ML17159A032

Insp Repts 50-387/97-07 & 50-388/97-07 on 970817-1020. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML17159A032
Person / Time
Site:	Susquehanna
Issue date:	10/30/1997
From:	Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17159A030	List: ML17159A029 ML17159A031 ML17159A032
References
50-387-97-07, 50-387-97-7, 50-388-97-07, 50-388-97-7, NUDOCS 9711070080
Download: ML17159A032 (54)

See also: IR 05000387/1997007

Text

e

U. S. NUCLEAR REGULATORY COMMISSION

REGION

I

Docket Nos:

License Nos:

50-387, 50-388

NPF-14, NPF-22

Report No.

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

Licensee:

Pennsylvania Power and Light Company (PP&L)

2 North Ninth Street

Allentown, Pennsylvania

19101

Facility:

Susquehanna

Steam Electric Station

Location:

P.O. Box 35

Berwick, PA 18603-0035

Dates:

August 17, 1997 through October 20, 1997

Inspectors:

Approved by:

K. Jenison, Senior Resident Inspector

B. McDermott, Resident Inspector

J. Richmond, Resident Inspector

Clifford J. Anderson, Chief

Projects Branch 4

Division of Reactor Projects

V7if070080 9'71030

PDR

nOOCK OSOaOSa7'

PDR

0

EXECUTIVE SUMMARY

Susquehanna

Steam Electric Station (SSES), Units 1 5 2

NRC Inspection Report 50-387/97-07, 50-388/97-07

This inspection included aspects of Pennsylvania Power and Light Company's (PPSL's)

operations, maintenance,

engineering and plant support at SSES.

The report covers a nine

week period of resident inspection.

~Oerations

PPSL management

conservatively opted to shut down Unit 2 in response to an

increasing trend of unidentified reactor coolant system leakage before reaching

Technical Specification (TS) limits. Good management

involvement was observed

during preparation for the shutdown and an orderly shutdown was conducted with

no significant challenges to the operators.

An inspector follow-up item was opened

to track the licensee's root cause investigation of the equipment failure.

(Section

01.1)

A reactor feedwater pump (RFP) minimum flow control valve failed open resulting in

a reactor water level induced transient.

The Plant Control Operator (PCO) reduced

power to approximately 68%, reactor water level was recovered,

and the unit was

returned to a steady state condition.

PCO actions were conservative

and in

accordance with unit procedures.

The licensee initiated an event review team (ERT)

to determine the root cause of the transient.

The cause of the equipment failure

and the results of the ERT investigation will be reviewed as an inspector follow-up

item. (section 01.2)

Interviews were conducted with licensed and non-licensed operators to assess

the

implementation of SSES Operations department procedure OI-AD-016, Operator

Rounds.

Based on these interviews, the inspectors determined that portions of

procedure sections 4.2 through 4.5 were routinely delayed, amended or missed

during periods of high activity. This issue was discussed with licensee management

on three occasions.

The licensee made changes to the procedure to ensure that the

procedure was clear and allowed shift supervision the flexibilityto delay or amend

the requirements for general equipment inspections in the subject procedure steps.

The licensee's

immediate corrective actions were adequate

and were completed

prior to the end of the inspection period.

The failure to follow procedure Ol-AD-016

as written during previous operator rounds was a violation of TS 6.8.1.

(section

01.3)

The PCOs responded well to those alarmed conditions requiring actions.

PCOs were

able to describe the reasons for their actions and discuss the impact of their actions

upon the units.

PCO actions were determined to be conservative and in accordance

with established

plant procedures.

(section 04.1)

The resolution of several issues by the PPSL Corrective Action Team (CAT) was

direct, safety oriented, and conservative.

(section 07.1)

Executive Summary

Maintenance

The work authorization (WA) activities observed during this inspection period were,

in general, well performed.

The WAs described

and controlled maintenance

activities with adequate,

but in some cases general, procedures.

The maintenance

activities were implemented by well trained and experienced maintenance

technicians,

and resulted in equipment being returned to service in good conditior .

(section M1.1)

SSES surveillance activities, observed during this inspection period, were well

performed, described and controlled by detailed SSES procedures,

and performed by

well trained, experienced

and capable technicians/operators.

(section M1.2)

The maintenance task certification matrix and its implementation were adequate to

control the assignment of qualified workers to safety related

maintenance

activities.

No violation of NRC requirements was identified. (section M1.3)

The licensee's corrective actions in response to an interrupted cool down of the "C"

Emergency Diesel Generator

(EDG) were adequate.

The interrupted cool down did

not affect the operability of the EDG. (section M2.1)

PPRL requested

enforcement discretion for TS requirements concerning

a failed

acoustic position indicator for the "S" Safety Relief Valve.

PPSL requested

the

enforcement discretion to avoid an undesirable transient as the result of forcing

compliance with a license condition. The NRC approved PPRL's request after

determining the action involved minimal or no safety impact and had no adverse

radiological impact on public health and safety.

(section M2.2)

PPRL allowed maintenance work to proceed on the "A" Standby Liquid Control

(SBLC) pump nitrogen accumulator without evaluating whether the activity would

affect operability. After questions regarding operability impact were raised by the

NRC, an initial operability determination by the Shift Technical Advisor was weak

because lt did not address known technical issues with the potential to affect

operability.

The failure to provide adequate

procedures for control of maintenance

on safety related equipment is a violation of TSs.

(section M3.1)

'I

Corrective actions for a safety related check valve deficiency, identified in 1994, did

not address generic implications.

In 1996, the same condition was identified on a

different valve and, in this case, the planned actions to prevent recurrence were

appropriate.

However, the administrative process to implement and track these

actions was not initiated. These two corrective action problems are considered

a

violation of minor significance because this had no impact on safety.

(section

M7.1)

Executive Summary

EncnineerinE

~

The erosion control program portion of engineering corrective actions for an

indicated high level in a reactor core isolation cooling (RCIC) drain pot was

determined to be outstanding.

(section E2.1)

~

The engineering corrective actions for problems with the Unit 1 RCIC drain pot level

switch were not timely. This allowed continuous degradation of the drain line and a

continuous alarmed condition for over ten months after it caused

a forced

shutdown.

A modification to replace the drain pot level switch was completed and

has been effective in restoring the normal operation of the RCIC system.

(section

E2.1)

In February 1997, PP&L identified that the "A" Control Structure (CS) chiller would

not automatically start as designed

and took immediate actions to correct. the

problem.

However, PP&L initiallyfailed to recognize this condition as outside the

plant's design basis, as described

in the Final Safety Analysis Report. After

identification by the NRC, PP&L initiated a Condition Report, determined the

condition was reportable, and submitted a Licensee Event Report as required.

Corrective actions for both the technical problem and the failure to recognize the

condition outside the design basis were implemented by PP&L.

In this case, the

failure to report a condition outside the design basis within 30 days of discovery is

characterized

as a non-cited violation. (section E4.1)

The initial operability determination for the Unit 2 High Pressure

Coolant Injection

(HPCI) overspeed trip assembly problem was weak.

Nuclear System Engineering

personnel overlooked the potential impact on the HPCI injection valve and how this

impact could affect the response time to rated flow. PP&L management

made a

conservative decision to declare HPCI inoperable, pending further evaluation.

A

subsequent

revision of the operability determination provided a good basis for

operability. Significant licensee attention was focused on resolution of the problem

and the overspeed trip assembly has performed acceptably since the corrective

maintenance.

(section E4.2)

PP&L failed to perform a 10 CFR 50.59 safety evaluation prior to opening a plant

equipment hatch assumed to be closed by the tornado design basis analysis.

This

condition existed for an extended period before identification by the NRC.

Subsequently,

plant equipment hatches have been verified to be in the condition

assumed

by the tornado analysis (shut) and are now being administratively

controlled.

PP&L's evaluation to determine whether an unreviewed safety question

existed with the hatch open is expected in January 1998 and will be reviewed to

determine the safety significance of this violation.

In the interim, this item is being

tracked as an unresolved item.

(section E8.1)

A review of the SSES responses

to 10 CFR 50.63, Station Blackout (SBO) rule was

conducted.

The licensee installed an auxiliary diesel power source to increase the

SBO coping duration of its 125 Vdc batteries from approximately 5-hours to greater

than 8-hours.

The NRC safety evaluation report concluded that SSES must meet a

0

Executive Summary

4-hour coping duration.

Therefore, the inspectors concluded that there was no

current regulatory requirement for the licensee to maintain the auxiliary power

source.

(section E8.2)

PPSL failed to perform a 10 CFR 50.59 safety evaluation prior to placing a floating

service platform on the spray pond that serves as the ultimate heat sink for both

SSES units. This condition existed for an extended period before identification by

the NRC.

PPRL has yet to perform an evaluation to determine whether an

unreviewed safety question existed with the platform on the spray pond.

Subsequently,

the spray pond was verified to be in the condition assumed

by the

Final Safety Analysis (the platform was removed).

Analysis of the spray pond

design basis and evaluation of the potential USQ will be reviewed with the response

to this violation. (section E8.3)

I. Operations

01

04

07

08

TABLE OF CONTENTS

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

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1

01.1

Unit 2 Shutdown Due to Increasing Unidentified Drywell Leakage .,

1

01.2

Operator Response to a Feedwater Level Transient ...

~ .. ~....

~ 3

01.3

Nuclear Plant Operator (NPO) Performance

~

~ . ~... ~... ~...... 4

Operator Knowledge and Performance ......,.... ~............

~ .. 5

04.1

Operator Response

to Operating Occurrences ..

~ .., ~... ~...

~ . 5

Quality Assurance

in Operations ....

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6

07.1

Corrective Action Team (CAT) Support of Plant Operations ...... 6

Miscellaneous Operations Issues ~...

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~ .. ~... ~..... ~.... ~, 6

08.1

Review of Licensee Event Reports

~ . ~...

~ ~... ~....

~ ..,,... 6

08.2

Review of NRC Open Items

.

~ ~...

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~ .. ~... 8

I. Maintenance

I

. 10

M1

M3

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

10

M1.1

Preplanned Maintenance ActivityReview ..................

10

M1.2

Preplanned

Surveillance ActivityReview...... ~... ~.... ~...

11

M1.3

Maintenance Technician Task Certification ..

~ ~.............

12

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

13

M2.1

Trip of the "C" Emergency Diesel Generator

(EDG) During Surveillance

Testing..........................................

13

M2.2

Unit 1 "S" Safety Relief Valve (SRV) Acoustic Position Indicator

(Acoustic Monitor) Failure

.

~ .. ~... ~...

~ ~...............

14

Maintenance Procedures

and Documentation ........ ~...........

1.5

M3.1

Release of Unit 1 Standby Liquid Control (SBLC) Accumulator Work

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1 5

Quality Assurance

in Maintenance.................. ~.........

17

M7.1

Unit 1 RHR Pump "A" Recirculation Check Valve Inspection ~.... 17

M7.2

Condition Report (CR) Support for Maintenance Activities ......

18

III. Engineering................ ~..... ~.............,.......,

..

~ ..

. 19

E2

E4

E8

Engineering Support of Facilities and Equipment

E2.1

Reactor Core Isolation Cooling (RCIC) Drain Pot Level Switch ..

Engineering Staff Knowledge and Performance

E4.1

Control Structure Chiller Automatic Start Capability........

~

E4.2

High Pressure

Coolant Injection (HPCI) Operability Determination

Miscellaneous Engineering Issues...............

~ .. ~........

E8.1

Unit 2 Reactor Building Truck Bay Hatch

E8.2

Station Blackout Design Basis ........... ~....... ~....

E8.3

Floating Service Platform on Safety Related Spray Pond

. ~....

.. 19

.. 19

. 20

. 20

. 22

.. 24

. 24

. 25

. 27

V. Plant Support ........

~ .,....,.......,..............

I

F2

Status of Fire Protection Program

F2.1

Control Room CO, Fire Protection System .. ~...

R7

Radiological protection and Chemistry (RPC) Controls

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VI

O

R7.1

Health Physics Frisking, Problems and Corrective Actions ....... 28

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

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X1

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

ITEMS OPENED, CLOSED, AND DISCUSSED

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o 30

LIST OF ACRONYMS USED................

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~ 3 1

Re ort Details

Summar

of Plant Status

Unit 1 began the inspection report period at 100% power.

Temporary power reductions

were made for planned activities including main turbine valve testing,

a control rod

sequence

exchange,

a condenser water box leak investigation, and control rod scram time

testing.

An unplanned power reduction was necessary

as a result of a reactor feedwater

pump minimum flow valve that failed open'on September

1, 1997. At the end of the

report period, Unit

1 was at 100% power.

Unit 2 began the

inspection report period at 100% power,

An unplanned shutdown was

performed on September

16, 1997, in response to an increasing trend of unidentified

reactor coolant leakage.

After repairs were made to a cracked valve bonnet vent line, the

unit was returned to operation on September 24, 1997.

Other temporary planned power

reductions were made to support a control rod sequence

exchange, control rod scram time

testing, and main turbine valve testing.

At the end of the report period, Unit 2 was at

100% power.

I. 0 erations

01

Conduct of Operations

01.1

Unit 2 Shutdown Due to lncreasin

Unidentified Dr well Leaka

e

a.

Ins ection Sco

e 71707

On September

12, 1997, Plant Control Operators

(PCOs) identified an increasing

trend on both divisions of the containment radiation monitor and a corresponding

increase in the unidentified leakage collected in the "B" Containment Sump (CR 97-

3022). The inspectors reviewed the licensee's

actions in response to these

indications of a leak inside containment.

b.

Observations

and Findin s

The Technical Specification (TS) 3.4.3.2 lim!tfor unidentified reactor coolant

system leakage is 5 gpm, or an increase of 2 gpm in any 24-hour period.

I'ollowingthe Spring 1997 refueling outage, the Unit 2 unidentified leakage rate

was typically 0.04 gpm or less.

On September

12, 1997, the unidentified leakage

rate increased to approximately 0.80 gpm and then stabilized for several days.

Chemistry samples of the containment sump indicated that the leak was from

reactor coolant, e.g. the liquid portion of the primary system, rather than a steam

piping leak.

PPSL management

began planning for a shutdown on September

19,

1997 to minimize the radiological impacts during the next refueling outage.

However, on September

16, the leakage rate took a second step increase, to an

average of approximately 2.0 gpm.

PPRL management

decided to initiate an orderly plant shutdown on September 16,

1997, based on the increasing leakage rate.

The inspectors observed that

0

.2

Operations management's

expectations for control of the shutdown were clearly

articulated at the pre-activity briefing. As of September

17, 1997, Unit 2 was in

the Cold Shutdown condition for investigation of the leak and to make repairs.

The

inspectors considered

PP&L's decision to shut down ahead of schedule because

of

the increasing leakage trend, and before reaching TS limits, a conservative measure.

After the unit was placed in Cold Shutdown, PP&L determined the leak was from a

0.75 inch bonnet vent line off the "B" Reactor Recirculation Pump discharge valve.

A weld on the vent line was found to have a through-wall crack, 180 degrees

around its circumference.

PP&L's preliminary finding was that the vent line had not

been properly installed during the Spring 1997 outage'and that vibration caused

a

weld to crack.

PP&L's review of vibration test results from the Unit 2 seventh refueling outage,

and work authorizations (WAs) performed since that time, did not identify other

similar maintenance

circumstances.

In addition, inspections of lines similar to the

one that failed were performed to identify similar configurations with the potential

for fatigue failure and no evidence of such conditions were found.

PP&L concluded

the Unit 1 systems would be unaffected by the implications of this incident because

Unit 1 containment experiences

less vibration than Unit 2 and because tests of

vibration sensitive piping during the Unit 1 eighth refueling outage were acceptable.

Based on the root cause investigations initial findings, the maintenance

error which

led to this failure was considered

an isolated case.

The failed vent line and its associated

isolation valves were not used by PP&L and

therefore they were removed during the forced outage through a formal plant

modification. A start up Plant Operations Review Committee (PORC) meeting was

conducted on September 21, 1997.

The shutdown open item list was reviewed

and each item was dispositioned by the committee.

The inspectors observed that

the committee asked thorough and probing questions regarding the resolution of

technical issues.

PP&L management

acknowledged

a weakness

exists in the

number of ways the plant can be modified that do not use the same level of control

required In the formal modification process.

Programs other than the modification

process that can change plant components,

or equipment configuration, include

Replacement Item Equivalents, maintenance

repairs or use-as-is,

Bypasses, setpoint

changes,

and several others.

Nuclear System Engineering (NSE) management

is

evaluating this weakness

and is developing

a corrective action plan.

The bonnet vent line failure is the first example of an equipment failure that

necessitated

an unplanned operational transient during this inspection period.

An

inspector follow-up item (IFI) will be opened to track this issue for future NRC

review of the licensee's root cause investigation and corrective actions for this

equipment failure. A second equipment failure during this period is discussed

in

Section 01.2 of this report and will also be tracked under this item.

(IFI 50-

387,388/97-07-01 a)

c.

Conclusions

PPSL management

conservatively opted to shut down Unit 2 in response to an

increasing trend of unidentified reactor coolant system leakage before reaching TS

limits. Good management

involvement was observed during preparation for the

shutdown and an orderly shutdown was conducted with no significant challenges to

the operators.

An inspector follow-up item was opened to track the.licensee's

root

cause investigation of the equipment failure.

01.2

0 erator Res

onse to a Feedwater Level Transient

a.

Ins ection Sco

e 71707

On September

1, 1997, the Unit 1 "B" Reactor Feedwater Pump (RFP) minimum

flow control valve failed open.

This control valve failure resulted in a reactor water

level transient.

The inspectors reviewed the licensee's

response to this transient.

b.

Observations

and Findin s

On September

1, 1997, an RFP minimum flow control valve failed open directing

approximately 6000 gpm from the discharge of the "B" RFP to the main condenser

hotwell. Because of the flow being recirculated to the hotwell, instead of being

supplied to the reactor vessel, steam flow exceeded feedwater flow and reactor

water level began to decrease.

The Plant Control Operator (PCO) reduced power to

approximately 68%, control of reactor water level was recovered,

and the unit was

returned to a steady state condition.

The inspectors reviewed the actions of the

control room operators and determined that their actions were conservative

and in

accordance with unit procedures.

The licensee initiated a WA to repair the control

valve and established

an Event Review Team (ERT) to review the root cause of the

transient.

The inspectors considered the feedwater control valve failure a second example of

an equipment failure that caused

an unplanned operational transient during this

inspection period.

An IFI item will be opened to track this issue for review of the

licensee's root cause investigation and corrective actions.

(IFI 50-

387,388/97-07-01 b)

C.

Conclusions

A reactor feedwater pump (RFP) minimum flow control valve failed open resulting in

a reactor water level induced transient.

The PCO reduced power to approximately

68%, reactor water level was recovered,

and the unit was returned to a steady

state condition.

PCO actions were conservative and in accordance with unit

procedures.

The licensee initiated an Event Review Team (ERT) to review the root

cause of the transient.

The cause of the equipment failure and the results of the

ERT investigation will be reviewed as an inspector follow-up item.

I,

0

o~s

Nuclear Plant 0 erator

NPO

Performance

Ins ection Sco

e 71707

On October 9, 1997, the inspectors determined that certain portions of NPO rounds

as described

in Operations department procedure Ol-AD-016 were not being

performed in a consistent and complete manner.

A review of the licensee's

corrective actions for this issue was performed.

b.

Observations

and Findin s

Based on interviews with five NPOs and ten licensed operators, the inspectors

determined that the licensee was not fully implementing Operations department

procedure OI-AD-016, Operator Rounds.

The inspectors determined that the

required check sheet data, including TS surveillances, were being adequately taken

during operator rounds.

However, additional Ol-AD-016 general and routine

required actions were not always performed when other plant activities were

deemed more appropriate by the Unit Supervisor and/or the Assistant Unit

Supervisor.

The flexibilityto omit certain general visual inspections (GVls) was not

addressed

in Ol-AD-016. Through interviews, the inspectors found that the GVls of

Ol-AD-016 were interrupted on a regular basis by interfering activities and were

routinely not completed to the level that the operators interviewed felt that they

were meeting the requirements of the procedure,

The interview process was chosen by the inspectors for this determination because:

(1) there is no available objective evidence on which to judge whether these general

and routine requirements were being completed,

(2) the inspectors verified that field

audits by PPRL similarly concluded that there were weaknesses

in the NPO round

activities and, (3) it was anticipated that any NRC accompaniments

of NPO rounds

would not be interrupted by the type of activities described by the NPOs.

The inspectors verified through their interviews with NPOs, PCOs, Unit Supervisors

(USs), and Shift Supervisors

(SS) that portions of the GVls required by Ol-AD-016

sections 4.2 through 4.5 were delayed, amended or missed during periods of high

activity. The inspectors verified that neither Operations management

nor the NPOs

had documented the failure to implement OP-AD-016 as written in a condition

report (CR). This issue was discussed with SSES site management

on October 10,

1997 and with Operations department management

on October 16, 1997.

TS 6.8.1, Procedures,

requires procedures including Ol-AD-016 to be established,

implemented and maintained.

The failure to ensure that Operations department

procedure Ol-AD-016 was implemented as established

is considered

a violation

(VIO 387,388/97-07-02).

On October 17, 1997, the inspectors met with SSES site

management

and were presented with an action plan that included procedure

changes

and training topic additions that were intended to eliminate the procedural

compliance issue and clarify NPO performance expectations.

SSES management

stated that they considered certain parts of Ol-AD-016 to be general guidelines

which should be considered

in relationship to the NPO's experience

and training,

even though the procedure was written in a form that would require complete

implementation.

For example, step

1 of the General Rounds Expectations

attachment to Ol-AD-016 states that

~ .. All rotating equipment such as pumps,

motors shall be inspected each shift .. ~ Inspections of protective covers on MCC's

and load centers shall be performed .. ~ it is required to inspect all operator

accessible

areas of the plant ... The licensee changed the Rounds Expectations

attachment to read, for example, "When checking rotating equipment such as

pumps, motors, etc., consider the following.. ~ ", through procedure change PCAF 1-

97-0590 series.

This change clarifies that the requirements

are considered

guidelines, and provides the flexibilityfor more or less effort in given areas based on

other more significant shift activities.

The inspector concluded that the immediate

corrective actions were acceptable.

Conclusions

Interviews were conducted with non-licensed and licensed operators to assess

the

implementation of SSES Operations department procedure OI-AD-016, Operator

Rounds.

Based on these interviews, the inspectors determined that portions of

procedure sections-4.2 through 4.5 were routinely delayed, amended or missed

during periods of high activity. This issue was discussed with licensee management

on three occasions.

The licensee made changes to the procedure to ensure that the

procedure was clear and allowed shift supervision the flexibilityto delay or amend

the requirements for general equipment inspections in the subject procedure steps.

The licensee's immediate corrective actions were adequate

and were completed

prior to the end of the inspection period.

The failure to follow procedure OI-AD-01.6

as written during previous operator rounds was a violation of TS 6.8.1.

Operator Knowledge and Performance

0 erator Res

onse to 0 eratin

Occurrences

Ins ection Sco

e 71707

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

responsibilities throughout the inspection period.

For alarm conditions, the

inspectors verified that appropriate alarm response

procedures were implemented

and that the required actions were completed.

Observations

and Findin s

For the following alarmed conditions, the inspectors observed/reviewed

and verified

that appropriate alarm response

procedures were implemented.

AR 015-G6, Seismic Trigger

AR 214-01, HPCI Pump Suction Hi

AR-029-01, EDG Room Temperature

AR-051-01, Loose Parts Monitor

ON-200-05, Excess Drywell Leakage

C.

AR-016-H5, System Particulate Iodine Nobel Gas

AR-016-01, River Water Makeup

AR-009-01, Loss of River Water Makeup

h

Conclusions

The PCOs responded

well to alarmed conditions in the control room, in those cases

requiring actions.

PCOs were able to describe the reasons for their actions and

discuss the impact of their actions on the plant.

Each of the observed actions were

conservative and in accordance with established

plant procedures.

07

Quality Assurance in Operations

07.1

Corrective Action Team

CAT Su

ort of Plant 0 erations

a.

Ins ection Sco

e 71707

During the week of August 25, 1997, several issues were followed through the

Condition Report (CR) process and the functioning of the CAT'in support of plant

operations.

b.

Observations

and Findin s

The resolution of several issues was inspected.

These issues includqd loose pole

pieces on 4 kV electrical breakers and level indication maintenance

on the standby

liquid control system.

In each case the actions of the CAT team were direct, safety

oriented, and conservative.

However, during one specific observed CAT meeting,

the CAT was not aggressive

in ensuring that internal milestones for CR action item

closure were met, in that it granted completion date extensions with little

dlscusslon.

c.

Conclusions

The resolution of several issues by the PP&L Corrective Action Team (CAT) was

direct, safety oriented, and conservative.

08

Miscellaneous Operations Issues

08,1

Review of Licensee Event Re orts

a 0

Ins ection Sco

e 90712

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

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

the event description, cause,

and corrective action.

The inspectors evaluated

whether further information was required from the licensee, whether generic

implications were involved, and whether the events warranted onsite follow-up.

.7

Observations

and Findin s

The following LERs were reviewed and closed during this inspection period:

Closed

LER 50-387 97-010

On March 25, 1997, with Unit

1 in Condition 1, at 100% power, the. licensee

discovered, during a review of a hydrostatic pressure test procedure for Unit 2, that

during the Unit

1 hydrostatic pressure test performed in October 1996, the reactor

vessel low-level (Level 3) instruments had been isolated without entering the

Limiting Condition for Operation (LCO) for TS 3.3.2.

In addition, it was determined

that the time limits for the TS action statement

had been exceeded.

The root cause of this problem was determined by the licensee to be the use of a

draft TS amendment to prepare procedure revisions.

A list of approximately 380

procedures

requiring revision was generated

from the draft amendment.

The list

was not validated against the final approved amendment.

Exceeding the action

statement time limits of TS 3.3.2 was identified by PPRL as a condition prohibited

by TS and was reported per 10 CFR 50.73(a)(2)(l)(B).

The inspectors verified portions of the licensee's corrective actions which included

the revision of surveillance and test procedures,

the verification of the submitted TS

amendment data and the presentation of training topic reviews of the event to SSES

and corporate engineering personnel.

The inspectors determined that the errors

were related to personnel performance and that the existing PPSL administrative

procedure was adequate,

if implemented.

The associated

equipment for the isolated

instruments could have been manually actuated, if required.

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

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

(NCV 387/97-07-03) This NCV is closed.

Closed

LER 50-387 97-016

On July 3, 1997, with both Unit 1 and Unit 2 in Condition 1, at 100% power,

PPKL determined that the monthly surveillance to inspect fire hose stations had not

been completed within the TS 4.7.6.5.a required frequency.

The licensee further

determined that the frequency for performing this surveillance was exceeded

seven

times since January 1995.

In addition, the licensee determined that an associated

TS surveillance requirement of fire hydrants had exceeded

its frequency on one

occasion since January 1995.

These instances

are violations of TS in that they constitute conditions prohibited by

TS and are reportable per 10 CFR 50.73(a)(2)(i)(B). The licensee determined that

the cause of the events was a flawed scheduling tool used to track surveillances

against

a fixed date rather than the last performance date of the surveillance.

The

inspectors verified portions of the licensee's corrective actions which included

revising the method of tracking and scheduling performed surveillances and training

0

the appropriate plant personnel.

The inspectors further verified for a sample of

components that there was no pattern of surveillance failures of fire hose stations

or fire hydrants.

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

non-cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.

(NCV 50-387,388/97-07-04)

This NCV is closed.

Closed

LER 50-387 97-01

On July 2, 1997, with both Unit

1 and Unit 2 in Condition 1, at 100% power, the

licensee determined that it was not complying with TS Table 3.3.7.10-1, action

101

~ The TS require a gross radioactivity analysis on liquid effluent grab samples

when the associated

effluent monitoring instrumentation

is not operable.

The

licensee was performing a gamma isotopic analysis in such instances,

which does

not measure gross radioactivity to a sensitivity of 1x10'icrocurie/ml.

This is a

violation of TSs and was reportable per 10 CFR 50.73(a)(2)(l)(B). The cause of the

event was determined to be human performance.

In addressing the violation of TSs

the licensee stated

in its LER that "it was not recognized that a change to the TSs

was required since it was viewed that the isotopic analysis was an improved

method of analysis.

There were no safety consequences

or compromises to public

health and safety as a result of this event as the isotopic analysis is a better

analysis in determining radioactivity in effluents."

e

The inspectors verified portions of the licensee's corrective actions specific to this

TS which included, implementing the requirement to perform the gross radioactivity

analysis and proposing a revision to the TS to incorporate the second testing

methodology.

This licensee identified and corrected violation is being treated as a

non-cited violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.

(NCV 50-387/97-07-05) This NCV is closed.

C.

Conclusions

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

appropriately reported, and provided an accurate description of the causes

and

corrective actions.

Based on a sample review of the licensee's corrective actions,

the inspectors determined that PP&L was implementing adequate corrective actions.

08.2

Review of NRC 0 en Items

Ins ection Sco

e 92901

The inspectors reviewed licensee corrective actions submitted to the NRC in

response to notices of violation.

In addition, licensee corrective actions for those

items that required follow-up were reviewed.

b.

Observations

and Findin

s

The following violations (VIOs) were reviewed during this inspection period:

Closed

VIO 50-388 97-03-01: Two examples of an Inadequate

Procedure

Two instances of inadequate safety related procedures

were identified,

One

procedure addressed

the movement of fuel assemblies

and other components within

the spent fuel pool. The second procedure addressed

an alarm response for an

indication of high radiation in the stack monitoring system.

The licensee responded

to this violation in PP&L letter PLA 4644 (Byram/NRC'Document Control Desk,

dated August 6, 1997). The licensee's corrective actions included procedure

changes, training, and the issuance of communications to involved SSES personnel

~

The inspectors verified portions of the licensee's corrective actions and determined

that the licensee's

response

was adequate.

This violation is closed.

U date

VIO 50-388 97-03-02:Core Spray System Surveillance Preconditioning

The licensee responded to this violation in PP&L letter PLA 4644 (Byram/NRC

Document Control Desk, dated August 6, 1997), and denied the validity of the

violation. The NRC responded to the licensee's

response

in NRC letter (Hehl/Byram,

dated August 26, 1997), upheld the violation and requested

additional information

and corrective action,

This violation remains open pending its final resolution.

Closed

VIO 50-388 97-03-03:Four Examples of a Failure to Perform a 10 CFR 50.59 Evaluation

In four instances,

PP&L failed to perform a 10 CFR 50.59 safety evaluation for

changes to plant facilities. The licensee responded to this violation in PP&L letter

PLA 4644 (Byram/NRC Document Control Desk, dated August 6, 1997). The

licensee's response was determined to be adequate

in that for each instance the

licensee addressed

the specific cause of the violation. The root causes identified by

the licensee were related to specific technical interpretations or personnel

performance issues.

Each of the specific corrective actions were reviewed by the

inspectors and determined to be adequate.

However, the licensee's response

and

corrective actions did not address whether previous or present programmatic

weaknesses

exist that may have contributed to the root cause of the violation. The

inspectors reviewed the violation and could not identify a common programmatic

problem or pattern.

Because the specific actions were adequate

and the PP&L

program description appears to be adequate, this violation is closed.

10

II. Maintenance

M1

Conduct of Maintenance

M1.1

Pre

lanned Maintenance Activit Review

a.

Ins ection Sco

e 62707

The inspectors observed/reviewed

selected preplanned maintenance

activities.

b.

Observations

and Findin s

The following WA activities were found to have been well performed.

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 assignea

functions.

The involvement of'the system

engineer in the planned maintenance activity was verified by the inspectors to be

appropriate for the specific instances.

PPRL continued to depend heavily on the

training and experience level of its work force, in addition to system

engineer/foreman

designated

maintenance

acceptance

testing, to ensure the quality

of performed maintenance.

This practice is in deference to providing more detailed

procedures

and increased management oversight.

This approach appeared to be

affective in the specific instances identified below.

WA S44545

High Pressure

Coolant Injection Cable Installation

WA P72390

"A" Residual Heat Removal Heat Exchanger Outage

WA S73559

"B" Recirculation Pump Motor Temperature Switch

WA H70004 "B" Emergency Diesel Generator 24-hour Run

WA S72470

Vent Plug Removal

WA V60717 Instrument Air/Service Air

WA V71705 Instrument Air/Service Air

W'A S73108

Containment Radiation Monitor Pump Replacement

WA S64976

Refueling Water Storage Tank Level Probe

WA H60536

Emergency Diesel Generator Turbocharger Coast down Time

WA P71161

Spent Fuel Pool temperature

WA S73786. Reactor Core Isolation Cooling

WA C73437

4 kV Switchgear

As part of the review of WA P72390, permits 1-97-1155, 1-97-1149, and 1-97-

1158 were also reviewed.

The permits were discussed with the operators and

reviewed against design drawings and control room indications to determine if the

permits adequately protected personnel from injury and safety related equipment

from damage.

These permits were determined to be adequate.

C.

11

Conclusions

The work authorization (WA) activities addressed

during this inspection period were

in general well performed.

The WAs described and controlled maintenance

activities with adequate,

but in some cases general, procedures.

The maintenance

activities were implemented by well trained and experienced

maintenance

technicians,

and resulted in equipment being returned to service in good condition.

M1.2

Pre

lanned Surveillance Activit Review

a.

- Ins ection Sco

e 62707

The inspectors observed/reviewed

selected preplanned surveillance activities to

ensure that the operability, availability and capability of safety related equipmer'.t

was maintained.

A special test of the instrument air system was also observed.

b.

Observations

and Findin s

SSES surveillance activities were found to be well performed.

The activities were

described and controlled in detail by SSES procedures.

The maintenance

and/or

Operations personnel performing the surveillances were well trained, experienced

and capable of explaining and discussing the technical aspects of their assigned

functions.

The involvement of the system engineer in the planned surveillance

activities and their performance briefings ("tailboard") were verified by the

inspectors to be appropriate for the specific instance.

The inspectors

observed/reviewed

the following preplanned surveillance activities.

SM-059-001

SO-1 59-002

TP-1 1 8-01 6

SO-252-002

SO-024-001

SO-1 53-004

18 Month Vacuum Relief Valve Set Pressure Test,

September

17, 1997

Stroke Test of Containment Vacuum Breakers,

September 3, 1997

Test of Instrument Air Cross-tie Valve PCV 12560,

September 3, 1997

HPCI Quarterly Surveillance, September

5, 1997

"A" Diesel Generator Monthly Surveillance, September 9, 1997

Standby Liquid Control Quarterly Surveillance,

September 9, 1997

C.

Conclusions

SSES surveillance activities, observed during this inspection period, were found to

be in general, well performed, described and controlled by detailed SSES

procedures,

and performed by well trained, experienced

and capable

technicians/operators.

~

M1.3

12

Maintenance Technician Task Certification

Ins ection Sco

e 62707

The inspectors reviewed the maintenance

department task certification matrix and

interviewed PPSL personnel that recently evaluated the implementation of the

maintenance task certification process.

b.

Observations

and Findin s

The inspectors reviewed a number of sources to determine if task certification was

being appropriately applied in safety related maintenance

activities.

Included in this

review was a PPSL Nuclear Assessment

Services (NAS) comparison of a large

number of WAs. The NAS comparison evaluated the task certifications of persons

doing the WA activities and found few discrepanciesThese

results agreed with the

findings of NRC Inspection Report 50-387,388/97-80,which found maintenance

department workers to be appropriately trained and task certified.

WA 55339 was reviewed.

This WA addressed

maintenance

performed on a non-

safety related positive displacement radiological waste pump (OP304B).

In addition,

the inspectors interviewed a PPKL representative

who had recently evaluated the

maintenance work performed on the pump.

The inspectors found that a first crew

of workers performed work outside of the tasks identified on the original WA, This

error resulted in the need for repeated work by a second crew, under supplemental

WA instructions, and delayed the return to service of the pump.

The inspectors

reviewed the certifications necessary for the maintenance tasks performed and

found that the personnel met SSES maintenance

program requirements.

Because

the maintenance

errors occurred on non-safety related equipment, and did not result

in a challenge to safety related equipment, no violation of NRC requirements was

identified.

On March 14, 1997, a crane. operator tipped over a 14 ton crane in the SSES yard.

This issue was addressed

in NRC inspection report 50-387,388/97-02.

The cover

letter for the inspection report requested the licensee to discuss the events in

writing. The licensee responded to the cover letter request in PPSL letter PLA 4632

(Jones/NRC document desk, dated June 27, 1997).

PPRL described its corrective

actions for the event in its response.

NRC Inspection Report 50-387,388/97-02,

section M2.1 stated that "a number of weaknesses

were identified by the licensee

and the inspectors including operator training and supervisory oversight" and that

the "event was similar to an inspector identified issue with the placement of a self-

propelled crane on a railroad rail near an excavation in 1996". The report concluded

that no violations of NRC requirements were identified.

The inspectors reviewed the licensee's corrective actions, associated

CRs, the PP5L

response to the NRC request for information, a PPRL audit of the event, an ERT

report which addressed

root causes for the event and PPSL Nuclear department

programmatic improvements in response to the event.

In addition to the prior

weaknesses

in the training of the crane operator and his supervision, this review

13

identified weaknesses

in the Nuclear department training and qualification process

for crane operators, which the licensee

is addressing.

No violations of NRC

requirements were identified; no programmatic links were identified (regarding task

certification of workers) between the weaknesses

associated with WA 55339 and

the March 14, 1997, crane event; and the licensee's

initial corrective actions for the

identified weaknesses

in both cases were adequate.

Some long term corrective

actions have yet to be completed.

No violations of NRC requirements were

identified in either case.

c.

Conclusions

The inspectors concluded that the maintenance task certification matrix and its

implementation were adequate to control the assignment of workers to safety

related maintenance activities.

No violation of NRC requirements were identified.

M2

Maintenance and IVlaterial Condition of Facilities and Equipment

M2,1

Tri

of the "C" Emer enc

Diesel Generator

EDG

Durin

Surveillance Testin

a.

Ins ection Sco

e 62707

The trip of the "C" EDG following the performance of a TS surveillance was

inspected/reviewed

during the course of normal surveillance observation.

b.

Observations

and Findin s

The inspectors observed portions of the surveillance and determined that the

operating portions of the surveillance were well controlled and implemented.

The

testing scheme was well briefed with the participating technicians, closely followed

and implemented by control room operators and adequately covered by PPS,L

procedures.

On August 18, 1997, following the completion of a 24-hour EDG run and load

rejection test, the EDG was allowed to run unloaded for 5 minutes and then the

stop

push-button was depressed

in accordance with procedure SO-024-001,

Monthly Diesel Surveillance.

Within forty five seconds of depressing the stop push-

button, the EDG tripped on indicated high jacket water temperature.

Other

indications of jacket water temperature showed that it was within normal operating

limits. When the EDG stop push-button

is pushed,

a 5 minute cool down of the

EDG is expected but, this did not occur.

The licensee initiated CR 97-2682 and WA S72651 to account for the failed

indication of jacket water temperature.

The CR contained

an operability

determination (OD) which stated that the temperature circuit and protective

functions are bypassed

in the emergency operation mode.

The OD also stated that

=the cause of the EDG trip was known, and that it had previously occurred as

documented

in CR.96-0184.

14

The inspectors determined that the corrective actions associated

with the two CRs,

and the interrupted cool down of the "C" EDG were adequate.

The licensee

determined that the interrupted cool down did not affect the operability of the EDG.

Conclusions

The licensee's corrective actions in response to an interrupted cool down of the "C"

EDG were adequate

and the interrupted cool down did not affect the operability of

the EDG.

Unit

1 "S" Safet

Relief Valve

SRV Acoustic Position Indicator Acoustic Monitor

Failure

Ins ection Sco

e 72707

On September

10, 1997, with Unit

1 in Condition 1, at 100% power, a control

room an'nunciator alarmed indicating that a Division 2 SRV had opened.

Operators

evaluated other plant parameters

and confirmed that the "S" SRV had not opened

although its acoustic monitor status lights were illuminated.

The inspectors

reviewed the licensee's actions in response to the acoustic monitor failure.

Observations

and Findin s

An investigation and surveillance were performed by instrumentation and control

technicians to evaluate the acoustic monitor failure.

In parallel with the

investigation, the licensee began preparations for requesting enforcement discretion

from the TSs that require an operable SRV acoustic monitor for the "S" SRV. After

reaching the conclusion that the acoustic monitor failure was inside containment,

PP&L requested

enforcement discretion, by letter dated September

11, 1997 (PLA-

4669).

PPRL requested

enforcement discretion to allow continued operation of the

Unit with the acoustic monitor inoperable, until an outage of sufficient duration

would allow drywell access,

but no later than the Unit

1 tenth refueling outage.

A conference call was held between the NRC and PPRL on the afternoon on

September

12, 1997. After discussion of the technical issues, prior equipment

failures, and alternate means of detecting an open SRV, enforcement discretion was

granted by Mr. John Stolz, Director, Project Directorate 1-2, Office of Nuclear

Reactor Regulation,

A supplemental letter (PLA 4670) documenting commitments

by PPSL during the conference

call was issued to the NRC later the same day.

The

NRC issued the written Notice of Enforcement Discretion (NOED) by letter dated

September

17, 1997.

PPSL submitted an emergency amendment request to the

NRC on September

15, 1997, to have the TSs changed to reflect the enforcement

discretion.

The TS amendment was issued by the NRC on September 23, 1997.

This issue will be evaluated for closure in conjunction with the routine NRC review

of Licensee Event Report 50-387/97-020-00,Operation

Prohibited By Technical

Specification - Loss of MSRV Acoustic Monitor.

15

c ~

Conclusions

PP&L requested enforcement discretion for TS requirements concerning

a failed

acoustic position indicator for the "S" Safety Relief Valve.

PPS.L requested the

discretion to avoid an undesirable transient as a result of forcing compliance with a

license condition.

The NRC approved PPSL's request after determining the action

involved minimal or no safety impact and had no adverse radiological impact on

public health and safety.

M3

IVlaintenance Procedures

and Documentation

M3.1

Release of Unit

1 Standb

Li uid Control

SBLC Accumulator Work

Ins ection Sco

e 62707

On September 9, 1997, the inspector observed work on the "A" SBLC accumulator

when no TS limiting condition for operation had been entered.

The inspectors

reviewed the control of work and PPS.L's basis for determining that the accumulator

work would not affect the operability of the "A" SBLC pump.

b:

Observations

and Findin

s

The "B" SBLC pump was taken out of service for planned maintenance at 5:00 a.m.

on September 9, 1997.

The "B" SBLC pump motor's power supply was de-

terminated and consequently, the Unit Supervisor documented entry into TS 3.1.5

Action a.1. With one SBLC pump inoperable, Action a.1 requires the licensee to

restore the inoperable pump within 7 days or be in at least Hot Shutdown withing

the next 12-hours.

TS 3.1.5 Action a.2. requires that with the SBLC system

otherwise inoperable, the system must be restored within 8-hours or the unit must

be in the Hot Shutdown condition within the next 12-hours.

On the morning of September 9, 1997, the inspectors found that maintenance

personnel had depressurized

the "A" SBLC accumulator to repair the accumulator's

charging valve under WA H70595 while work on the "B" SBLC pump was still in

progress.

The maintenance

personnel were performing actions to ensure the "A"

SBLC pump's accumulator was charged according to MT-053-003, SBLC

Accumulator Maintenance.

This activity is routinely completed prior to the SBLC

quarterly surveillance as directed by step 5.7 of SO-153-004, Quarterly SBLC Flow

Verification, Revision 21. The inspectors noted that SO-153-004did not contain

precautions regarding performance of this step relative to operability impact.

The

maintenance activity is performed in support of SO-153-004under

a blanket WA

which is used to track workers time. After further review, the inspectors found that

neither maintenance

procedure MT-053-003, Revision 5, nor the WA contained

precautions or notes regarding the impact on SBLC operability.

The inspectors discussed the release of this work with the responsible Unit

Supervisor (US). The US's activities and the maintenance

personnel's actions were

supported by their respective procedures.

According to the US, his decision to

16

allow work on the '='A" SBLC accumulator was influenced, in part, by the fact that

this activity had been done the same way for a very long time and was not

previously considered to have an operability impact.

The inspectors discussed, with the cognizant NSE system engineer, the potential

impact of having no accumulator.

Two possible effects were discussed,

the

potential to liftthe pump's discharge line relief valve, diverting injection flow and

the potential to invalidate assumptions

in the SBLC piping analysis.

Based on review of the procedural controls for the accumulator work and

discussions with cognizant NSE personnel, the inspectors concluded that PPSL did

not have

a pre-existing analysis to support depressurizing

an accumulator and still

consider the associated

SBLC pump operable.

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.

PPKL failed to provide an adequate-

procedure for, the control of the accumulator maintenance,

since the impact of the

activity was not clearly understood.

This failure is considered

a violation of TS 6.8.1.

(VIO 50-387/97-07-06)

The inspectors discussed the potential TS compliance issue with a NAS

representative

who was observing the work as part of a surveillance for "Potential

Preconditioning of Equipment Prior to Testing".

The NAS surveillance was

performed as an initiative in response to recent SSES and industry events (reference

VIO 50-387/97-03-02).

The NAS representative

took appropriate actions to follow-

up the TS compliance issue and initiated CR 97-2958.

The NAS representative

also

initiated CR 97-2973 to document his observation. that charging the SBLC

accumulators,

as a prerequisite to the surveillance test, may precondition the

system.

After the issue was brought to Operations by NAS, an initial operability

determination was prepared by the Shift Technical Advisor (STA) who discussed the

issue with the system engineer.

The operability determination states:

The accumulators were originally designed to provide over-

pressurization protection along with several other design

improvements.

The existing system configuration has a relief

valve at the discharge of each pump which would provide this

protection.

~ . There is industry experience that also suggests

that the accumulators may not be needed

and based on the

system configuration have been subsequently

eliminated.

The inspectors considered the initial operability determination technically incorrect in

its description of the accumulator function and weak in that it did not address the

known technical issues with the potential to affect operability.

The fact that other

plants have removed accumulators did not establish the operability of the system at

SSES without plant specific analysis.

However, the inspectors considered the

0'

17

safety impact of this event low since the accumulator was restored to its original

configuration in less than one hour (before the STA's operability determination).

fven if PPSL's CR investigation and root cause determine TS 3.5.1 Action a.2.

should have been entered, the actual duration of the "A" SBLC pump work was

significantly less time than allowed by the TS.

The routine charging of SBLC accumulators before required surveillance testing, and

the training provided to STAs on operability determinations, will both be addressed

during the closeout of the violation.

C.

Conclusions

PPSL allowed maintenance work to proceed on the "A" Standby Liquid Control

(SBLC) pump nitrogen accumulator without evaluating whether the activity would

affect operability. After the question of operability impact was raised by the NRC,

an initial operability determination by the Shift Technical Advisor was weak because

it did not address known technical issues with the potential to affect operability.

The failure to provide adequate

procedures for control of maintenance

on safety

related equipment is a violation of TSs.

M7

Quality Assurance

in Maintenance

M7.1

Unit

1 RHR Pum

"A" Recirculation Check Valve Ins ection

~

~

a.

Ins ection Sco

e 62707

On August 19, 1997, the inspectors observed

a portion of the preventive

maintenance activity used to meet inservice test program (IST) requirements for the

residual heat removal (RHR) check valve 151-F046A. This activity was performed

as part of an on-line maintenance work window for RHR Division I equipment under

WA P71715.

b.

Observations

and Findin s

The RHR minimum flow check valve is a 4" bonnet hung check valve mounted in a

vertical pipe.

In 1994, a similar 3" check valve failed to prevent reverse flow in the

core spray system.

During the 1994 occurrence, the dimensional tolerances of the

core spray check valve allowed less than full coverage of the valve seat by the disk.

The result was minor reverse flow through the valve. At SSES, sixteen bonnet

hung check valves are used in core spray and RHR systems.

On August 19, the inspectors questioned how the corrective actions from the 1994

problem had been incorporated into preventive maintenance WA P71715.

The

maintenance

foreman stated that the Valve Team requested

certain measurements

and that they had provided a drawing to illustrate the tolerances of interest.

18

The inspectors determined that the informal tolerance checks, uncontrolled

document and acceptance

criteria being used to assess

the condition of the check

valve were corrective actions for a previous condition adverse to quality. This

concern was discussed with the maintenance

foreman and a NAS - Surveillance

Services representative.

On August 25, 1997, the Valve Team supervisor initiated CR 97-2775 to document

that a corrective action for CR 96-1902 was not appropriately closed.

This 1996

CR documented that a Unit 2 "A" Core Spray (CS) minimum flow check valve

inspection found another example of the 1994 tolerance problem.

Although CR 96-

1902 required all core spray and RHR minimum flow check valves be inspected, the

administrative process to track this action was not initiated.

On August 26, 1997, a NAS - Surveillance Services representative

initiated

CR 97-2786.

This CR documents that the corrective actions for a 1994 Significant

Operating Occurrence Report and a 1994 Non-Coriformance Report did not address

the inspection of similar check valves.

CR 97-2786 also identifies the corrective

action tracking problem discussed

in CR 97-2775, but adds the perspective that

preventive maintenance WA's performed since 1994 have informally checked the

subject tolerances.

The inspectors concluded that PPRL failed to take adequate

corrective actions in

1994 and in 1996 for the check valve tolerance deficiencies.

The inspectors

considered the safety significance of minor CS or RHR minimum flow, check valve

back-leakage

under design basis conditions to be minimal ~ However, this problem

could result in damage of safety related equipment during routine surveillance

testing.

The previous corrective action problems are in the licensee's corrective

action process,

are being evaluated,

and had no impact on the safe operation of the

plant.

This failure constitutes

a violation of minor significance and is being treated

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

(NCV 50-387,388/97-07-07)

Conclusions

Corrective actions for a safety related check valve deficiency identified in 1994 did

not address the generic issue.

In 1996 the same condition was identified on a

different valve and, in this case, the planned actions to prevent recurrence were

appropriate.

However, the administrative process to implement and track these

actions was not initiated. These two corrective action problems are considered

a

violation of minor significance because there was no impact on safety.

Condition Re ort CR Su

ort for Maintenance Activities

Ins ection Sco

e 62707

Inspection activities were conducted to determine if the CR process was being

made use of in the course of Maintenance department activities, including the

willingness of Maintenance department personnel to make use of the CR process.

,19

b.

Observations

and Findin s

The inspectors reviewed a PPSL compilation of CRs that resulted from Maintenance

department workers.

The sources of the.CRs spanned

a representative

cross

section of the Maintenance department and the technical issues were varied.

A

PPSL survey that represented

interviews with a large number of SSES maintenance

workers was reviewed by the inspectors.

The conclusions from the survey were

that maintenance workers were aware of the CR process

and were willingto use

the process to correct problems.

During the course of normal inspection activities

the inspectors discussed

the CR process with SSES maintenance workers.

The

results of the NRC conversations with the SSES maintenance workers were similar

to those conclusions in the PPRL survey.

Although some maintenance

personnel

expressed

reservations

regarding the effectiveness of the CR process, the workers

interviewed were willing to submit CRs when necessary.

No violations of NRC

requirements were identified.

C.

Conclusions

A PPRL compilation of Maintenance-department

generated

condition reports (CR)

was reviewed.

The CRs were generated

by a representative

cross section of the

Maintenance department and the technical issues were varied.

The conclusions of a

PPRL survey were found to be consistent with NRC interviews in that maintenance

workers were found to be aware of the CR process

and were willingto use the

process to correct problems,

E2

Engineering Support of Facilities and Equipment

E2.1

Reactor Core Isolation Coolin

RCIC Drain Pot Level Switch

Ins ection Sco

e 37551

P

The condition of the Unit 1 RCIC drain pot level switch was reviewed/inspected

to

evaluate the licensee's control over the current degradation of the RCIC steam line

drain piping and to ensure that the degradations

did not result in another plant

transient (see

IR 50-387, 388/96-11).

b.

Observations

and Findin

s

The control, trending and tracking of the RCIC drain line pipe degradation was

partially implemented under WA S79877. The licensee's

engineering diagnostic

actions were determined to exceed those actions recommended

by EPRI and to be

comprehensive.

The 1996 RCIC system piping degradation was evaluated to be the

result of flow impingement and general erosion.

From the standpoint of the erosion

control program, engineering corrective action was determined to be outstanding.

,20

From a second perspective, the drain pot was bypassed

and allowed the drain line

to degrade,

and a continuous alarmed condition existed in the control room for a

period of approximately ten months following the unscheduled

plant shutdown that

resulted from the RCIC drain line failure (see IR 387,388/96-11).

A modification

that replaced the drain pot level switch with a different type switch was completed

during this inspection period under Design Change Package

(DCP) 97-9060.

This

modification appeared

to be effective in preventing

a high level condition in the

RCIC drain pot and removed the alarmed condition in the control room.

The

corrective actions to resolve the RCIC steam line drain pot problems were not

aggressive;

resulted in a system important to safety being operated outside of its

normal alignment for greater than two years; did not prevent an unscheduled

plant

shutdown; and displayed an alarmed condition in the control room for an extended

period of time.

Conclusions

The erosion control program portion of engineering corrective actions for an

indicated high level in a reactor core isolation cooling drain pot was determined to

be outstanding.

The engineering corrective actions for problems with the Unit

1

RCIC drain pot level switch were not timely. This allowed continuous degradation

of the drain line and a continuous alarmed condition for over ten months after it

caused

a forced shutdown.

A modification to replace the drain pot level switch was

completed and has been effective in restoring the normal operation of the RCIC

system.

E4

Engineering Staff Knowledge and Performance

E4.1

Control Structure Chiller Automatic Start Ca abilit

a e

Ins ection Sco

e 37551

On July 15, 1997, the inspectors reviewed open temporary modifications for Unit 1

controlled under the Bypass Program described

in NDAP-QA-484. Bypass 0-97-005

for the "B" Control Structure (CS) chiller was selected for additional review based

on its apparent safety significance and questions regarding the ability of the standby

"A" CS chiller to start automatically.

Observations

and Findin s

The CS chillers provide the safety related cooling supply to electrical equipment in

the CS and the 4 kV emergency switchgear for Unit 1. Section 9.2.12 of the SSES

FSAR states that a start of the standby control structure chilled water train will be

automatic on failure of the operating train.

FSAR Table 9.2-15 shows

a failure

modes and effects analysis for the CS chilled water system.

For the assumed

failure of a chiller, the chilled water loop circulating pump trips and the standby

chiller train starts automatically.

21

Bypass 0-97-005 states that removal of an existing jumper on the safety indication

panel (SIP) for the "8" CS chiller will ensure that a trip of the "B" chiller remains

sealed in. This design will assure that the "A" CS chiller, when in "standby," will

automatically start.

The Bypass states that this configuration meets the design

intent of the chiller logic.

During a review of open Bypasses

on July 15, 1997, the inspectors questioned

whether the plant had been operated outside its design basis in the past when the

"B" CS chiller was in service.

This issue was subsequently discussed with Nuclear

Licensing and Nuclear System Engineering personnel.

The problem with the "B" CS chiller was first identified on February 27, 1997.

Although PP&L captured the wiring error in CR 97-0434 and corrected the condition

as of March 1, 1997, PP&L failed to recognize that the plant had previously been

operated outside the design basis.

After discussions with the inspector, the

licensee issued CR 97-2641 on August 13, 1997, to document this discovery.

In

the reportability evaluation for CR 97-2641 PP&L determined this condition was

reportable under 10 CFR 50.73.

LER 50-387/97-019-00was

submitted to the NRC on September

11, 1997. The

LER states that the "A" CS chiller would not have automatically started as designed

if the "B" CS chiller tripped on low oil pressure,

but would have started on any

other trip of the "8" CS chiller. This condition was determined to have existed

since initial startup of the. plant and was the result of a change

in the chiller logic

during pre-operational testing.

The inspectors determined that this condition should

have been reported by PP&L in March 1997.

PP&L concluded that the root cause

for the late NRC notification was a less than adequate reportability determination by

the Operating Experience Services organization.

As corrective action, PP&L

completed reportability training for the OES organization.

This training willcontinue

as refresher training and as part of the initial training for new OES personnel.

The inspectors reviewed the training outline and class attendance

roster for PP&L

course nomber AD064, Reportability Determination, the training referenced

in the

LER. The training outline referenced

NRC reportability guidance in NUREG 1022 and

described practical examples that require students to evaluate scenarios using the

applicable SSES procedure and the NRC guidance.

The inspectors considered the

training outline to be thorough.

Based on the training roster, the inspectors

concluded that the OES personnel involved in the LER issue, members of PP&L's

licensing staff, and other members of the OES staff had attended the training.

10 CFR 50.73(a)(2)(ii)(B) requires licensees to report any condition that was outside

the design basis of the plant.

In this case,

PP&L initiallyfailed to recognize the

previous condition as outside the design basis.

However, the technical problem

was limited to a very specific problem with a single chiller and was promptly

corrected by the licensee upon identification. After the problem with the

reportability evaluation was identified, PP&L appropriately submitted an LER

discussing the technical issue and the inadequate reportability determination.

PP&L

developed and implemented corrective actions to address their root cause findings.

22

The instructor guide and attendance

records for the reportability evaluation training

were reviewed and verified by the inspector.

The failure to report oper'ation in a

condition that was outside the plant's design basis within 30 days of discovery is a

violation of 10 CFR 50.73.

However, this failure constitutes

a violation of minor

significance and is being treated as a non-cited violation, consistent with Section IV

of the NRC Enforcement Policy. (NCV 50-387/97-07-08)

C.

Conclusions

PP5L identified that the "A" CS chiller would not automatically start as designed

in

February 1997 and took immediate actions to correct the problem.

However, PPRL

initially failed to recognize this condition as outside the plant's design basis, as

described

in the Final Safety Analysis Report.

After identification by the NRC, PPSL

initiated a Condition Report, determined the condition was reportable, and submitted

a Licensee Event Report as required.

Corrective actions for both the technical

problem and the failure to recognize the condition outside the design basis were

implemented by PP&L.

In this case, the failure to report a condition outside the

design basis within 30 days of discovery is characterized

as a non-cited violation.

E4.2

Hi h Pressure

Coolant In'ection

HPCI 0 erabilit

Determination

a 0

Ins ection Sco

e 37551

On August 6, 1997, operators observed

an unusual sequence

of HPCI stop and

~ control valve movement during a weekly auxiliary oil pump preventive maintenance

(PM) activity. The inspectors reviewed the licensee's operability determination for

the apparent degradation of the HPCI system.

b.

Observations

and Findin s

The HPCI lube oil system has two pumps, a shaft driven pump that provides oil

when the turbine speed is greater than 1500 rpm, and a motor driven auxiliary oil

pump for when the turbine speed is less than 1500 rpm. When HPCI receives an

initiation signal, the auxiliary oil pump starts to provide the motive force for opening

of the HPCI stop and control valves.

PPRL performs a weekly PM activity that

starts the auxiliary oil pump causing the HPCI stop and'control valves to cycle as

they would for an automatic start.

On August 6, 1997, operators observed

an unusual sequence

of HPCI stop and

control valve movement during a weekly auxiliary oil pump PM activity. The

operators'bservation

was documented

in CR 97-2568 and an operability

determination was prepared by NSE. The NSE investigation of the event determined

that the HPCI turbine's overspeed trip assembly had unexpectedly actuated

following the auxiliary oil pump start.

This trip interrupted the opening cycle of the

turbine stop and control valves, causing them to close.

Approximately five seconds

after the trip, the overspeed

assembly automatically reset (as designed)

and the

valves began their open sequence

a second time.

23

The original operability determination for CR 97-2568 reasoned that computer

traces showed the HPCI valves would respond to an initiation but that it would take

HPCI approximately five seconds

longer to inject than normally expected.

PPS,L

considered

HPCI operable because

the system would still meet its 30-second

injection time design basis, even with this delay.

The HPCI injection valve receives an open signal from a limit switch on the turbine

stop valve.

The injection valve's control logic has a seal-in feature to ensure the

valve completes its intended open or close stroke before changing direction.

On

August 7, 1997, the inspectors questioned how the HPCI injection valve response

time would be affected by the interruption of the normal HPCI turbine valve

sequence.

PPKL's review, in response to the inspector's questions, identified the potential for

the HPCI injection valve to begin closing after completing its open travel in response

to a system initiation. Although it is designed to reopen, the delivery of full HPCI

injection flow could take up to 36 seconds.

Based on this discovery, PP5L declared

HPCI inoperable on August 7, 1997, and reported the loss of the single train safety

system to the NRC as required by 10 CFR 50.72.

CR 97-2596 was initiated to

document this discovery.

On August 15, 1997, NSE"revised the HPCI operability determination and concluded

that the system could perform its intended safety function with the subject

degradation.

PPSL's evaluation developed two approaches

to support their

conclusion that HPCI had been degraded but remained operable.

In the first

approach,

PPS.L used historical stroke time data to show that the overspeed trip and

reset would not cause the injection valve to close.

However, the margin credited in

this evaluation was 0.25 seconds.

Since this margin was not significant, PPS.L

developed

a second approach assumed the injection valve does go closed, but

credits the injection valve's ability to pass full HPCI flow before reaching the full

open position.

The inspectors reviewed the licensee's completed CR evaluation, HPCI start time

lines, and the engineering calculation for flow capability of the injection valve.

No

problems were identified with PPRL's reevaluation of HPCI operability. The

inspectors considered the second approach, which took credit for the flow

capability of the injection valve at less than full open, a stronger basis for

operability.

The inspector's review of this issue did not identify any violations of

NRC requirements.

Corrective maintenance

activities, with significant NSE and consultant involvement,

were effective in resolving the unexpected

overspeed trips on the start of the

auxiliary oil system.

Following completion of the maintenance

on August 15, 1997,

no unexpected trips of the overspeed tappet occurred and the licensee is continuing

to monitor the system performance closely.

,24

C.

Conclusions

The initial operability determination for the Unit 2 high pressure coolant injection

(HPCI) overspeed trip assembly problem was weak.

Nuclear System Engineering

personnel overlooked the potential impact on the HPCI injection valve and how this

impact could affect the response

time to rated flow. PPRL management

made a

conservative decision to declare

HPCI inoperable, pending further evaluation.

A

subsequent

revision of the operability determination provided a good basis for

operability.

Significant licensee attention was focused on resolution of the problem

and the overspeed trip assembly has performed acceptably since the corrective

maintenance.

ES

Miscellaneous Engineering Issues

E8.1

Unit 2 Reactor Buildin Truck Ba

Hatch

a.

Ins ection Sco

e 71707 37551

The inspectors observed that a large floor hatch on elevation 749 of the Unit'2

reactor building was open and appeared to have been that way for many years.

This hatch separates

elevation 749 from the reactor building truck bay.

The

inspectors questioned the impact of the open door on the plant's design basis.

Observations

and Findin s

The NSE personnel reviewed the requirements for closure of plant hatches

in

response to the inspector's question.

Calculation EC-012-2419 lists 26 hatches

that are required to be closed and secured

based on the assumptions

used in the

design basis tornado analysis.

10 CFR 50, Appendix A, Criterion 2, requires

structures important to safety be designed to withstand the effects of natural

phenomena

such as tornadoes without loss of capability to perform their safety

functions.

To investigate this issue further NSE personnel performed a plant walk down to

verify the correct position and appropriate "tie-downs" for all 26 hatches listed in

the tornado analysis.

On June 11, 1997, PPSL initiated CR 97-1950 to document

that the Unit 2 truck bay hatch on elevation 749 of the reactor building was open

and that hatch "H2" located in the "C" EDG bay did not have "tie-downs" installed.

Immediate actions for this CR included the closure of the truck bay hatch and

installation of "tie-downs" on hatch "H2."

PPSL's actions to prevent recurrence for CR 97-1950 include a revision to

procedure NDAP-QA-0409, Door, Floor Plug and Hatch Control, to identify hatches

that must be closed and secured to meet the tornado analysis assumptions.

Also,

an analysis is being done to support opening of these hatches during all plant

operating conditions.

PP&L considers completion of this analysis necessary

before

opening the hatches listed in the tornado analysis and NDAP-QA-0409 provides an

administrative control to ensure this is done.

The analysis is targeted for

completion in January 1998.

25

The inspectors questioned whether PP&L's ongoing review of the current licensing

basis, as described

in a letter to the NRC dated February 13, 1997, would have

identified that the hatch position did not match the assumptions

in the tornado

analysis.

On October 17, 1997, the inspectors met with SSES and PP&L

engineering personnel to determine if the PP&L current licensing basis process

would have identified this issue.

Based on the information provided at this meeting,

the inspectors determined that licensee's

program to review their licensing and

design basis and update the UFSAR would not have identified this issue.

Therefore,

the enforcement discretion per Section VII.B.3 of the NRC enforcement policy could

not be applied.

PP&L's resolution plan for CR 97-1950 includes a re-analysis of the tornado design

basis scheduled for completion in January 1998.

Based on these results, PP&L will

decide whether an unreviewed safety question (USQ) existed.

The open Unit 2 truck bay hatch was not previously addressed

by an engineering

analysis.

No safety evaluation was performed in accordance with 10 CFR 50.59 to

determine if a USQ would result from the changing the, hatch configuration

previously assumed

in the tornado analysis.

The failure to perform the safety

evaluation required by 10 CFR 50.59 is considered

an apparent violation. PP&L's re-

analysis of the torna'do design basis and evaluation of the potential USQ will be

reviewed, in part, to determine the safety significance of this apparent violation.

This item is open, pending PP&L's reanalysis and is being tracked as an unresolved

item.

(URI 50-387,388/97-07-09)

c.

Conclusions

PP&L failed to perform a 10 CFR 50.59 safety evaluation prior to opening a plant

equipment'hatch

assumed to be closed by the tornado design basis analysis.

This

condition existed for an extended period before identification by the NRC. Plant

equipment hatches

have been verified to be in the condition assumed

by the

tornado analysis (shut) and are now being administratively controlled.

PP&L's

evaluation to determine whether an unreviewed safety question existed with the

hatch open is expected in January 1998 and will be reviewed to determine the

safety significance of this violation.

In the interim, this item is being tracked as an

unresolved item.

E8.2

Station Blackout Desi

n Basis

a.

Ins ection Sco

e 37551

A review of the SSES responses

to 10 CFR 50.63, Station Blackout (SBO) rule was

conducted to determine if SSES met the established

design requirements for SBO

coping duration and auxiliary power sources.

26

b.

Observations

and Findin s

The licensee installed an auxiliary diesel power source to increase the SSES SBO

coping duration of its 125 Vdc batteries from approximately 5-hours to in excess of

8-hours.

In order to ensure this coping duration extension, it is necessary to ensure

that the auxiliary diesel power source is maintained in an available condition.

The

licensee currently tests the auxiliary diesel power source once a year. for a short

duration.

However, the licensee does not perform the vendor recommended

equipment preventive maintenance/surveillance

schedule,

and does not maintain the

equipment within the quality requirements of 10 CFR 50 Appendix B.

The

inspectors reviewed portions of the following referenc'es to determine if the licensee

was required to meet an SBO coping requirement of greater than 4-hours.

PPSL References

1.

2.

3.

4.

5.

6.

7.

PPSL letter,

PPSL letter,

PPSL letter,

PP5L letter,

PPS.L letter,

PP&L letter,

PPS.L letter,

Keiser/NRC public document room,

Keiser/NRC public document room,

Keiser/NRC public document room,

Keiser/NRC public document room,

Keiser/NRC public document room,

Keiser/NRC public document room,

Keiser/NRC public document room,

NRC References

dated

dated

dated

dated

dated

dated

dated

April 17, 1989

April 17, 1990

February 27, 1991

August 1, 1991

March 13, 1992

April 14, 1992

May 13, 1992

1.. Safety Evaluation, dated January 14, 1992

2.

Supplemental Safety Evaluation, dated June 16, 1992

NRC reference

2 determined that it was only necessary

for the licensee to meet a 4-

hour coping duration.

This requirement can be met with the currently available 125

Vdc batteries.

Therefore, the inspectors determined that there was no current

regulatory requirement for the licensee to maintain the auxiliary power source.

C.

Conclusion

A review of the SSES responses

to 10 CFR 50.63, Station Blackout (SBO) rule was

conducted to determine if SSES met the established

design requirements.

The

licensee installed an auxiliary diesel power source to increase the SSES SBO coping

duration of its 125 Vdc batteries from approximately 5-hours to in excess of 8-

hours.

The NRC safety evaluation report concluded that SSES must meet a 4-hour

coping condition. Therefore, the inspectors concluded that there was no current

regulatory

requirement for the licensee to maintain the auxiliary power source.

E83

a.

27

Floatin

Service Platform on Safet

Related S ra

Pond

Ins ection Sco

e 37551

The inspectors observed that a large floating service platform was being stored on

safety related spray pond that is the ultimate heat sink for both SSES units.

The

spray pond services the emergency service water (ESW) and residual heat removal

service water (RHRSW) systems.

The inspectors questioned the impact of the

floating service platform on the performance of safety related equipment associated

with the spray pond.

b.

Observations

and Findin s

The NSE and licensing personnel were interviewed to determine if design

documentation existed for the platform, which was used as a special tool during

spray nozzle maintenance.

The licensee was not able to identify design

documehtation for the design, fabrication, or installation of the floating platform.

In

addition, the licensee was not able to identify documentation to show that a safety

evaluation was performed prior to the placement of the floating platform on the

spray pond.

No safety evaluation was performed in accordance with 10 CFR 50.59

to determine if a USQ would result from placing a floating platform on the spray

pond.

Subsequent

to the inspectors'uestions,

the licensee removed the platform

from the spray pond.

The failure to perform the safety evaluation, as required by

10 CFR 50.59, is a violation. (VIO 50-387,388/97-07-10)

On October 17, 1997, the inspectors met with SSES and PPSL engineering

personnel to determine if the PPRL current licensing basis process would have

identified this issue.

Based on the information provided at this meeting, the

inspectors determined that the licensee's

program to review their licensing and

design basis and update the UFSAR would not have identified this issue.

Therefore,

the enforcement discretion per Section VII.B.3 of the NRC enforcement policy could

not be applied and this item is being cited.

Analysis of the spray pond design basis

and evaluation of the potential USQ will be, reviewed with the response to this

violation.

C.

Conclusions

PP5L failed to perform a 10 CFR 50.59 safety evaluation prior to placing a floating

service platform on the spray pond that serves as the ultimate heat sink for both

SSES units. This condition existed for an extended period before identification by

the NRC. The spray pond was verified to be in the condition assumed

by the Final

Safety Analysis (the platform was removed).

PPSL has yet to perform an

evaluation to determine whether an unreviewed safety question existed with the

platform on the spray pond.

Analysis of the spray pond design basis and evaluation

of the potential USQ will be reviewed with the response to this violation.

28

IV. Plant Su

ort

F2

Status of Fire Protection Program

F2.1

Control Room CO, Fire Protection S stem

a.

Ins ection Sco

e 83750

The licensee's programmatic response to a potential fire in the control room was

reviewed.

b.

Observations

and Findin s

The SSES control room fire suppression

system was determined to be a manually

initiated system which actuates

on a delayed basis.

It uses CO, gas injected

beneath the control room electrical cabinets and the control room floor. This

system will not actuate automatically.

On a CO, system initiation, whether the

initiation is valid or not, the licensee has two off normal (ON) procedures

in place to

affect an evacuation of the control room and respond to a fire in the control room:

ON-013-001, Response to Fire and ON-100-009, Control Room Evacuation.

The immediate actions required by these procedures

are to declare there is a fire

and/or habitability problem in the control room, initiate a manual scram, evacuate

the control room, and then initiate a safe shutdown of the units from the remote

shutdown panel.

There is no SSES expectation that operators will remain in the

control room after a control room evacuation is determined to be necessary.

Therefore, self contained breathing apparatus

(SCBAs) are identified by SSES plant

procedures for use only by the fire brigade and are not required or intended for

operator use in the control room, as an alternative to abandoning the control room.

C.

Conclusions

The licensee's programmatic response to a potential fire in the control room was

reviewed and determined to rely on off normal procedures which require the manual

initiation of a CO, fire protection system and the immediate evacuation of the

control room. The controls established

by the licensee to ensure that control room

operators do not require the use of self contained breathing apparatus

(SCBA),

during a fire and/or habitability problem in the control room. These controls were

determined to be adequate.

R7

Radiological protection and Chemistry (RPC) Controls

R7.1

Health Ph sics Friskin

Problems and Corrective Actions

a.

Ins ection Sco

e 83750)

NRC Inspection Reports 50-387,388/96-04and

97-02 discussed

problems with

health physics (HP) frisking practices using hand held contamination monitors, and

,

29

the licensee's

response

to those frisking issues.

The latter inspection found that

appropriate frisking techniques were used during NRC observations,

and that

assistant

HP foreman were providing close oversight of contract HP technicians.

This inspection reviewed associated

HP performance as identified in PP&L condition

reports (CRs) to determine whether any continuing problems were evident in this

area.

b.

Observations

and Findin s

The inspectors reviewed a PP&L compilation of approximately 104 HP department

CRs and discussed the CRs with representatives

of the HP organization, the

Independent Safety Evaluation Services, and Nuclear Assessment

Services.

During

these discussions,

the inspectors questioned the licensee's review and disposition

of the CRs.

In specific, only three CRs from the Unit 2 eighth refueling outage

identified problems with either "frisking" or "contractors".

No trend was found by

the inspectors or PP&L among the three CRs, since each of the CRs dealt with

different technical aspects,

and each of the CRs appeared to have adequate

corrective:action implemented.

The inspectors verified that the licensee implemented corrective actions from a CR

(96-0106) that dealt with improvements to monitoring equipment, postings and

changes to policies that govern removal of potentially contaminated materials from

the Radiological Controlled Area.

The inspectors reviewed the licensee's evaluation of the compilation of HP CRs

discussed

above,

a PP&L audit of HP issues,

and an ISES review of the above

mentioned CRs and HP issues.

No programmatic trends were identified regarding

frisking practices with hand held monitors; and the licensee's initial corrective

actions for the specific identified weaknesses

in the three CRs inspected were

adequate,

C.

Conclusions

An evaluation of condition reports (CRs), from the Unit 2 eighth refueling outage,

concluded that there was no continuing trends regarding inadequate frisking

practices with hand held monitors.

The licensee's initial corrective actions for the

identified weaknesses

in the three CRs inspected were adequate.

X1

Exit Meeting Summary

The inspectors presented

the inspection results to members of licensee management

at the conclusion of the inspection on October 20, 1997. The licensee

acknowledged the findings presented.

0

P

,30

~Oened

ITEMS OPENED, CLOSED, AND DISCUSSED

50-387, 388/97-07-01

50-387, 388/97-07-02

50-387/97-07-06

50-387,388/97-07-09

50-387,388/97-07-1 0

Closed

IFI

Equipment Failure Root Cause Evaluations

VIO

Inadequate

Implementation of Operator Rounds

VIO

Inadequate

Procedures for SBLC Maintenance

URI

Re-analysis of the Tornado Design Basis

VIO

Floating Platform on the Spray Pond 50.59

50-387/97-01 0

50-387,388/97;07-03

50-387/97-01 6

50-387,388/97-07-04

50-387/97-01

50-387/97-07-05

50-387,388/97-07-07

LER

Control of Reactor Vessel Water Level Switches

NCV

Control of Reactor Vessel Water Level Switches

LER

Missed Surveillances for Fire Protection Equipment

NCV

Missed Surveillances for Fire Protection Equipment

LER

Gross Analysis on Liquid Effluent Grab Samples

NCV

Gross Analysis on Liquid Effluent Grab Samples

NCV

Inadequate

Corrective Actions for Check Valve

Problems

50-387/97-07-08

50-388/97-03-01

50-388/97-03-03

NCV

CS chiller was Outside the Plant's Design Basis

VIO

Two Examples of an Inadequate

Procedure

VIO

Four Examples, Failure to Perform 50.59 Evaluation

~Udated

50-388/97-03-02

VIO

Core Spray System Surveillance Preconditioning

31

LIST OF ACRONYMS USED

AR

CFR

CIG

CL

CR

CREOASS

DG

EDG

ERT

FSAR

IERP

IRC

LCO

LER

NCR

NCV

NPO

NRC

NRR

OES

OP

PCO

QA

RHR

RHRSW

SGTS

SOOR

SPING

SSES

TBVS

TS

UFSAR

USQ

WA

Alarm Response

Code of Federal Regulations

Containment Instrument Gas

Check Lists

Condition Report

Control Room Emergency Outside Air Supply System

Diesel Generator

Emergency Diesel Generator

Event Review Team

Final Safety Analysis Report

Industry Event Review Program

Instrumentation and Controls

Limiting Conditions for Operation

Licensee Event Report

Nonconformance Report

Non-Cited Violation

Nuclear Plant Operator

Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Operating Experience Services

Operating Procedure

Plant Control Operator

Quality Assurance

Residual Heat Removal

Residual Heat Removal Service Water

Standby Gas Treatment System

Significant Operations Occurrence

Report

System Particulate Iodine Noble Gas

Susquehanna

Steam Electric Station

Turbine Building Ventilation Stack

Technical Specification

Updated Final Safety Analysis Report

Unreviewed Safety Question

Work Authorization