ML17159A119

Insp Repts 50-387/97-09 & 50-388/97-09 on 971021-1208. Violations Noted.Major Areas Inspected:Operations, Engineering,Maintenance & Plant Support.Also Includes Results of Insp by Regional Physical Security Inspector

ML17159A119
Person / Time
Site:	Susquehanna
Issue date:	12/31/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17159A117	List: IR 07100021/2012008 ML17159A116 ML17159A119
References
50-387-97-09, 50-387-97-9, 50-388-97-09, 50-388-97-9, NUDOCS 9801140387
Download: ML17159A119 (45)

See also: IR 05000387/1997009

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket Nos:

License Nos:

50-387, 50-388

NPF-14, NPF-22

Report No.

50-387/97-09, 50-388/97-09

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:

October 21, 1997 through December 8, 1997

Inspectors:

K. Jenison, Senior Resident Inspector

B. McDermott, Resident Inspector

J. Richmond, Resident Inspector

E. King, Physical Security Inspector

P. Frechette,

Physical Security Inspector

Approved by:

Clifford Anderson, Chief

Projects Branch 4

Division of Reactor Projects

980ii40387 97i2Si

PDR

ADQCK 05000387

8

PDR

EXECUTIVE SUMMARY

Susquehanna

Steam Electric Station (SSES), Units

1 5 2

NRC Inspection Report 50-387/97-09, 50-388/97-09

This integrated inspection included aspects of Pennsylvania Power and Light Company's

(PPS.L's) operations, engineering, maintenance,

and plant support at SSES.

The report

covers an 7-week period of resident inspection; in addition, it includes the results of an

announced

inspection by a regional physical security inspector.

~Oerations

I

Licensed operators responded well to specific annunciated plant conditions.

Licensed operators were able to clearly describe the reasons for their actions,

discuss the impact of their actions upon the safe operation of the units, and fully

implement

established plant procedures.

(section 01.1)

Following a February 13, 1997, local control panel alarm test failure, the licensee

initiated a condition report (CR) and work authorizations to determine why an

associated

control room annunciator did not reflash as expected.

The CR

investigation determined that the annunciator reflash did not occur because

of a

failed reflash unit. The Unit 1 and Unit 2 computer records for point EGZ14 were

affected by the reflash unit failure, however, there was no evidence to indicate that

this condition was other than an isolated instance. Unit 1 records for computer

point EGZ12 were found to provide an accurate record of the February 13, 1997

test. The licensee's corrective actions and root cause determination associated with

CR-97-0289 were determined to be adequate,

as was operator response to the

routine alarm panel test failure.

No violations of NRC requirements were identified.

(section 02.1)

Several weak initial operability determinations were identified by the inspectors.

After discussions with Operations and Nuclear System Engineering personnel,

additional information was provided that justified why the equipment was capable of

performing its intended safety function. The inspectors noted that PPSL has not

provided operability determination training for on shift personnel responsible for

initial operability determinations.

Operations management

is aware of this issue and

is planning to enhance training in this area.

(section 05.1)

Working hours of SSES operations staff who perform safety related functions were

reviewed.

No examples of routine heavy use of overtime, as defined by Technical

Specification (TS), were identified; one plant operator worked 12 days, without a

day off, however, this appeared to be an isolated case and no further examples

were identified which would indicate a repetitive use of heavy overtime. Two

examples were found where, after management

approval for overtime was granted,

the administrative forms were not processed

in a timely manner.

One example

identified an inaccuracy in an administrative report used to monitor overtime use.

Condition

reports have been written by the licensee to evaluate and correct these NRC

identified weaknesses.

The identified deficiencies are administrative in nature and

the use of overtime was controlled by SSES management;

no violations of NRC

requirements were identified. (section 06.1)

~

Operators responded well on September

1, 1997, when a feedwater pump minimum

flow control valve failed open.

The licensee initiated a condition report to review

the root cause and work authorizations to perform corrective actions.

The inspector

reviewed the licensee's corrective actions and found them to be adequate.

(section 08.1)

Maintenance

Seven of the eight planned maintenance activities reviewed during this period were

found to be appropriately conducted and controlled.

In one instance, informal

drawings were used during corrective maintenance

on non-safety related equipment.

This activity had no impact on safety related equipment and no violation of NRC

requirements occurred:

(section M1.1)

The surveillance activities observed were adequately performed and appropriately

controlled.

No violations of NRC requirements were identified. (section M1.2)

The licensee's initial actions in response to an unexpected half scram during

surveillance testing were adequate

and the licensee initiated an event review. This

issue will be tracked for inspector followup. (section M2.1)

In March 1997, maintenance

procedures for the replacement of the bonnet vent line

for reactor recirculation valve HV-2F031B failed to ensure the vent line support

configuration was not altered from its original design.

As a result, excessive

vibration during power operation caused

a weld on the bonnet vent line to crack, --

resulting in a loss of reactor coolant.

The failure to provide adequate

procedures for

control of safety related maintenance

is identified as a violation. (section M3.1)

~En ineerin

~

PPRL identified three conflicts between the feedwater penetration isolation valve

configuration and the licensing basis.

Although these issues were placed in PP5L's

corrective action process, the NRC questioned the need for licensing actions and

more timely corrective action.

The three issues involve 1) the failure to test certain

feedwater containment isolation valves in accordance with 10 CFR 50 Appendix J,

2) the acceptability of the reactor water clean up isolation valve configuration as an

alternative to 10 CFR 50 Appendix A design requirements,

and 3) the consequential

failure of a feedwater isolation valve during a feedwater line break event and

compliance with 10 CFR 50 Appendix A design requirements.

These issues remain

unresolved pending additional information from PPS.L. (section E1.1)

- ~

SSES emergency diesel generator

(EDG) frequency TS surveillance

requirements'ere

compared to emergency core cooling system (ECCS) design basis

assumptions.

EDG frequency is proportional to ECCS pump speed which

determines post accident ECCS injection flow rates.

When the lowest EDG

frequency allowed by TS is overlaid onto SSES design basis ECCS pump

performance assumptions,

the results are non conservative,

because there are

situations in which calculations show ECCS pumps can not provide the required

post accident injection flow.

However, actual EDG frequency variation, as shown

by test data, is significantly better than that allowed by TSs, and when actual

frequency test data is overlaid with design ECCS pump performance assumptions,

the ECCS flow rates are shown to be adequate

and safe.

Resolution of the

nonconservative

TS surveillance criteria will be tracked as an unresolved item.

(section E2.1)

~

PP&L identified a potential non-conservatism

in the vendor supplied methodology

used to establish minimum critical power ratio (MCPR) limits for single loop

operation.

The identification of this issue by PP&L was viewed as a strength, and

as an indication of level of scrutiny being given to fuel related calculations.

The

inspector verified that conservative interim corrective actions have been

implemented for SSES pending the resolution of the potential issue, by the NRC

Office of Nuclear Reactor Regulation.

(section E7.1)

~

The licensee maintained an effective security program.

Management support was

evident.

Quality assurance

audits were thorough and in-depth.

Alarm station

operators were knowledgeable and alert. Security equipment was tested and

maintained in accordance with the security plan and security training was performed

in accordance with the training and qualification plan.

The provisions for land

vehicle control measures satisfy regulatory requirements and licensee commitments.

(section IV)

TABLEOF CONTENTS

I ~ Operations

01

02

05

06

08

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

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01.1

Operator Response to Operational Occurrences

Operational Status of Facilities and Equipment

02.1

"E" Emergency Diesel Generator

(EDG) Alarm Panel

Operation

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Operator Training and Qualification

05.1

Training for Operability Determinations

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Operations Organization and Administration ..... ~....

06.1

Overtime Approval Review

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

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08.1

Followup of Open Items ............ ~......

08.2

Licensee Event Report Review......... ~.....

OC577E

,

1

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1

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. 2.3.3

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~ 5.5.6.6

~ 8

I. Maintenance

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M2

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

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M1,1

Preplanned

Maintenance ActivityReview ... ~..........

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M1.2

Planned Surveillance ActivityReview.....................

10

Maintenance and Material Condition of Facilities and Equipment .......

11

M2.1

Unexpected Half Scram During Reactor Pressure Switch Surveillance

M8

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Maintenance Procedures

and Documentation

M3.1

Replacement of Valve HV-2F031B Bonnet Vent Line

Miscellaneous Maintenance Issues... ~.....

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M8.1

Followup of Open Items

11

12

12

14

14

E1

E2

E7

E8

Conduct of Engineering... ~........ ~.... ~....... ~.......

E1.1

Feedwater Penetration Containment Isolation Deficiencies ...

Engineering Support of Facilities and Equipment

E2.1

Emergency Diesel Generator Frequency and ECCS Performance

Quality Assurance

in Engineering Activities...................

E7.1

Thermal Limits for Single Loop Operation

Miscellaneous Engineering Issues

.

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E8.1

Review of Updated Final Safety Analysis Report ..

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II~ Engineering....... ~...'.....................

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V. Plant Support

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S1

S2

S5

S6

Conduct of Security and Safeguards Activities

S1.1

Security Program Review

Status of Security Facilities and Equipment

.

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S2.1

Alarm Stations and Communications

S2.2

Testing, Maintenance and Compensatory Measures...

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- Security and Safeguards Staff Training and Qualification

S5.1

Training and Qualification (TRQ) Plan Implementation

Security Organization and Administration .......

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S8

S6.1

Management Support........ ~.....

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Quality Assurance

in Security and Safeguards Activities

S7.1

Quality Assurance Audits .................

Miscellaneous Security and Safety Issues

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S8.1

Vehicle Barrier System (VBS) Overview

S8.2

Vehicle Barrier System ..

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S8.3

Bomb Blast Analysis.............. ~.......

S8.4

Procedural Controls

S8.5

Review of Updated Final Safety Analysis Report (U

S8.6

Previously Identified Items

FSAR).....

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V. Management Meetings................,

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

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Re ort Details

Summar

of Plant Status

Unit 1 was at 100% power at the beginning of the inspection period.

During the weekend

of October 25, 1997, planned power reductions were made to support hydraulic control

unit maintenance.

Similar maintenance activities were performed over the weekends of

November 1, 1997, and November 8, 1997. A planned power reduction was made on

November 16, 1997 to support main turbine valve testing.

The unit was returned to 100%

power and remained at 100% power until the end of the inspection period.

, Unit 2 was at 100% power at the beginning of the inspection period.

On the weekend of

November 15, 1997, a power reduction was made to support a control rod pattern

adjustment.

Following the rod pattern adjustment,

a problem occurred with the level

control valve for the "4C" feedwater heater.

A power reduction to 80% was directed by

procedures after preparations for maintenance

on the control valve caused

an automatic

isolation of the steam supply to the feedwater heater.

An air line to the feedwater heater

level control valve was repaired and the unit was returned to full power operation on

November 16, 1997, and remained at 100% power until the end of the inspection period.

I. 0 erations

01

Conduct of Operations

'1.1

0 erator Res

onse to 0 erational Occurrences

a.

Ins ection Sco

e 71707

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

responsibilities throughout the inspection period.

The inspector verified that

appropriate alarm response

procedures were implemented and that the required

actions were completed,

b.

Observations

and Findin s

The following activities were observed/reviewed:

AR-01 5-001

ON-247-001

AR-220-001

AR-1 24-001

AR-206-G1 5

Stack Monitoring System

Loss of Feedwater Extraction Steam System

"B" Feedwater Heater System

Instrument Air System

Main Turbine Sentinel Trip Function

Topical headings such as 01, Ms, etc., are used in accordance with the NRC standardized reactor inspection report outline.

1

Individual reports are not expected to address

all outline topics.

Licensed operators responded well to those observed/reviewed

alarmed conditions

requiring actions.

Licensed operators were able to clearly describe the reasons for

their actions and discuss the impact of their actions upon the safe operation of the

units.

In general Plant Control Operator actions were determined to be

conservative,

in accordance with established plant procedures,

and based on

detailed plant training.

c.

Conclusions

Licensed operators responded well to specific annunciated plant conditions.

Licensed operators were able to clearly describe the reasons for their actions,

discuss the impact of their actions upon the safe operation of the units, and fully

implement established plant procedures.

02

Operational Status of Facilities and Equipment

02.1

"E" Emer enc

Diesel Generator

EDG Alarm Panel OC577E 0 eration

a.

Ins ection Sco

e 71707

On February 13, 1997, the licensee performed routine alarm testing of the OC577E

control panel in the "E" EDG building. During the performance of this routine test a

plant control operator (PCO) noted that an expected control room alarm panel (AR-

016-F02) did not reflash.

The inspector reviewed this panel test failure and the

licensee's corrective actions.

b.

Observations

and Findin s

Control Panel OC577E contains local controls for certain "E" EDG support

equipment and associated

annunciators.

Testing this local alarm panel results in a

common control room panel alarm, two Unit 1 computer data points and two Unit 2

computer data points.

Following the control panel alarm test failure, the licensee initiated a condition

report (CR) 97-0289 and work authorizations (WAs) S70529 and S66261.

The

inspector reviewed the associated

WAs and drawing FF65111.

WA S70529 was

initiated on February 15, 1997 to determine why the control room did not get a

reflash during the February 13, 1997, panel test.

During this initial investigation PPRL determined that the input to the Unit 2

computer for point EGZ12 had been degraded since August 13, 1996. WA S66261

was written to correct this problem.

This review also determined that the Unit 1

computer was capable of recording point EGZ12 and that both computers were

capable of recording point EGZ14.

On February 13, 1997, at the time that the failed alarm test was performed, a

separate

plant testing activity was being performed under test procedure

(TP) TP-

024-149. This TP controlled the positions of breakers OB56502A and OB56503A

causing several alarms to be activated in the control room and locally. Because the

control room annunciator was already alarmed, the February 13, 1997, test at panel

OC577E should have caused the control room annunciator to reflash.

However, it

did not reflash because the reflash unit had failed.

Based on review of the data, the

failure of the reflash unit affected the records for computer point EGZ14 on the Unit

1 and Unit 2 computers.

The record for Unit 1 computer point EGZ12 was

unaffected by the reflash unit failure and provided a valid record of the OC577E

panel alarm test on February 13, 1997.

After completing a review of the above data, the inspector determined that the

alarming/ref lashing of specific control room annunciators related to OC577E panel

tests were affected by activities conducted under TP-024-149 in combination with

the failure of a reflash unit. The Unit 1 and Unit 2 computer points EGZ14 were

affected by the failure of the reflash function. Computer point EGZ12 on Unit 2

was degraded during the February 13, 1997 panel tests and did not always

accurately register the panel test.

Unit 1 computer point EGZ12 was operable

throughout the February 13, 1997 test and was unaffected.

There was no evidence

to indicate that the interaction of TP-024-149, the alarm test at control panel

OC577E and the failure of the reflash unit was other than an isolated instance.

Further, there is no evidence of previous repeated failures of the reflash units.

The

licensee's corrective actions and root cause determination associated with CR-97-

0289 were determined to be adequate;

operator response to the test failure was

determined to be acceptable;

and no violations of NRC requirements were identified.

Conclusions

Following a February 13, 1997, local control panel alarm test failure, the licensee

initiated a condition report (CR) and work authorizations to determine why an

associated

control room annunciator did not reflash as expected.

The CR

investigation determined that the annunciator reflash did not occur because

of a

failed reflash unit. The Unit 1 and Unit 2 computer records for point EGZ14 were

affected by the reflash unit failure, however, there was no evidence to indicate that

this condition was other that an isolated instance. Unit 1 records for computer point

EGZ12 were found to provide an accurate record of the February 13, 1997 test.

The licensee's corrective actions and root cause determination associated with CR-

97-0289 were determined to be adequate,

as was operator response to the routine

alarm panel test failure,

No violations of NRC requirements were identified.

Operator Training and Qualification

Trainin

for 0 erabilit

Determinations

The inspector reviewed a sample of the CRs and initial operability determinations

'ssued

during the inspection report period.

Initial operability determinations are

often made on shift by the Shift Technical Advisor (STA) and approved by the Shift

Supervisor (SS).

Several examples were identified where initial operability

determinations did not address the impact a specific degradation would have on the

safety function of the equipment.

In each case, the shortcomings in documentation

were considered weaknesses

and no impact on equipment operability was

identified.

In one example, CR 97-3271 identified that a normally isolated floor drain valve for

the "A" residual heat removal (RHR) pump room was jammed and could not be

verified to be closed.

The operability determination (OD) stated, "AIIECCS

[emergency core cooling system] pumps, remain operable.

There is no leakage in

any room which may affect operability of RHR or Core Spray."

The inspector observed that this OD did not address why the reactor building room

floor drain system was capable of preventing the loss of redundant safety systems

during a postulated line break in the ECCS rooms.

This capability is described

in

FSAR section 3.4.

Discussions with the SS who approved the CR revealed that

compensatory'measures

were being implemented to ensure that floor drain isolation

valves from other ECCS rooms were closed and would be continuously attended by

an operator, if opened.

The inspector considered this action a reasonable

compensatory measure to ensure the ECCS rooms were not cross connected

in a

way that would allow a flooding event to'disable multiple trains of ECCS equipment.

The floor drain valve OD, and several others, were discussed with Operations

Department supervision.

These examples highlighted the fact that the STAs have

not received specific training on evaluating degraded conditions or making

operability determinations.

The STAs have been through routine engineering

training which provides only limited information on this subject.

In response to this

issue, Operations Department supervision is developing a plan to provide specific

training for the STAs, and on shift supervision, regarding the evaluation of degraded

conditions and ODs.

The inspector considered the planned training effort a positive

response to'this weakness.

The licensee's efforts to improve the quality initial

operability determinations are routinely monitored and willcontinue to be assessed

during resident inspector reviews of the CR system.

Several weak initial operability determinations were identified by the inspectors.

After discussions with Operations and Nuclear System Engineering personnel,

additional information was provided that justified why the equipment was capable of

performing its intended safety function. The inspectors noted that PPSL has not

provided operability determination training for on shift personnel responsible for

initial operability determinations.

Operations management

is aware of this issue and

is planning to enhance training in this area.

06

Operations Organization and Administration

06.1

. Overtime A

royal Review

a.

Ins ection Sco

e 71707

The inspectors reviewed the use of overtime by SSES operations staff who perform

safety related functions against the requirements of TS 6.2.2(f).

b,

Observations

and Findin s

TS 6.2.2(f) provides guidelines on the use of overtime hours and states that an

individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour

period, or more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, or more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any

seven day period, (all excluding shift turnover time). The TS also requires that

deviations from the guidelines shall be authorized by the Superintendent of Pant-

Susquehanna

in accordance with established

procedures.

SSES administrative

procedure NDAP-QA-0650 implements the TS requirements by requiring prior

approval of deviations from the overtime guidelines, and by requiring work group

supervisors to monitor for potential deviations and to detect and document

unapproved deviations.

The inspectors reviewed the hours worked by SSES nuclear plant operators

(NPOs)

and auxiliary system operators (ASOs) for a two week period from October 25,

1997, to November 9, 1997. The inspectors found that the overtime deviation

forms provided an adequate justification, listed precautions,

and had appropriate

signatures

and dates.

However, several minor findings were identified:

The word "Approved"'or "Disapproved" on the overtime request form

adjacent to the signature line for the General Manager-SSES/Duty Manager

was not always circled.

SSES operations personnel believed that the

signature indicated approval, without the need to circle the word. The

inspectors reviewed the selected sample to determine if there were examples

that were at odds with this SSES management

belief.

No counter examples

were identified. NDAP-QA-0650 only requires the overtime approval form to

be completed and does not address the completion of the form in detail.

Therefore, the inspectors considered the approval of the overtime, without

circling the word, as an administrative clarity issue and did not consider this

to be a procedural non-compliance issue.

Two examples were identified where verbal approval for an overtime

deviation had been made, but the overtime deviation forms were not

completed until after the overtime had been performed.

Condition report CR

97-3958 has been written by the licensee to evaluate this NRC identified

weakness.

Because the overtime was approved in advance

and performed

with management's

awareness,

no violations of NRC requirements were

identified.

The inspector reviewed Daily Overtime Deviation Reports (DODRs) for the same two

week period in which overtime request forms were reviewed.

The DODR, which

required by NDAP-QA-0650, is distributed to work group supervisors for the

purpose of monitoring potential overtime limitdeviations.

A weakness was

identified with the DODR in that the report shows total hours worked for SSES

personnel for a rolling 2-day and 7-day period, but does not indicate if an individual

has exceeded

16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> worked in a 24-hour period.

One example was identified by

the inspector where an individual's actual hours worked, as documented on shift

schedules

and approved by overtime deviation forms, exceeded

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7-day

period,

However, the DODR incorrectly showed 59 hours6.828704e-4 days <br />0.0164 hours <br />9.755291e-5 weeks <br />2.24495e-5 months <br /> worked during the same

period, for this individual ~ The inaccuracy in the DODR appeared to be an example

of a weakness

in the administrative oversight of operator overtime and not a failure

to follow or implement the SSES administrative process.

Condition report CR 97-

3957 was written by the licensee to evaluate and resolve the apparent inaccuracy

in the DODR. Because there was a singular administrative example with little safety

significance and the licensee took adequate

corrective actions, no violations of NRC

requirements were identified.

C.

Conclusion

Working hours of SSES operations staff who perform safety related functions were

reviewed.

No examples of routine heavy use of overtime, as defined by Technical

Specification (TS), were identified; one plant operator worked 12 days, without a

day off, however, this appeared to be an isolated case and no further examples

were identified which would indicate a repetitive use of heavy overtime. Two

examples were found where, after management

approval for overtime was granted,

the administrative forms were not processed

in a timely manner.

One example

identified an inaccuracy in an administrative report used to monitor overtime use.

Condition reports have been written by the licensee to evaluate and correct these

NRC identified weaknesses.

The identified deficiencies are administrative in nature

and the use of overtime was controlled by SSES management;

no violations of NRC

requirements were identified.

08

Miscellaneous Operations Issues

08.1

Followu

of 0 en Items

a 0

Ins ection Sco

e 92901

The inspectors reviewed the licensee response

and corrective actions for open

inspection items from prior NRC inspections.

b.

Observations

and Findin s

The following open items were reviewed during this inspection period:

(U date

VIO 50-387 388 97-04-02:Staffing of the Nuclear Safety Assessment

Group (NSAG)

0

NSAG was not staffed in accordance with TS requirements.

The licensee

responded to this violation in PPSL letter PLA-4666, dated September 4, 1997. As

part of its corrective action for this violation, PP&L undertook a review of TS

Section 6. The review was conducted by a contractor and documented

in a draft

report entitled "Assessment of Susquehanna

Steam Electric Station Technical Specifications Section 6.0 by MDM Services Corporation."

This report identified a

number of deficiencies with respect to the TS and proposed

a CR for each

deficiency, which PPSL then initiated.

The inspector reviewed the identified CRs and determined that the licensee's initial

corrective actions were adequate.

Long term corrective actions include future

revisions to the Improved Technical Specification (ITS) submittal and meetings with

the NRC Office of Nuclear Reactor Regulation to ensure that the ITS will resolve the

deficiencies.

Long term corrective actions for these additional TS Section 6.0

deficiencies will be tracked as corrective actions for this violation.

Closed

IFI 50-387 388 97-07-01a:Unit 2 Shutdown Due to Increasing Unidentified

Drywell Leakage

This open item is discussed

in Section M3.1 of this inspection report and is

considered closed based on the issuance of VIO 50-388/97-09-03.

Closed

IFI 50-387 388 97-07-01b:Operator

Response to a Feedwater Level

Transient

On September

1, 1997, Unit 1 plant control operators observed

a flow of greater

than 6000 gpm through the reactor feedwater pump (RFP) minimum flow control

valve (FCV) to the main condenser hotwell.

The inspector reviewed the failure that

contributed to this condition and the licensee's corrective actions.

In response to the diversion of water to the main condenser hotwell, reactor water

level decreased.

The operators reduced reactor power to 80% power.

Reactor

water level was recovered and returned to its normal level (+35 inches).

This

transient was caused by the catastrophic failure of a pressure regulator for the

minimum FCV. The pressure regulator was a Parker model, with a plastic dome; the

plastic dome failed, which removed the air supply to the associated

FCV positioner

and valve operator.

The RFP minimum FCV is designed to fail open on a loss of

instrument air pressure to ensure minimum flow protection to the pump is not

inadvertently lost. Work authorization (WA) S72660 was issued to replace the

failed instrument air pressure regulator.

The Parker model pressure regulator was

replaced by a Norgren model pressure regulator of a different design through the

SSES Replacement Item Equivalency (RIE) process.

The different regulator design is

not expected to be subject to the same type of failure as the Parker model.

Operators responded well on September

1, 1997, when a feedwater pump minimum

flow control valve failed open.

The licensee initiated a condition report to review

the root cause and work authorizations to perform corrective actions.

The inspector

reviewed the licensee's corrective actions and found them to be adequate.

C.

Conclusion

PP&L's corrective actions for several events being tracked by NRC open

items were reviewed.

The licensee's initial responses to the issues were

considered adequate,

and the long term corrective actions being implemented

were viewed as reasonable.

08.2

Licensee Event Re ort Review

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

the event description, cause and 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.

b.

Observations

and Findin s

Closed

LER 50-387 97-019-00:Control Structure Chiller Would Not Auto Start

On August 13, 1997, with Unit 1 and Unit 2 at 100% power, PPS.L determined that

prior to March 1, 1997, the control structure chiller (CS chiller) would not operate

as described

in the design basis.

The operation of both SSES units outside the

design basis, prior to March 1, 1997, was reported per 10 CFR 50.73(a)(2)(ii).

PPSL identified a problem with the "B" CS chiller trip indication logic that would

prevent the "A" CS chiller from automatically starting on February 28, 1997. The

logic problem was corrected on March.1, 1997, however, PPSL failed to identify

that the previous operation was a condition outside the plant's design basis.

In the

LER, PPRL addressed

both the CS chiller problem and the failure to recognize that

the problem was a reportable event.

A non-cited violation was identified relative to

this issue in NRC Inspection Report 50-387/97-07and

concluded the licensee had

taken adequate corrective actions.

This LER is closed.

Closed

LER 50-387 97-020-00:Loss of MSRV Acoustic Monitor

On September 10, 1997, with Unit 1 at 100% power, the acoustic monitor for the

"S" Main Steam Relief Valve (MSRV) was declared inoperable based on erratic

indication.

Operators used independent plant variables to confirm the MSRV had

not opened.

Subsequent

PPSL investigations determined that the repair of the "S"

MSRV acoustic monitor would require a containment entry.

TSs required that the

"S" MSRV acoustic monitor be restored to service within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or the unit be in

Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

PP5L requested

enforcement discretion

for the continued operation of Unit 1 until an outage of sufficient duration, not to-

exceed the Unit 1 10th refueling outage.

A notice of enforcement discretion

(NOED) was issued by the NRC on September

11, 1997, prior to expiration of the

TS allowed outage time. This event was reportable per 10 CFR 50.73(a)(2)(l)(B)

because the NRC's decision to exercise enforcement discretion, by issuing the

NOED, does not change the fact that a violation occurred when Unit 1 remained at

power beyond the time limitspecified in the TS action statement.

This issue is discussed

in detail in NRC Inspection Report 50-387/97-07.

The

inspector found that PPSL appropriately identified the issue and requested

enforcement discretion.

PPRL's response to the problem was considered adequate

corrective action in this case.

The inspector determined that PPSL met the

applicable TS action statement prior to approval of the NOED.

NRC Administrative

Letter 95-05, Section G, states that "in all cases, the NRC willnot normally take

enforcement action for the TS or licensee condition violations during the period the

NOED was in effect, except for the root causes

leading to the noncompliance..."

Based on the information available at this time, the inspector identified no violations

of NRC requirements regarding the root cause of the acoustic monitor failure. This

LER is closed.

Conclusions

The events reported by PPSL in the LERs reviewed during this period were

appropriately reported, and provided an accurate description of the causes

and

corrective actions.

The inspector determined that for the LERs discussed

in brief,

the corrective actions were reasonable,

and that these events require no additional

onsite followup.

II. IV!aintenance

Conduct of Maintenance

Pre lanned Maintenance Activit Review

Ins ection Sco

e 62707

The inspector observed/reviewed

selected preplanned maintenance to determine

whether the activities were conducted in accordance with NRC requirements

and

SSES procedures.

Observations

and Findin s

Maintenance activities authorized by the following WAs were observed/reviewed

during this inspection period:

V70904

Instrument Air Compressor

During observation of maintenance

performed under WA V70904, the inspector

determined that the maintenance technicians were performing work in accordance

with a hand drawn drawing provided by SSES work planning.

The inspector

discussed the use of the uncontrolled drawing with SSES management

because it

was an additional example of a previously identified problem (reference

NRC

10

Inspection Report 50-387/97-03).

It is SSES management's

expectation that only

controlled drawings will be used in the field for maintenance.

In this particular

instance, the use of this uncontrolled drawing did not impact on the operability of

safety related equipment and no violation of NRC requirements was identified.

SSES management's

actions in response to the issue were adequate

and no

additional NRC effort was necessary

in this specific instance.

Portions of the following additional WAs were observed/reviewed:

S74293

S73121

S70169

V72667

V72174

C60644

S70529

250 Vdc Battery

Rod Block Monitor 1b

Rod Block Monitor 1b

SBLC Accumulator Pressure

Investigation

Back Draft Isolation Damper Testing

ESS Bus Repair

Computer Point Investigation

The observed portions of the maintenance

activities listed above were performed

adequately and in accordance with applicable procedures.

The maintenance

activities were described and controlled with adequate,

but in some cases general

procedures.

The maintenance

personnel performing the maintenance were well

trained, experienced

and capable of explaining and discussing the technical aspects

of their assigned functions.

The involvement of Nuclear System Engineering

personnel in the maintenance activities was verified by the inspectors to be

appropriate for the specific instances.

C.

Conclusions

Seven of the eight planned maintenance activities reviewed during this period were

found to be appropriately conducted and controlled.

In one instance, informal

drawings were used during corrective maintenance

on non-safety related equipment.

This activity had no impact on safety related equipment and no violation of NRC

requirements occurred.

M1.2

Planned Surveillance Activit Review

a.

Ins ection Sco

e 61726

The inspector observed/reviewed

selected preplanned surveillance activities.

b.

Observations

and Findin s

Portions of the following preplanned surveillance activities were observed/reviewed:

SO-1 50-002

SO-070-001 B

SI-278-209

Reactor Core Isolation Cooling, October 17, 1997

Monthly Standby Gas Treatment Surveillance,

November 26, 1997

Weekly Functional Test of the Average Power Range

11

SI-255-206

SO-024-001

SO-149-01 5

SO-149-014

Monitors, November 12, 1997

Quarterly Channel Functional Test of Scram Discharge

valve High Water Level Indication, November 11, 1997

Monthly "B" Diesel Generator Operability Test,

November 17, 1997

Residual Heat Removal 2 Year Reactor Protection

Instrumentation Checks, November 11, 1997

Residual Heat Removal Cold Shutdown Valve

Exercising, November 11, 1997

The subject surveillance activities were determined to conform to the requirements

of TS and met PP&L administrative requirements

(approvals, scheduling

and

permits).

Components were properly removed from service and, when appropriate,

the TS limiting condition for operations (LCOs) were documented

and met.

C.

Conclusions

The surveillance activities observed were adequately performed and appropriately

controlled.

No violations of NRC requirements were identified.

M2

Maintenance and Material Condition of Facilities and Equipment

M2.1

Unex ected Half Scram Durin

Reactor Pressure Switch Surveillance

a.

Ins ection sco

e 62707

An unexpected

half scram, during the performance of a TS surveillance, was

inspected/reviewed

during the course of normal surveillance observation.

b.

Observations

and Findin s

During performance of TS surveillance S!-158-303, Quarterly Calibration of Reactor

Vessel Steam Dome Pressure

Channels PS-B21-1N023A,B,C,D,an unexpected

half

scram was received.

Following a satisfactory calibration check of PS-B21-1N023A,

the instrument isolation valve was opened to return the pressure switch to service,

in accordance with SI-158-303.

Control room annunciator

RPS CHANNELA1/A2

AUTO SCRAM was unexpectedly received and no other high pressure annunciators

alarmed (e.g. annunciator RX VESSEL Hl PRESS TRIP was not received).

The

surveillance test was stopped and the half scram was reset.

The inspector discussed this event with the responsible Instrument & Controls (I&C)

foreman and reviewed the event observations of the Operations unit supervisor (US)

and the I&C technicians involved. Immediately following the half scram, I&C

technicians checked associated

relays and the Shift Technical Advisor (STA)

checked the computer alarm history, but found no apparent cause for the Reactor

Protection System (RPS) actuation.

The half scram annunciator alarmed

approximately 5 seconds after the pressure switch isolation valve was opened by

the I&C technicians.

This RPS high pressure trip channel does not, by design, have

12

any intended trip delay.

The I&Ctechnicians had their hands off of the pressure

switch, at the local instrument rack, when the annunciator alarmed.

Immediately

following this event, the pressure switch was re-checked and all trip and

annunciator functions were verified to perform satisfactorily.

The I&C foreman believed this event was caused by a pressure spike induced during

the valve operation.

Based on relay drop-out times, a pressure spike of very short

duration could have resulted in de-energizing the RPS actuation relays without

necessarily de-energizing the associated

high pressure annunciator relay.

PP&L

further determined that the apparent 5 second delay between the valve

manipulation and receipt of the RPS annunciator alarm could be a communications

delay between the control room operator and the I&C technicians at the local panel.

Condition report (CR) 97-3745 was initiated to review this matter.

This event was

similar to an unexpected

half scram during a Unit-2 calibration check of PS-B21-

2N023A, which occurred on July 10, 1997 (reference

CR 97-2224).

The

licensee's initial actions and evaluations appeared to be reasonable.

However, since

this was a second occurrence

and there was an apparent time delay between the

valve operation and the alarm, an IFI will be opened to track this issue for review of

the licensee's root cause investigation and corrective actions.

(IFI 50-387,388/97-09-01)

Conclusion

The licensee's initial actions in response to an unexpected half scram during

surveillance testing were adequate

and the licensee initiated an event review. This

issue will be tracked for inspector followup.

Maintenance Procedures

and Documentation

Re lacement of Valve HV-2F031B Bonnet Vent Line

Ins ection Sco

e 62707

On September 18, 1997, PP&L identified a cracked weld on the 3/4 inch bonnet

vent line for reactor recirculation system valve HV-2F031B. This crack was

determined to be the source of the unidentified leakage that resulted in the

unplanned shutdown of Unit 2 on September 17, 1997. The inspector reviewed

PP&L's root cause evaluation for this event which was documented

as part of the

resolution for CR 97-3099.

Observations

and Findin s

On January 20, 1997, a meeting between Maintenance, Nuclear System

Engineering, Nuclear Technology, and Quality Control personnel was held to discuss

the applicability of PP&L Specification M-1067, Installation and Inspection of Pipe

Supports Associated with Piping System Repairs, Replacements,

and Modifications.

At the conclusion of the meeting, the involved personnel had differing opinions on

13

the outcome and several departments

relaxed their positions regarding use of the

subject design specification before a revision of the specification was formally

issued.

The maintenance work package for replacement of the bonnet vent line

valves (WA V53671) was approved on January 25, 1997.

On March 23, 1997, the bonnet vent line for HV-2F031B was cut and rewelded in

order to replace the two manual isolation valves on the line. The replacement

valves were selected under the replacement item evaluation (RIE) program and

installed as a regular maintenance activity. The bonnet vent line was designed to

be supported by a rigid hangar at the end farthest from the recirculation valve.

As a

result of the discussions during the January 20, 1997, meeting, the new line was

not inspected to Specification M-1067 by Maintenance or Quality Control personnel.

The inspections previously performed under this Specification were to verify proper

support configurations (eg. proper load bearing) following "modifications". The

revised specification, which was proposed/discussed

at the January 20, 1997,

meeting was issued after completion of the maintenance,

on March 27, 1997. The

inspector found that the revised specification called for inspections to be performed

after maintenance

involving cutting, welding, replacement of components,

or any

activity which may alter the piping configuration.

PP&L's event review team (ERT) documented the following root causes

in

CR 97-3099:

~

The weld crack was caused by excessive vibration during operation that

resulted from the piping being in a cantilevered configuration and not

supported by its hanger.

~

The installation methods used during the replacement of the bonnet vent line

could have caused the lack of proper bearing on the existing rigid hanger.

~

A primary cause of the cantilevered condition was lack of requirements in

Specification M-1067 for an inspection following maintenance

(non-

modification) piping rework to ensure that the piping remained properly

seated

in the hangar after welding.

PP&L developed twenty one corrective actions to address the conclusions and

recommendations

of the ERT. The inspector reviewed a sample of the planned

corrective actions in CR 97-3099 and determined that they addressed

both the

specific problem that occurred and the broader generic implications of this event.

The inspector considered the licensee's decision to change the interpretation of

PP&L Specification M-1067, and implement the change in the field without formal

approval, a non-conservative

approach to activities effecting the performance of

safety related components.

Unit 2 Technical Specification (TS) 6.8.1 requires written procedures

be established,

implemented, and maintained covering the procedures recommended

in Appendix A

of Regulatory Guide (RG) 1.33, Revision 2, February 1978.

Item 9.a. of Appendix A

to RG 1.33, requires procedures for maintenance that can affect the performance of

safety related equipment.

The inspector concluded that the maintenance

procedure

used to replace bonnet vent line valves on recirculation system valve HV-2F031B

was not adequate

because it did not ensure the repair work returned the equipment

to its original design configuration.

On January 20, 1997, an informal change was

made in the interpretation of Specification M-1067 that was intended, according to

PP5L personnel, to eliminate hanger inspections and to reduce work load.

Although

there was no verbatim requirement for the inspections following maintenance,

a

conservative practice that had existed since initial construction was changed

without formal approval through revision of the specification.

As a result, the

bonnet vent line was not configured as designed and subsequently failed in service

causing

a loss of reactor coolant.

The failure to provide adequate

procedures for the control of safety related

maintenance

on reactor coolant system piping is considered

a violation of TS 6.8.1.

(VIO 50-388/97-09-02)

Conclusions

In March 1997, maintenance procedures for the replacement of the bonnet vent line

for reactor recirculation valve HV-2F031B failed to ensure the vent line support

configuration was not altered from its original design.

As a result, excessive

vibration during power operation caused

a weld on the bonnet vent line to crack,

resulting in a loss of reactor coolant.

The failure to provide adequate

procedures for

control of safety related maintenance

is a violation.

Miscellaneous Maintenance Issues

Followu

of 0 en Items

Ins ection Sco

e 92902

The inspectors reviewed the licensee's

response

and corrective actions for open

inspection items from prior NRC inspections.

Observations

and Findin s

The following open item was reviewed during this inspection period:

U date

URI 50-387 388 97-03-03:Omission of the Back Draft Isolation Dampers

in the SSES Maintenance

Rule Program

The back draft isolation dampers (BDIDs) are safety related ventilation system

components which automatically isolate various rooms, to protect redundant

equipment from the harsh environment created by high energy line break events.

The function of the BDIDs was not initiallyscoped into the, licensee's maintenance

rule program.

A determination of the operability and maintenance

rule status of the

BDIDs has been tracked as an unresolved item.

15

As of December 19, 1997, PPSL has tested all BDIDs in SSES Unit 1 and Unit 2

ventilation systems.

There were 36 of 70 BDIDs which failed to close when an

initiation signal was simulated.

PP5L initiated CRs to track the failed dampers and

document an operability determination for each failure. Of the 36 BDID failures, 33

have already been re-worked, successfully tested, and returned to service.

The

inspector found that the operability determinations generally fell into two categories.

One subset of the failed dampers were in series with a BDID that passed.

The operability determination for this group credited the operable BDID for

being capable of isolating the ventilation duct.

A second subset of failed BDIDs were in series with BDIDs that also failed.

In these cases,

PPRL performed an initial operability determination based on

existing ventilation calculations for similar conditions (i.e. open doors in

rooms with high energy line break protection) and engineering judgement.

Formal calculations are planned to support this subset of initial

determination.

The licensee's final operability determination and maintenance

rule scoping will be

reviewed in conjunction with the closure of this unresolved item.

C.

Conclusions

The appropriateness

of licensee responses to the above open item was r'eviewed.

The licensee's initial responses

to the reviewed item was adequate,

and the

immediate corrective actions were completed.

This item (URI 97-03-03) willremain

open, pending further NRC review of PPRL's maintenance

rule program and a final

review of the corrective actions for CR 97-1648.

III. En ineerin

E1

Conduct of Engineering

E1.1

Feedwater Penetration Containment Isolation Deficiencies

a.

Ins ection Sco

e 37551

The inspector reviewed the progress of PP&L corrective actions for a deficiency

concerning certain Final Safety Analysis Report (FSAR) assumptions

regarding a

water seal for the feedwater (FW) containment penetration discussed

in URI 96-06-

01. During this review, the inspector identified three deficiencies in PPRL's

Condition Report (CR) system that appeared to require additional NRC review.

b.

Observations

and Findin s

Three deficiencies identified in the CR system concern the capability to isolate the

primary containment FW penetrations.

Although the deficiencies are interrelated

and must be evaluated

as such for safety impact, they are discussed

below as

16

discrete issues.

These issues were initiallyidentified by PP5L as documentation

deficiencies in CR 96-1407, dated September 9, 1996.

PPS.L developed an

operability determination that provides a safety basis for why the containment

penetration is operable and why continued operation with these deficiencies does

not constitute an undue risk to public health and safety.

10 CFR 50 A

endix J Testin

SSES Technical Specification (TS) 6.8.5 requires that a program be established,

implemented, and maintained to comply with the leakage rate testing of the

containment required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option 8, as

modified by exemptions.

Appendix J requires that all licensees for water-cooled

power reactors test the leak tight integrity of the primary reactor containment,

systems and components,

including containment isolation valves.

10 CFR 50 Appendix A, General Design Criteria 55 (GDC 55), requires containment

isolation valves for each line that is part of the reactor coolant pressure boundary

and that penetrates

primary reactor containment.

The containment isolation valves

are required to meet configurations specified in GDC 55, unless it can be

demonstrated that the containment isolation provisions for specific lines are

acceptable

on some other defined basis.

The SSES Unit 1 and Unit 2 isolation valve arrangement for the FW penetration is

discussed

in FSAR Section 6.2.4.3.2,1 and was approved by the NRC in SSES

Safety Evaluation Report (SER) Section 6.2.4.1

~ The design basis credits an

alternate arrangement of isolation valves as equivalent to GDC 55 requirements.

The alternate arrangement consists of three isolation valves for each FW header.

Short term containment isolation is provided by the 10A/8 check valves inside

containment and the 7A/8 check valves outside containment.

Manually operated

stop-check valves (32A/8) are located farther upstream to provide long term

isolation capability.

AII three valves credited in this arrangement exist in the plant,

however, the 7A/8 check valves are not listed in TS Table 3.6.3-1, Primany

Containment Isolation Valves, and have never been tested in accordance with

10 CFR 50, Appendix J (Appendix J) requirements.

RWCU Containment Isolation - General Desi

n Criteria

GDC 55

FSAR Section 6.2.4.3.2 discusses

exceptions to the containment isolation valve

arrangements

required by GDC 55 that have been approved by the NRC as

acceptable

on some other defined basis.

Although the exception to GDC 55 for the

main feedwater containment isolation valve arrangement

is explicitly discussed

in

this FSAR section, the isolation valve arrangement for the RWCU branch lines

connected to this penetration is not discussed.

Since the isolation valve

arrangement for the RWCU branch lines is not described

in the FSAR as an

exception to GDC 55, it is implied that the RWCU isolation arrangement meets the

GDC 55 requirements.

17

The RWCU branch lines connect to each FW header between the 7A/B check valves

and the 32A/B stop-check valves.

Each RWCU branch line has a motor-operated

gate valve (82A/B) which can be remotely operated from the control room. The

RWCU 82A/B valves are listed in the FSAR, and TSs, as manual containment

isolation valves (ie. remote manual valves with no automatic isolation capability),

and are leakage rate tested valves.

The inspector noted that, the RWCU branch lines have a containment isolation

capability similar to the FW lines. The FW and RWCU lines share two containment

isolation check valves in series (FW10A/B and the FW 7A/B) for short term

isolation.

For positive long term containment isolation, both FW and RWCU lines

have manually operated isolation valves further away from containment.

For the

FW lines, the FW 32A/B stop-check valves provide this long term isolation

capability, and for the RWCU lines, this capability is provided by the RWCU 82A/B.

The inspector noted that despite the similarities to the FW isolation valve

arrangement, the RWCU isolation valve arrangement does not meet GDC 55

requirements

and is not described

in the FSAR (or the SER) as a deviation from

GDC 55.

Conse

uential Failure of FW Isolation Check Valves

FSAR Section 3,6.2.1.1 states that pipe breaks are not postulated

in fluid system

piping between containment isolation valves because certain design requirements

are met.

The second design requirement of FSAR Section 3.6.2.1.1 states,

"The

piping is restrained reasonably close to the valve, such that occurrence of a pipe

break inside or outside containment beyond these restraints willimpair neither

operability of the valve nor the integrity of the containment penetration."

No

deviation from this design basis is identified in FSAR Section 3,6.2.1.1 relative to

the FW lines.

PPSL identified that the FW 10A or 10B inboard containment isolation check valve

can be disabled as a consequence

of a postulated line break on its associated

FW

line inside containment.

The inspector determined that this consequential failure is

not explicitly described or evaluated in the FSAR design/licensing basis for FW

penetration isolation design.

For a FW line break with a consequential failure of the 10A or 10B, the 32A/B stop-

check valves would be capable of providing both immediate and long term positive

containment isolation for the main FW line. Although the RWCU branch lines can

be isolated using remote manual containment isolation valves (82A/B), no short

term containment isolation would exist.

Upstream of the RWCU 82A/B valves are

the RWCU 39A/B check valves.

Although these check valves are within the original

"break, exclusion zone" of the piping, they are not listed as containment isolation

valves in the TSs and are not in the Appendix J leakage rate test program.

0

18

An NRC review of FW isolation valve configurations and licensing bases at other

boiling water reactors (BWRs) of similar design found that there are approved

containment isolation designs which acknowledge

a consequential failure of the

inboard FW isolation check valve.

However, for these plants the FSARs and SERs

reflect the consequential failure, indicating that the scenario was reviewed and

approved as part of their licensing basis.

The design bases for these plants credit

two containment isolation check valves outside containment for both the FW line

and the RWCU line. These check valves are expected to remain operable with a

postulated line break inside containment.

In addition, these plants have long term

positive containment isolation capability using either a motor operated gate valve or

stop-check valve.

For these facilities, the containment isolation valves credited in

the "other acceptable

means" of meeting GDC 55 are listed in TS as containment

isolation valves and are tested under the requirements of 10 CFR 50, Appendix J.

In contrast, for SSES the consequential failure of the FW 10A/B check valves was

not identified in the FSAR and was not approved in the SSES SER (NUREG-0776).

Also, the RWCU branch lines at SSES do not have tested containment isolation

'check valves similar to the other BWRs.

0 erabilit

Determinations and Assurance of Public Safet

PP&L evaluated the operability of the FW containment penetrations using the

guidance provided in NRC Generic Letter 91-18, Information to Licensees

Regarding

Two NRC Inspection Manual Sections on Resolution of Degraded and

Nonconforming Conditions and on Operability, in an evaluation dated May 7, 1997.

This evaluation was the thirteenth revision of an operability determination that

integrated

a number of deficiencies identified after the FW loop issues reported in

LER 50-387/96-02.

The operability determination documented

in CR 96-0046

provides an integrated assessment

of design basis issues identified in seven

separate

CRs (including CR 96-1407).

The licensee's operability determination addresses

the inability of the FW 7A/B to

provide containment isolation and the consequential failure of the FW 10A/B for

following three scenarios:

~

For a design basis loss of coolant accident (LOCA), PP&L's evaluation credits

the FW 10A/B containment isolation check valves for short term isolation

and the remote manually operated valves outside containment (FW 32A/B

and RWCU 82A/B) for long term positive containment isolation.

The FW

10A/B, FW 32A/B, and RWCU 82A/B containment isolation valves are all

tested under PP&L's Appendix J program.

Following a LOCA, operators will

close the remote manual valves when directed by procedure and, at that

point, all lines will be protected by two leakage rate tested containment

isolation valves.

~

For a feedwater line break inside containment (bounded by the design basis

LOCA), PP&L's evaluation assumes the inboard check valve associated with

the broken line is disabled (10A or 10B). The evaluation credits the

19

immediate closure of the FW 32A/B stop-check valves and, the untested

RWCU 39A/B check valves, in conjunction with the closed RWCU system,

for short term isolation of the RWCU branch lines.

Positive long term

isolation of both the FW and RWCU lines can be accomplished with the

remote manually operated FW 32A/B and RWCU 82A/B valves.

PP&L's

evaluation determined that there would be no consequences

to the offsite

dose for this scenario because

calculations and simulator scenarios show the

core would not become uncovered during this postulated event.

With no

core damage, therefore there would be no source term for dose projections.

PP&L continued to evaluate this issue throughout the remainder of the

inspection period.

As of December 19, 1997, PP&L reached

a preliminary

conclusion that although the stresses

on the FW 10A/B (and associated

piping) were in excess of design limits, the stresses

would be within the

yield strength of the components.

Based on this, it is expected that the

10A/B would remain capable of meeting their intended safety function. After

formal approval of the preliminary calculations, PP&L planned to revise this

portion of the operability determination to add this information.

~

For a small break LOCA, PP&L's evaluation is essentially the same as

described for the design basis LOCA. This part of the evaluation justifies

that HPCI will be capable of injecting and that when HPCI is no longer

needed, the feedwater line can be isolated as previously discussed.

The inspectors noted that PP&L's operability determination does not assume

a

single failure or licensing basis accident source terms.

Although these assumptions

represent

a degradation

in the design basis defense

in depth, they appear to be

consistent with the guidance in GL 91-18. The GL states that a loss of single

failure capability, or the loss of conservatism committed to by licensees to satisfy

licensing requirements,

are losses of quality or margin that are subject to an

operability determination and corrective action.

Re ulator

Concerns

On November 18, 1997, the inspector questioned the timeliness of PP&L's planned

corrective actions associated with CR 96-0046 and whether continued operation on

the basis of an operability determination was appropriate given the deficiencies

related to 10 CFR 50 Appendix A design requirements for containment isolation and

10 CFR 50 Appendix J containment isolation valve testing requirements.

On November 25, 1997, representatives

from NRC Region

I and the Office of

Nuclear Reactor Regulation (NRR) met with licensee representatives

in Allentown,

Pennsylvania.

A subsequent

meeting was held in Rockville, Maryland, on December

3,.1997.

During these meetings, PP&L described the physical configuration of FW

penetration and their basis for concluding the containment penetration is operable.

20

The inspectors determined that although PPRL is planning what appears to be

appropriate corrective action, several questions remain regarding regulatory

compliance and the timeliness of planned modifications.

These issues are currently

under review by NRC Region

I and NRR, however, additional information from PPRL

is necessary

in order for the NRC to reach a conclusion.

The issues are as follows:

The FW 7A/B containment isolation valves are credited in the SSES licensing

and design basis as part of the alternate containment isolation valve

configuration approved as an exception to 10 CFR 50 Appendix A GDC 55

requirements.

Containment Isolation valves are required to be leakage rate

tested by TS 6.8.5, 10 CFR 50.54(o), and 10 CFR 50, Appendix J, Option B.

The FW 7A and 7B containment isolation valves have not been leakage rate

tested

in accordance with PPRL's Appendix J test program.

(URI 50-387,388/97-09-03)

The isolation valves for RWCU branch lines are part of the FW penetration

isolation arrangement but, do not meet the containment isolation

requirements of GDC 55.

FSAR Section 6.2 lists the lines penetrating the

containment that do not meet either the explicit requirements of GDC 55, or

the alternative Standard Review Plan acceptance

bases,

but were accepted

on some other defined bases.

The RWCU branch line isolation arrangement

is not discussed

in the FSAR and was not reviewed in the SSES SER.

Although the RWCU isolation valves 82A/B can provide long term positive

closure of the line, similar to the FW 32A/B, this deviation from GDC 55

does not appear to have been previously reviewed.

(URI 50-387,388/97-09-04)

The consequential failure of the FW 10A or 10B check valve during a FW line

break event was not discussed

in FSAR Section 3.6.2.1

~ 1, which describes

the FW system's response to a line break inside containment.

In addition,

this consequential failure was not acknowledged

in the SSES SER. The

inspector considered this a previously unanalyzed condition which is part of

the design basis.

This issue is of concern since its resolution may require

physical modifications in the plant or licensing actions to review a new

configuration as an alternative to GDC 55 requirements.

(URI 50-387,388/97-09-05)

In addition to the technical aspects of each issue, the unresolved items above will

also address whether the issues were reportable to the NRC under 10 CFR 50.72

requirements and whether the licensee's schedule for corrective action, as required

by 10 CFR 50 Appendix B, is commensurate with the safety significance of the

deficiencies.

Licensee Corrective Action

Condition Report 96-1407, dated September 9, 1996, identified documentation

discrepancies

regarding the feedwater penetration within the FSAR, between the

FSAR and the SER, and between the FSAR and the SSES design.

.~

21

PP&L incorporated corrective actions for these issues into an integrated action plan

for correcting a number of containment related deficiencies.

The most recent

version of the action plan, dated January 23, 1997, includes modifications to the

FW 7A/8 check valves, and the RWCU 39A/B check valves, to make them capable

of meeting PP&L's Appendix J test program acceptance

criteria,

In conjunction

with the modifications, PP&L planned changes to the TS table of containment

isolation valves, the FSAR table of containment isolation valves, and the FSAR

sections on compliance with GDC 55 and feedwater line breaks.

Implementation of

the modification is scheduled for Unit 1 during the spring 1998 refueling outage and

for Unit 2 during the spring 1999 refueling outage.

On December 19, 1997, a conference call was held between NRC and PP&L

management.

During this discussion,

PP&L management stated that a letter will be

sent to the NRC regarding both the technical and regulatory aspects of these issues.

NRC management

requested that the letter address

PP&L's perspectives

on the

following issues:

1)

the design basis of the FW and RWCU containment penetration, including

compliance with 10 CFR 50 Appendix J and A'ppendix A design

requirements,

2)

the consequential failure of the FW 10A/8 isolation valves during line break

scenarios,

3)

the deficiencies affecting the capability of the existing FW 7A/8 and RWCU

39A/B valves to perform as containment isolation valves,

4)

the basis for operability of the containment penetration,

5)

the use of compensatory measures,

including the ability of personnel to

perform these actions and the time frame required,

6)

the planned corrective actions for the physical components and the licensing

basis, and

7)

the planned schedule for these corrective actions.

Based on the December 19, 1997, conference call, the PP&L letter is expected by

the first week of January 1998.

Conclusions

PP&L identified three conflicts between the feedwater penetration isolation valve

configuration and the licensing basis.

Although these issues were placed in PP&L's

corrective action process, the NRC questioned the need for licensing actions and

more timely corrective action.

The three issues involve 1) the failure to test certain

feedwater containment isolation valves in accordance with 10 CFR 50 Appendix J,

2) the acceptability of the reactor water clean up isolation valve configuration as an

22

alternative to 10 CFR 50 Appendix A design requirements,

and 3) the'consequential

failure of a feedwater isolation valve during a feedwater line break event and

compliance with 10 CFR 50 Appendix A design requirements.

These issues remain

unresolved pending additional information from PP&L.

E2

Engineering Support of Facilities and Equipment

E2.1

Emer enc

Diesel Generator Fre uenc

and ECCS Performance

a.

Ins ection Sco

e 73753

In response to NRC resident inspector questions concerning the operability of the

EDGs in August 1996, the licensee commenced

a vendor supported review of the

EDG vendor manual

~ The vendor conducted

a number of support visits and system

walk downs, and identified several testing and design related deficiencies.

In

August 1.997, the EDG vendor (Cooper-Bessemer)

notified the licensee that the EDG

frequency response,

as stated in the SSES TS, was not a reasonable

expectation for

the performance of its machine.

The licensee initiated a CR to resolve this issue.

The resident inspectors reviewed the licensee's corrective actions associated with

the CR to determine if any design basis or generic issues existed.

b.

Observations and Findin s

A review of the following references was conducted:

(1)

SSES TS 4.8.1

~ 1.2, Electrical Power Systems - A.C. Sources - Operating

(2)

SSES FSAR Sections:

(a)

3.13.1, Compliance with NRC Regulatory Guides

(b)

8.1.6.1.b, Electric Power, Compliance with regulatory

Guides

(c)

8.1.6.2.c, Electric Power, Compliance with IEEE 338, 344, and

387

(d)

8.3.1, AC Power Systems

(3)

SSES Condition Report 97-2874

(4)

SSES Improved Technical Specification (ITS) 3.8.1.12.b, currently submitted

to the NRC for review and approval

(5)

Regulatory Guide (RG) 1.9-1971,Selection,

Design, Qualification, and

Testing of Emergency Diesel Generator Units Used as Class 1E Onsite

Electric Power Systems at Nuclear Power Plants

(6)

IEEE 387-1972, Standard Criteria for Diesel Generator Units Applied as

Standby Power Supplies for Nuclear Power Generating Stations

23

SSES TS 4.8.1.1.2 (reference

1) states that the licensee shall:

Verifythat the diesel starts from ambient conditions and

accelerates

to at least 600 rpm in less than or equal to 10

seconds.

The generator voltage and frequency shall be 4160

+/- 400 volts and 60 +/- 3 Hz within 10 seconds after the

start signal.

The parameters

stated in the TS are supported by and consistent with the SSES

FSAR (reference 2).

The licensee's

CR (reference 3) addresses

the fact that the ECCS equipment is not

analyzed or tested at 57 Hz, and also addressed

the difference in the required

frequency response

between the current TS (reference

1) and the ITS submittal

(reference 4). The inspectors reviewed preliminary licensee data and met with PP&L

engineering and licensing representatives

on November 20, 1997, and on

December 8, 1997, to discuss these issues.

The following determinations were made by the inspectors:

The licensee's initial FSAR and TS submittal differed from the frequency

'esponse

endorsed

by the NRC in RG 1.9 (reference 5). The FSAR (reference

2a & 2b) committed to IEEE 387 (reference

6) for EDG frequency response,

in leu of RG 1.9, and states "At no time during the [EDG) loading sequence

willthe frequency or voltage drop to a level which will degrade the

performance of any of the loads".

No specific value is listed in the FSAR for

EDG frequency response.

The TS (reference

1) uses 60 +/- 3 Hz, vice 60

+/- 1.2 Hz, for the acceptance

criteria of EDG frequency response.

When

the inspectors requested to see the basis for this deviation, PP&L stated that

there was apparently no design analysis or data to support the use of a

frequency response different than the one endorsed by RG 1.9.

PP&L

stated that the NRC had approved the original TS submittal without any

comment on the frequency response deviation.

The SSES ITS submittal (reference 4) is currently being reviewed by the

NRC. The ITS submittal uses the frequency response

endorsed

by RG 1.9 of

60 +/- 1.2 Hz. PP&L has not completed any formal analysis, in support of

ITS, to determine if this frequency response

is appropriate for the SSES

EDGs and ECCS equipment.

PP&L stated that during the operability

determination performed for CR 97-2874, a frequency drop of 1.2 Hz (i.e.

operation at 58.8 Hz) appeared to result in a core spray flow rate which was

less than assumed

in FSAR Chapter 15, Accident Analysis.

Field surveillance test data shows that the SSES EDGs maintain 60 +/-

0.4 Hz (i.e. a frequency response of +/- 0.4 Hz) when started and loaded in

accordance with reference (1). On November 20, 1997, the licensee did not

have an analysis to show that this frequency response deviation willmeet

24

the ECCS design basis post-accident analysis, as documented

in FSAR

Chapter 15, Accident Analysis.

PPSL stated that the operability

determination performed for CR 97-2874 indicated that a frequency drop in

excess of 1.0 Hz (i.e. operation at less than 59.0 Hz) would be required

before any ECCS flow rate dropped below the minimum assumed

in FSAR

Chapter 15, Accident Analysis.

~

The ECCS equipment has not been tested by the licensee or analyzed for

performance characteristics

(i.e. pump speed and motor current) with either a

+/- 1.2 Hz or a +/- 3 Hz frequency deviation from a nominal 60 Hz.

When ECCS pump curves, generated from field surveillance data, are

corrected for a lower motor speed corresponding to 57 Hz, the pump curves

appear to be non-conservative

in that they do not meet the design input

assumptions

used by the General Electric (GE) ECCS safety analysis

calculational model, SAFER/GESTR (GE proprietary accident analysis).

The

licensee has not performed any analysis to verify whether the ECCS pump

curves, when corrected to a frequency deviation of +/- 1.2 Hz (per

references 4 and 5) willsatisfy the design input assumptions for the GE

accident analysis.

On December 10, 1997, the licensee completed a

calculation using actual test data (+/- 0.4 Hz) and determined that the

original design conclusion of the GE SAFER/GESTR calculations were met.

Based on the above information, the current SSES TS, as well as the SSES ITS

submittal, appear to use non-conservative

acceptance

criteria for surveillance

testing of the EDG frequency response.

A formal engineering analysis will be

performed to evaluate the EDG frequency response

and revise the ITS submittal, if

required.

PPRL'management

has stated that the appropriate TS surveillance tests

will be revised to use a conservative acceptance

criteria for EDG frequency

response

prior to the next performance;

EDG frequency response

can only be

verified when the EDGs are operated in the emergency mode during LOCA loss of

off site power (LOOP) testing, performed during refueling outages.

The operability

determination performed for CR 97-2874, stated that the current EDG frequency

response of +/- 0.4 Hz, as indicated by previous surveillance test data, was

adequate to support the ECCS flow rates assumed

in the FSAR accident analysis.

The NRC identified that the current SSES TSs allow a frequency variation of +/- 3

Hz, which differs from the variation accepted

by the NRC in Regulatory Guide 1.9

(+/- 1.2 Hz) and from the frequency experienced

in field tests (+/- 0.4 Hz). When

the TS allowed frequency variation is overlaid with General Electric's proprietary

ECCS pump curves, the amended pump curves appear to be non-conservative

in

that they do not meet the design input assumptions

used by the General Electric

(GE) ECCS safety analysis calculational model, SAFER/GESTR.

No formal analysis

or test has been conducted by the licensee to ensure that FSAR Chapter 15

accident analysis can be met using any of the frequency variation bands other than

+/- 0.4 Hz.

Resolution of this issue will be tracked as an unresolved item.

(URI 50-387,388/97-09-06)

25

C.

Conclusions

SSES emergency diesel generator

(EDG) frequency TS surveillance requirements

were

compared to emergency core cooling system (ECCS) design basis

assumptions.

EDG frequency is proportional to ECCS pump speed which

determines post accident ECCS injection flow rates.

When the lowest EDG

frequency allowed by TS is overlaid onto SSES design basis ECCS pump

performance assumptions, the results are non conservative,

because there are

situations in which calculations show ECCS pumps can not provide the required

post accident injection flow.

However, actual EDG frequency variation, as shown

by test data, is significantly better than that allowed by TSs, and when actual

frequency test data is overlaid with design ECCS pump performance assumptions,

the ECCS flow rates are shown to be adequate

and safe.

Resolution of the

nonconservative

TS surveillance criteria will be tracked as an unresolved item.

E7

Quality Assurance

in Engineering Activities

E7.1

Thermal Limits for Sin le Loo

0 eration

a.

Ins ection Sco

e 37551

On October 31, 1997, PP&L identified a potentially non-conservative

assumption in

an analysis that was used to establish the thermal limits for single loop operation

(SLO). The analysis was performed by Siemens Power Corporation (Siemens) and

PPRL identified the issue during an independent evaluation of the Siemens analysis.

The inspector reviewed PPtkL's immediate corrective actions for this issue.

b.

Observations

and Findin s

PPSL documented

a potential non-conservatism

in the minimum critical power ratio

(MCPR) limits for SLO in CR 97-3641 and immediately established administrative

controls.

Changes to operating and off-normal procedures were made that direct

operators to enter TS 3.2.3 if a unit is forced into SLO. PP5L determined that this

TS limiting condition for operation was appropriate because the action statement

requires operators to restore the MCPR to within the limits. Since the appropriate

limits are in question, the procedure changes direct operators to comply with the TS

and reduce power to below 25%.

The inspector concluded that PPRL implemented conservative compensatory

measures for this issue and has initiated appropriate steps to resolve the potential

problem with the fuel vendor.

The inspector verified a portion of the immediate

corrective actions listed in CR 97-3641 had been performed by verifying Unit 1

control room procedures

had been revised as required by the CR.

On November 12, 1997, Siemens issued

a letter to PPS.L that formally

acknowledged the potential non-conservatism

and showed the issue had been

entered

in Siemens corrective action process.

On November 21, 1997, Siemens

issued

a letter to the NRC describing the issue and enclosed

a justification for

26

limiting boiling transition checks to the upper portion of the fuel ~ A review by the

Office of Nuclear Reactor Regulation is in progress to evaluate this issue and PPSL

intends to submit a letter to the NRC describing why the generic Siemens

justification applies to SSES.

The NRC Office of Nuclear Reactor Regulation is

currently resolving this issue directly with SSES and Siemens.

c.

Conclusions

PPRL identified a potential non-conservatism

in the vendor supplied methodology

used to establish minimum critical power ratio (MCPR) limits for single loop

operation.

The identification of this issue by PPRL was viewed as a strength, and

as an indication of the level of scrutiny being given to fuel related calculations.

The

inspector verified that conservative interim corrective actions have been

implemented for SSES pending the resolution of the potential issue, by the NRC

Office of Nuclear Reactor Regulation.

E8

Miscellaneous Engineering Issues (92902)

E8.1

Review of U dated Final Safet

Anal sis Re ort

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

E1.1 of this report, the inspectors reviewed the applicable portions of the UFSAR

that related to the areas inspected.

In section E1.1 of this report, several

inconsistencies

were noted between the wording of the UFSAR and the plant

configuration and procedures.

IV. Plant Su

ort

S1

Conduct of Security and Safeguards Activities

S1.1

Securit

Pro ram Review

a,

Ins ection Sco

e 81700

On a sampling basis, the inspectors determined whether the security program, as

implemented, met the licensee's commitments in the NRC-approved security plan

(the Plan) and NRC regulatory requirements.

The security program was inspected

during the period of September 8-11, 1997. Areas inspected included:

previously

identified item; management support and audits; alarm stations and

communications; testing, maintenance

and compensatory measures,

training and

qualification; and the vehicle barrier system.

27

b.

Observations

and Findin s

One previously identified item involving marginally effective assessment

aids

(section S8.6, this report) was closed based on the effectiveness of the licensee's

corrective actions, inspectors'bservations,

and discussions with security

management.

Management support is ongoing as evidenced by the allocation of

resources to permit security supervision's participation in a management

leadership

program, the approval of funding for a new security computer, adequate

manning

levels to permit effective program implementation and the procurement of additional

training aids to enhance tactical response training. Audits were thorough and in-

depth and alarm station operators were knowledgeable of their duties and

responsibilities and were not engaged with activities that would interfere with their

response functions.

Security equipment was being tested and maintained in

accordance with the NRC-approved physical security plan and security training was

being performed in accordance with the NRC-approved training and qualification

(TRQ) plan.

Based on the inspectors'bservations

and discussions with plant engineering and

security management,

the inspectors determined that the licensee's

provisions for

land vehicle control measures satisfy regulatory requirements

and licensee

commitments.

C.

Conclusions

The inspectors determined that the licensee was conducting its security and

safeguards

activities in a manner that protected public health and safety and that

the program, as implemented, met the licensee's commitments and NRC

requirements.

S2

Status of Security Facilities and Equipment

S2.1

Alarm Stations and Communications

a 0

Ins ection Sco

e 81700

Determine whether the Central Alarm Station (CAS) and Secondary Alarm Station

(SAS) are:

(1) equipped with appropriate alarm, surveillance and communication

capability, (2) continuously manned by operators,

and (3) use independent and

diverse systems so that no single act can remove the capability of detecting

a threat

and calling for assistance,

or otherwise responding to the threat, as required by NRC

regulations.

b.

Observations

and Findin s

Observations of CAS and SAS operations verified that the alarm stations were

equipped with the appropriate alarm, surveillance, and communication capabilities.

Interviews with CAS and SAS operators found them knowledgeable of their duties

and responsibilities.

The inspectors also verified through observations

and

28

interviews that the CAS and SAS operators were not required to engage

in activities

that would'interfere with the assessment

and response functions, and that the

licensee had exercised communication methods with the local law enforcement

agencies

as committed to in the Plan.

Additionally, the inspectors evaluated the effectiveness of the assessment

aids, by

observing on closed circuit television (CCTV), a walkdown of the protected area.

The licensee recently completed a major assessment

aid upgrade which included the

replacement of 44 cameras

and the installation of 15 extensions on the camera

towers which enhanced the camera's field of view by eliminating the walling effect

on several zones.

The inspectors determined that the assessment

aids in both alarm

stations had excellent picture quality.

Conclusion

The alarm stations and communications met the licensee's

Plan commitments and

NRC requirements.

Testin

Maintenance and Com ensator

Measures

Ins ection Sco

e 81700

Determine whether programs are implemented that will ensure the reliability of

security related equipment, including proper installation, testing and maintenance to

replace defective or marginally effective equipment.

Additionally, determine that

when security related equipment fails, the compensatory measures

put in place are

comparable to the effectiveness of the security system that existed prior to the

failure.

Observations and Findin s

The inspectors reviewed testing and maintenance

records for security-related

equipment and found that documentation was on file to demonstrate that the

licensee was testing and maintaining systems and equipment as committed to in the

Plan.

A priority status was being assigned to each work request and repairs were

normally being completed within the same day a WA necessitating compensatory

measures

was generated.

The inspectors also noted that the working relationship

among security, maintenance department and the instrumentation and control (IRC)

was excellent as evidenced by no opened work requests requiring compensatory

measures.

Conclusions

Documentation on file confirmed that security equipment was being tested and

maintained as required.

Repair work was timely and the use of compensatory

measures was found to be appropriate and minimal.

29

S5

Security and Safeguards Staff Training and Qualification

S5.1

Trainin

and Qualification TRQ Plan Im lementation

a.

Ins ection Sco

e 81700

Determine whether members of the security organization were trained and qualified

to perform each assigned security related job task or duty in accordance with the

NRC-approved T&Q plan.

b.

Observations

and Findin s

On September 10, 1997, the inspectors met with the security training coordinator

and discussed training department enhancements

and program initiatives

implemented since the previous program inspection conducted in November 1996.

The discussions

revealed that the licensee is in the process of revising the NRC-

approved TRQ plan.

The revisions involve the consolidation of similar critical tasks

so that the training process, by the reduction of the number of tasks, would become

more streamlined and less of an administrative burden.

Additionally, the inspectors

discussed the licensee's protective strategies associated with the licensee's ability

to protect the site against the design basis threat.

The inspectors were informed

that the training department has been actively involved in drill development, drill

participation, and the development and performance of table top exercises to assist

the security officers (SOs) in their knowledge of tactical response

and deployment.

Additionally, during the inspection, the inspectors randomly interviewed a number of

SOs to determine if they possessed

the requisite knowledge and ability to carry out

their assigned duties.

C.

Conclusions

The inspectors determined that training had been conducted in accordance with the

TRQ plan.

Based on the SOs responses

to the inspectors'uestions

and

inspectors'bservations,

the training provided by the security training staff was

considered effective.

S6

Security Organization and Administration

S6.1

Mana ement Su

ort

a.

Ins ection Sco

e 81700

Conduct a review of the level of management support for the licensee's physical

security program.

30

b.

Observations and'Findin

s

The inspectors reviewed various program enhancements

made since the last

program inspection, which was conducted in November 1996. These

enhancements

included the allocation of resources to permit security supervision's

participation in a management

leadership program, the approval of funding for a

new security computer, adequate

manning levels to permit effective program

implementation and the procurement of additional training aids to enhance tactical

response training.

The inspectors reviewed the Manager Nuclear Security's position in the

organizational structure and reporting chain.

The Manager Nuclear Security reports

to the Manager - Plant Services, who reports to the Vice President Operations.

Additionally, the inspectors noted that the access

authorization and fitness-for-duty

programs, being safeguards

related, report directly to the Manager Nuclear Security.

C.

Conclusions

Management support for the physical security program was determined to be

effective.

No problems with the organizational structure that would be detrimental

to the effective implementation of the security and safeguards

programs were

noted.

S7

Quality Assurance in Security and Safeguards Activities

S7.1, Qualit

Assurance Audits

a 0

Ins ection Sco

e 81700

Review the licensee's Quality Assurance

(QA) 'report of the NRC-required security

program audit to determine if the licensee's commitments as contained in the Plan

were being satisfied.

b.

Observations

and Findin s

The inspectors reviewed the 1996 QA audit of the security program, conducted

September 23- November 4, 1997, (Audit No.96-118) and the 1996 QA audit of

the fitness-for-duty (FFD) program, conducted November 11 - December 30, 1996,

(Audit No.96-141). The audits were found to have been conducted in accordance

with the Plan and FFD rule.

The security audit report identified two condition reports (CR) and three

observations.

One CR involved security plan changes not being adequately

reviewed and one CR involved the control of designated

vehicles outside the

protected area for other than maintenance

or emergency purposes.

The FFD audit

identified one CR. The CR involved four emergency response

personnel assigned to

Emergency Plan - Emergency Operations Facility (EOF) reporting responsibilities not

subjected to the FFD random testing program.

The inspectors determined that the

31

findings were not indicative of programmatic weaknesses,

and the observations

would enhance

program effectiveness.

The inspectors determined, based on

discussions with security management

and FFD staff and a review of the responses

to the findings, that the corrective actions were effective.

C.

Conclusions

The review concluded that the audits were comprehensive

in scope and depth, that

the findings were reported to the appropriate levels of management,

and that the

audit program was being properly administered.

S8

Miscellaneous Security and Safety Issues

S8.1

Vehicle Barrier S stem

VBS Overview

On August 1, 1994, the Commission amended

10 CFR Part 73, "Physical Protection

of Plants and Materials," to modify the design basis threat for radiological sabotage

to include the use of a land vehicle by adversaries for transporting personnel and

their hand-carried equipment to the proximity of vital areas and to include the use of

a land vehicle bomb.

The amendments

require reactor licensees to install vehicle

control measures,

including VBSs, to protect against the malevolent use of a land

vehicle.

Regulatory Guide 5.68 and NUREG/CR-6190 were issued in August 1994

to provide guidance acceptable to the NRC by which the licensees could meet the

requirements of the amended regulations.

A letter dated February 13, 1996, from the licensee to the NRC forwarded

Revision II to its physical security plan that detailed the actions implemented to

meet the requirements of 10 CFR 73.55 (c)(7),(8), and (9) and the design goals of

the "Design Basis Land Vehicle" and "Design Basis Land Vehicle Bomb." A NRC

May 9, 1996, letter advised the licensee that the changes submitted had been

reviewed and were determined to be consistent with the provisions of 10 CFR 50.54(p) and were acceptable for inclusion in the NRC-approved security plan.

This inspection, conducted in accordance with NRC Inspection Manual Temporary

Instruction 2515/132, "Malevolent Use of Vehicles at Nuclear Power Plants," dated

January 18, 1996, assessed

the implementation of the licensee's vehicle control

measures,

including vehicle barrier systems, to determine if they were

commensurate with regulatory requirements and the licensee's physical security

plan.

S8.2

Vehicle Barrier S stem

aO

Ins ection Sco

e Tl 2515 132

The inspectors reviewed documentation that described the VBS and physically

inspected the as-built VBS to verify it was consistent with the licensee's summary

description submitted to the NRC.

32

b.

Observations

and Findin s

The inspectors'alkdown of the VBS and review of the VBS summary description

disclosed that the as-built VBS was consistent with the summary description and

met or exceeded

the specifications in NUREG/CR-6190.

c.

Conclusion

The inspectors determined that there were no discrepancies

in the as-built VBS or

the VBS summary description.

S8.3

Bomb Blast Anal sis

a.

Ins ection Sco

e Tl 2515 132

The inspectors reviewed the licensee's documentation of the bomb blast analysis

and verified actual standoff distances provided by the as-built VBS.

b.

Observations

and Findin s

The inspectors'eview of the licensee's documentation of the bomb blast analysis

determined that it was consistent with the summary description submitted to the

NRC. The inspectors also verified that the actual standoff distances provided by

their as-built VBS were consistent with the minimum standoff distances calculated

using NUREG/CR-6190. The standoff distances were verified by review of scaled

drawings and actual field measurements.

C.

Conclusion

No discrepancies

were noted in the documentation of bomb blast analysis or actual

standoff distances provided by the as-built VBS.

S8.4

Procedural Controls

a.

Ins ection Sco

e Tl 2515 132

The inspectors reviewed applicable procedures to ensure that they had been revised

to include the VBS.

b.

Observations

and Findin s

The inspectors reviewed the licensee's

procedures for VBS access control

measures,

surveillance and compensatory measures.

The procedures contained

effective controls to provide passage

through the VBS, provide adequate

surveillance and inspection of the VBS, and provide adequate compensation for any

degradation of the VBS.

33

c.

Conclusions

The inspectors'eview of the procedures

applicable to the VBS disclosed no

discrepancies.

S8.5

Review of U dated Final Safet

Anal sis Re ort UFSAR

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 parameters to the UFSAR description.

Since the

UFSAR does not specifically include security program requirements, the inspectors

compared licensee activities to the NRC-approved physical security plan, which is

the applicable document.

While performing the inspection discussed

in section IV,

Plant Support, of this report, the inspectors reviewed Section 6.1 of the Plan,

Revision JJ, dated April 30, 1996, titled, "Surveillance."

The inspectors

determined, by observations, that the protected area perimeter was installed and

maintained as required in the Plan.

S8.6

Previousl

Identified Items (81066)

Closed

IFI 50-387 388 95-06-01:Marginally Effective Assessment

Aids

During a previous security inspection conducted in March 1995, the inspectors

determined, based on observations, that the assessment

aids were marginally

effective. To resolve the concerns, the licensee committed to upgrade the

assessment

aids by replacing cameras where needed

and repositioning cameras to

enhance the cameras fields of view.

Based on the inspectors'bservations

and discussions with security management,

the inspectors determined that the corrective actions implemented by the licensee to

address the above noted issues were reasonable;

complete, and effective.

V. IVlana ement lNeetin

s

X1

Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

conclusion of the inspection on December 10, 1996. The licensee acknowledged the

findings presented

and made no objections at the time of the meeting.

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

should be considered proprietary.

No proprietary information was identified.

The Region

I physical security inspectors met with licensee representatives

at the

conclusion of their inspection on September

11, 1997. At that time, the purpose and

scope of the inspection were reviewed, and the preliminary findings were presented.

The

licensee acknowledged the preliminary inspection findings, on September 11, 1997, and a

general summary of the security inspection findings on December 10, 1997.

34

ITEMS OPENED, CLOSED, AND DISCUSSED

~Qened

IF I 50-387,388/97-09-01

Unexpected Half Scram During Reactor Pressure Switch

Surveillance

VIO 50-388/97-09-02

Replacement of Valve HV-2F031B Bonnet Vent Line

URI 50-387,388/97-09-03

Leakage Rate Testing for FW 7A/B containment isolation

valves

URI 50-387,388/97-09-04

RWCU Isolation Valves and Requirements of GDC 55

URI 50-387,388/97-09-05

URI 50-387,388/97-09-06

Consequential

Failure of the FW 10A/B Check Valves

Emergency Diesel Generator Frequency and ECCS Performance

Closed

IFI 50-387,388/95-06-01

Marginally Effective Assessment

Aids

IFI 50-387,388/97-07-01

a

IFI 50-387,388/97-07-01 b

Unit 2 Shutdown/Increasing

Unidentified Drywell Leakage

Operator Response to a Feedwater Level Transient

LER 50-387/97-019-00

Control Structure Chiller Would Not Auto Start

LER 50-387/97-020-00

Loss of MSRV Acoustic Monitor

Discussed

VIO 50-387,388/97-04-02

Nuclear Safety Assessment

Group (NSAG)

URI 50-387,388/97-03-03

Omission of the Back Draft Isolation Dampers in the SSES

Maintenance

Rule Program

t

LIST OF ACRONYMS USED

AEOD

ALARA

CAS

CCTV

Office for Analysis and Evaluation of Operational Data

As Low As Is Reasonably Achievable

central alarm system

closed circuit television

Code of Federal Regulations

Core Spray

35

CS Chiller

EA

EP

ESF

gpm

GPO

IFI

IFS

IMC

IPAP

ISI

LER

MD

NCV

NMSS

NOV

NRC

NRR

OE

Ol

PA

PPR

RA

RHR

RP

RPRC

SALP

SAS

SI

SO

T&Q

the Plan

Tl

TS

UFSAR

VBS

Control Structure Chiller

Escalated Action

Emergency Preparedness

Engineered Safety Feature

gallons per minute

Government Printing Office

Inspection Follow-Up Item

Inspection Follow-Up System

Inspection Manual Chapter

Integrated Performance Assessment

Process

In-Service Inspection

Licensee Event Report

Management Directive

Non-Cited Violation

Office of Nuclear Material Safety and Safeguards

Notice of Violation

Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Office of Enforcement

Office of Investigations

protected area

Plant Performance Review

quality assurance

Regional Administrator

Residual Heat Removal

Radiation Protection

Radiological Protection and Chemistry

Systematic Assessment of Licensee Performance

secondary alarm system

International System of Units

security officer

training and qualification

NRC-approved physical security plan

Temporary Instruction

Technical Specification

Updated Final Safety Analysis Report

vehicle barrier system