel Code 1977 Edition, summer 1979

addenda).

Conclusion

Design modification packages

were found to be complete and thorough.

Design

requirements were established

and documented

in the design modification package.

The responsible

engineers were cognizant of the pertinent regulatory requirements,

and compliance to the engineering procedures

was evident,

except for the error

found in package

No. 95-3014F which was promptly corrected.

The licensee implemented

an effective program that eliminated over 60 percent of

the mechanical snubbers

at the facility.

IV. Plant Su

ort

Radiological Protection and Chemistry (RP&C) Controls

Radiolo ical Controls

During routine tours of the plant the inspector verified that a sample of doors

required to be locked for the purpose of radiation protection, by Technical

Specifications and procedures,

were actually locked.

While touring the plant, the

inspector found that radiological areas were appropriately posted and that radiation

38

workers were following applicable Health Physics practices.

The ihspector also

found that the self contained breathing apparatus

(SCBA) units staged at various

locations in the plant indicated that periodic inspections

are being performed.

R6

RP8cC Organization and Administration

R6.1

Administrative Re uirements for Workers Involved in Safet

Related Activities

a.

Ins ection Sco

e 71707

The inspector verified that the licensee has a program intended to control the

regular use of overtime for workers involved in safety related activities.

Specifically, the process implemented to control health physics technician overtime

was reviewed.

b.

Observations

and Findin s

Overtime requirements

are established

by Unit 1, and 2, TS 6.2.2.

The SSES

site-wide program implementing these requirements

is described

in NDAP-QA-00-

0650, Conduct of Site Support.

The inspector selected the use of overtime by Health Physics

(HP) technicians

during the most recent 1996, Unit 1 refueling outage as a sample for this inspection

item.

Based on discussions with SSES HP management

and review of upper tier

documentation,

the inspector determined that there were approximately 60

instances where extended overtime was employed (greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7 day

period) and that the HP Department did not have documented

practices in place to

control and limitthe routine use of overtime.

For the period covered by this

inspection sample, the licensee failed to meet the guidelines in TS 6.2.2 in limiting

the routine heavy use of overtime.

Following discussions with the inspector, the licensee initiated a condition report to

track resolution of the issue.

Prior to discussions with the inspector the Department

had identified the issue and established

the means to increase the number of

contract HP technicians for the upcoming Unit 2 refueling outage.

They also had

begun (in draft form) a program to control overtime in the HP Department,

HP-Hl-

083, Control of Overtime.

C.

Conclusions

The licensee failed to adequately control Health Physics technician overtime during

the most recent Unit 1 outage.

In approximately 60 cases the licensee did not meet

the guidelines in Technical Specification 6.2.2, "Unit Staff," which constitutes

a

licensee identified and corrected violation. This is being treated as a non-cited

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

39

V. Mana ement Meetin s

X1

Exit Meeting Summary

The inspectors presented

the inspection results to members of licensee management

at the conclusion of the inspection on January

13, 1996.

The licensee

acknowledged

and did not object to the findings as presented.

The inspectors determined that during the course of the inspection proprietary

materials were provided for the inspectors'eview.

These materials were discussed

in Sections 3.1 and 3.2 of this report in a way as to not disclose their proprietary

nature.

The materials were returned to the licensee after the inspectors completed

their review.

The licensee identified no other materials examined during the

inspection that should be considered

proprietary.

X3

Drop-in Meeting By PP&L Managers

Mr. W. Hecht and others of his staff, representing

PPRL management

conducted

a

drop-in meeting with NRC staff on November 14; 1996, at the Region

I office.

Representing

the NRC were Messrs.

H. Miller and A. Blough of the Region staff.

The topics covered during the meeting involved an overview of the PPRL

organization and the utility approach to Nuclear Department issues.

No conclusions

were formulated during the meeting.

Licensee briefing materials are attached to this

inspection report.

~Oened

50-387,388/96-1 3-01

50-387,388/96-1 3-02

Closed

ITEMS OPENED, CLOSED, AND DISCUSSED

VIO

Failure to provide adequate

control for HELB room doors

blocked open

VIO

Foreign Potential brought inside the permit boundary

without approvals, notifications or documentation

50-387/96-1 7

50-387/94-1 9-01

50-387/95-1 6-01

50-387/96-1 0

50-387/96-1

1

50-387/96-1 2

50-/387/96-1 0-02

50-388/95-20-01

LER

Non-Conservatism

in Heat Balance Calculation

IFI

Licensee's Abilityto Activate the Backup Emergency

Operating Facility (EOF)

IFI

Emergency Preparedness

Training

LER

Main Steam Line Penetration

Leakage Rate Exceeded

Technical Specification Limit

LER

Secondary Containment Bypass Leakage Rate Exceeded

Technical Specification Limit

LER

Missed Firewatch

VIO

Control Rod Drive Mechanism Replacement

URI

Standby Liquid Control IST Instrumentation

Discussed

50-387 9/ 6-13

50-388/96-09

50-387/94-14-01

50-388/94-1 5-01

LER

Reactor Condition Change Without LPCI

LER

RHR Pump Failure To Start

URI

Pressure

Locking/Thermal Binding

LIST OF ACRONYMS USED

CFR

CR

CREOASS

CTP

DR

EOF

ESS

FPL

HELB

HEPA

HPCI

IFI

INPO

LER

Mwi,

NCV

NOV

NPO

NRC

NRR

NSE

PCO

PORC

RCIC

RHR

RP&C

RWCU

SALP

SGTS

SCBA

Sl

SLC

SO

TS

UFSAR

URI

WA

Code of Federal Regulations

Condition Report

Control Room Emergency Outside Air Supply System

Core Thermal Power

Drain Recommendation

Emergency Operating Facility

Emergency Safeguard

System

Florida Power and Light

High Energy Line Break

High Efficiency Particulate Air

High Pressure

Coolant Injection

Inspection Follow-Up Item

Institute of Nuclear Power Operations

Licensee Event Report

Mega-Watt Thermal

Non-Cited Violation

Notice of Violation

Nuclear Plant Operator

Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Nuclear System Engineering

Plant Control Operators

Plant Operations Review Committee

Reactor Core Isolation Cooling

Residual Heat Removal

Radiological Protection and Chemistry

Reactor Water Cleanup

Systematic Assessment

of Licensee Performance

Standby Gas Treatment System

Self Contained Breathing Apparatus

International System of Units

Standby Liquid Control

System Operator

Technical Specification

Updated Final Safety Analysis Report

Unresolved Item

Work Authorization

NRCRe ionI

Meetin wit

A rninistrator

PP8zL Senior Mana ement

Novernbez14, 1996

NRC Region I Offices

King ofPrussia, PA

~ Overview of PP8zL Resources

~ Key Corporate Issue

Electric.UtilityIndustry Restructuring

~ PP8zL's Approach to Nuclear

~ Key Nuclear Department Initiatives

~ Open Discussion

0

vervievr o

esources

CORPORATE STRUCTURE

"<<"-:"-=='-'"'PPP8IL!!RESQURCES-""-"'-"=:"='-'.s

'8~x:.>,'

"."A "~,"'~'~w.: '", '

'6'~PFg,

,PENNjÃei'A.-..':POIIER';."II.";:LLGi ->~,:-:PPWER

':',,.'iiikki'i,ME@',i';::,'.COMPA'3'i:--:-:

-'.;:.-,",'-,',i'::SPECTRUM,,EIIIERG

,':NUCL'EAR'"DEPARTMENT'.:;

PP8zL Service Area Generation

WAL ENPAUPACK

Hyd

44

Generation

Coal

Nuclear

Oil/Gas

Hydro

Total Capacity

Customers

Residential/Business

Service Area

Average Revenue

Operating Revenues

Net Assets

Em lo ees

60%

34%

7.8 Mkw

1.2 Million

83% / 17%

10,000 sq. miles

7.1) / kwh

$2.8 Billion

$6.5 Billion

- 6,500

PP&I. DIMENSIONS

BRUNNER ISLAND

Coal

1469 MW

MA

NS CREEK

Coal,

1, Gas

1940 M

HOLTWOOD

Coal, Hydro

175 MW

MONTOUR

Coal,

- 1525MW-t,;;;,

V

",-*' SUSQUEHANNA

SUNBURY, '-: =."'.:.-'"" 1950 MW

Coal:<

-1950 MW

389 MW ..

4

vervievr 0

Corporate Strategic Direction

Superior Nuclear Performance

Focus on Core Business in the

Communities We Serve

Electric Energy Market Development

Shaping the Future for Competitive

Success

e

or orate

ssue

E ectric Utii

Industry Restructuring

Electric Utilities Have Made

Si

'cant Progress in the Transition

&omVertically-Integrated Franchised

Monopolies to Competitive

Businesses

e

or orate

ssue

E/ectric UtilityIndustry Restructuring

Safe Operation

>> Impacts of Business Decisions

Electrical System Reliability

>> Control of Transmission Facilities

Financial QualjLBcations

>> Funding Decommissioning

>> Definition of an Electric Utility

e

or orate

ssue

Electric UtilityIndustry Restructuring

~ PP &L'sPosition

. Comiinitment to Superior Nuclear Performance

Advocate for Competition

Heavy Involvement in Shaping Pennsylvania's

Model

>> Generation Reliability

>> Decommissioning-

>> Stranded Investment

>> PJM as an Independent System Opera'.or

roaC

to

uC ear

We Have a Conservative Operating Philosophy

Being Accountable for Safe Operation

Performing Self Assessments

and Maintaining an

External Perspective

Preserving Fundamentals While Continuously

Improving

Our Managemerit is Involved

Providing Active Leadership

Maintaining a Long Term Corporate Commitment

S

roac

to

uc ear

We Emphasize Communication

Listening to Others

Learning Through Industry Involvement

Fostering an Environment of Trust and Involvement With

Employees and the Public

We Maximize Employee Potential

Technical and Business Training

Developing Supervisors and Managers

We Plan for the Future

Safety, Reliability, and Financial Objectives are Mutually

Compatible

Key Nuclear Department Initiatives

~ October 9, 1996 NRC Letter

10CFR50.54k

~ Employee Concerns Program

~ Supervisory Development

Key Nuclear Department Initiatives

October 9, 1996 10CFR50.54

Letter

Susquehanna

Current Licensing Basis Strengths:

>> Strong InitialReview and Documentation

>> Major Projects Aided Continued Enhancement

Proactive Assessment Began in February 1996

Enhancements

are Underway

Ongoing Work WillSupport a Thorough Response

Key Nuclear Department Initiatives

Employee Concerns Program

We Have Monitored the Effectiveness ofThis Program

Since Its Inception and WillContinue to Do So.

1995 ECP Periodic Independent Assessment

>> Strong Nuclear Safety Culture

>> Improved Sensitivity by Line Management

>> Employees/Contractors

are Willingto Raise Concerns

Periodic Independent Assessments WillContinue

Industry Lessons Learned

NRC Allegation Advisor Annual Report

Key Nuclear Department Initiatives

Supervisory Development

Leadership Academy

>> Designed to Enhance the Department's Ability

to Balance its Business, Interpersonal and

Technical 0'j~ectives

>> Modeled After Plant Certification Program

>> Focused Training on Management, Business

and Leadership Skills

15

~

~ I

0