Text

Forwards Insp Repts 50-387/97-01 & 50-388/97-01 on 970114-0224 & Notice of Violation.Violations Either Identified by NRC or Resulted in Degradation of safety- Related Components
	ML17158B997
Person / Time
Site:	Susquehanna
Issue date:	03/14/1997
From:	Pasciak W; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	Byram R; PENNSYLVANIA POWER & LIGHT CO.
Shared Package
ML17158B998	List: IR 05000387/1997001; ML17158B997; ML20136J365;
References
	NUDOCS 9703200086
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CATEGORY 2

REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

I

t

CESSION NBR:9703200086

DOC.DATE: 97/03/14

NOTARIZED: NO

IL:50-387 Susquehanna

Steam Electric Station, Unit 1, Pennsylva

50-388

Susquehanna

Steam Electric Station, Unit 2, Pennsylva

AUTH.NAME

AUTHOR AFFILIATION

PASCIAK,W.J.

Region

1 (Post

820201)

RECIP.NAME

RECIPIENT AFFILIATION

BYRAM,R.G.

Pennsylvania

Power

& Light Co.

SUBJECT:

Forwards

insp repts

50-387/97-01

6 50-388/97-01

on

970114-0224

s notice of violation.Violations either

identified by

NRC or resulted in degradation

of safety-

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(50 Dkt)-Insp Rept/Notice of Violation Response

NOTES:

DOCKET

05000387

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05000387

E

A

P

9'C

RECIPIENT

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PD1-2

PD

INTERNAL: ACRS

AE

LE CE

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B

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OE DIR

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LITCO BRYCE P J

H

NRC

PDR

NOTES:

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POSLUSNY,C

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21

ENCL

21

March 14, 1997

Mr. Robert G. Byram

Senior Vice President

- Nuclear

Pennsylvania

Power 5 Light Company

2 North Ninth Street

Allentown, Pennsylvania

18101

SUBJECT:

NRC INTEGRATED INSPECTION REPORT 50-387/97-01, 50-388/97-01

AND

NOTICE OF VIOLATION.

Dear Mr. Byram:

This refers to the inspections conducted

between January

14, 1997 and February 24,

1997, at the Susquehanna

Steam Electric Station.

The inspections covered routine

activities by the resident inspectors

and announced

inspections

by Region

I specialist

inspectors for radiological effluent control and emergency

preparedness.

The enclosed

report presents

the results of these inspections.

Overall, your conduct of operations

at the Susquehanna

facility during this period was

characterized

by safe operation and conservative

decision making.

The NRC specialist

inspections found that PP5L continues to maintain a very good radioactive liquid and

gaseous

effluent control program, and a good emergency preparedness

program.

However, based on the results of this inspection the NRC has also determined that three

violations of NRC requirements

occurred.

These violations are cited in the enclosed

Notice

of Violation (Notice) and the circumstances

surrounding them are described

in detail in the

subject inspection report.

One violation involves the failure of operators to respond

in

accordance

with procedures

when an accumulation of hydrogen gas occurred in the offgas

recombiner system.

The second violation concerns the design of the bypass indication

system.

The NRC determined that it does not meet a requirement referenced

by 10 CFR 50.55a.

The third violation involves two examples where corrective action in the

maintenance

area was not effective.

These violations are of concern because

they were

~

either identified by the NRC or resulted in the degradation of safety related components.

You are required to respond to this letter and should follow the instructions specified in the

enclosed

Notice when preparing your response.

In your response,

we request that you

discuss the extent to which the bypass indication system installed at Susquehanna

differs

from guidance of Regulatory Guide 1.47 and the system's design specification.

The NRC

will use your response,

in part, to determine whether further enforcement action is

necessary

to ensure compliance with regulatory requirements.

9703200086

970314

PDR

ADQCK 05000387

8

PDR

llllllll9lllltllilllIIIIIII',IIIIIlllllllllll

Mr. Robert G. Byram

2

In accordance

with 10 CFR 2.790 of the NRC's "Rules of Practice,"

a copy of this letter,

its enclosures,

and your response

will be placed in the,NRC Public Document Room (PDR).

Sincerely,

ORIGINAL SIGNED BY:

Walter J. Pasciak, Chief

Reactor Projects Branch No. 4

Division of Reactor Projects

Docket Nos.:

50-387;50-388

License Nos:

NPF-14, NPF-22

Enclosures:

1. " Inspection Report 50-387/97-01, 50-388/97-01

2.

Notice of Violation

cc w/encl:

G. T. Jones,

Vice President

- Nuclear Operations

G. Kuczynski, Plant Manager

J. M. Kenny, Supervisor,

Nuclear Licensing

G. D. Miller, Manager - Nuclear Engineering

R. R. Wehry, Nuclear Licensing

M. M. Urioste, Nuclear Services Manager, General Electric

C. D. Lopes, Manager

- Nuclear Security

W. Burchill, Manager, Nuclear Safety Assessment

H. D. Woodeshick, Special Office of the President

J. C. Tilton, III, Allegheny Electric Cooperative,

Inc.

Commonwealth of Pennsylvania

Mr. Robert G. Byram

Dlstnbutlon w/encl:

Region

I Docket Room (with concurrences)

Nuclear Safety Information Center '(NSIC)

D. Barss, NRR (Emergency Plan IRs)

K. Gallagher,

DRP

D. Screnci, PAO (1) SALP (23)

NRC Resident Inspector

J. Wiggins, DRS

R. Ragland,

DRS

DRS File

PUBLIC

Distribution w/encl: (t/ia E-Mail)

W. Dean, OEDO

C. Poslusny,

Project Manager,

NRR

J. Stolz, PDI-2, NRR

Inspection Program Branch, NRR (IPAS)

R. Correia, NRR

D. Taylor, NRR

DOCUMENT NAME: g:ttbranch4<9701.sus

To receive a copy of this document. In

ate ln the boxr

C

~ Copy without attachment/enclosure

'E i Copy with attachment/enclosure

N

No copy

OFFICE

NAME

DATE

RI:DRP

I'Pasciak;

3/t

97

OFFICIAL RECORD COPY

NOTICE OF VIOLATION

Pennsylvania

Power and Light Company (PPSL)

Susquehanna

Unit 1 and Unit 2

Docket Nos. 50-387, 50-388

License Nos. NPF-14, NPF-22

During an NRC inspection conducted

from January

14, 1997, through February 24, 1997,

three violations of NRC requirements

were identified.

In accordance

with the "General

Statement of Policy and Procedures

for NRC Enforcement Actions," NUREG-1600, the

violations are listed below:

Technical Specification (TS) 6.8.1 requires that written procedures

shall be

established

and implemented for applicable procedures

recommended

in Appendix

'A'f Regulatory Guide 1.33, Revision 2, February 1978.

Regulatory Guide 1.33,

Appendix 'A', item 5, requires procedures

for abnormal, offnormal, and alarm

conditions.

Item 5 further states that procedures

for annunciators

should contain

the immediate action that is to occur automatically and the immediate operator

action.

Alarm response

procedure AR-231-001 for the "Unit 2 Recomb Discharge H2 Conc

Hi - Hi" annunciator lists the automatic action for a 2% hydrogen concentration

as

an Offgas System Isolation.

Further, AR-231-001 Operator action 2.2.1 requires

operators to ensure automatic actions occur.

Contrary to the above, on December

19, 1996, operators failed to ensure the

automatic actions occurred after the "Unit 2 Recomb Discharge H2 Conc Hi - Hi"

annunciator

alarmed and after a grab sample show a hydrogen concentration of 8%.

Specifically, the offgas system did not automatically isolate and operators

did not

take immediate manual action to isolate it.

This is a Severity Level IV violation (Supplement

1).

10 CFR Part 50, Section 50.55a, "Codes and Standards,"

requires that protection

systems meet the requirements

of the Institute of Electrical and Electronic Engineers

(IEEE) "Criteria for Nuclear Power Plant protection systems," Std 279-1971.

IEEE 279, Section 4.13, requires that, if the protective action of some part of the

protection system has been bypassed,

or deliberately rendered inoperative for any

purpose, this fact shall be continuously indicated in the control room.

Regulatory Guide (RG) 1.47, May 1973, describes

an acceptable

method of

complying with the requirements of IEEE Std 279.

RG 1.47 states that an

acceptable

system will automatically indicate at the system level the bypass or

deliberately induced inoperability of the protection system.

Contrary to the above, since initial operation, the bypass indication system

(BIS) at

Susquehanna

has not provided the continuous control room indication required by

IEEE 279, and 10 CFR 50.55a, when a portion of the residual heat removal system

is bypassed.

The BIS does not automatic'ally indicate at the system level when an

RHR pump is rendered

inoperable by a trip circuit that is enabled when the pump's

suction valve is not full open.

As a result, the RHR system is inoperable during

9703200093

9703i4

PDR

ADOCK 05000387

G

PDR

quarterly RHR suction valve testing and no automatic indication of this condition is

provided at the system level.

This is a Severity Level IV violation (Supplement

1).

10 CFR 50, Appendix B, Criterion XVI, requires that licensees establish measures to

assure that conditions adverse to quality such as failures, malfunctions,

deficiencies,.defective

material and equipment and nonconformances

are promptly

identified and corrected.

Contrary to the above, two examples were identified where the licensee failed to

control maintenance

activities such that conditions adverse to quality were created

and not promptly identified and corrected.

In 1991, the licensee failed to implement adequate

corrective actions in

response

to a vendor letter that identified a deficiency on the contact

surfaces of the 'E'mergency diesel generator bridge transfer switch.

As a

result of the licensee's failure to implement corrective actions to preclude

the condition identified by the vendor, the transfer switch failed to perform

its function on December 10, 1997, during an 'E'mergency diesel

surveillance test.

2.

In December 1996, the licensee's corrective actions in response

to the failed

'E'iesel generator transfer switch included the development of a trouble

shooting plan.

As a result of inadequate

control and review of the trouble

shooting plan, a failure was induced in safety related equipment and the

'E'mergency

diesel generator failed a second surveillance test.

This is a Severity Level IV violation (Supplement

1).

Pursuant to the provisions of 10 CFR 2.201, Pennsylvania

Power and Light Company is

hereby required to submit a written statement

or explanation to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington,

D.C. 20555 with a

copy to the Regional Administrator, Region I, and a copy to the NRC Resident Inspector at

the facility that is the subject of this Notice, within 30 days of the date of the letter

transmitting this Notice of Violation (Notice).

This reply should be clearly marked as a

"Reply to a Notice of Violation" and should include for each violation:

(1) the reason for

the violation, or, if contested,

the basis for disputing the violation, (2) the corrective steps

that have been taken and the results achieved,

(3) the corrective steps that will be taken

to avoid further violations, and (4) the date when full compliance will be achieved.

Your

response

may reference or include previous docketed correspondence,

if the

correspondence

adequately addresses

the required response.

If an adequate

reply is not

received within the time specified in this Notice, an "order or a Demand for Information may

be issued as to why the license should not be modified, suspended,

or revoked, or why

such other action as may be proper should not be taken.

Where good cause

is shown,

consideration will be given to extending the response time.

Because

your response

will be placed in the NRC Public Document Room (PDR), to the

extent possible, it should not include any personal privacy, proprietary, or safeguards

information so that it can be placed in the PDR without redaction.

If personal privacy or

proprietary information is necessary

to provide an acceptable

response,

then please provide

a bracketed copy of your response

that identifies the information that should be protected

and a redacted copy of your response that deletes such information.

If you request

withholding of such material, you ~mus

specifically identify the portions of your response

that you seek to have withheld and provide in detail the bases for your claim of withhold-

ing (e.g., explain why the disclosure of information will create an unwarranted

invasion of

personal privacy or provide the information required by 10 CFR 2.790(b) to support a

request for withholding confidential commercial or financial information).

If safeguards

information is necessary

to provide an acceptable

response,

please provide the level of

protection described

in 10 CFR 73.21.

Dated at King of Prussia,

PA

this 14th day of March 1997

f

~pQ RKQy

Wp0

g.

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALEROAD

KING OF PRUSSIA, PENNSYLVANIA19406 1415

Marek 14, 1997

Mr. Robert G. Byram

Senior Vice President

- Nuclear

Pennsylvania

Power

Ei Light Company

2 North Ninth Street

Allentown, Pennsylvania

18101

SUBJECT:

NRC INTEGRATED INSPECTION REPORT 50-387/97-01, 50-388/97-01

AND

NOTICE OF VIOLATION.

Dear Mr. Byram:

This refers to the inspections conducted

between January

14, 1997 and February 24,

1997, at the Susquehanna

Steam Electric Station.

The inspections

covered routine

'activities by the resident inspectors

and announced

inspections

by Region

I specialist

inspectors for radiological effluent control and emergency preparedness.

The enclosed

report presents

the results of these inspections.

Overall, your conduct of operations

at the Susquehanna

facility during this period was

characterized

by safe operation and conservative

decision making.

The NRC specialist

inspections found that PPhL continues to maintain a very good radioactive liquid and

gaseous

effluent control program, and a good emergency

preparedness

program.

However, based

on the results of this inspection the NRC has also determined that three

,violations of NRC requirements

occurred.

These violations are cited in the enclosed

Notice

of Violation (Notice) and the circumstances

surrounding them are described

in detail in the

subject inspection report.

One violation involves the failure of operators to respond

in

accordance

with procedures

when an accumulation of hydrogen gas occurred in the offgas

recombiner system.

The second violation concerns the design of the bypass indication

system.

The NRC determined that it does not meet a requirement referenced

by 10 CFR 50.55a.

The third violation involves two examples

w'here corrective action in the

maintenance

area was not effective.

These violations are of concern because

they were

either identified by the NRC or resulted in the degradation of safety related components.

You are required to respond to this letter and should follow the instructions specified in the

enclosed

Notice when preparing your response.

In your response,

we request that you

discuss the extent to which the bypass indication system installed at Susquehanna

differs

from guidance of Regulatory Guide 1,47 and the system's design specification.

The NRC

will use your response,

in part, to determine whether further enforcement

action is-

necessary

to ensure compliance with regulatory requirements.

Mr. Robert G. Byram

2

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice,"

a copy of this letter,

its enclosures,

and your response

will be placed in the NRC Public Document Room (PDR).

Sincerely,

Walter J.

asciak, Chief

Reactor Projects Branch No. 4

Division of Reactor Projects

Docket Nos.:

50-387;50-388

License Nos:

NPF-14, NPF-22

Enclosures:

1

~ Inspection Report 50-387/97-01, 50-388/97-01

2.

Notice of Violation

cc w/encl:

G. T. Jones,

Vice President

- Nuclear Operations

G. Kuczynski, Plant Manager

J. M. Kenny, Supervisor, Nuclear Licensing

G. D. Miller,'anager - Nuclear Engineering

R. R. Wehry, Nuclear Licensing

M. M. Urioste, Nuclear Services Manager, General Electric

C. D. Lopes, Manager - Nuclear Security

W. Burchill, Manager, Nuclear Safety Assessment

H. D. Woodeshick, Special Office of the President

J. C. Tilton, III, Allegheny Electric Cooperative, Inc.

Commonwealth of Pennsylvania

NOTICE OF VIOLATION

Docket Nos. 50-387, 50-388

License Nos. NPF-14, NPF-22

Pennsylvania

Power and Light Company (PPRL)

Susquehanna,

Unit

1 and Unit

2'uring

an'NRC inspection conducted

from January

14, 1997, through February 24, 1997,

three violations of NRC requirements

were identified.

In accordance

with the "General

Statement of Policy and Procedures

for NRC Enforcement Actions," NUREG-1600, the

violations are listed below:

'echnical

Specification (TS) 6.8

~ 1 requires that written procedures

shall be

established "and implemented for applicable procedures

recommended

in Appendix

'A'f Regulatory Guide 1.33, Revision 2, February 1978.

Regulatory Guide 1.33,

Appendix 'A', item 5, requires procedures

for abnormal, offnormal, and alarm

conditions.

Item 5 further states that procedures

for annunciators

should contain

the immediate action that is to occur automaticatly and the immediate operator

action.

Alarm response

procedure AR-231-001 for the "Unit 2 Recomb Discharge H2 Conc

Hi - Hi" annunciator lists the automatic action for a 2% hydrogen concentration

as

an Offgas System Isolation.

Further, AR-231-001 Operator action 2.2.1 requires

operators to ensure automatic actions occur.

Contrary to the above, on December

19, 1996, operators failed to ensure the

automatic actions occurred after the "Unit 2 Recomb Discharge H2,Conc Hi - Hi"

annunciator

alarmed and after a grab sample show a hydrogen concentration

of 8%.

Specifically, the offgas system did not automatically isolate and operators

did not

take immediate manual action to isolate it.

This is a Severity Level IV violation (Supplement

1).

10 CFR Part 50, Section 50.55a, "Codes and Standards,"

requires that protection

systems meet the'requirements

of the Institute of Electrical and Electronic Engineers

(IEEE) "Criteria for Nuclear Power Plant protection systems," Std 279-1971.

IEEE 279, Section 4.13, requires that, if the protective action of some "part of the

protection system has been bypassed,

or deliberately rendered inoperative for any

purpose, this fact shall be continuously indicated in the'control room.

Regulatory Guide (RG) 1.47, May 1973, describes

an acceptable, method of

complying with the requirements of IEEE Std 279.

RG 1.47 states that an

acceptable

system will automatically indicate at the system level the bypass, or

deliberately induced inoperability of the protection system.

Contrary to the, above, since initial operation, the bypass indication system (BIS) 'at

Susquehanna

has not provided the continuous control room indication required by

IEEE 279, and 10 CFR 50.55a, when a portion of the residual heat removal system

is bypassed.

The BIS does not automatically indicate at the system level when an

RHR pump is rendered

inoperable

by a trip circuit that is enabled when the pump's

suction valve is not full open.

As a result, the RHR system is inoperable during

2

quarterly RHR suction valve testing and no automatic indication of this condition is

provided at the system level.

This is a Severity Level IV violation (Supplement

1).

10 CFR 50, Appendix 8, Criterion XVI, requires that licensees establish measures

to

assure that conditions adverse to quality such as failures, malfunctions,

deficiencies, defective material and equipment and nonconformances

are promptly

identified and corrected.

Contrary to the above, two examples were identified where the licensee failed to"

control maintenance

activities such that conditions adveise

to" quality were created

and not promptly identified and corrected.

1.

In 1991, the licensee failed to implement adequate

corrective actions in

response

to a vendor letter that identified a deficiency on the contact

surfaces of the 'E'mergency diesel generator bridge transfer switch.

As a

result of the licensee's failure to'implement corrective actions to pr'eclude

the condition identified by the vendor, the transfer switch failed to perform

its function on December 10, 1997, during an 'E'mergency diesel

surveillance test.

In December 1996, the licensee's corrective actions in response to the failed

'E'iesel generator transfer switch included the development of a trouble

shooting plan.

As a result of inadequate

control and review of the trouble

shooting plan, a failure was induced in safety related equipment and the

'E'mergency

diesel generator failed a second'surveillance

test.

This is a Severity Level IV violation (Supplement

1).

Pursuant to the provisions of 10 CFR 2.201, Pennsylvania

Power and Light Company is

hereby required to submit a written statement or explanation to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a

copy to the Regional Administrator, Region I, and a copy to the NRC Resident Inspector at

the facility that is the subject of this Notice, within 30 days of the date of the letter

transmitting this Notice of Violation (Notice). This reply should be clearly marked as a

"Reply to a Notice of Violation" and should include for each violation:

(1) the reason for

the violation, or, if contested,

the basis for disputing the violation, (2) the corrective steps

that have been taken and the results achieved,

(3) the corrective steps that will be taken

to avoid further violations, and (4) the date when full compliance will be achieved.

Your

response

may reference or include previous docketed correspondence,

if the

correspondence

adequately addresses

the required response.

If an adequate

reply is not

received within the time specified in this Notice, an order or a Demand for Information may

be issued as to why the license should not be modified, suspended,

or revoked, or why

such other action as may=be proper should not be taken.

Where good cause

is shown,

consideration will be given to extending the response

time.

0

Because your response

will be placed in the NRC Public Document Room (PDR), to the

extent possibl'e, it should not include any personal privacy, proprietary, or safeguards

information so that it can be placed in the PDR without redaction.

If personal privacy or

proprietary information is necessary

to provide an acceptable

response,

then please provide

a bracketed copy of your response that identifies the information that should be protected

and a redacted

copy of your response that deletes such information.

If you request

withholding of such material, you ~mus

specifically identify the, portions of your response

that you seek to have withheld and provide in detail the bases for your claim of withhold-

ing (e.g., explain why the disclosure of information will create an unwarranted

invasion of

personal privacy or provide the information required by 10 CFR 2.790(b) to support

a

request for withholding confidential commercial or financial information).

If safeguards

information is necessary

to provide an acceptable

response,

please provide the level of

protection described

in 10 CFR 73.21.

Dated at King of Prussia,

PA

this 14th day of March 1997

U. S. NUCLEAR REGULATORY COMMISSION

REGION

I

Docket Nos:

License Nos:

50-387, 50-388

NPF-14, NPF-22

Report No.

50-387/97-01, 50-388/97-01

Licensee:

Pennsylvania

Power and Light Company

2 North Ninth Street

Allentown, Pennsylvania

19101

Facility:

Susquehanna

Steam Electric Station

Location:

P.O. Box 35

Berwick, PA 18603-0035

Dates:

January

14, 1997 through February 24, 1997

Inspectors:

K. Jenison,

Senior Resident Inspector

B. McDermott, Resident Inspector

L. Eckert, Radiation Specialist

J. Jang,

Sr. Radiation Specialist

J. Lusher, Emergency Preparedness

Specialist

Approved by:

Walter J. Pasciak, Chief

Projects Branch 4

Division of Reactor Projects

9703200099

9703i4

PDR

ADOCK 05000387

6

PDR

EXECUTIVE SUMMARY

Susquehanna

Steam Electric Station, Units

1 5 2

NRC Inspection Report 50-387/97-0'I, 50-388/97-01

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 announced

inspections by Region

I specialist

inspectors for radiological effluent control and emergency preparedness.

~Oerations

\\

An accumulation of hydrogen gas in excess of the Technical Specification (TS)

concentration limit occurred in the Unit 2 main condenser offgas system.

The

system did not automatically isolate as designed,

prior to reaching this level, due to

the use of jumpers in the high hydrogen isolation circuit. Operators did not

manually initiate a system isolation when a TS required alternate sample showed

the hydrogen concentration to be 400% of the automatic system's setpoint.

The

operators'ailure

to implement the actions of the high hydrogen alarm response

procedure

in response to multiple indications of a high concentration

is cited as a

violation.

A Unit 2 RHR pump failed to start when a limit switch on it's suction valve did not

operate properly.

As a result of the switch failure, the 'D'HR pump was

inoperable with the reactor in Condition

1 for greater than the 7 days and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

allowed by Technical Specifications.

PPSL has implemented appropriate corrective

actions.

NRC review of the event determined the failure was beyond reasonable

licensee control and, as such, the failure to meet TS is being treated as a non-cited

violation, consistent with section VI.A. of the NRC Enforcement Policy.

PPS.L identified that operators made a reactor mode switch change, placing Unit

1

in Condition 2 (Startup), when the limiting conditions for operation of TS 3.5.1

were not met.

PP&L determined that human performance was the root cause of

the event and implemented corrective actions focused on procedural enhancements

and training.

This violation of TS 3.0.4 is being treated

as a licensee identified non-

cited violation.

Maintenance

Problems with the material condition and reliability of the condensate

transfer

system and the Unit 1 reactor core isolation cooling (RCIC) system steam line drain

pot have not been resolved by PPSL, despite their recurrence over the last year.

PPSL's failure to maintain a reliable condensate

transfer system necessitates

entry

into off normal procedures for loss of emergency core cooling system

(ECCS) keep-

fillpressure

and unplanned starts of certain ECCS pumps.

The failure to resolve the

reactor core isolation cooling (RCIC) drain pot problem has the potential to cause

additional steam leaks and RCIC system unavailability.

The failure to properly perform maintenance

activities on the 'B', 'C'nd 'E'.

emergency diesel generators

resulted in degradation of their generators'lip

ring

assemblies.

Although operability of the diesel generators was not challenged, the

potential existed for common cause degradation

due to inadequate

performance of

maintenance.

The failure to properly perform this maintenance,

in accordance with

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.

The Susquehanna

Unit 1 and Unit 2 switchyards are considered to be within the

scope of the maintenance

rule program and are being monitored by PPSL on the

plant level.

The inspector found that PPKL was meeting the maintenance

rule

requirements with regard to monitoring of the switchyards.

~ncnineerinq

Nuclear System Engineering provided a through revision of an operability

determination for a degraded power supply impacting low pressure coolant injection

valves.

Although the initial operability determination made by operators on a

backshift was upheld, the initial justification for the degraded condition did not have

a technical basis and relied entirely on meeting

a Technical Specification

surveillance requirement.

~

On December 10 and on December 21, 1996, the 'E'mergency diesel generator

(DG) failed a functional test.

The cause of'the first failure was a high resistance

contact on the DG bridge transfer switch which was not maintained as

recommended

by the manufacturer.

The second test failure was caused by two

damaged

gate firing circuits.

The gate firing circuits were damaged during

inadequate troubleshooting

and testing activities performed by the licensee.

0

The initial Nuclear System Engineering

(NSE) operability determination following the

first failure was determined to be weak, but the NSE activities following the second

failure were determined to be very strong and aggressive.

Causal factors for the

failures included inadequate

control of vendor recommendation

for preventive

maintenance

and vendor manual documentation,

and inadequate

control of pre-

exercising equipment that may mask weaknesses

that would affect TS surveillance

testing activities.

A violation was issued for inadequate corrective actions in

response to the vendor's notification and previous like conditions, and the

licensee's troubleshooting

and testing activities following the first failure.

Plant Su

ort

~

Oversight of the Radiological Effluent Technical Specifications program was good.

Corrective actions for audit findings were considered to be appropriate; the effluent

radiation monitoring system calibration program was well maintained; and

maintenance

and surveillance of air cleaning and ventilation systems were very

good.

The Offsite Dose Calculation Manual and Annual Radioactive Effluent

Release

Report were well-detailed.

The licensee continues to maintain a good emergency preparedness

program.

The

emergency response

plan and implementing procedures were current and effectively

implemented.

The emergency facilities, equipment, instruments and supplies were

found to be maintained in a state of readiness.

All required inventories were

completed.

A sampling of emergency response

organization personnel training

records and the records pertaining to on-shift dose assessment

indicated that

training and qualifications were current.

A review of quality assurance

reports

found that quality assurance

audits were thorough and that they satisfied NRC

requirements.

TABLE OF CONTENTS

I. Operations

"01

02

Conduct of Operations

01.1

Offgas System Recombiner Hydrogen Accumulation

Operational Status of Facilities and Equipment

. ~.....

~

.

02.1

Unit 2 'D'HR Pump Start Failure

08

Miscellaneous Operations Issues

08.1

Mode Change Requirement Not Met ....

08.2

Review of Licensee Event Reports

04

Operator Knowledge and Performance

04.1

Operator Response

to Operational Occurrences

~

0

~

0

~

0

1

3

5

6

II. Maintenance

M1

M2

III. Engineering

Conduct of Maintenance.........

M1.1

Planned Maintenance Activity Review ~.................

M1.2

Surveillance Test ActivitySample Reviews

Maintenance

and Material Condition of Facilities and Equipment

M2.1

Material Condition of Plant Equipment and Systems

~

. ~....

Maintenance Staff Knowledge and Performance

M4.1

Review of Emergent Maintenance

- 'E'iesel Generator

Preventive Maintenance

Maintenance Organization and Administration

M6.1

Verification of Maintenance

Rule Requirements

- Switchyards

.

8

9

10

11

12

14

E2

E8

Engineering Support of Facilities and Equipment

E2.1

Operability Determination For RHR Swing-bus MG Set

E2.2

Engineering Support of Diesel Generator Maintenance

E2.3

Bypass Indication System (BIS) Design.....

Miscellaneous Engineering Issues.....

E8.1

Review of FSAR Commitments

14

15

18

19

IV. Plant Support .....

R1

R2

R3

R6

R7

R8

Radiation Protection and Chemistry Controls (RP&C)

R1.1

Implementation of Radioactive Liquid and Gaseous

Effluent

Control Programs ...

Status of RP&C Facilities and Equipment

.

R2.1

Calibration of Effluent/Process

Radiation Monitoring Systems

(RMS)

R2.2

Calibration of Area Radiation Monitoring Systems (ARMS)

R2.3

Air Cleaning Systems

RP&C Procedures

and Documentation

RP&C Organization and Administration ...

Quality Assurance

(QA) in RP&C Activities

Miscellaneous

RP&C Issues.....';........................

R8.1

Review of FSAR Commitments

19

.20

20

21

22

23

24

25

v

TABLE OF CONTENTS (Continued)

P1

P2

P3

P5

P6

P7

P8

Conduct of Emergency Preparedness

(EP) Activities

Status of EP Facilities, Equipment, and Resources

EP Procedures

and Documentation .....

Staff Training and Qualification in EP

EP Organization and Administration

Quality Assurance

(QA) in EP Activities

Miscellaneous

EP Issues

P8.1

Review of FSAR Commitments

25

26

~...'. '8

29

30

V. Management

Meetings ............

X1

Exit Meeting Summary

30

Re ort Deta'ils

Summar

of Plant Status

Unit

1 began this inspection period at 100 percent power.

On January 24, a traffic

accident near the plant caused

a loss of the Emergency Notification system, however

commercial phone I:.,es were still available.

Subsequently

PPSL discovered that the call

back portion of the Tele Notification System for emergency responders

was not functional

and made

a

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months NRC notification as required by 10 CFR 50.72.

On February 1, PPRL

made an a telephone notification to the NRC after a Unit

1 reactor recirculation pump

controller failed, causing

a reactor power increase to 103.5% of the rated core thermal

power limit. Operators reduced power to less than 100% within approximately 65

seconds of the failure.

Planned power reductions were made during this inspection period

in support of control rod stroke testing, control rod pattern adjustment,

and routine turbine

valve testing.

Unit 2 began this inspection period at 100 percent power with all control rods fully

withdrawn.

Power reductions were made during this period in support of repairs for a

main condenser tube leak and control rod hydraulic control unit maintenance.

On February

15, Unit 2 was at 95% power when a damper for the 'B" emergency switchgear room

cooling train failed.

On February 16, the 'A'mergency switchgear room cooling fan

failed.

The loss of both trains of emergency switchgear room cooling was reported to the

NRC on February 16, as required by 10 CFR 50.72.

I. 0 erations

01

Conduct of

Operations'1.1

Off as S stem Recombiner

H dro en Accumulation

a.

Ins ection Sco

e 71707

On December 19, 1996, hydrogen gas accumulated

in the off gas recombiner

system after problems occurred during a swap of the recombiner train serving the

Unit 2 main condenser.

The inspector observed the response

of control room

operators to this event and subsequent

meetings held to evaluate the occurrence.

b.

Observations

and Findin s

At 7:45 a.m., operators

began to swap alignment of the Unit 2 main condenser

from the Unit 2 offgas train to the common offgas train in accordance with

procedure OP-222-001.

In accordance with procedures,

the automatic Hi - Hi

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

reactor inspection report outline.

Individual reports are not expected to address

all outline

topics.

hydrogen isolation signals for both the Unit 2 and common offgas trains were

manually bypassed.

'

At 8:15 a.m.,

a chemistry grab sample was taken from the Unit 2 offgas

recombiner train as required by TS Action Statement 3.3.7.11 when the automatic

isolation circuit is inoperable.

The grab sample contained

a hydrogen concentration

of 0.24%.

At 10:00 a.m., two automatic valves for the Unit 2 offgas train failed to close as

expected when operators attempted to isolate the Unit 2 offgas train.

Consequently,

the Unit 2 train was not completely isolated.

Operators placed the

transfer evolution on hold pending an investigation of the valves that failed to close

by maintenance

personnel.

At 12:18 p.m., Chemistry informed the control room that an offgas sample showed

an 8% hydrogen concentration.

Based on this sample, operators began

preparations to manually close valves for the Unit 2 recombiner lines in order to

complete the isolation of the Unit 2 train.

At 12:45 p.m., chemistry personnel informed the control room that a confirmatory

sample indicated

a 9% hydrogen concentration.

Operations management

was

informed and preparations

were made to back out the recombiner transfer

procedure

and place the Unit 2 recombiner train back in service.

The inspector discussed

the offgas system alignment and the results of the

chemistry samples with Operations management.

Specifically, the inspector

questioned

whether the offgas system procedures

required operators to manually

initiate a system isolation since the automatic system isolation setpoint had been

exceeded.

At 1:08 p.m. operators manually initiated an offgas system isolation in accordance

with AR-231-001 based on confirmation of a hydrogen concentration greater than

the hi-hi hydrogen setpoint of 2%.

TS 3.12.2.6 requires the hydrogen concentration

in the main condenser offgas

system to be limited to less than or equal to 4% by volume. With the

concentration of hydrogen greater than 4%, the concentration must be restored to

below the limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

During this event, the hydrogen concentration

in

the offgas system exceeded

the 4% hydrogen limit of .TS 3.11.2.6 for less, than 5

hours.

However, operators failed to recognize entry into this limiting condition for

operation.

Based on review of this event, the inspector determined the following:

~

Operators did not implement the actions of AR-231-001 when the first.grab

sample showed the hydrogen concentration

at 400% of the automatic

isolation setpoint I2% hydrogen).

Operators failed to recognize entry into the TS limiting conditions for

operation (LCO) when the hydrogen concentration

exceeded

4%.

A manual bypass of the offgas system's automatic high hydrogen isolation

signal is routinely made to inhibit spurious isolations from moisture in the

system during transfer activities.

The inspector determined that although

this activity is not precluded by TS, the use of alternate grab samples during

a routine evolution is not a conservative method to compensate

for a design

problem.

The operational practice of bypassing the automatic isolations and history of

hydrogen detection system problems led to a general understanding that the

hydrogen indication in the control room was unreliable during recombiner

transfer evolutions.

NRC Region

I has requested

a review of the SSES TS for the offgas system

automatic high hydrogen isolation by the Office of Nuclear Reactor Regulation.

Specifically, the review was requested to determine the adequacy of:

1) the

current TS requirements for alternate grab samples,

2) the SSES practice of

bypassing automatic system isolations signals during transfer of recombiners,

and

3) the applicability of the standard Improved Technical Specifications to the SSES

design.

c.

Conclusions

Hydrogen gas accumulated

in the Unit 2 offgas recombiner train, reaching

a

concentration greater than Technical Specification limits and the system did not

automatically isolate, as designed,

prior to reaching this concentration

because

operators bypassed

the isolation circuit. Operators did not manually initiate a

system isolation after both an alarm and an alternate grab sample showed

a

hydrogen concentration

in excess of the automatic isolation setpoint.

The operators'ailure

to manually initiate an offgas system isolation as required by

the alarm response

procedure for high hydrogen concentration

is cited as a

violation.

(VIO 388/97-01-01)

02

Operational Status of Facilities and Equipment

02.1

Unit 2 'D'HR Pum

Start Failure

a.

Ins ection Sco

e 92700

The inspector conducted

an on site review of the subject plant condition in order to

verify that PP&L had met the reporting requirements of 10 CFR 50.73, that PP&L

had taken or planned appropriate corrective actions, and that continued operation of

the facility is being conducted

in accordance with Technical Specifications and

other regulatory requirements.

Observations

and Findin s

On November 21, 1996, the 'D'HR pump automatically tripped when operators

attempted to start it for suppression

pool cooling.

A protective circuit for the pump

was found energized

and would have prevented

a start of the pump in either the

shutdown cooling or low pressure coolant injection (LPCI) modes.

PP5L's investigation determined that Rotor ¹3 of the 'D'HR pump's suction valve

motor actuator (F004D) did not operate consistently with the rotors used for valve

control.

Contacts on Rotor ¹3 continued to show the valve was not full open after

its companion rotors had reached their full open alignment, cutting off power to

open the valve.

This sequence

difference caused the 'D'HR pump trip relay

E11A-K22B to remain energized,

enabling the pump's protective trip.

PPSL determined that Rotor ¹3 of the actuator for valve F004D had been in this

condition since November 14, 1996, when the valve was last operated for a routine

surveillance.

Based on the control room log entries, the inspector determined that

the 'D'HR pump was inoperable for greater than 7 days and 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months .

TS 3.5.1,

Action b.1, allows 7 days for restoration of a single inoperable

RHR pump:

If the 7

day period is. exceeded,

Action b.1 further requires that the unit be in hot shutdown

within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ,

Operators were not aware of the. failure and therefore no action

was taken.

PPSL's initial response

to this event was to verify the proper condition of all other

Unit 1 and Unit 2 RHR pump trip relays.

Based on a recommendation

from NSE,

operators cycled valve F004D and the pump's protective relay deenergized.

Additional strokes of F004D in an attempt to repeat the original failure were not

successful.

The root cause was later determined to be a minor variances (0.135

seconds)

in the drop out time of Rotor ¹3 relative to Rotor ¹1.

As an interim

action, temporary procedure changes

were implemented to require verification that

the RHR pump trip relays are deenergized

following routine RHR valve surveillances

and system alignments.

Long term corrective actions consist of enhancements

to

maintenance

procedures for valve actuator limit switches and rework of all the RHR

pump suction valve actuator switches.

The inspector concluded that PPSL's failure to place the unit in hot shutdown after

7 days and approximately 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months was a violation of the TS requirements.

However, the safety significance of this violation was minor due to the fact that all

'ther ECCS sub-systems

were operable during this time and the operability of the

'B'HR pump maintained 100% functional capability in the affected LPCI sub-

system.

Corrective actions for this event were reviewed and found to be good.

'his violation resulted from an equipment failure that was not avoidable by

reasonable

licensee quality assurance

measures

or management

controls, and

therefore is not being cited, consistent with section VI.A. of the NRC Enforcement

Policy,

c.

Conclusions

A Unit 2 'D'HR pump failed to start when a limit switch on it's suction valve did

not operate properly.

As a result, the 'D'HR pump was inoperable with the

reactor in Condition

1 for greater than the 7 days and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed by

Technical Specifications.

The licensee implemented appropriate corrective actions

and NRC review of the event determined the failure was beyond reasonable

licensee

control.

This issue is being treated as a non cited violation, consistent with section

VI.A. of the NRC Enforcement Policy.

04

Operator Knowledge and Performance

04.1

0 erator Res

onse to 0 erational Occurrences

Control room operators were observed during performance of their on-shift

responsibilities throughout the inspection period.

The inspectors verified that

appropriate alarm response

procedures

were implemented and that the required

actions were completed.

The following activities were observed

and the inspector

determined that operators responded

well to these occurrences.

ON-158-001

Loss of Reactor Protection System,

February 19, 1997

OP-257-004

SPDS UPS, February 14, 1997

AR-106

HVAC Reactor Building Fan Damper Trouble, February 24, 1997

0

08

Miscellaneous Operations Issues

08.1

Mode Chan

e Re uirement Not Met

a.

Ins ection Sco

e 92700

As on site follow up of this event, the inspector verified that the reporting

requirements of 10 CFR 50.73 had been met, that appropriate corrective action had

been taken, and that continued operation of the facility was conducted in

accordance with Technical Specifications and other regulatory requirements.

b.

Observations

and Findin

s

During the restart of SSES Unit

1 on October 19, 1996, following it's 8th refueling

outage, operators repositioned the reactor mode switch to "Startup," changing the

reactor's operating mode from "Cold Shutdown" (Condition 4) to "Startup"-

(Condition 2). TS 3.5.1 requires two operable

LPCI subsystems

in Condition 2, and

at the time operators changed the mode switch position, the 'B'oop of LPCI had

not been made operable.

Making a reactor mode change to Condition 2 when an

applicable LCO is not met constitutes

a violation of Technical Specification 3.0.4.

The error was identified by the Unit Supervisor (US), who then directed operators to

align the 'B'PCl.subsystem.

The alignment was completed and the subsystem

was declared operable 44 minutes after the mode switch had been placed in

"Startup."

PPSL attributes the event to human error.

While in Condition 4, the US determined

that an LCO was not required for the RHR-pumps during the process of aligning it

for the standby LPCI mode.

However, the US later failed to recognize that the RHR

realignment was not complete when he authorized the mode change.

In the LER,

PPRL reported that the US lost focus on the requirement of TS 3.0.4.

In response to this event, PPSL counseled the US, reviewed the event with all

operations personnel,

and implemented procedural enhancements

to the operating

procedure which controls the."Startup" mode change.

Actions to prevent

recurrence described

in the LER include a review of this event with operations

personnel during Training Cycle 96-6, and an evaluation to determine if

modifications that would allow faster transition from shutdown cooling to the LPCI

mode would be cost beneficial.

The inspector reviewed changes

PPRL made to procedure GO-100-002 in response

to this event.

The procedure now provides steps to alert the US that LPCI must be

restored and the LCO must be cleared, prior to making the mode change.

The

inspector also reviewed the lesson plan for Manager of Operations Agenda

discussion for training cycle 96-6.

As with the procedures,

this training focused on

a US responsibility to maintain an overall view of plant conditions, evolutions in

progress,

and the goals to be achieved.

As discussed,

making a reactor mode change to Condition 2 when an applicable

LCO is not met constitutes

a violation of TS 3.0.4.

This licensee-identified

and

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

VII.B.1 of the NRC Enforcement policy.

Conclusions

PPS.L identified that operators made

a reactor mode change,

placing Unit

1 in

Condition 2 (Startup), when the limiting conditions for operation of Technical Specification (TS) 3.5.1 were not met.

PP8cL determined that human performance

was the root cause of the event and implemented corrective actions focused on

procedural enhancements

and training.

This violation of TS 3.0.4 is being treated

as a licensee identified non-cited violation.

08.2

Review of Licensee Event Re orts

lns ection Sco

e 90712

The inspector reviewed Licensee Event Reports (LERs) submitted to the NRC to

verify that the details of the event were clearly reported, including the accuracy of

description of the cause

and 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 during this inspection period.

b.

Observations

and Findin s

Closed

LER 50-387 96-008: Alternate Continuous Gaseous

Effluent Sampling

On August 2, 1996, Unit 1 was in Condition 3, when the 'A'ngineered Safeguard

System (ESS) bus was inadvertently deenergized

during maintenance

work

(reference

LER 50-387/96-007).

Loss of the 'A'SS bus caused

a loss of the

normal effluent sample flow from the Unit 1 turbine building and reactor building

vents.

TS 3.3.7.11-1 Action 112, states that effluent releases

via this pathway

may continue for up to 30 days provided samples

are continuously collected with

auxiliary sampling equipment.

PP5L determined that the alternate sampling was

not implemented in a timely manner because

personnel failed to question the

effects of alarms that indicate a loss of vent flow, and placed priority on restoration

of the 'A'SS bus.

The failure to follow procedures

is a violation of NRC requirements.

This licensee

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

with section VII.B.1 of the NRC Enforcement Policy.

H

Closed

LER 50-387 96-014:

Completion of Technical Specification Required

Shutdown

On October 19, 1996, with Unit

1 starting up, the acoustic monitor for the 'L'ain

steam safety/relief valve (SRV) began to indicate the SRV was open when alternate

control room indications showed that it was closed.

The acoustic monitor was

declared inoperable in accordance with TS 3.3.7.5.

Since it was not expected that

the monitor could be repaired without a drywell entry, the unit was shutdown in

accordance

with TS 3.3.7.5, action 80b.

This issue was previously reviewed in NRC Inspection Report 96-11, section 02.2.

Closed

LER 50-388 96-009:

Unit 2 'O'HR Pump Start Failure.

The event is discussed

in section 02.1 of this report and the LER is therefore

closed.

Closed

LER 50-387/96-013:

Mode Change Requirement Not Met

The event is discussed

in section 08.1 of this report and the LER is therefore

closed.

c.

Conclusions

The events reported by PPhL in the Licensee Event Reports

(LER) reviewed during

this period were appropriately reported and provided an accurate description of their

causes

and corrective actions.

The inspector determined that for the LERs

discussed

in brief, the corrective actions were reasonable,

that no generic

implications were involved, and,that these events require no additional onsite

followup. Two of the LERs listed were reviewed in greater detail as discussed

in

sections 02.1 and 08.1 of this report.

II. IVlain enance

IVI1

Conduct of IVlaintenance

M1.1

Planned Main enance

Activi

Review

a.

Ins ection Sco

e 62707

A variety of maintenance

activities were reviewed on'he basis of their complexity,

safety (or risk) significance, or other considerations.

A sample of work permits,

equipment tagouts, procedures,

drawings, and vendor technical manuals associated

with these maintenance

activities were reviewed as part of the inspection.

Through

observation of the maintenance

activities and interviewing maintenance

personnel,

the inspector sought to verify that the activities were performed in accordance

with

procedures

and regulatory requirements,

that personnel

were appropriately trained

and qualified, and that appropriate radiological controls were followed.

b.

Observa ions and Findin s

The following maintenance

activities were reviewed through direct observation

and/or review of the completed work packages:

WA S70402

Unit

1 Battery Charger 1D633 Corrective Maintenance,

February 14, 1997.

WA S72516

'B'iesel Generator Slip Ring Brush Investigation,

February 5, 1997

~

WA S72517

'C'iesel Generator Slip Ring Brush Investigation,

February 6, 1997.

WA V70291

High Pressure

Coolant Injection (this WA is associated

with

CR 96-2240)

WA S70254

WA S79015

High Pressure

Coolant Injection

Destructive Examination of ThermoLag Material

WA V70300

Safety Parameter

Display System-Uninterruptible

Power

Supply

c.

Conclusions

In general, the work activities were adequately controlled and observed portions

were performed in accordance with station procedures.

In some cases, it was not

apparent to the inspector that work groups were using procedures

as discussed

in

NDAP-QA-500, Conduct of Maintenance.

The licensee's followup for problems

identified with the diesel generator slip rings is discussed

in section M2 of this

report.

M1.2, Surveillance Test Activit Sam

le Reviews

'a.

Ins ection Sco

e 61726

The inspectors observed portions of selected surveillance tests involving different

technical disciplines for safety-significant systems.

b.

Observations

and Findin s

Through observation and review of records, the inspectors verified that the test

activities were properly released for performance, that the test instrumentation was

within its current calibration cycle, and that it was being performed by qualified

personnel

in accordance

with approved test procedures.

The inspectors

also

verified that the tests conform to TS requirements

and that applicable LCOs were

taken.

The following activities were reviewed=during this period:

SO-024-001

'A'iesel Generator Monthly Surveillance, February 3, 1997

SO-259-002

Quarterly Suppression

Chamber Vacuum Breaker Test,

February 14, 1997

Sl-280-308

18 Month Calibration of RWCU, MSIV, PCIS, Secondary Containment

Isolation Reactor Vessel Water Levels, February 21, 1997

c.

Conclusions

The routine surveillance activities observed during this inspection period were

adequately performed.

10'aintenance

and Material Condition of Facilities and Equipment

Material Condition of Plant

E ui ment and S stems

Ins ection Sco

e 62707

During routine observations

of plant operations the general condition of

equipment'as

examined to determine the effectiveness of licensee controls for identification

and resolution of maintenance

similar problems, and an assessment

of the

potential for common mode failure.

12

Additional inspection by PP&L under WA S72516 and S72517 found that the

'B'nd

'C'iesels each had one brush retainer clip misaligned to the point where it

impacted the free movement of the brush.

PPS,L determined the restricted

movement of one brush on each of the two generators'would

not impact

operability.

However, the loss of multiple brushes for a single collector ring has the

potential to cause

a loss of generator field, depending

on the number of remaining

brushes

and their condition.

The brush binding was caused

by misalignment of its retaining clip.

Based on the

as-found condition, the retaining clip rotated clockwise with the torquing of its

fastener.

The inspector reviewed SM-024-E01, Revision 6, "Diesel Generator

'E'8

Month Inspection" and MT-GE-002, Revision 12, "Brush, Commutator And Slip

'ing

Inspection And Maintenance."

SM-024-E01, steps 6.18.1 and 6.18.1, require

checks to ensure the brushes

are properly positioned.

MT-GE-002, step 8.4.1 also

contains

a step to ensure freedom of movement of the brush in its holder.

Based

on review of the procedures

and the as-found condition, the inspector determine

that the root cause of the problem was inadequate

work performance

and

oversight.

The inspector determined that the licensee's failure to adequately perform checks of

the generator brushes constitutes

a violation of minor significance and is being

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

Policy.

Conclusions

The failure to properly perform maintenance

activities on.the 'E', 'B'nd

'C'mergency

diesel generators

resulted in degradation of their generators'lip

ring

assemblies.

Although the operability was not challenged prior to identification, the

potential existed for common cause degradation

due to inadequate

performance of

maintenance.

The failure to properly perform safety related maintenance

activity in

accordance with established

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.

IVl6

Maintenance Organization and Administration

M6.1

Verification of Maintenance

Rule Re uirements - Switch ards

a.

Ins ection Sco

e

6270'7

During review of emergent maintenance

on the 500 kV switchyard air system, the

inspector sought to verify that the basic requirements of the maintenance

rule have

been satisfied with regard to the SSES switchyards.

b.

Observations

and Findin s

13

The 500 kV switchyard air system is comprised of a single air manifold which

supplies air pressure to maintain the switchyard breakers

in their closed position.

Check valves for individual breakers

are relied upon to sustain the required air

pressure

at individual breakers short duration air supply problems.

On January 23, a leak developed

on the air manifold, causing an alarm at both

SSES and the Power Dispatcher office. A temporary fix was implemented,

however on January 24 the problem resurfaced.

While permanent repairs were

being effected on January 25, the air supply to 5 of the 6 breakers in the

switchyard had to be isolated from their air supply.

During this time, the

breakers'heck

valves were relied upon to maintain the air pressure

and consequently their

positions.

The inspector reviewed PPRL's actions in response to this incident

because

both the air leak, and actions necessary to repair it, had the potential to

cause

a load reject for SSES Unit 2.

In accordance with the PPSL maintenance

rule implementing procedures,

GDS-18,

"System Scoping for Maintenance

Rule Applicability," and GDC-14, "Determining

'Levels of Monitoring Required foI Structures, Systems,

and Components Within The

Scope of 10 CFR 50.65," the switchyards are classified as non-risk significant

systems

and are monitored using plant level performance criteria.

These criteria

are:

Unplanned Capability Loss Factor - 0%

Unplanned Scrams while Critical over last 12 months - 0

No repetitive Maintenance Preventable

Functional Failures

The inspector found that PPS.L system engineers

are performing quarterly system

reviews for the switchyard system as required by NDAP-QA-0501.

However, the

inspector noted that the problems that occurred on January 23 are not counted for

maintenance

rule purposes

since the switchyards are monitored on the plant level.

PPS,L does address

this type of failure under the corrective action process

due to

the potential for such

a problem to cause

a plant transient.

Conclusions

The Susquehanna

Unit

1 and Unit 2 switchyards are considered to be within the

scope of the licensee's maintenance

rule program and are being monitored on the

plant level.

The inspector found that PPRL was meeting the maintenance

rule

requirements with regard to monitoring of the switchyards.

14

III. En ineerin

E2

Engineering Support of Facilities and Equipment

.E2.1

0 erabilit

Determination For RHR Swin -bus MG Set

a.

Ins ection Sco

e 37551

On February 10, 1997, PPSL initiated CR 97-0225 after discovering that the Unit

2, Division II RHR swing-bus motor generator

(MG) set voltage was reading low.

During routine rounds, an NPO found that the MG set output voltage was reading

460 Vac vice the expected 480 Vac. The inspector reviewed the licensee's actions

in response to this discovery and the support provided by Nuclear Systems

Engineering

(NE).

b.

Observations

and Findin s

The Division II RHR swing-bus MG set provides the normal power supply for valves

that must'ep'osition for proper Division II (the 'B'HR loop) LPCI injection.

Specifically it supplies power to the RHR injection'.valve, the RHR minimum flow

valve, the reactor recirculation pump discharge valve and the recirculation pump

discharge bypass, valve.

The operability determination for CR 97-0225 is based on an assessment

of TS 3.8.3 which requires-the preferred power source,

a preferred power source M/G

set, alternate power source,

and automatic transfer switch.

The licensee

determined that there was no impact on operability since the surveillance

requirements for TS 3.8.3 do not specify a minimum voltage,'he TS only requires

that the load groups be energized.

In review of CR 97-0225, the inspector found that PPRL's initial operability

determination was based on the RHR swing-bus motor generator set having power

available and did not address whether 'the degraded voltage output would affect

operability of downstream components.

This issue was immediately discussed with

the Shift Supervisor and subsequently,

Nuclear System Engineering personnel.

According to the guidance in Generic Letter 91-18, when it is not clear that a

system can perform as described

in its current licensing bases,

performance of the

TS surveillance alone may not verify operability.

The inspectors determined that

the initial operability evaluation did not address whether the system could perform

as required by licensing basis.

0

On February 11, the licensee completed

a supplemental operability determination to

address the minimum voltage necessary for operability of the subject motor

operated valves.

The supplemental'evaluation

gave appropriate consideration to the

capability and design basis requirements of the valves for the'degraded

voltage

condition.

PPSL determined that the connected equipment will meet its design

basis and operate

as expected down to 90% of equipment rated voltage (460 Vac).

15

The inspector determined that although the supplemental operability determination

provided a sound technical position, the initial operability determination by the

operations shift and shift technical advisor did not.

C.

Conclusions

Nuclear System Engineering provided a through revision of an operability

determination for a degraded power supply impacting low pressure

coolant injection

valves.

Although the initial determination made by operators on a backshift was

upheld, the initial determination did not provide any technical justification and relied

on meeting the verbatim requirements of Technical Specifications.

E2.2

En ineerin

Su

ort of Diesel Generator Maintenance

a.

Ins ection Sco

e 62707

On December 10 and 21, 1996, the 'E'G failed surveillance SO-024-014,

Monthly Functional Test.

The inspector reviewed the SSES engineering activities in

response

to the failures, licensee's activities to resolve the. root cause of the DG

failures, evaluated the licensee's,corrective

action, and performed an-independent

limited root cause evaluation of the failures.

b.

Observations

and Findin

s

At 8:30 a.m. on December 10, 1996, approximately 20 seconds after the 'E'G

began surveillance SO-024-014, Monthly Functional Test, a generator loss of field

alarm annunciated.

The alarm was followed by a master trip lock out relay.

The

inspector reviewed the associated

work authorizations,

the SSES trouble shooting

plan dated December 10, CR 96-2198 and the SSES 'E'G operability

determination associated with this failure.

Subsequent

to the December 10.failure

and the initial corrective actions by the licensee, testing activities were performed.

These activities were followed by a second surveillance failure on December 21,

1996.

The inspector further reviewed the licensee's corrective actions through

February 24, 1997 involved with the second diesel failure.

The following WAs were reviewed/evaluated

by the inspector:

WA A63686, Work Activity

WA Z62350, Status Activityfor 'E'G Availability

WA S61863, Investigate and Troubleshoot

WA S61896, Investigate and Troubleshoot

The inspector determined that the 'E'G was not credited as the power source for

any SSES class

1E system during either of the test failures, and the test'failures

had no effect on the TS operability requirements of either unit.

It was further

determined that each of the other four diesels (A through D) was properly aligned in

the control room throughout the tests and'was available to perform its intended TS

function.

16

Even though the failures did not have an immediate impact on the operability of

either unit, several safety significant issues were identified by the inspector during

the 'event reviews.

The licensee was not able to identify a specific cause of the December 10,

failure, immediately following the failure. The failure was similar to one that

occurred on August 8, 1993, and described in Significant Operations

Occurrence

Report (SOOR)93-194 and a third one described

in SOOR 1-92-

293.

The operability determination that was written following the December

10, 1996, failure did not fully explain the cause of the failure, and did not

fully explain why successful completion of a surveillance test following the

December 10 failure supported the position that the equipment was

operable.

The inspector concluded that the operability determination was

not complete.

2

~

SSES Operations management

came to a similar conclusion following their

review of the operability determination and requested

additional testing and

evaluation of the 'E'G.

The inspector determined that the actions taken by

Operations management

were aggressive,

technically based and very

conservative.

The testing that was performed on the 'E'G following the first failure was

not well controlled, was not approved by the manufacturer,

was not

described in the DG vendor manual (IOM-79), and did not rec'eive

a rigorous

formal engineering safety evaluation.

Following the second 'E'G

surveillance test failure, the licensee and a vendor representative

concluded

that the trouble shooting and maintenance

activities conducted following the

first failure caused the failure of two gate firing circuits, which resulted in

the second

DG surveillance test failure.

In addition, it was concluded that

the testing outlined in TP-024-149, Diesel Surveillance did not adequately

test the components affected by the trouble shooting activities.

The inspector determined that the licensee failed to adequately control DG

maintenance

and testing activities during the execution of the trouble

shooting plan following the first failure. Very aggressive

and comprehensive

corrective actions were undertaken

by the licensee following the second

DG

test failure. These actions included a return to service component testing

matrix prepared with the help of vendor representatives.

10 CFR 50 Appendix B states that measures

shall be established to assure that

conditions adverse to quality such as failures, malfunctions, deficiencies, defective

material and equipment and nonconformances

are promptly identified and

corrected.

Contrary to the above,

The licensee failed to implement adequate

corrective actions in response

to a

1991 vendor letter that identified a deficiency on the contact surfaces of the

17

'E'mergency diesel generator bridge transfer switch.

As a result of the

licensee's failure to implement corrective actions to preclude the condition

identified by the vendor, the transfer switch failed to perform its function on

December 10, 1997, during an 'E'mergency diesel surveillance test.

The licensee's corrective actions in response to the failed 'E'iesel generator

transfer switch included the development of a trouble shooting plan dated

December 10, 1996, that was associated

with CR 96-2198.

The trouble

shooting activities conducted under the plan were not adequately

implemented, controlled, nor reviewed in that the activities resulted in the

failure of additional equipment and a second 'E'mergency diesel generator

surveillance test failure.

These two issues are considered examples of inadequate

corrective action and are

being cited as a violation.

(VIO 50-387/97-01-02I

The licensee performed an extensive root cause

and engineering evaluation of the

two failures and identified the following two additional contributing factors in

addition to a number of issues of lessor importance.

Each of the licensee identified

issues is associated with a condition report with.required corrective action and

management

review milestones.

The cause of the first failure was a failure of an DG bridge transfer switch to

make an effective contact upon receiving a start signal.

This susceptibility

was identified by the vendor in 1991 and communicated to the licensee by

letter.

The licensee included the letter in the vendor manual but did not

include the maintenance

recommendations

of the vendor in the 'E'G

preventive maintenance

program nor did it perform an engineering evaluation

determining that the preventive maintenance

recommendations

of the vendor

were not necessary.

Normal surveillance activity of the 'E'G included an allowance for

manipulating the bridge transfer switch prior to the performance of the

surveillance.

This switch manipulation masked the lack of the vendor

recommended

preventive maintenance

by mechanically removing an oxide

coating on the transfer switch contacts.

Conclusions

On December 10 and 21, 1996, the 'E'G failed surveillance SO-024-014,

Monthly Functional Test.

The cause of the first failure was a high resistance

contact on the DG bridge transfer switch which was not maintained as

recommended

by the manufacturer.

The second test failure was caused by two

damaged

gate firing circuits.

The gate firing circuits were damaged

during

inadequate

troubleshooting

and testing ac'tivities performed by the licensee.

The

initial SSES engineering operability determination following the first failure was

determined to be weak, but the SSES engineering activities following the second

failure were determined to be very strong and aggressive.

Additional causal factors

18

include the control of vendor recommendation for preventive maintenance

and

vendor manual documentation,

and the control of pre-exercising equipment that,

may mask weaknesses

that would affect TS surveillance testing activities.

A

violation was issued for inadequate

corrective actions to the vendors notification

and previous like conditions, and the licensee's troubleshooting

and testing

activities following the first failure.

E2.3

B

ass Indication S stem

BIS Desi

n

a.

Ins ection Sco

e 37551

As follow up to the Unit 2 RHR pump start failure discussed

in section 02.1, the

inspector reviewed the alarm circuitry that provides indication of the RHR pump's

proper standby alignment.

b.

Observations

and Findin s

During discussions with NE personnel the inspector learned that the bypass

indication system

(BIS) annunciator for the RHR pump is energized when the

pump's suction valve is fully closed.

In contrast, the RHR pump trip signal occurs

when the valve in not full open.

The Institute of Electrical and Electronic Engineers

(IEEE) "Criteria for Nuclear Power

Plant Protection Systems," Standard 279-1971, requires that when the protective

action of some part of a system has been bypassed,

this fact shall be continuously

indicated in the control room.

Regulatory Guide 1.47 provides additional guidance,

and requires that the indication of a bypass condition should be at the system level,

whether or not it is also at the component or channel level.

The inspector determined that the BIS alarm does not, in all cases,

indicate when

the automatic start of the RHR pump is inhibited by the suction valve interlock.

10 CFR Part 50, Section 50.55a, "Codes and Standards,"

requires the SSES design

to meet IEEE 279 standard

and failure to meet this requirement is a violation.

(VIO 97-01-03)

Based on this finding, the inspector questioned whether the licensee's design basis

review project in response to the October 9, 1996, NRC request for information

under 50.54(f) had previously identified this discrepancy.

Conclusion

The NRC has identified that the bypass indication system

(BIS) does not alarm

when a protective trip is active for individual residual heat removal pumps.

NRC

regulations require that when a system is bypassed,

that it shall be continuously

alarmed at the system level in the control room.

The failure to provide an alarm for

this bypass

is a violation of 10 CFR 50.55a, "Codes and Standards."

19

E8

Miscellaneous Engineering Issues (92902)

E8.1

Review of FSAR Commitments

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 description.

While performing the inspections discussed

in Section 08.2 this report, the inspectors reviewed the applicable portions of the

UFSAR that related to the areas inspected.

The inspector determined that the

Bypass Indication System for the RHR system does not meet the FSAR Section.

3.13 commitment to Regulatory Guide 1.47, May 19, 1973.

Section 08.2 of this

inspection report contains addition information on this issue.

IV. Plant Support

R1

Radiation Protection and Chemistry Controls (RP5C)

R1.1

Im lementation of'Radioactive

Li uid and Gaseous

Effluent Control Pro rams

a.

Ins ection Sco

e 84750-01

The inspection consisted of:

(1) tour radioactive liquid and gaseous

effluent

pathways and its process facilities, (2) review of radioactive, liquid and gaseous

effluent release permits, (3) review of Condition Reports compiled by the

Operations,

and (4) review of unplanned or unmonitored release pathways.

b.'bservations

and Findin s

Radioactive liquid effluents from the site were released into the cooling tower

blowdown line for dilution prior to reaching the Susquehanna

river.

Cooling tower

blowdown line flow rates varied depending on the river flow rate which was a

minimum of about 5,000 gpm during radioactive liquid releases.

Radioactive

gaseous

effluents from the site were released through five rooftop vents on the

reactor building.

Radioactive gaseous

effluents (i.e., noble gases,

particulates,

and

radioiodines) were monitored at each vent.

The inspectors toured'the above release pathways and selected radioactive liquid

and gas process facilities and equipment; including

(1) radioactive liquid and

gaseous

effluent radiation monitoring system (RMS), (2) air cleaning systems,

and

(3) the control room.

The inspectors noted that the effluent control procedures

were detailed, easy to

follow, and Offsite Dose Calculation Manual (ODCM) requirements were

incorporated into the appropriate procedures.

The inspectors also determined that

the liquid and gaseous

discharge permits were complete, and met the Technical

Specification (TS)/ODCM requirements for sampling and analyses

at the frequencies 0

20

and lower limits of detection established

in the TS/ODCM. There were no

unplanned releases

during 1996.

c.

Conclusions

Based on the above observations,

reviews, and discussions,

the inspectors

determined that the licensee established,

implemented,

and maintained effective

radioactive liquid and gaseous

effluent control programs.

R2

Status of RPS.C Facilities and Equipment

R2.1

Calibration of Effluent/Process

Radiation Monitorin

S stems

RMS

a.

Ins ection Sco

e 84750-01

The inspectors reviewed the most recent calibration results for the following

selected effluent/process

RMS and its system flow rates for both units.

The

inspectors also reviewed the licensee's

RMS self-assessment

and RMS work orders.

The inspector also reviewed selected)RC

calibration procedures.

Liquid Radwaste Effluent Monitor (Common to both units)

Liquid Radwaste Effluent Line Flow Rate

Cooling Tower Blowdown Flow Rates

Service Water Effluent Monitors

Residual Heat Removal Service Water Radiation Monitors

Main Steam Line Monitors

Standby Gas Treatment Vent Monitors (Common to both units)

Reactor Building Vent Noble Gas Monitors (low, mid., and high ranges)

Reactor Building Vent Noble Gas Monitoring System Flow Rate

Turbine Building Vent Noble Gas Monitors (low, mid., and high ranges)

Turbine Building Vent Noble Gas Monitoring System Flow Rate

Main Condenser

Offgas Pre-Treatment

Noble Gas Monitors

b.

Observations

and Findin s

The IRC Department and Chemistry Department had the responsibility of performing

electronic and radiological calibrations, respectively, for the above effluent/process

radiation monitors.

The System Engineer had the responsibility to maintain the

operability for the abo've RMS and upgrade the system,

as necessary.

All

calibration results reviewed were within the licensee's acceptance

criteria.

During

the review of the above RMS radiological calibration efforts, the inspectors

independently verified several calibration results, including linearity tests and

conversion factors.

The comparison results were very good.

During the previous inspection conducted

in July 1995, it was noted that the

.

radiological calibration techniques implemented by the licensee were excellent, such

as energy calibration and five solid sources for the conversion factors and the

21

linearity test (See Inspection Report Nos 50-387/388/95-19 for detail).

No changes

in radiological calibration methodology were noted.

c.

Conclusions

Based on the above review, the inspectors determined that the licensee had

maintained an excellent RMS calibration program.

R2.2

Calibration of Area Radiation Monitorin

S stems

ARMS

a.

Ins ection Sco

e 83750

The inspectors reviewed the most recent calibration results for the following

selected ARMS for both units.

Sectio~ 12.3.4 of FSAR describes many aspect of

the ARMS and the inspectors reviewed selected aspects

including: (1) ARMS

locations, (2) selection criteria for energy dependence,

accuracy, and

reproducibility, (3) calibration method and testability, and (4) alarm set points.

Reactor Building Area High Radiation Monitors (Units

1 &2)

Turbine Building Area High Radiation Monitors (Units

1 &2)

Spent Fuel Pool Area High Radiation Monitors (Units 1&2)

Refueling Floor Area High Radiation'Monitors (Units 1&2)

The following 1&C calibration procedures were reviewed to determine their

adequacy.

0

IC-079-010

Channel Calibration of Area Radiation Monitors

SI-179-305

18 Month Calibration of Spent Fuel Storage Pool Area

Radiation RE-23714 Monitor

SI-279-337

18 Month Calibration of Spent Fuel Storage Pool Area

Radiation RE-13714 Monitor

Observations

and Findin s

The l&C Department had the responsibility to perform electronic and radiological

calibrations for the above ARMS. The expected

dose rates of the radiological

calibration equipment were calculated by radiation protection (RP) personnel.

The

inspectors noted that the above calibration procedures were easy to follow. All

reviewed calibration results were within the licensee's acceptance

criteria.

The inspectors discussed

ARMS locations; selection criteria for energy dependence,

accuracy,

and reproducibility; calibration method and testability; and alarm set

points with representatives

from l&C and RP.

The inspectors noted that the

licensee had good knowledge in the abov'e areas.

The inspectors also discussed

free air calibration methodology described

in "ANSI/ANS-HPSSC-6.8.1-1981,

Location and Design Criteria for Area'Radiation Monitoring Systems for Light Water

Nuclear Reactors."

The licensee stated that they would consider this reference for

potential program enhancements.

0

22

c.

Conclusions

Based on the above reviews and discussions,

the inspectors determined that the

licensee established

and implemented

a good ARMS calibration program.

R2.3

Air Cleanin

S stems

a.

Ins ection Sco

e 84750-01

The inspector reviewed the licensee's:

(1) most recent surveillance test results,

(2) work orders, system performance summaries,

and interviewed system

engineers,

as needed, to determine the implementation of TS requirements for the

following systems.

~

Control Room Emergency Outside Air Supply System

~

Standby Gas Treatment System

The inspectors reviewed the following surveillance test results for the above noted

ventilation systems.

~

Visual Inspection,

In-Place HEPA Leak Tests,

In-Place Charcoal Leak Tests,

Air Capacity Tests,

Pressure

Drop Tests, and

Laboratory Tests for the Iodine Collection Efficiencies.

b.

Observations

and Findin

s

The licensee has chosen to assign

a group of individuals within system engineering

to oversee each of the ventilation systems.

As a group of individuals had been

assigned,

the individuals were not solely dedicated to ventilation system oversight.

One of these individuals supervised the other system engineers

assigned to the

station ventilation systems.

Test procedures

provided good guidance.

Surveillance test results of the above

systems were within the licensee's

acceptance

criteria established

by the test

procedures

and TS.

Discussions with the system engineers

and review of

performance summaries indicated that a good level of attention had been placed on

ventilation systems.

Most importantly, the inspectors noted that there had been no

turnover among the ventilation system engineers over the past several years.

Conclusions

Based on the above reviews and discussions,

the inspectors determined that the

above noted ventilation systems were well maintained.

23

R3

RPKC Procedures

and Documentation

a.

Ins ection Sco

e 84570-01

The inspectors reviewed the ODCM implemented at the SSES including:

(1) dose

factors, (2) setpoint calculation methodology,

and (3) bioaccumulation factors for

aquatic sample media.

The inspector reviewed the 1995 Annual Radioactive

Effluent Report to verify the implementation of TS.

b.

Observations

and Findin s

The ODCM provided descriptions of the sampling and analysis programs, which are

established for quantifying radioactive liquid and gaseous

effluent concentrations,

and for calculating projected doses to the public.

All necessary

parameters,

such as

effluent radiation monitor setpoint calculation methodologies,

site-specific dilution

factors, and dose factors, were listed in the ODCM. The licensee adopted other

necessary

parameters

from Regulatory Guide 1.109.

The 1995 Annual Radioactive Effluent Report provided total released radioactivity

for liquid and gaseous

effluents.

The report also contained any changes to the

ODCM as necessary

and meteorological data.

There were no obvious anomalous

measurements,

omissions or trends.

The 1995 projected dose assessment

report

contained maximum individual and population doses resulting from routine

radioactive airborne and liquid effluents.

Doses were well below the regulatory

limits. The inspectors reviewed selected 1996 monthly projected dose assessment

results and noted that there were no trends.

Conclusions

Based on the above review, the inspectors determined that the licensee's

ODCM

contained sufficient specification,.information,

and instruction to acceptably

implement and maintain the radioactive liquid and gaseous

effluent control

programs.

The licensee met all TS/ODCM reporting requirements.

R6

RPEcC Organization and Administration

a.

Ins ection Sco

e 84570-01

H

The inspector reviewed the organization and administration of the radioactive liquid

and gaseous

effluent control programs and discussed with the licensee changes

made since the last inspection, conducted

in July 1995.

b.

Observations

and Findin s

The chemistry staff had primary responsibility for conducting the radioactive liquid

and gaseous'effluent

control programs.

Operations,

Engineering, Radwaste

Operations,

and Instrumentation and Controls organizations supported the

radiological effluent control programs relative to air cleaning systems, radioactive

0

24

liquid discharges,

and radiation monitoring system calibrations.

The Chemistry

Supervisor remained under operations.

Since the last inspection of this program area, the following organizational changes

were made.

The reactor water cleanup and fuel pool system engineers were reassigned

to system engineering from chemistry.

Chemistry was reassigned

to the Operations Manager.

The Chemistry Department lost one technician and one scientist position.

No degradation of the effluents control program was noted as a result of these

changes.

Conclusions

The RPSC organization assigned oversight of the radioactive effluents control

program was well staffed.

R7

Quality Assurance

(QA) in RPSC Activities

a.

Ins ection Sco

e 84750-01

The inspection consisted of a review of Quality Assurance

(QA) Audit Reports

required by the TS and a review of corrective actions implemented to address

audit

findings.

The inspectors reviewed QA Audit Report Nos.95-033 and 95-114 which

were reports regarding the chemistry and effluents programs, respectively.

The

inspectors also reviewed QA Audit Report No.95-159 which pertained to an audit

of a vendor who supplied chemistry analytical services to the licensee.

The inspectors also reviewed (1) QA policy of the measurement

laboratory; (2)

implementation of the measurement

laboratory quality control (QC) program for

radioactive liquid and gaseous

effluent samples;

and (3) internal memorandum,

QA

Requirements

for Radiological Programs.

b.

Observations

and Findin s

The inspectors noted that individuals with appropriate backgrounds were used to

conduct the audit.

No "technical" issues of regulatory significance were identified

by the licensee audit team.

Licensee corrective actions to audit observations

and

recommendations

were considered to be appropriate.

The inspectors noted that the

frequency by which QA audits was changed from yearly to once per every two

years according to the UFSAR.

The inspectors noted that QC for gamma measurements

were maintained.

Comparisons

of QC samples

(blind, spike, and duplicate) were in good agreement.

25

Conclusion

Based on the above reviews, the inspectors determined that the licensee met the

QA audit requirements

and implemented

a very good QC program for chemistry

measurements.

R8

Miscellaneous

RPRC Issues

R8.1

Review of FSAR Commitments

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.

While performing the inspections discussed

in this report, the inspectors reviewed

the applicable portio'ns of the UFSAR that related to the areas inspected.

The

inspectors verified that the UFSAR wording was consistent with the observed plant

practices, procedures

and/or parameters.

P1

Conduct of Emergency Preparedness

(EP) Activities

lns ection Sco

e 82701

The inspector reviewed the licensee's action item tracking system and the

emergency planning self-assessment

program to determine the effectiveness

of licensee controls.

Observations

and Findin

s

An action item is initiated by a CR and tracked in the licensee's action item tracking

system.

The inspector reviewed 14 emergency preparedness

items listed in the

action item tracking system that resulted from condition reports, recommendations

from the 1996 audit, and comments from emergency drills. Those items were

appropriately assessed

and were being tracked.

Corrective action completion dates

were assigned

and being met.

The Supervisor, Nuclear Emergency Preparedness

performed self- assessments

using tracking system items to determine whether corrective actions were adequate

and whether enhancements

could be made to the emergency preparedness

program.

An area that has been under review is the licensee's emergency action

level (EAL) classification scheme,

i.e., whether to continue to seek NRC approval

for the Nuclear Management

and Resources

Council, Inc. (NUMARC) National

Environmental Studies Project (NESP)007 EALs or retain and enhance the Criteria

for Preparation

and Evaluation of Radiological Emergency Response

Plans and

Preparedness

in Support of Nuclear Power Plants, NUREG 0654/FEMA-REP-1,

Revision 1, EALs that comprise the current classification scheme.

(This matter is

discussed

further in section P3.)

The licensee also initiated a self- assessment

into

26

why the maintenance

group had performed work and made changes to EP

equipment and facilities without informing the EP group and why emergency plan

procedure changes were not always complete.

The licensee determined that the

problem appeared to be in the ownership of the EP program.

Conclusions

The inspector determined through interviews with emergency personnel

and

review of CRs that the action item tracking system was appropriately used

to identify and track corrective action items.

Additionally, self-assessments

were being performed to evaluate the appropriateness

of corrective actions

for identified items and to identify areas for improvement in.the EP program.

P2

Status of EP Facilities, Equipment, and Resources

a.

Ins ection Sco

e

82701

The inspector conducted

an audit of the licensee's

emergency facilities and

equipment by touring the Control Room, Operations Support Center (OSC),

Technical Support Center (TSC), the Emergency Operations Facility (EOF).

The

inspector reviewed facility equipment inventories and surveillances conducted

during the last quarter of 1996, for completeness

and accuracy.

b.

Observations

and Findin s

The inspector found the emergency facilities to be operationally ready and

emergency equipment as described in the emergency plan.

The inspector noted

that the inventories and surveillances of the facilities and equipment were properly

completed and that any identified discrepancies

were either immediately corrected

or documented,

with work orders written for repair or replacement.

Conclusions

The inspector found that emergency facilities and equipment were as described

in

the emergency plan, survey instruments were within the calibration requirements,

inventories and surveillances were completed,

and the facilities and equipment were

~ in a state of readiness.

P3

EP Procedures

and Documentation

a.

Ins ection Sco

e 82701

1

The inspector reviewed recent emergency response

plan changes to assess

the

impact on the effectiveness of the EP program.

b.

Observations

and Findin s

27

0

The inspector reviewed Revision 25 to the emergency

plan during the inspection.

The changes

made to the emergency plan were: changes

in alarm panel

designation; changes

in staffing of the new organization due to the relocation of the

EOF to the East Mountain Business Center; changes

in management

and facility

titles; corrections of typographical errors, and other minor corrections.

Additionally, the inspector discussed

an unresolved item with the licensee that had

been opened in'1990, during inspection 50-387,388/90-18,

and subsequently

closed based upon the licensee's submittal of NUMARC EALs. The unresolved item

involved a review of the NUREG 0654 EALs to assure that all EALs in use at that

time were clear and unambiguous

(50-387, 388/90-18-01).

When the licensee

decided to convert to the NUMARC NESP007 EAL guidance, the unresolved item

became moot.

The licensee submitted the NUMARC NESP007 EAL scheme to the NRC for

approval in January 1993.

The NRC responded with a request for additional

information in January 1994.

The licensee met with the NRC in June 1994 to

discuss the EALs and resubmitted them for approval in October 1995.'he

NRC

requested

additional information in July 1996.

In response,

the licensee sent a

letter in October 1996 requesting

an extension of time for the response

and another

meeting with the NRC early 1997.

The unresolved item was closed in inspection report 50-387, 388/95-25, because

the licensee had submitted the NUMARC NESP007 EALs to the NRC and the matter

was being tracked as a licensing issue.

During the inspection, the inspector determined that the licensee continued to make

changes to the current (NUREG 0654) EALs to meet the NUREG 0654 EAL

guidance throughout the period.

Identified ambiguities were also reduced through

the 10 CFR 50.54(q) process for emergency plan changes.

However, the licensee

indicated to the inspector that it is uncertain about whether it will continue to seek

NRC approval for the NUMARC NESP007 EALs or update the current EALs.

Conclusions

The inspector concluded that Revision 25 to the plan met 10 CFR 50.54 (q)

requirements

and did not reduce the effectiveness of the emergency plan.

With regard to the NUMARC versus NUREG EAL matter, this will be tracked as an

inspector followup item.

(IFI 50-387, 388/97-01-04)-

~i

28

P5

Staff Training and Qualification in EP

a.

Ins ection Sco

e 82701

The inspector interviewed the Vice President Nuclear Operations, the Plant

Manager, Health Physics Supervisor, Supervisor Nuclear Emergency Planning,

Recovery Managers,

and training personnel to determine the effectiveness of

training.

Additionally, the inspector reviewed EP training records, training

procedures,

lesson plans, emergency plan, and position specific procedures

associated with on-shift dose assessment

to evaluate the licensee's

EP training

program'.

b.

Observations

and Findin s

The inspector interviewed personnel who were qualified members of the emergency

response

organization.

AII of the personnel interviewed indicated that the licensee

conducted integrated mini drills in the TSC and the EOF and found them to be very

effective for training and keeping personnel current in their EP duties and

responsibilities.

Additionally, the inspector reviewed approximately 30% of the

emergency response

organization

(ERO) training records and verified that

, 'qualification and training were in accordance with the training matrix and were

current.

The inspector determined that all on-shift level II health physics tech'nicians were

trained in dose assessment

and protective action recommendations

for providing

suppolt to the shift supervisor prior to the manning and activation of the TSC.

The

technicians performed on-shift dose assessments

using real time meteorological and

source term conditions.

Training does not include performing "what if" calculations

because

those calculations would be performed at the TSC and/or EOF, once they

are activated.

The inspector also reviewed the dose calculator training and dose assessment

and

protective actions lesson plans.

c.

Conclusion

~

The inspector found, through inter'views and the review of training records, that the

ERO, and radiation protection personnel were being adequately trained as required

by the emergency plan, the training was current and that the training program was

being effectively implemented.

The inspector also found that dose calculator

training and dose assessment

and protective action lesson plans were acceptable.

29

p6

EP Organization and Administration

a e

Ins ection Sco

e 82701

The inspector reviewed the licensee's

EP group staffing and management

to

determine what changes

have occurred since the last program inspection

(September,

1994) and if those changes

had any adverse effect on the program.

Observations

and Findin

s

Since the last program inspection (September

1994), the position of

Supervisor, Emergency Preparedness

was refilled, one of the EP staff retired

and the position was eliminated.

During that period of time, the licensee

moved its EOF to a location that is about 23 miles from the plant.

Additionally, the licensee streamlined its ERO by eliminating some of the

administrative positions.

The move and changes to the ERO were approved

by the NRC. A demonstration

drill was performed in July 1996.

Conclusions

The inspector concluded that management

involvement and control of the EP

program was good.

Changes

made since the last program inspection did not appear

to have any adverse effects on the

program.'7

Quality Assurance

(QA) in EP Activities

Ins ection Sco

e 82701

The inspector reviewed QA audit (10 CFR 50.54(t)) reports of the EP program,

conducted

in 1995 and 1996.

Additionally, the inspector interviewed a director of

an off-site agency to determine the effectiveness of the licensee's off-site interface.

Observations

and Findin s

The inspector reviewed audit reports95-023 and 96-057.

Audit report 95-.

023 contained no items that rose to the level necessitating

a CR, but

included 18 recommendations.

Audit report 96-057 contained three items

requiring a CR and six recommendations.

The three CRs identified the

following deficiencies:

(1) annual preventive maintenance

on the public

notification system was not preformed in 1995 (CR 96-1118); (2) some

emergency procedures

were, not current (CR 96-1132); and (3) three

individuals "on-call" had been removed from the qualification system.

The inspector also compared the reports of the audits and noted negative trends in

the maintenance

of training records (both on and off-site), in maintenance

of

facilities and equipment,

and in emergency plan and position specific procedure

changes.

These negative trends had also been identified by the licensee and

corrective actions were being taken.

30

The inspector interviewed the Director, Luzerne County Emergency Management

Agency, to determine the effectiveness of the licensee's off-site interface.

The

Director indicated that the licensee was very supportive in training county and local

municipality representatives,

and in assisting the county with emergency plan

changes.

The Director also indicated that many of the emergency county personnel

are volunteers and the licensee's extra efforts and time expended for training these

personnel was very much appreciated.

Additionally, the inspector was given a tour

of the Luzerne County Emergency Operations Center and the emergency response

mobil command unit and its associated

emergency equipment.

c.

Conclusion

The inspector concluded that the licensee had conducted audits in accordance with

10 CFR 50.54(t), as required, and that the off-site interface was effective.

PS

Miscellaneous

EP issues

P8.1

Review of FSAR Commitments

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

UFSAR description highlighted the need for a special focused review that compares

plant practices, procedures,

and/or parameters

to the UFSAR description.

Section

13.6 of. the UFSAR refers to the emergency plan.

Since the UFSAR does not

specifically include emergency plan requirements,

the inspector compared

licensee'ctivities

to the emergency

plan.

The inspectors specifically reviewed on shift dose

assessment

capabilities and training.

This is discussed

in Section P5.

No

discrepancies

were noted.

V. Mana ement Meetin

s

X1

Exit Meeting Summary

i

inspectors presented

the Effluent Control Program inspection results to members of the

licensee management

at the conclusion of the inspection on January 17, 1997.

The

licensee acknowledged the findings presented.

The inspectors presented the inspection results to members of licensee management

at the

conclusion of the inspection on February 26, 1997.

The licensee acknowledged the

findings presented.

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary.

No proprietary information was identified.

~Oened

ITEMS OPENED, CLOSED, AND DISCUSSED

50-388/97-01-01

50-387,388/97-01-02

50-387/97-01-03

50-387,388-97-01-04

Closed

VIO

IF I

Operators'ailure to implement actions of high

hydrogen alarm response

procedure

in response to

multiple indications of a high concentration

Adequacy of BIS alarm circuits for the RHR systems

Corrective Action For 'E'G Maintenance

Completion of corrective action for EAL scheme

50-387/96-008

50-387/96-01 3

50-387/96-01 4

50-388/96-009

LER

Alternate Continuous Gaseous

Effluent Sampling

LER

Mode Change Requirement Not Met

LER

Completion of Technical Specification Required

LER

Unit 2 'D'HR Pump Start Failure

f

ARMS

CFR

CR

LCO

LER

NRC

NE

Ol

RPC

Sl

SOOR

TS

LIST OF ACRONYMS USED

Area Radiation Monitoring Systems

. Code of Federal Regulations

/

Condition Report

Condensate

Transfer System

Diesel Generator

Emergency Action Level

Emergency Core Cooling System

Emergency Operations Facility

Emergency Preparedness

Emergency Response

Organization

Heating, Ventilation, and Air Conditioning

Instrumentation and Controls

Limiting Conditions for Operation

Licensee Event Report

Low Pressure

Coolant Injection

Motor Generator

Main Steam Isolation Valve

Non-Cited Violation

'otice

of Violation

Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Nuclear Systems

Engineering

Nuclear Management

and Resources

Council, Inc.

National Environmental Studies Project 007 EALs,

Criteria for Preparation

and Evaluation of Radiological Emergency

Response

Plans and Preparedness

in Support of Nuclear Power Plants,

NUREG 0654 FEMA-REP-1, Revision 1, EALs

Off-site D'ose Calculation Manual

Office of Enforcement

Office of Investigations

Operational Support Center

Quality Assurance

Quality Control

Reactor Core Isolation Cooling

Residual Heat Removal

Radiation Monitoring System

Radiation Protection

Radiological Protection and Chemistry

Systematic Assessment

of Licensee Performance

International System of Units

Significant Operations Occurrence

Report

Safety/Relief Valve

Susquehanna

Steam Electric Station

Technical Specification

Technical Support Center

Updated Final Safety Analysis Report

S'

ML17158B997

Text

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