ML17157A627

Insp Repts 50-387/90-26 & 50-388/90-26 on 901230-910211. Violation Noted.Major Areas Inspected:Operations Radiological Controls,Maint/Surveillance Testing,Emergency Preparedness,Security & Engineering/Technical Support

ML17157A627
Person / Time
Site:	Susquehanna
Issue date:	03/19/1991
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17157A626	List: ML17157A625 ML17157A627
References
50-387-90-26, 50-388-90-26, NUDOCS 9103290049
Download: ML17157A627 (36)

See also: IR 05000387/1990026

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Inspection

50-387/90-26; 50-388/90-26

Report Nos.

License Nos.

NPF-14; NPF-22

Licensee:

Pennsylvania Power and Light Company

2 North Ninth Street

Allentown, Pennsylvania

18101

Facility Name:

Inspection At:

Susquehanna

Steam Electric Station

Salem Township, Pennsylvania

Inspection

Conducted:

December 30, 1990 - February

11, 1991

Inspectors:

G. S. Barber, Senior Resident Inspector, SSES

J. R. Stair, Resident Inspector, SSES

H. J. Kapl n, S

io

Reac

ngineer, DRS

Approved By:

J

~

ite, Chief

eactor Projects Section No. 2A,

Division of Reactor Projects

ate

Ins ection Summar:

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p

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d ai hfll ig

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radiological controls, maintenance/surveillance

testing, emergency preparedness,

security,

engineering/technical

support, safety assessment/quality

verification, and Licensee Event

Reports, and Significant Operating Occurrence Reports.

Results:

During this inspection period, the inspectors found that the licensee's activities were

directed toward nuclear and radiation safety.

One violation was identified.

The violation

involved failure to maintain activities as specified by the Procedure 80-QA-300, Conduct of

Operations, relative to implementing Technical Specification 3.6.3 as it pertains to inoperable

Main Steam Isolation Valves.

See Section 2.2.2 for details.

An Executive Summary is included and provides an overview of specific inspection findings.

T

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TABLE OF CONTENTS

EXECUTIVESUMMARY......

SUMMARYOF OPERATIONS ~...

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1.1

Inspection Activities........

1.2

Susquehanna

Unit 1 Summary

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1.3

Susquehanna

Unit 2 Summary ..

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OPERATIONS

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2.1

Inspection Activities................. ~..........

2.2

Inspection Findings and Review ofEvents...............

2.2.1

Loss of Shutdown Cooling - Unit 2

2.2.2

Inoperable Inboard Main Steam Isolation Valves - Unit 1

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RADIOLOGICALCONTROLS

3.1

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

3.2

Inspection Findings

3.2.1

Review of Licensee Posting Practices

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MAINTENANCE/SURVEILLANCE.........................

4.1

Maintenance and Surveillance Inspection Activity

4.2

Maintenance Observations

4.2.1

Use of Unapproved Sealing Material on Secondary Containment

Boundary Removable Walls

4.3

Surveillance Observations........

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4.3.1

Missed Surveillances

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EMERGENCY PREPAREDNESS................

5.1

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

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Inspection Findings

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SECURITY

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6.1

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

6.2

Inspection Findings

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

7.1

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

7.2

Inspection Findings

7.2.1

RHR Pump Cooler Failure - Metallurgical Report Review

7.2.2

Deficiency 'Reduction Program - Incorrect Assumption Made For

250 VDC

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Table of Contents (Continued)

8.

SAFETY ASSESSME NT/QUALITYVERIFICATION

8.1

Licensee Event Reports (LER), Significant Operating Occurrence

Report

8.1.1

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

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9.

MANAGEMENTAND EXIT MEETINGS .......................

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9.1

Routine Resident Exit and Periodic Meetings....... ~..........

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EXECUTIVESUMMARY

Susquehanna

Steam Electric Station

Inspection Reports

50-387/90-26; 50-388/90-26

4

December 30, 1990

- February

11, 1991

operations (71707, 92701, 92720)

A loss of Shutdown Cooling in Unit 2 occurred on January

8 which caused reactor

temperature to increase from 108 to 135 degrees F.

The cause was attributed to the failure of

an I&C work planner to reference all applicable drawings when preparing the work

instruction.

On January

15, the inboard Main Steam Isolation Valves (MSIVs) were declared inoperable

due to low Containment Instrument Gas (CIG) pressure.

Plant operators failed to recognize

the applicability of TS 3.6.3 for the condition; and the applicable surveillance procedure

failed to reference the pertinent Limiting Condition For Operation.

This matter was

identified as a violation of TS 6.8.1 for failure to maintain activities in accordance with the

procedure 80-QA-300, Conduct of Operations (NV4 387/90-26-01).

Radiolo ical Controls (71707)

Individual workers and Health Physics personnel implemented radiological protection

program requirements.

Periodic inspector observation noted no inadequacies

in the licensee's

implementation of the radiological protection program.

Licensee posting practices relative to 10 CFR 19.12 were reviewed.

The licensee also

performed a review of posting practices and noted that posting responsibilities were not

clearly delineated nor was the procedure adequate for the scope of the activities.

The

licensee has implemented specific procedure enhancements

and procurement activities to

improve postings.

Maintenance/Surveillance

(61726, 62703)

The licensee exercised good control of maintenance

and surveillance activities.

No scrams

were attributable to maintenance or surveillance activities.

However, improper performance

of a Unit 2 work activity led to a shutdown cooling isolation.

1

The inspector noticed a change in the sealing material used for the temporary walls for the

Unit 1 Reactor Building during a routine tour and questioned

the use of unapproved

material

111

for this application in the plant.

Accordingly, the licensee is reviewing their use of

consumable materials for various safety-related applications.

F >ur LERs were reviewed during the period concerning missed surveillances

as a result of

dissimilar causes.

The inspector plans to continue monitoring this area for potential program

weaknesses.

Emer enc

Pre aredness

No emergency preparedness

issues emerged during the reporting period.

~ecurit

(71707)

Routine observation of protected area access

and egress control showed good control by the

licensee.

En ineerin /Technical Su

ort (37700, 71707, 92720)

Metallurgical Reports covering the RHR Pump Motor Cooler Failures were reviewed.

These

reports concluded that the primary cause of the failure was under deposit corrosion with some

contribution from microbiological induced corrosion.

A Licensee Event Report (LER) was written to document a concern identified in 1989

regarding the ability of the 250 VDC batteries to meet their four-hour minimum load

requirements.

This LER was written as a result of reviewing old issues for reportability

under the new reporting criteria established by the licensee.

This issue was not reported at

the time it was identified since compensatory

measures

were promptly implemented.

afet

Assessment/As

urance f

ualit

(90712, 92700, 92701, 92720)

A total of 14 LERs were reviewed during the period, 5 of which were followed up in this

report.

A total of 61 Significant Operating Occurrence Reports were reviewed during the period, 3 of

which were followed up in this report.

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1.

SUlVMARYOF OPERATIONS

1.1

Inspection Activities

~Detail

The purpose of this inspection was to assess

licensee activities at Susquehanna

Steam Electric

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

Within each

inspection area, the inspectors documented

the specific purpose of the area under review, the

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

This

assessment

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

personnel,

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

applicable documents.

Abbreviations are used throughout the text.

Attachment

1 provides a

listing of these abbreviations.

1.2

Susquehanna

Unit 1 Summary

Unit 1 operated at or near full power until experiencing an extraction steamline isolation on

February 4.

A manual power runback to 80 percent was performed pending repairs to a level

control valve on the drain line to the 3C feedwater heater.

Full power was restored on

February 6 and was maintained throughout the remainder of the period.

Scheduled power

reductions were also conducted during the period for control rod pattern adjustments,

surveillance testing, and maintenance.

No ESF actuations or scrams occurred during the

period.

1.3

Susquehanna

Unit 2 Sumniary

Unit 2 operated at full power prior to January 5, when the unit was shutdown to replace an

0-ring on the "B" reactor recirculation pump motor.

Other problems corrected while

shutdown were two suppression pool-to-drywell vacuum breakers which failed to reseat

following functional testing, and a failed main generator current transformer.

Full power was

restored on January

12 following repairs and was maintained throughout the rest of the-

period.

Scheduled power reductions were conducted during the period for control rod pattern

adjustments,

surveillance testing, and maintenance.

One ESF actuation and no scrams

occurred during the period.

A shutdown cooling system isolation occurred on January 8.

See Section 2.2.1 for details.

2.

OPERATIONS

2.1

Inspection Activities

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

regulatory requirements.

Pennsylvania Power and Light (PP&L) Company management

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

discussions with personnel,

independent verification of safety system status and Limiting

2

Conditions for Operation, and review of facility records.

These inspection activities were

conducted in accordance with NRC inspection procedures 71707, 92701, and 92720.

The inspectors performed

15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> of deep backshift inspection during this reporting period.

2.2

Inspection Findings and Review of Events

2.2.1

Loss of Shutdown Cooling - Unit 2

A loss of shutdown cooling (SDC) occurred at 9:44 a.m., January 8, due to the opening of a

states link in the RHR Low Pressure permissive circuitry. The licensee was installing a new

switch (B31-N018A) in the RHR pressure permissive circuitry when the isolation occurred.

To de-energize the circuit, a states link (a connector that the work instructions described

as

providing 'power between terminal points FF-1 and FF-2 as shown on GE Elementary Dwg.

No Ml-B21-101 Sheet

10) was opened.

However, opening of this states link also

deenergized

the K39 and K33A relays; which, in turn, caused RHR suction valves

(F-008 and F-009) to close.

During the transient, from 9:44 a.m. to 1,0:50 a.m., reactor

water temperature rose from 108 to 135 degrees F.

The licensee throughly examined the cause for this event, prior to resetting the isolation

signal, to ensure that no additional problems would result.

The isolation was reset, SDC

restored,

and the heatup was terminated.

The licensee formed an Event Review Team (ERT) ~

The NRC was notified per 10 CFR 50.72.

The ERT reviewed the event and determined that the cause was due to an I&C work planner

not referencing the proper drawings when he developed the instructions for the pressure

switch replacement.

The work instructions involved jumper installation and opening states

links within a wiring panel.

The jumper installation was necessary

to prevent the RHR

isolation by maintaining the circuit energized when the links were opened.

However, the

work planner improperly based the work instructions solely on GE Elementary Dwg. No.

M1-B21-101, an elementary drawing that did not describe all of the details within the wiring

panel

~ The ERT determined that the use of the elementary drawing was improper to use as a

sole reference for planning the work. The ERT concluded that the work planner failed to

review the applicable wiring connection lists and diagrams that were pertinent to this work;

and consequently failed to identify the proper jumper connections on the work description.

As a result, the jumpers were not installed on the proper contacts.

Accordingly, when the

links were opened, the isolation logic was actuated,

and the RHR valves closed.

As a result of this event, the licensee is developing an Instrumentation & Controls planners

guide.

This guide willprovide direction for planning of I&C maintenance

functions

including utilization of all applicable drawings and references during the planning process.

Training on this document will be performed for appropriate personnel.

In addition, the

physical wiring arrangement in the subject panel willbe modified to improve field

wiring/internal wiring interface and to improve logic circuit testability.

The estimated

3

completion date for the planners guide preparation and applicable training is September

1,

1991.

The inspector reviewed the ERT findings and proposed corrective actions and noted that the

conclusion and corrective measures

appeared

to adequatly address this event.

2.2.2

Inoperable Inboard Main Steam Isolation Valves - Unit 1

The Containment Instrument Gas (CIG) System supplies a local MSIV accumulator that,

along with springs, ensures rapid closure of the Main Steam Isolation Valves during accident

conditions.

Accordingly, MSIV closure time is dependent on the air pressure in the

accumulator.

While the pre-1989 FSAR listed "springs alone" as an acceptable closing

method, NCR 89-0064 questioned

the ability of the inboard MSIVs to close during a design

basis accident (DBA) with springs alone.

After detailed analysis, the licensee concluded that

both springs and air are necessary

to meet the design closure times for a DBA, i.e., greater

than 3 but less than 5 seconds.

As a result, the licensee modified the inboard MSIV

operability statement in the applicable Shift Surveillance Operating Log Procedure SO-100-

006 to require that CIG pressure be maintained at 85 psig or greater to ensure these closure

times.

At 8:40 a.m., January

15, an operator on rounds noted that Unit 1 CIG pressure

had dropped

to 80 psig.

The operator reported the low pressure to the control room.

Consequently,

the

inboard MSIVs were declared inoperable,

and TS LCO 3.4.7.a. was entered since procedure

SO-100-006 referenced this TS as being applicable.

TS LCO 3.4.7.a requires restoration of

the affected MSIVs to operability, or isolation of the affected steam lines within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />; or

otherwise, plant shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Accordingly, action was taken by IAC

to adjust the malfunctioning Pressure Control Valve (PCV-16241) to achieve control pressure

in the normal band.

Following successful adjustment,

the system was returned to an operable

status.

CIG pressure was restored,

and TS LCO 3.4.7.a.

was exited at 3:15 p.m.

The

licensee continues to monitor CIG pressure to verify that pressure remains above 85 psig.

During this evolution, the outboard MSIVs remained operable since these valves were not

affected by the malfunctioning of PCV-16241.

The cause of the event appears

to be due to a combination of factors:

1) low flow through the

valve hampers its ability to control pressure in a tight band; 2) very fine particles on the

valve disc and seat are believed to hamper totally free, uninhibited valve movement; and 3)

the control band for the valve is at the extreme low end of its design.

The licensee took

immediate corrective action to adjust the PCV within the control band and has taken

additional action to increase flow through the system to improve PCV response.

In addition,

system filters were inspected for unusual debris or dessicant breakdown.

No unusual

indications were noted.

The inspector reviewed the licensee's actions and specifically questioned

the licensee on the

applicability of TS LCO 3.6.3, "Primary Containment Isolation Valves," since the MSIVs

0

affected are listed in Table 3.6.3.1.

The licensee reviewed the TS and determined that it was

applicable.

The inspector noted that TS 3.6.3.a. requires remedial action within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />,

whereas TS 3.4.7.a. allowed 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Specifically, TS 3.6.3.a. requires isolating the '

affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (as opposed to the 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> permitted by TS 3.4.7.a) or be

in hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The inspector noted that while neither TS was actually violated in this particular instance, it

was fortuitous, and not by design, that the licensee did not exceed the LCO for TS 3.6.3.

The inspector identified, that TS 6.8.1 required the licensee to establish, implement, and

maintain written procedures'affecting

safety-related activities; and that Procedure 80-QA-300,

"Conduct of Operations," Section 6.2, Formal Directions, required the licensee to maintain

plant operations within the boundaries specified by Technical Specifications and License

Conditions.

Accordingly, the failure to maintain plant operations

as specified by Procedure

80-QA-300, "Conduct of Operations," due to the plant operators'ailure

to implement the TS 3.6.3.a relative to their determination that the inboard MSIVs were inoperable constitutes

a

violation of TS 6.8.1. (NV5 50-387/90-26-01)

The licensee has subsequently

submitted PCAF 1-91-0028 to add TS LCO 3.6.3.a to Shift

Surveillance Operating Log Procedure,

SO-100-006.

3.

RADIOLOGICALCONTROLS

1

3.1

Inspection Activities

PP8.L's compliance with the radiological protection program was verified on a periodic basis.

These inspection activities were conducted in accordance with NRC inspection procedure

71707.

3.2

Inspection F<indings

Observations of radiological controls during maintenance activities and plant tours indicated

that workers generally obeyed postings and Radiation Work Permit requirements.

No

inadequacies

were noted.

3.2.1

Review of Licensee Posting Practices

The inspector reviewed posting practices relative to 10 CFR 19. 12 to assess

the licensee's

method for posting information pertaining to violations, civil penalties,

and orders that were

related to radiological working conditions.

Postings must be made within two days of receipt

and they must be made in areas in which the affected activities take place.

In addition, they

must remain posted for 5 days or until corrective action is complete, whichever is longer.

The licensee previously identified some problems with postings.

SOOR 1-90-306

documented

missing postings in the control structure access

area that were removed for a

remodeling effort.

Licensee investigation found that there were four reasons why the event

0

cumented missing postings in the control structure access

area that were removed for a

remodeling effort.

Licensee investigation found that there were four reasons why the event

occurred:

1) clear accountability for posting, auditing, and updating of these

10 CFR 19

requirements were not specified in NDI-QA-3.3.4, the licensee's procedure which describes

posting requirements; 2) the locations of all posting areas was not procedurally identified; 3)

routine reviews of the condition and content of the material posted is not performed; and 4)

postings are performed by several groups on site which leads to inconsistent posting practices.

The licensee took prompt action to correct the immediate posting deficiencies by replacing the

removed postings, auditing postings to ensure the proper material was in place, and providing

direction on removing out-of-date information. In addition, as long-term corrective action,

NDI-QA-3.3.4 is being revised to specify the Docket Control Center Supervisor as the

individual who is solely responsible for updating and ensuring adequate postings.

A new

procedure checklist will be used as the basis for future audits.

The licensee is also in the

process of procuring dedicated bulletin boards for postings.

Long-term actions are scheduled

to be completed on or before March 31, 1991.

Some of the new bulletin boards were in

place at the end of the inspection period.

The inspector reviewed licensee actions for their self-identified posting problems and noted

that they were thorough and their schedule appeared

to be timely. A spot check of existing

postings showed that they were adequate.

However, the postings in the Unit

1 Access Area

were cluttered and portions of the postings were covered.

This was corrected by the licensee.

In addition, the inspector questioned

the licensee on postings made at the corporate office.

The licensee informed the inspector that postings at the corporate offices are made on the

corporate communications bulletin boards and are controlled by Licensing.

At the time of

this review, there were no outstanding violations, civil penalties, or orders involving.

radiological work practices that required posting by the licensee at the corporate office.

The

inspector had no further questions.

4.

MAINTENANCE/SURVEILLANCE

4.1

Maintenance and Surveillance Inspection Activity

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

maintenance activities to ensure that specific programmatic elements described below were

being met.

Details of this review are documented in Sections 4.2 and 4.3.

4.2

Maintenance Observations

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

work was conducted in accordance with approved procedures,

regulatory guides, Technical

Specifications, and industry codes or standards.

The following items were considered,

as

applicable, during this review: Limiting Conditions for Operation were met while

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

obtained prior to initiating the work; activities were accomplished

using approved procedures

and quality control hold points were established

where required; functional testing was

performed prior to declaring the involved component(s)

operable; activities were

.t

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

controls were implemented; and equipment was returned to service in accordance with the

licensee's procedures.

These observations and/or reviews included:

evaluation of differential and discharge pressures for the "A" Containment Radiation

Monitor Sample Pump per WA S16089 on January 24;

investigation of Transverse Incore Probe problems per WA 16099 on January 24;

eighteen month inspection on the "E" Emergency Diesel Generator per WA A-04597

on January 25;

inspection/replacement of Cylinder Liners as Required to Support Diesel Generator

(DG) Work per WA S05015 on January 25;

annual preventive maintenance

on the "A" Containment Instrument Gas compressor

per WA P05044 on February

1; and,

installation of relays and wiring to support the "C" DG Fuel Oil Tank Low Level

Switch Upgrade per WA C00675 on February 7.

No unacceptable

conditions were identified.

4.2.1

Use of Unapproved Sealing Material on Secondary Containment Boundary

Removable Walls

During a tour of the Unit 1 reactor building, the inspector noted that the licensee had

replaced the caulking type sealing material used on the removable walls of the Unit

1 reactor

building with an expandable

foam type material.

Per applicable drawings and design

specifications,

a neoprene gasket provides the primary sealing material for the removable

walls.

However, per the drawings, ifair gaps exist around the gasket, an approved sealing

material such as Dow Corning 790 caulking may be used for additional sealing.

The licensee

was therefore asked to provide a copy of the replacement item equivalency evaluation (RIEE)

or a safety evaluation which properly evaluated the material and determined it was acceptable

for use.

The licensee was not able to find documentation which provided the requested

information and consequently

generated

a Nonconformance Report (NCR) to document the

condition and disposition the nonconformance.

The inspector reviewed the NCR and noted that an NPE evaluation stated that the expandable

foam (HILTICB120 Filler Foam) now "in-use" was unacceptable

due to its inferior

adhesion,

tensile strength, and flame resistance characteristics.

The maintenance group

disagreed with the evaluation and stated that they considered

the foam acceptable for use

since the neoprene gasket provides secondary containment boundary integrity, and the sealing

material, although used for additional protection, is not required.

Based on the NCR, the

inspector noted that the licensee must determine whether the material is acceptable for use

and take action in accordance with that determination.

Since the licensee verified that the neoprene 'gasket was in place on the removable walls, the

inspector noted that secondary containment integrity was not in question.

However, the

concern remained regarding the licensee's

apparent failure to perform a proper evaluation

prior to substituting another material for the specified sealant.

Work documents provided by

the licensee demonstrated

that review was performed and authorization obtained prior to

substituting the sealing material.

However, it was apparent that the review failed to

adequately consider the drawing specification calling for DOW Corning 790 caulking.

The use of the Susquehanna

Approved Materials (SAM) list in authorizing the substitution of

material on safety-related applications is not appropriate without a proper evaluation.

The

individual(s) reviewing the SAM list misinterpreted the allowed use of the Hilti foam for this

application.

Since weaknesses

in the process for substitution of materials apparently exist,

and the licensee has agreed to evaluate this matter for improvement.

This item will remain

unresolved pending evaluation of the licensee's review and corrective actions pertaining to the

substitution of materials.

(UNR 50-387/90-26-02)

4.3

Surveillance Observations

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

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

the test conformed to

Technical Specification requirements;

administrative approvals and tagouts were obtained

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

accordance with an approved procedure;

test instrumentation was calibrated; Limiting

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

restoration of the affected components

was properly accomplished;

test results met Technical

Specification and procedural requirements;

deficiencies noted were reviewed and

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

These observations and/or reviews included:

50-250-00, RCIC Quarterly Flow Verification, performed on January 24.

SO-030-003, Quarterly Control Structure Chilled Water Flow Verification, performed

on February 7.

No unacceptable

conditions were identified.

4.3.1

Missed Surveillances

The following LERs reviewed by the inspector are included in this section since they involve

surveillances which were not performed within their respective TS windows.

LER 90-031-

Technical

ecificati n R

uired Area Radiation Surve

Not Perf rmed-

Unit 1

On November 29, 1990, the licensee discovered that a radiation survey of the reactor

building refueling floor was not performed as required by TS 3.3.7.1, Action 71

~ The

licensee performed the required radiation surveys on November 27 and 28, preceeding the

event, but failed to perform the survey. on November 29.

Upon discovery of this condition

on November 30, the required survey was immediately performed.

The surveys were being

performed at 5:30 p.m. each day by second shift personnel,

and the survey was performed on

November 30 at 2:00 a.m., resulting in the required survey being taken approximately eight

and one half hours late.

The radiation surveys were required to compensate for the spent fuel storage pool criticality

monitors which had been removed from service on November 27, 1990.

The criticality

monitors were removed from service, declared inoperable, and TS LCO 3.3.7.1 entered

while an inspection of the reactor water cleanup filter/demineralizer vessels took place.

Since

the inspection of the filter/demineralizers required removal of floor plugs on the refueling

deck, the licensee was concerned that radiation levels in the vicinity of the criticality monitors

would increase resulting in exceeding alarm setpoints.

Alarming of the monitors would

interfere with work being performed since personnel are required to withdraw from the area

upon the sounding of the alarm per 10 CFR 70.24 (a)(3).

Therefore, the justification for

removing the criticality monitors from service was to prevent their alarming and to allow the

performance of the inspections.

The licensee determined that the missed survey was caused by personnel error and procedural

inadequacies

in that the responsibilities and specifications for performing the non-routine

survey was not clearly defined by procedures,

the survey was not designated

as priority work

or scheduled on the health physics (HP) work list, and the means available to remind HP

personnel that the survey was required was not sufficiently obvious.

In this case, the inspector also noted that the need to remove the criticality monitors from

service was not clearly established,

adequate procedural controls were not in place to assure

that compensatory

measures

were accomplished,

and the work for which the criticality

monitors were removed from service was not expedited.

In reviewing the procedural'controls

for removing equipment from service, the inspector noted that guidance had not been

established

to cause evaluation of decisions to remove equipment from service and voluntarily

enter TS LCOs.

Accordingly, the licensee. initiated action to implement such guidance in

.

appropriate procedures

to correct this weakness.

Other corrective action, planned or taken,

0

included revising procedures to: 1) clearly define responsibilities for non-routine survey

performance; 2) better identify the requirements for surveys; 3) improve the process for

communicating information and instructions; and 4) document shift turn-over instructions.

Personnel training relative to this event and the revision of the applicable procedures

is

planned for completion by March 9, 1991.

These corrective actions appear adequate to resolve the problem.

Since the licensee met the

requirements

stated in 10 CFR 2 Appendix C, Sections V.A and V.G.1, this item is

considered

a non-cited violation,

(NON 50-387/90-26-03)

LER

0-009-0

HPCI and R I

team

I

Pre sure Low Re

onse Time Te tin

Not

Performed Within R

uired Time Interval -

nit 2

On September

19, 1990, the licensee discovered that the response time testing for HPCI and

RCIC steam supply low pressure instrumentation was not completed within the required

18

month surveillance interval specified by the TS.

The elapsed time from previous testing was

approximately 30 1/2 months or 8 months beyond the allowable grace period.

The licensee

immediately tested both the HPCI and RCIC instruments following discovery, with

satisfactory results.

The licensee found the cause of this event to be an incorrect determination of channel

redundancy of the affected instrumentation during a review of the elementary diagrams in

1989.

This resulted in procedural revisions which specified testing at a lesser than allowable

frequency.

Corrective actions taken were to correct the testing frequencies specified in the

applicable surveillance procedures

and to assure that no other similar situations existed by

reviewing response time testing procedures for correct testing frequencies.

Inspector review of this event and the licensee's corrective actions found their response

acceptable.

Since the licensee met the requirements

stated in 10 CFR 2 Appendix C, Section

V.A and V.G.1, this item is considered

a non-cited violation.

(NON 50-388/90-26-01)

LER

0-010- 0

ondensate Transfer Pum

Dischar e Low Pressure Alarm

ic

urveillance Not

om le ed Within the R

ired Monthl

Time Interval -

nit 2

On October 2, 1990, the licensee discovered that the monthly channel functional test of the

condensate

transfer pump discharge low pressure alarm logic had not been completed within

the required surveillance time interval.

The discovery was made during a review of a print-

out of surveillance tests that had been determined not applicable for existing plant conditions

(out-of-mode)

~

The latest possible date for performing the surveillance was September 27.

Since the test was immediately performed following discovery on October 2, the test

exceeded

the allowable period by 5 days.

The licensee determined the cause of the event to be a scheduling error on the part of

Instrumentation and Controls (I&C) personnel due to insufficient procedural controls.

Station

10

procedures did not require independent review of out-of-mode determinations, which might

have identified the improper placement of this test in the out-of-mode category.

In response,

the licensee reviewed all common surveillance tests under

ISAAC department

responsibility and verified that no other tests were inappropriately placed in the Out-of-Mode

condition.

Corrective actions completed to prevent a recurrence involve changes to ISAAC and

administrative'procedures

which now require a second level of review prior to placing a

surveillance in the out-of-mode category.

The inspector reviewed and discussed

this event with members of the licensee's staff.

Licensee response to the event was found to be appropriate.

Since the licensee met the

requirements

stated in 10 CFR 2 Appendix C, Sections V.A. and V.G.1, this item is

considered

a non-cited violation.

(NON 50-388/90-26-02).

LER 90-012-00 Turbine Overs

eed Testin

Not

om leted Within Re uired Time F llowin

erational Condition Chan

es -

nit 2

On October 28, the licensee determined that they had, on two previous occasions,

not

complied with the TS requirement to perform turbine overspeed

protection testing within 24

hours of entry into Condition 2 (Startup).

The requirement to perform this testing within 24

hours of startup was incorporated into the TS 4.0.3 bases in 1988 as a result of Generic Letter 87-09, but is not stated in TS 4.3.8.2, which mandates turbine overspeed protection

system testing requirements.

The licensee determined that since performance of this test follows placing the turbine in

service at approximately

15 percent power, overspeed

testing could not be performed within

the required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following entry into Condition 2.

The amendment to TS 4.0.3 bases

did not recognize this testing constraint and imposed the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time limit. However, the

licensee failed to recognize this new turbine overspeed

testing requirement.

The licensee has temporarily changed their testing method such that the valves are now cycled

in Condition 4 (Cold Shutdown) prior to placing the unit in startup.

However, the licensee

considers this undesirable due to the potential degradation of the turbine valves which are

cycled without steam pressure to mitigate mechnical shock upon closure.

The preferred

method is with the turbine in service.

Accordingly, the licensee plans to submit a TS change

request which would require turbine overspeed protection system testing within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of

placing the turbine in service, thereby reducing the potential for valve degradation.

The inspector reviewed and discussed

this event with appropriate licensee staff.

As a result,

the inspector found the licensee's actions in response to this event acceptable.

However, a

violation of the licensee's TS did occur as a result of the failure to perform this test within

the required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following entry into Condition 2.

Since the licensee met the

requirements

stated in 10 CFR 2 Appendix C, Section V.A. and V.G.1, this item is

considered

a non-cited violation.

(NON 50-388/90-26-03).

11

Qgnclusion

Although the above LERs all pertain to missed surveillances,

the causal factors are dissimilar.

The inspector, therefore, concluded that enough dissimilarities between these LERs exist such

that non-cited violations were appropriate for each situation.

Specifically:

the causes for

LER 90-031-00 involved poor shift turnover and inadequate procedural guidance concerning

radiation surveys; the cause for LER 90-009-00 involved an error made in previous

determination of the appropriate frequency in which to perform certain HPCI and RCIC

instrument response time testing; the cause for LER 90-010-00 involved an error placing a

surveillance test for the condensate

transfer system logic onto the out-of-mode list; and, the

cause for LER 90-012-00 involved the failure to recognize that an amendment to a TS bases

resulted in a change in the requirements

to perform turbine overspeed

testing.

In each case,

the licens'ee met the requirements of 10 CFR 2 Appendix C, Sections V.A. and V.G.1.

As

part of the routine resident inspection program, the inspectors will continue to monitor this

area to determine ifthere are programatic weaknesses.

5.

EMERGENCY PREPAREDNESS

5.1

Inspection Activity

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

could have required entry into the emergency plan.

5.2

Inspection Findings

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

were

identified.

6.

SECURITY

6.1

Inspection Activity

PPEcL's implementation of the physical security program was verified on a periodic basis,

including the adequacy of staffing, entry control, alarm stations, and physical boundaries.

These inspection activities were conducted in accordance with NRC inspection procedure

71707.

6.2

Inspection Findings

On a periodic basis, the inspector reviewed access

and egress controls throughout the period.

No unacceptable conditions were noted.

0

12

7.

ENGINEERING/TECHNICALSUPPORT

7.1

Inspection Activity

The inspector periodically reviewed engineering and technical support activities during this

inspection period.

The on-site Technical (Tech) section, along with Nuclear Plant

Engineering (NPE) in Allentown, provided engineering resolution for problems during the

inspection period.

The Tech section generally addressed

the short term resolution of

problems while NPE scheduled modifications and design changes,

as appropriate,

to provide

long lasting problem correction. The inspector verified that problem resolutions were

thorough and addressed

at preventing recurrences.

In addition, the inspector reviewed short

term actions to ensure that the licensee's corrective measures

provided reasonable

assurance

that safe operation could be maintained.

7.2

Inspection Findings

7.2.1

RHR Pump Cooler Failure - Metallurgical Report Review

The inspector reviewed several supplemental

metallurgical reports provided by the licensee

covering their investigation of a leak in the residual heat removal (RHR) pump motor oil

cooler that occurred in May 1990.

(See Inspection Report 50-387/90-10).

These reports

were identified as PLI-64448, PLI-64190 and TML-197-90-002.

The RHR pump motor coolers are fabricated from a single coil of 7/8 inch diameter copper

tubing.

There are 8 coolers (4 per unit).

Emergency Service Water (ESW) flows through

the cooler and is the heat sink for the system.

The ESW system is supplied by a pond with

makeup water coming from the cooling tower blowdown and with additional makeup from

the Susquehanna

River, as needed.

The licensee reviewed the likely failure mechanisms

and concluded that the leakage was

caused by corrosion involving both microbiological induced corrosion (MIC) and under

deposit corrosion.

The inspector also noted that, in addition to examining the failed RHR pump motor cooler,

the licensee examined the remaining seven coolers and two 90-10 copper-nickel RCIC

(reactor core isolation cooling) coolers.

During these additional examinations, similar

corroded conditions as observed in the failed RHR cooler were found, except that no through-

wall leakage had occurred.

Pit depths varied, but in one of the RHR units pit depth was

found to be 35% of the wall, and a pit depth of 60% of the wall was found in one of the

RCIC coolers.

The licensee also noted that during a destructive examination, various internal

deposits had high levels of microbiological activity and contained high levels of sulfate

reducing and acid producing bacteria.

Such indications supported MIC as a major cause of

13

the corrosion.

The corrosive conditions were aggravated by the fact that the ESW was

stagnant between 65 to 75 percent of the time since 1987.

Subsequent

to the event, the licensee replaced all eight RHR coolers with new copper units

and plans to replace the RCIC 90-10 copper-nickel coolers with AL6XN(Ni-Cr-Mo

stainless),

an alloy of superior resistance to MIC. This alloy will also be used to'replace the

tubing in other selected heat exchangers.

In addition, the licensee intends to initiate an 18

month inspection and cleaning program for those components subject to MIC. No

inadequacies

were noted.

7.2.2

Deficiency Reduction Program - Incorrect Assumption Made For 250 VDC

Battery Load Profiles

As part of a comprehensive program to reduce the number and impact of outstanding

deficiencies, the licensee is reviewing all open NCRs, SOORs, and EDRs.

This is being

done as a part of the licensee's overall deficiency reduction program.

In addition to assessing

significance, basis for continued operations,

and the adequacy of schedules for closure of

these deficiencies,

a re-evaluation of the previous reportability determinations

was performed

using current philosophy and NRC guidance.

The licensee's current reporting threshold

emphasizes

the need to evaluate reportability based on the potential adverse consequences

of

these uncorrected deficiencies.

As a result the following item was deemed to meet reporting

thresholds such that had it occurred today, it would have been determined to be reportable

and thus was reported per 10 CFR 50.73.

SOOR 1-89-045 documented

a condition that could have pievented the fulfillmentof the

safety function of the Unit

1 250VDC battery.

This system had no automatic trip features or

procedural controls to ensure the removal of certain non-safety related loads during a station

blackout.

Battery banks ID650 and ID660 are required to provide power to essential loads

during a station blackout.

Overloading these batteries could have prevented the fulfillmentof

the support system safety function for HPCI ~

There was no similar impact on Unit 2 since a

modification was completed in 1982 which installed a non-safety related battery bank for non-

essential loads.

This condition was originally identified on January 26, 1989, but was not reported.

However, based on the new reporting criteria, this postulated single failure event was later

reported via LER 50-387/90-027-00.

At the time this postulated event was identified, the

licensee modified plant procedures ON-104-001, "Unit 1 Response

to Loss of All Offsite

Power," and EO-100-030, "Unit 1 Response

to Station Blackout," to require removing non-

essential loads during a station blackout.

These procedure changes provided reasonable

assurance

that the Unit 1 250 VDC system would perform its safety related support function.

'he inspector reviewed the licensee's actions for this event and noted that the licensee took

prompt compensatory

action to correct the deficiency when it occurred.

The licensee

determined, in 1989, that the event was not reportable since the compensatory

action

ll

C

0

V

14

, corrected the deficiency.

The reporting of this event is due to applying current criteria which

effectively lowered the reporting threshold.

These criteria are a direct result of more

stringent review standards

and have resulted in increased reporting of these types of events.

The inspector had no further questions at this time.

8.1

SAFETY ASSESSMENT/QUALITY VERIFICATION

Licensee Event Reports (LER), Significant Operating Occurrence Report

(SOORs), and Open Item (Ol) Followup (90712, 92700)

8.1.1

Licensee Event Reports

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

were clearly reported, including the accuracy of the description of the cause and the adequacy

of corrective action.

The inspector determined whether further information was required

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

warranted onsite followup. The following LERs were reviewed:

Unit

1

90-023-'00

90-024-00

Ninth Fuel Bundle Loaded into Core Before SRM's Verified Operable.

ESF Actuations Due to Opening of 13.8 KV Startup Bus 10 Feeder Breaker.

90-025-00

Spurious Actuation of the RPS While in Cold Shutdown - No Control Rod

Motion Since All Rods Inserted.

90-026-00

Control Structure Ventilation Dampers Could Fail Closed During

LOCA/LOOP. This event was reviewed in NRC Inspection Report No.

50-

387/90-25.

90-027-00

Incorrect Assumption Made For 250 VDC Battery Load Profiles.

This event is

reviewed in Section 7.2.2. of this report.

90-028-00

Postulated Single Failure Could Have Placed the Plant in a Condition Outside

Design Basis.

This event was reviewed in NRC Inspection Report 50-387/90-

15.

90-029-00

"B" Standby Gas Treatment System Unexpected Auto Start.

90-030-00

Entries Into Condition 2 Without Completed Surveillances on Unit 1 and Unit

2.

This event was reviewed in NRC Inspection Report 50-387/90-25.

i

l

1y

15

90-031-00

Technical Specification Required Area Radiation Survey Not Performed.

This

event is reviewed in Section 4.3.1

~ of this report.

+nit 2

90-008-01

Secondary Containment Boundary Poor was Blocked Open.

This report

updates LER 90-008 and provides the results of a radiological evaluation of the

effects of the open door on accident analysis dose estimates.

This event was

initially reviewed in NRC Inspection Report No. 50-388/90-15.

90-009-00

HPCI and RCIC Steam Supply Pressure Low, Response Time Testing Not

Performed Within Required Time Interval.

This event is reviewed in Section

4.3.1. of this report.

90-010-00

Condensate Transfer Pump Discharge Low Pressure Alarm Logic Surveillance

Not Completed Within the Required Monthly Time Interval.

This event is

reviewed in Section 4.3.1. of this report.

90-011-00

RWCU Inboard Containment Isolation Valve Declared Inoperable Due to

Incorrect Torque Switch Setting.

This event was reviewed in NRC Inspection

Report 50-388/90-21.

90-012-00

Surveillances Not Completed Within Allowable Time Following Operational

Condition Changes.

This event is reviewed in Section 4.3.1. of this report.

Except as described in the details of this report, the inspector had no further questions

regarding these matters.

8.1.2. Significant Operating Occurrence Reports

SOORs are provided for problem identification and tracking, short and long term corrective

actions, and reportability evaluations.

The licensee uses SOORs to document and bring to

closure problems identified that may not warrant an LER.

The inspectors reviewed the following SOORs during the period to ascertain whether:

additional followup inspection effort or other NRC response

was warranted; corrective action

discussed in the licensee's report appears appropriate; generic issues are assessed;

and,

prompt notification was made, ifrequired:

~Uni i

33 SOORs, inclusive of 1-90-427 through 1-90-431 and 1-91-001 through 1-91-028.

16

1

iit it 2

30 SOORs, inclusive of 2-90-167 through 2-90-171 and 2-91-001 through 2-91-025.

The following SOORs required inspector followup:

1-91-010

documented

the failure to enter all applicable TS LCOs during a drop in CIG

pressure.

See Section 2.2.2 of this report for details.

2-91-003

documented

the inability to perform surveillances on IRMs and SRMs in

accordance with the unit's TS.

This situation was reviewed in NRC Inspection

Report 50-388/90-25.

2-91-009

documented

an unexpected

isolation of RHR shutdown cooling on January

8.

This event is reviewed in Section 2.2.1. of this report.

Except as described in the details of this report, the inspector had no further questions

regarding these matters.

9.

MANAGEMENTAND EXIT MEETINGS

~

~

~

~

~

~

9.1

Routine Resident Exit and Periodic Meetings

The inspector discussed

the findings of this inspection with station management

throughout

and at the conclusion of the inspection period.

Based on NRC Region I review of this report

and discussions

held with licensee representatives,

it was determined that this report does not

contain information subject to 10 CFR 2.790 restrictions.

7'

Abbreviati n List

ATTACHMENT 1

P

AP

- Administrative Procedure

ADS

- Automatic Depressurization

System

ANSI - American Nuclear Standards Institute

CAC

- Containment Atmosphere Control

CFR

- Code of Federal Regulations

CIG

- Containment Instrument Gas

CRD

- Control Rod Drive

CREOASS - Control Room Emergency Outside Air Supply System

DG

- Diesel Generator

DX

- Direct Expansion

ECCS - Emergency Core Cooling System

EDR

- Engineering Discrepancy Report

EP

- Emergency Preparedness

EPA

- Electrical Protection Assembly

ERT

- Event Review Team

ESF

- Engineered Safety Features

ESW

- Engineering Service Water

EWR

- Engineering Work Request

FO

- Fuel Oil.

FSAR - Final Safety Analysis Report

ILRT - Integrated Leak Rate Test

ISAAC

- Instrumentation and Control

IRM

- Intermediate Range Monitor

JIO

- Justifications for Interim Operation

LCO

- Limiting Condition for Operation

LER

- Licensee Event Report

LLRT - Local Leak Rate Test

LOCA

- Loss of Coolant Accident

LOOP - Loss of Offsite Power

MSIV - Main Steam Isolation Valve

NCR

- Non Conformance Report

NDI

- Nuclear Department Instruction

NPE

- Nuclear Plant Engineering

NPO

- Nuclear Plant Operator

NRC

- Nuclear Regulatory Commission

OI

- Open Item

PC

- Protective Clothing

PCIS

- Primary Containment Isolation System

PMR

- Plant Modification Request

PORC - Plant Operations Review Committee

QA

- Quality Assurance

RCIC - Reactor Core Isolation Cooling

RG

- Regulatory Guide

RHR

- Residual Heat Removal

RHRSW

- Residual Heat Removal Service Water

RPS

- Reactor Protection System

RWCU

- Reactor Water Cleanup

SGTS - Standby Gas Treatment System

SI

- Surveillance Procedure,

Instrumentation and Control

SO

- Surveillance Procedure,

Operations

SOOR - Significant Operating Occurrence Report

SPING

- Sample Particulate, Iodine, and Noble Gas

SRM

- Source Range Monitor

TS

- Technical Specifications

TSC

- Technical Support Center

WA

- Work Authorization

~e