ML17157C355

Insp Repts 50-387/93-07 & 50-388/93-07 on 930330-0510. Violations Noted.Major Areas Inspected:Plant Operations, Radiation Protection,Surveillance & Maint & Safety Assessment/Quality Verification

ML17157C355
Person / Time
Site:	Susquehanna
Issue date:	05/26/1993
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17157C353	List: ML17157C352 ML17157C354 ML17157C355
References
50-387-93-07, 50-387-93-7, 50-388-93-07, 50-388-93-7, NUDOCS 9306080058
Download: ML17157C355 (35)

See also: IR 05000387/1993007

Text

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UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

Inspection

Report Nos.

50-387/93-07; 50-388/93-07

License Nos.

NPF-14; NPF-22

Licensee:

Pennsylvania Power and Light Company

2 North Ninth Street

Allentown, Pennsylvania

18101

Facility Name:

Inspection At:

Susquehanna

Steam Electric Station

Salem Township, Pennsylvania

Inspection

Conducted:

March 30, 1993 - May 10, 1993

Inspectors:

G. S. Barber, Senior Resident Inspector,

SSES

D. J. Mannai, Resident Inspector, SSES

R. K. Mathew, Reactor Engineer, D

S

B. J. M'Dermott,

ct

En in

r RP

Approved By:

J. Wh', Chief

R

or Projects Section No. 2A,

Date

Ins

tion Summa:

This inspection report documents routineand reactiveinspections

(during day and backshift hours) of station activities, including: plant operations; radiation

protection; surveillance and maintenance;

and safety assessment/quality

verification.

Findings and conclusions are summarized in the Executive Summary.

One violation was

identified pertaining to improper HPCI system valve lineup.

Section 2.2.1 pertains.

One

non-cited violation was identified concerning Reactor Protection System {RPS) overvoltage

setpoints.

Section 7.2.1 pertains.

Details are provided in the full inspection report.

9306080058

930527

PDR

ADOCK 05000387

Q

PDR

EXECUTIVE SUMMARY

Susquehanna

Inspection Reports

50-387/93-07; 50-388/93-07

March 30, 1993

- May 10, 1993

Operations (30702, 71707, 71710)

During the period, the inspector performed an engineered

safety feature (ESF) walkdown of

the Unit 1 High Pressure

Coolant Injection (HPCI) system.

The inspector determined the

system was capable of performing its intended safety function. However, the inspector found

the system lineup improper.

The inspector discovered

a containment boundary valve that

was closed, but not locked, as required.

The inspector also identified that the HPCI steam

admission valve was leaking by the seat.

Section 2.2.1 pertains.

The inspector identified oil levels slightly below the standstill level on several (10 of 16)

pump motor bearings on emergency service water and residual heat removal service water

pumps.

Electrical maintenance

concluded the oil levels were acceptable.

However, the

inspector identified a non-licensed operator training weakness during a review of the matter.

Section 2.2.2 pertains.

Maintenance/Surveillance

(61726, 62703)

The licensee generally exercised good control of maintenance

and surveillance activities.

The inspector identified minor procedural adherence

weaknesses

and a lack of complete

worker knowledge regarding safe use of a material during observation of a maintenance

activity. Section 4.4.2 pertains.

Bailey 740 millivoltconverters are used as class 1E isolators.

These converters can be

procured specifically for their isolation capability or for general applications.

To use a

general application converter for an isolation function, certain internal jumpers had to be

preset.

The inspector reviewed the isolation applications for both types of converters and

found them acceptable.

Section 4.4.1 pertains.

Engineering/Technical Support (71707, 92720, 93702)

The inspector discovered that the original overvoltage setpoint for the Unit 1 "B" Reactor

Protection System (RPS) power supply was questionably established.

The Main Steam

Isolation Valve (MSIV) AC solenoids were originally limited to a maximum of 125 vac.

The

current setpoint of 129.5 vac would have allowed voltage above the maximum design at the

MSIV AC solenoids.

A 1988 letter from the vendor revised the MSIV AC solenoid

maximum design voltage to 132 vac.

However, the licensee was not justified in operating

. 'Pe

with the current setpoint from 1982 to 1988.

This was a non-cited violation. The inspector

also noted that the licensee does not have a mechanism

to ensure that vendor initiated

changes to design information are included in plant information systems.

The licensee has

agreed to review the need, for a design input checklist or some other mechanism to ensure

that changes or clarifications to plant design information are adequately captured in plant

information systems.

Section 7.2.1 pertains.

Safety Assessment/Assurance

of Quality (40500, 90712, 92700, 92701)

The inspector reviewed two Licensee Event Reports during the period.

Section 8.1 pertains.

The Susquehanna

river exceeded flood stage during March and April. The licensee's actions

relative to preparing for, monitoring of, and responding to, river flooding was good, though

some minor procedural weaknesses

were observed.

The licensee agreed to revise the

procedure to correct the noted weaknesses.

Section 8.3 pertains.

Temporary Instruction TI-2515/112 required inspector review of licensee programs that

evaluate changes in population distribution and site proximity hazards.

In the course of this

review, the licensee initiated their own review and submitted an FSAR update. PAL did

not identify any significant changes.

The licensee did not have a formal program in place

prior to the TI issuance.

Currently, a formal program is being implemented to periodically

review and evaluate changes to the site environ.

The inspector concluded the licensee-

initiative was a strength.

Section 8.4 pertains.

TABLEOF CONTENTS

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EXECUTIVE SUMMARY ..

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SUMMARYOF OPERATIONS.......

1.1

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

1.2

Susquehanna

Unit 1 Summary....

1.3

Susquehanna

Unit 2 Summary....

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OPERATIONS

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2.1

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

2.2

Inspection Findings and Review of Events

2.2.1

Unit 1 High Pressure

Coolant Injection System ESF Walkdown

2.2.2

Safety Related Pump Motor Bearing Oil Levels

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3.

RADIOLOGICALCONTROLS

3.1

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

.3.2

Inspection Findings

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MAINTENANCE/SURVEILLANCE

4.1

Maintenance and Surveillance Inspection Activity.........

4.2

Maintenance Observations ................;...'...

4.3

Surveillance Observations

4.4

Inspection Findings

4.4.1

Class 1E Isolation Capability of the Bailey 740 Millivolt

Converter.......... ~..................

4.4.2

Thermo-Lag Repair Unit 1 Remote Shutdown Panel...

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EMERGENCY PREPAREDNESS

5.1

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

5.2

Inspection Findings

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SECURITY

6.1

Inspection Activity........

6.2

Inspection Findings

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Table of Contents (Continued)

7.

ENGINEERING/TECHNICALSUPPORT

7.1

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

7..2

Inspection Findings

7.2.1

Reactor Protection System Overvoltage Setpoint ...........

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8.

SAFETY ASSESSMENT/QUALITYVERIFICATION.............

8.1

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

8 ~2

Open Items ......

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8.2.1

(Closed) Unresolved Item 50-387/89-21-02, RCIC and HPCI

Rupture Disc NCRs on Post Work Testing Inadequate

8.2.2

(CLOSED) Unresolved Item 50-387-90-21-01, Firewatch

Rounds Not Completed As Required

8.2.3

(Closed) Violation 50-387/91-06-01, Inservice Test Program

0mlsslon

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8.3

Susquehanna

River Flooding

8.4

(Closed) Temporary Instruction (TI) 2515/112 - Licensee Evaluations

of Changes to the Environs Around Licensed Reactor Facilities

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9.1

Resident Exit and Periodic Meetings.........

9.2

Inspections Conducted By Region Based Inspectors

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1.

SU5&IARYOF OPERATIONS

1.1

Inspection Activities

Details

The purpose of this inspection was to assess

licensee activities at Susquehanna

Steam Electric

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

Within each

inspection area, the inspectors documented

the specific purpose of the area under review, the

scope of inspection activities and findings, and appropriate conclusions.

This assessment

is

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

independent calculation, and selective review of applicable documents.

'bbreviations are used throughout the text.

Attachment

1 provides a listing of these

abbreviations.

1.2

• Susquehanna

Unit 1 Summary

Unit 1 began the inspection period at 100% power.

One unplanned power reduction

occurred during the period,

Five planned power reductions were scheduled

on weekends for

balance of plant repairs.

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On March 31, the normal level control valve for the "4C" feedwater heater failed

closed, causing high level in the "4C" feedwater heater.

Extraction steam

automatically isolated.

Operators reduced power to 80% in accordance with ON-147-

001; Loss of Feedwater Heating Extraction Steam, and isolated the "C" feedwater

heater string per the requirements of OP-144-001,

Condensate

and Feedwater System.

Power was returned to 100% on April 1 following repairs to the feedwater heater

drain valve.

On April2, power was reduced to 98% to test and adjust feedwater level control.

Similar testing was previously performed at 60%, 70%, and 80% power on March

26-29.

Power was returned to 100% on April 3 at 4:30 a.m.

On April 3 at 6:50 a.m., power was reduced to 60% for additional feedwater heater

valve repairs.

Power was returned to 100% on April 4 following the valve repairs.

On April 8, power was reduced to 80% and the "B" feedwater heater string was

isolated to plug tube leaks in the "3B" feedwater heater.

Power was returned to

100% on April 11.

On April23, power was reduced to 60% to rework the auxiliary steam supply to the

steam jet air ejector (SJAE) pressure control valve actuator.

The licensee identified

- that the pressure control valve actuator required rework and auxiliary boiler steam

leak repairs were necessary

while preparing to repair a SJAE main steam supply valve

leak.

Power was returned to 100% on April 25.

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On April 30, power was reduced to 60% to repair the SJAE main steam supply valve,

Power was returned to 100% on May 1.

Operators conducted several other routine power reductions during the period to facilitate

surveillance testing.

No reactor scrams or ESF actuations occurred during the inspection

period.

Unit 1 finished the inspection period at 100% power.

1.3

Susquehanna

Unit 2 Summary

Unit 2 began the inspection period at 100% power.

On April 18, the "C" reactor feed pump

turbine tripped due to test circuit limit switch problem during emergency governor and trip

lockout testing.

A reactor recirculation runback was received, reducing power to 65%.

Following additional testing of the "C" reactor feed pump turbine, power was returned to

100% on April 19.

On April 22, during an investigation of "4C" feedwater normal level control valve, the "4C"

feedwater heater level rose which resulted in an automatic isolation of extraction steam.

Operators reduced power to 80% in accordance with ON-247-001, Loss of Feedwater

Heating Extraction Steam, and isolated the "C" feedwater string per the requirements of OP-

244-001, Condensate

and Feedwater System.

Power was returned to 100% on April 23

following repair of the feedwater heater level control valve.

Operators conducted several other routine power reductions to facilitate surveillance testing.

No reactor scrams or ESF actuations occurred during the inspection period.

Unit 2 finished

the inspection period at 100%.

2.

OPERATIONS

2.1

Inspection Activities

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

regulatory requirements.

Pennsylvania Power and Light (PP&L) Company management

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

discussions with personnel,

independent verification of safety system status and Limiting

Conditions for Operation, and review of facility records.

These inspection activities were

conducted in accordance with NRC inspection procedure 71707.

The inspectors performed 12.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of deep backshift inspections during the period.

These

deep backshift inspections covered licensee activities during between

10:00 p.m. and 6:00

a.m. on weekdays,

and weekends

and holidays.

2.2

Inspection Findings and Review of Events

2.2.1

Unit 1 High Pressure

Coolant Injection System ESF Walkdown

During the period, the inspector performed an Engineered Safety Feature Walkdown of the

Unit 1 High Pressure

Coolant Injection (HPCI) system to independently verify the status of

the system.

The inspector utilized the Risk-Based Inspection Guide for the Susquehanna

HPCI system during the walkdown.

The inspector performed the following during the ESF walkdown:

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Reviewed in-service test (IST) data

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Performed walkdown checklist contained in NUREG/CR-5392 Risk Based Inspection

Guide for the Susquehanna

Station HPCI System

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Verified key components

on mechanical and electrical checklists (CL) to

independently verify system lineup

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Reviewed work authorization system printout to identify existing deficiencies in the

system

Verified housekeeping

conditions

Verified combustible materials controls

Reviewed system instrumentation to determine ifthe process parameters

were

adequate

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Compared as-built configuration to as-built drawings

The inspector identified the following significant deficiencies during the walkdown:

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Valve 155F092 HPCI turbine exhaust vacuum breaker test valve found not locked as

required by the system checklist;

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Valve HV-155F001 HPCI turbine steam supply valve, leaking by the seat;

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Valve 155F036 HPCI steam trap outlet isolation valve, packing leak;

The inspector identified the following minor deficiencies:

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Oil leaking from MOV actuators for HV155F012 HPCI.minimum flow valve to

suppression

pool and HV155F066 HPCI turbine exhaust to suppression

pool;

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Several motor control center (MCC) covers mounting screws not properly fastened in

place - elevation 683'eactor Building;

1Y226 208/120 volt instrument distribution panel covers not secured - elevation

683'eactor

Building;

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Mirror insulation dented on HPCI discharge piping around valve HV152F007, HPCI

pump discharge valve elevation 670',

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Insulation missing from 3 1/2'ection of HPCI discharge piping elevation 670',

Valve HV155F079 HPCI turbine exhaust inboard vacuum breaker valve MOV manual

handwheel

has missing dust cap;

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Half of the lighting burned out in the HPCI pipe routing area (area 28 elevation

670');

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Loose handwheel found lying on deck grating in HPCI pipe routing area;

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Mirror insulation clips unclipped and misaligned on HV155F066 HPCI turbine

exhaust valve to suppression

pool;

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Webbed sling and "C" clamp in overhead

area of HPCI pipe routing area;

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OPI-PSHIN012A HPCI turbine exhaust rupture disk pressure switch isolation

valve

not properly lockwired;

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Cap downstream of HPCI lube oil sample valve 156020 is leaking oil;

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Several lights burned out in the HPCI pump room elevation 645'.

The following valves had insufficient packing gland stud thread engagement:

HV-155-F001, HPCI turbine steam supply;

1RV LSH 1N018, HPCI turbine exhaust line drain pot level switch root valve;

2RV LSH 1N018, HPCI turbine exhaust line drain pot level switch root valve;

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RV PT1N06/PI1R005 HPCI exhaust pressure instrument root valve;

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DRN LSH1N014 HPCI steam valve drain line level switch drain valve;

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155F001 HPCI steam line drain pot inboard drain valve.

The inspector notified the licensee that valve 155FO92 was not locked immediately following

discovery.

Operations promptly locked the valve.

The licensee documented

the problem in

Significant Operating Occurrence Report (SOOR)93-130.

Operations Department initiated

the HPCI system checklists for both units and formed a Status Control Occurrence Review

Team.

Nuclear System Engineering (NSE) initiated a Work Authorization to document the HPCI

steam admission valve seat leak.

The licensee is evaluating valve repair for the June 1993

quarterly work window.

NSE will closely monitor for any increase in the seat leak rate.

Additionally, lube oil samples were obtained to check for the presence of water resulting

from the leak.

Sampling confirmed minor water contamination, however, the system

engineer determined

the system was operable.

NSE initiated a WA to perform a feed and

bleed on the HPCI lube oil sump to reduce the moisture contamination.

NSE directed that

lube oil sampling frequency be increased

from quarterly to weekly until the valve is repaired.

NSE initiated Engineering Work Request (EWR) M30323 to evaluate the packing gland

thread engagement

issue for the valves identified.

Maintenance is also evaluating the need to

proceduralize the thread engagement

requirements.

Currently, the licensee's procedures only

address packing gland torque and do not specify minimum thread engagement for valve

packing gland studs.

The inspector found the system capable of performing its intended safety function. The

inspector verified risk significant components included on the system walkdown checklist to

be in the proper position.

However, the system was not properly aligned in accordance with

the system checklistCL-152-0012, Unit 1 HPCI System-Mechanical.

The HPCI turbine

exhaust vacuum breaker test valve (155FO92) is required to be closed, capped, containment

tagged and locked.

Additionally, the CL requires independent verification of the position of

this valve.

The inspector discovered the valve to be closed, but unlocked while performing

independent verification of the HPCI system lineup.

The valve is a containment boundary

valve and is required to be closed, capped, containment tagged and locked.

The valve has

primary containment atmosphere

on the containment penetration side of the valve.

The last

documented

system CL was performed was May 9, 1992 during an outage,

The licensee

could not positively determine the cause of the valve being unlocked.

The Status Control

Review Team could not locate any documentation that revealed subsequent

authorized

operation of the valve since the checklist was last completed.

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The inspector considered

the NSE response,

once identified, to the steam admission valve

seat leak a strength.

However, the condition went undetected for some period of time; Both

units have a history of the HPCI steam admission valve exhibiting seat leakage.

NSE had

the responsibility of monitoring these valves for leakage.

The system engineer, recently

assigned to the system, was aware of the need to monitor for leakage.

However, since no

specific formal monitoring frequency was established,

the problem went undetected.

The

system was last operated

on March 18, 1993 for HPCI quarterly flow verification and no

evidence of seat leakage existed.

NSE has committed to monitor the HPCI steam admission

valve for leakage on both units on a weekly basis.

The other minor deficiencies, although not significant, indicate the need for greater attention

to detail to the material condition of the system.

PPEcL took or planned corrective action for

the inspector identified deficiencies at the conclusion of the inspection period.

Licensee

housekeeping

and combustible material controls for the affected areas

was adequate,

System

labeling was excellent.

The inspector concluded there was no actual safety impact caused by the HPCI vacuum

breaker test valve not being locked.

However, the containment boundary valve not being in

the condition required by the CL was a weakness.

This is a violation of Technical Specification 6.8.1 which requires appropriate administrative controls for locked valves.

(VIO 50-387/93-07-01).

2.2.2

Safety Related Pump Motor Bearing Oil Levels

During a routine tour, the inspector identified that oil level was below the standstill level on

10 of 16 safety related pump motor bearings in the Engineered

Safeguards

Service Water

(ESSW) pumphouse.

The ESSW pumphouse contains four Emergency Service Water (ESW)

pumps and four Residual Heat Removal Service Water (RHRSW) pumps.

Each pump motor

has an upper and lower bearing.

The inspector had to climb to an elevated position to

clearly determine the upper bearing oil levels.

From the fioor, the inspector noted the levels

appeared

to be satisfactory.

The inspector questioned

the Auxiliary System Operator (ASO) on how he checked oil levels.

The ASO responded

he checked oil levels visually during rounds from the floor. He

considered

a level above the minimum level acceptable.

The particular individual did not

realize that there was a standstill level indication and that his check was ensure the oil level

was above the minimum level.

The individual stated this type of level marking was not

specifically covered in his non-licensed operator training.

The oil levels are not specifically

recorded on the logs but are expected to be checked during rounds.

For the bearings in

question, a sight glass exists with an operating range with minimum and maximum level and

the standstill level markings.

The standstill level mark indicates the proper oil level with the

pump secured.

This ensures proper oil level with the motor running.

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The inspector reviewed OP-PM-002, Good Lubrication Practices.

Section 4.1.1 of the

procedure requires oil levels be checked while the pump is running unless there is a static

mark (standstill level) ~

Furthermore the procedure

states ifno mark exists,

1/3 level oil

level should be maintained.

Electrical maintenance indicated the intent of the standstill level

is a reference level to ensure level remains above min and below max during pump

operation.

Electrical maintenance

stated an acceptable standstill level as a level 'close to the

standstill level.

The standstill level is a single line with no tolerance.

The inspector

concluded there was no safety significance of the condition since the oil levels were

acceptable.

However, the inspector considered

the knowledge deficiency a weakness.

In

response,

the licensee will upgrade non-licensed operator training to assure proper

performance of all level checks.

The inspector had no further questions,

3.

RADIOLOGICALCONTROLS

3.1

Inspection Activities

PP&L's compliance with the radiological protection program was verified on a periodic

basis.

These inspection activities were conducted in accordance

with NRC inspection

procedure 71707.

3.2

Inspection Findings

Observations of radiological controls during maintenance activities and plant tours indicated

that workers generally obeyed postings and Radiation Work Permit requirements.

4.

MAINTENANCE/SURVEILLANCE

4.1

Maintenance and Surveillance Inspection Activity

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

maintenance activities to ensure that specific programmatic elements described below were

being met.

Details of this review are documented in the following sections.

4.2

Maintenance Observations

- The inspector observed and/or reviewed selected

maintenanc'e activities to determine that the

work was conducted in accordance with approved procedures,

regulatory guides, Technical

Specifications, and industry codes or standards.

The following items were considered,

as

applicable, during this review:

Limiting Conditions for Operation were met while

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

obtained prior to initiating the work; activities were accomplished

using approved procedures

and quality control hold points were established

where required; functional testing was

performed prior to declaring the involved component(s) operable; activities were

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

controls were implemented; and the equipment was verified to be properly returned to

service.

These observations and/or reviews included:

WA 21481, Replace MDR Relay 42X-527022 for RHRSW Pump "1B" Supply Fan

1V506B, dated April 8.

WA 30114, Repair Thermo-Lag in Unit 1 Remote Shutdown Panel in accordance with

NCR 93-005 disposition, dated April 13.

WA 15336, C Emergency Service Water Pump Disassembly for Five Year Inspection,

dated April 15.

WA 30350, Replace HFA relay B21H-K51 in panel 1C622 for MSIV B/D isolation

logic, dated April 23.

4.3

Surveillance Observations

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

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

the test conformed to

Technical Specification requirements;

administrative approvals and tagouts were obtained

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

accordance with an approved procedure;

test instrumentation was calibrated; Limiting

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

restoration of the affected components was properly accomplished;

test results met Technical

Specification and procedural requirements;

deficiencies noted were reviewed and

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

These observations and/or reviews included:

SI-280-308,

18 Month Calibration of RWCU/MSIV System Isolation Reactor Water

Levels

1 and 2, dated April 6.

SI-180-203, Monthly Functional Test of Reactor Water Level LIS-B2-IN031A, B, C,

D, dated April 9.

SI-180-206, Monthly Functional Test of RWCU/MSIV Isolation Reactor Water Levels

1 and 2.

4.4

Inspection Findings

The inspector reviewed the listed maintenance

and surveillance activities.

The review noted

that work was properly released before its commencement,

systems and components were

properly tested before being returned to service, and that surveillance and maintenance

activities were conducted properly by qualified personnel.

Where questionable issues arose,

the inspector verified that the licensee took the appropriate action before system/component

'perability was declared.

Except as noted below, the inspectors had no further questions on

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the listed activities.

4.4.1

Class 1E Isolation Capability of the Bailey 740 MllivoltConverter

The inspector reviewed the class 1E isolator design of the Bailey type 740 millivolt

converter, specifically, relative to its use in isolating, class 1E analog inputs from computer

and annunciator systems.

This review was to determine the following: 1) whether the

licensee was bypassing the isolation capability of the converter through internal wire jumper

changes

and, 2) the possibility of inadequate documentation of changes

to the module

schematics

which, over time, could have resulted in the bypass of isolation features of

replacement converters.

The Bailey type 740 millivolt(mv) converter is designed to convert a millivoltor resistance

input signal to a 1-5 Vdc or 4-20 milliamperes output signal.

These converters provide

signal and power isolations between class 1E systems and the balance of plant (BOP) inputs.

There are two types of Bailey 740 millivoltconverters used at Susquehanna.

Types 7401 and

7403 are used with thermocouples

and resistance

temperature detectors,

respectively.

The inspector determined that twenty seven 740 mv converters were installed as isolators in

each unit. Of these, 25 were used for isolating non-1E computer/annunciator

inputs from

class 1E inputs and the remaining two were used for class 1E division isolations.

The

inspector noted that this converter had been previously tested and found to be acceptable for

use as an isolation device.

The inspector reviewed General Electric (GE) elementary diagrams, PP&L instrumentation

diagrams and vendor instruction manuals for several instrument loops which used Bailey 740

mv converters.

The inspector noted that the correct information was transferred from the GE

drawings as evidenced by the proper signal, power pin arrangements,

and wiring

configurations on the loop drawings.

The vendor instruction manual in the licensee's

document control system was appropriate for the applications at Susquehanna.

The inspector

also reviewed procurement documents and randomly inspected the Bailey 740 mv converters

in the warehouse

and found that they were properly identified and purchased

in accordance

with design requirements.

Thus, the inspector determined that the information provided in

the design documents

appeared

suitable for,the Bailey 740 mv converter applications.

10

Several (I&C) technicians were interviewed to determine their knowledge of the Bailey 740

mv converters installation and calibration.

Calibration'nformation was described in

procedure IC-DC-100, Revision 8, and vendor instruction manual 4574 K10-100.

The I&C

technicians were found to be adequately trained in the maintenance

and calibration of Bailey

740 mv converters and were familiar with its installation and operation.

The inspector also

visually verified a sample of converters installed in the diesel generator circuits.

Based on

this external inspection, the converters were found to be appropriate for their application.

Since both units were o'perating at power, the inspector was not able to verify the as-built

internal wiring of these converters.

To compensate for this, the licensee committed to verify

the wiring of a representative

sample of the mv converters during the-next periodic

calibration to assure that their isolation capability agrees with the design requirements.

If

any discrepancies

are identified the NRC Region

1 inspectors willbe informed.

The inspector questioned

the licensee regarding the possible installation of converters with

the incorrect jumper configuration.

This configuration could disable isolation features

without any accompanying external indication.

The inspector noted this as a credible

problem since certain Bailey multifunction 740 mv converters could be procured for general

applications and could be modified by the licensee to meet the class 1E isolation criteria.

In

response,

the licensee stated that all converters are tested and calibrated after any jumper

changes are made.

These changes would be noticed as anomalies during the calibration

process.

The licensee also stated that the mv converters were originally procured to meet

class lE isolation design and needed no further wiring or internal jumper changes during

initial installation.

In addition, periodic calibrations do not require any jumper changes or

wiring changes.

Any incorrect jumper or wiring changes

that c'ould bypass the converters

isolation function would be detected during the calibration as evidenced by incorrect

input/output response.

The manufacturer (Bailey), agreed with this assertion.

Work

documents were searched

to determine ifany=of the originally installed converters could have

been replaced with possible jumper or wiring changes present.

No converters have been

replaced.

Quality Control was found to be effectively monitoring calibration activities.

Based on the above, the inspector concluded that the licensee was currently providing

adequate jumper control for Bailey 740 mv converters and found no evidence of inadvertent

or improper bypassing of their isolation features.

One minor weakness

was noted in data

recording.

The inspector noted that the licensee was not documenting the calibration details

as shown in the vendor instruction manual in their calibration data sheets.

In response,

the

licensee agreed to review the calibration procedure (IC-DC-100) to determine whether there

is a need for additional instructions to avoid any possible errors.

4.4.2

Thermo-Lag Repair Unit 1 Remote Shutdown Panel

During the inspection period, the inspector observed portions of the Thermo-Lag repair in

'he

Unit 1 remote shutdown panel in accordance with NCR 93-005 disposition.

11

The inspector noted the following weaknesses:

. ~

Personnel did not cover floor/equipment as required by the work plan.

~

Yellow copy of signed ERF was not in work package

as required by NDAP-QA-306.

~

Personnel did not fully understand

respiratory safety precautions regarding use of the

trowel grade Thermo-Lag 330-1.

Additionally, the job planner did not include actual

safety precautions in the work package.

The work plan referenced

safety precautions

contained in other documents.

However, they were not available at thejob site.

The actual work was done in an acceptable manner consistent with the work plan.

However,

the above weaknesses

indicate inattention to detail regarding adherence

to specific work

procedure requirements

and a lack of thorough and complete knowledge regarding safe use of

the trowel grade Thermo-Lag 330-1.

The inspector discussed

the situation with both the

work group foreman and SSES Safety group.

The licensee agreed to include the material

safety data sheet (MSDS) in the work package where appropriate.

The MSDS provides

information concerning safe use of products used at the site.

The licensee plans to place a

Hazard Communications Center in a centrally located area of the plant.

The MSDS willbe

available to plant personnel at this more readily accessible

location.

The inspector

considered this a positive initiative.

~

~

~

5.

EMERGENCY PREPAREDNESS

5.1

Inspection Activity

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

could have required entry into the emergency plan.

5.2

Inspection Findings

No events were identified that required emergency plan entry.

6.

SECURITY

6.1

Inspection Activity

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

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

These inspection activities were conducted in accordance with NRC inspection procedure

71707.

12

6.2

Inspection Findings

The inspector reviewed access

and egress controls throughout the period.

No significant

observations were made.

7.

ENGINEERING/TECHNICALSUPPORT

7.1

Inspection Activity

The inspector periodically reviewed engineering and technical support activities during this

inspection period.

The on-site Nuclear Systems Engineering (NSE) organization, along with

Nuclear Technology in Allentown, provided engineering resolution for problems during the

inspection period.

NSE generally addressed

the short term resolution of engineering

problems; and interfaced with the Nuclear Modifications organization to schedule

modifications and design changes,

as appropriate,

to provide long term corrective action.

The inspector verified that problem resolutions were thorough and directed at preventing

recurrence.

In addition, the inspector reviewed short term actions to ensure that they

provided reasonable

assurance

that safe operation could be maintained.

7.2

Inspection Findings

7.2.1

Reactor Protection System Overvoltage Setpoint

During an ongoing review of reactor protection system (RPS) performance,

the. inspector

discovered

a potential concern with original establishment of the overvoltage setpoint for the

Unit 1 "B" RPS power supply.

Specifically, based on a March 1, 1993 letter on Design

Change Package (DCP) 92-3023, the Main Steam Isolation Valve (MSIV) solenoids are

designed to operate between

105 vac and 125 vac.

Other safety-related components powered

by the RPS busses

are designed to operate between

108 vac and 132 vac.

The current

overvoltage setpoint (129.5 vac) could potentially allow voltages above design to exist at the

MSIV solenoids.

This could result in excessive internal heating and shorten their qualified

life. The finding also implies a weakness in the licensee's

1982 efforts to determine and

document the associated

overvoltage setpoints.

The inspector questioned

the licensee on the establishment of RPS voltage setpoints provided

in Technical Specification (TS) 3.8.4.3.

These setpoints were determined prior to initial

licensing for each unit. Work Authorization (WA) U21180 (completed March 11, 1982)

measured

actual voltage drops along the power cable that supplied RPS components.

These

voltage drops were then added to the minimum and maximum design voltages for each RPS

component.

The most limiting voltage at any given component was then used to establish the

over and under voltage setpoints.

This WA showed that the most limiting voltage for the

MSIV AC solenoids was 126.1 vac, as compared to the current TS setpoint of 129.5 vac.

Thus, the current overvoltage setpoint could potentially allow voltage above design (125 vac)

at the MSIV solenoid valves.

I

13

The licensee provided a June 28, 1988 letter from the solenoid supplier that lists the

maximum acceptable voltage as 132 vac, and indicates that the current setpoint is acceptable.

However, this did not justify operation from 1982 to 1988 with the current setpoint.

The

licensee suggested

that General Electric (GE) verbally approved the operation of MSIV AC

solenoids up to 132 vac during initial construction.

WA U21180 showed that the MSIV AC

solenoids for the "A" RPS were inaccessible

and GE startup approved the omission.

In

addition, WA U21180 Step 5.b. excluded the MSIV AC solenoids from the overvoltage

setpoint determination.

This provided some limited justification for the licensee's position.

The inspector reviewed the licensee's justifications and noted that records loosely support

their assertion.

However, the licensee apparently operated for six years without appropriate

documentation for their RPS overvoltage setpoints.

Since the June 28, 1988 letter clarifies

the MSIV AC solenoid voltage requirements,

this concern is more administrative than

technical in nature.

Thus, although this apparent noncompliance was identified by the

inspector, it will not be cited because

the criteria in Section VII.B. of the enforcement policy

were satisfied.

The inspector also noted that the licensee did not have a predefined program to address

vendor initiated changes

to design information.

The June 28, 1988 letter changed

the

operating voltages to 108 vac to 132 vac. However, this information was not added to the

Susquehanna

Equipment Inventory System (SEIS) nor the equipment qualification (EQ)

database,

The lack of updates in these and other systems apparently led to the inclusion of

the old voltage band (105 vac-125 vac) in the March 1, 1993 DCP description.

Other

communications (SILs, TILs, RICSILs, etc.) are received that change or update design

information.

Although licensee programs review these communications,

there is no

requirement to update SEIS, the EQ database or other plant information systems (PMIS).

The licensee has agreed to review the need for a design input checklist or some other

mechanism to ensure that changes or clarifications to plant design information are adequately

captured in plant information systems.

8.

SAFETY ASSESSMENT/QUALITY VERIFICATION

8.1

Licensee Event Reports

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

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

adequacy of corrective action.

The inspector determined whether further information was

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

event warranted onsite followup. The following LERs were reviewed:

93-001-00

14

ESF Actuation Due to Electrical Transient When Radwaste Electrical

Transformer Failed

On February

1, 1993 invalid ESF actuations occurred on both units as a result of load center

transformer OX340 failure.

The inboard and outboard containment isolation valves for Loop

"B" of the Containment Gas Analyzer System isolated in both units.

Additionally, the

containment instrument gas back-up storage bottle header isolation valves opened.

The

licensee determined the cause of failure was water dripping onto the transformer core and

coils." The source of water was identified as condensation

forming on the internal surface of

HVAC ductwork and subsequent

leakage from the duct low point. PAL determined warm

moist air in the duct combined with the ambient room temperature below the dewpoint

resulted in the formation of condensation.

Licensee corrective actions consist of planning

installation of a moisture barrier below the ductwork and a review of the electrical system to

assess

capability of minimizing effects of faults in non-1E components on safety related

components.

The licensee was not able to determine the root cause of the high humidity in the process air

at the time of LER submittal.

The licensee is conducting a long-term investigation.

The

inspector agreed with the licensee's reportability determination.

The inspector determined

the licensee's

short-term actions to prevent recurrence were acceptable.

The licensee is

reviewing the onsite AC power system design for enhancements

to reduce the susceptibility

'f

non-class

1E faults from affecting safety-related

class 1E systems.

This event was

documented in NRC Inspection Report 50-387/93-01.

93-002-00

Instrument Repair Leak Required Entry into LCO 3.0.3,

On January 22, the licensee entered Technical Specification (TS) Limiting Condition for

Operation (LCO) 3.0.3 at 12:55 p.m. following repair of a small leak'n the valve manifold

for reactor water level switch LIS-B21-IN031D. The licensee repaired the leak due to

heightened awareness of the effects of reference leg leaks on reactor water level (Generic Letter 92-04) ~ LIS-B21-IN031D provides initiation signals to Division Core Spray, Division

IILPCI, HPCI, ADS and RCIC. The action of TS LCO 3.3.3.b requires the associated

inoperable trip system to be placed in the tripped condition within one hour or declare the

associated

ECCS inoperable.

The licensee declared the associated

ECCS inoperable since

placing the trip system in the tripped condition would result in actuation of the ECCS.

TS 3.0.3 was entered when the ECCS TS 3.5.1 actions could not be met.

The licensee

repaired the leak and LCO 3.0.3 was cleared at 3:23 p.m. on January 22:

The inspector

agreed with the licensee's reportability determination.

There were no safety consequences

resulting from entry in TS LCO 3.0.3.

The inspector found the licensee's

decision to effect

the repair prudent.

15

8.2

Open Items

8.2.1

(Closed) Unresolved Item 50-387/89-21-02, RCIC and HPCI Rupture Disc NCRs

on Post Work Testing Inadequate

During inspection 50-387/89-21, the inspector noted that non-conformance reports {NCRs)

identified missed visual examinations (VT-2's) for the reactor core isolation cooling (RCIC)

and the High Pressure

Coolant Injection (HPCI) systems.

These visual exams were required

after the replacement of each turbine's exhaust rupture disc.

However, they were not done.

The inspector reviewed the work authorizations (WAs) for both HPCI and RCIC and noted

that rupture disc replacement was specified as a part of the preprinted instructions.

However, these instructions did not specify the VT-2 exam as required by administrative

procedures

and the ASME code.

The VT-2 exam requirement was later added to the

recommended

operational testing section of the RCIC WA by hand.

Following completion of

the RCIC maintenance work, four licensee groups reviewed the WA, failed to notice the

missed VT-2, and ultimately closed the WA. Although the HPCI work was similar, the VT-

2 exam was inadvertently omitted from the work documentation,

and thus, not performed.

The inspector opened this unresolved item due to weaknesses

in the licensee's control of

post-maintenance

testing.

The licensee investigated the cause of the missed VT-2's and determined that the missed VT-

2 exam on RCIC was due to an oversight by operations (the WA was closed without

performing the VT-2 exam specified in the operational testing section).

The licensee

attributed the missed VT-2 exam on HPCI to an oversight by the work planning group

(failure to specify that a VT-2 exam was required following replacement of the disk).

Reviews of the WAs for closure by the work group, quality control (QC) and operations also

failed to identify the missing requirements.

As a result, the licensee provided the following

, corrective actions:

Maintenance is to ensure that all post work testing requirements,

including visual

exams, are included on the Equipment Release Form (ERF) associated

with the work

document.

This willensure that all post work testing requirements

are entered in the

computerized system status file by the Unit Coordination Group.

Training per Hot Box 89-63 was conducted for the operation's personnel to stress the

importance of proper review and closeout of work documents.

AD-QA-482, Post Maintenance/Modification Test Program specifies the requirements for

post maintenance

testing.

The licensee attributed the failure to perform the required VT-2

exams to isolated personnel error and they are confident that the actions stated above will

prevent future similar errors.

16

In a previous update (50-387/92-20), the inspector searched

the NCR database

and identified

five cases where VT-2 visual examinations were missed; two in 1989, one in 1990, one in

1991, and one in 1992.

The cause for each instance was unique (not similar to the

aforementioned

missed VT-2's) and the inspector concluded that for each case, appropriate

corrective actions were taken to prevent recurrence.

In the current inspection, the inspector reviewed AD-QA-482 (NDAP-QA-482) and discussed

the previously missed VT-2's with the unit coordination group and shift supervision.

The

NCR database

was searched for recently missed VT-2 exams.

None were found. In

discussions with the licensee,

the inspector noted an increased

awareness of the VT-2

examination requirements.

Based on the above, this item is closed.

8.2.2

(CLOSED) Unresolved Item 50-387-90-21-01, Firewatch Rounds Not Completed

As Required

In January

1990, the licensee submitted a Licensee Event Report (LER 50-387/90-002-00)

that informed the NRC that during a three week period, four of seven roving firewatch

personnel did not complete all of their assigned rounds during midnight shifts.

The failure to.

make certain firewatch rounds was a violation of plant Technical Specifications 3.7.6 and

3.7.7.

The licensee's investigation found that the four individuals had received adequate training and

understood their responsibilities.

As a result, PP&L terminated their employment.

As

corrective actions the licensee installed a watchman key code station system to provide a

permanent,

easily-retrievable record of all firewatch rounds.

In addition, the licensee

implemented additional supervisory unannounced

backshift inspections.

The NRC opened an

unresolved item pending completion of the licensee's corrective actions.

Subsequently,

an

audit of firewatch logs and security transactions

was performed by personnel from PP&L's

Allentown office. The audit sampled security access

data and firewatch logs for eight roving

firewatch employees of all shifts during the week ending July 22, 1990.

They did not find

any skipped rounds, missed stations, or falsified times on the firewatch logs for that time

period.

The inspector independently reviewed a sample of the watchman key code system data,

official firewatch logs, and discussed

the status of the firewatch program with licensee

personnel.

No problems were identified and it appears that the licensee's corrective actions

have been effective in preventing recurrence of the problem.

The inspector reviewed a sample of the watchman key code system data, official firewatch

logs, and discussed

the status of the firewatch program with licensee personnel.

No

problems were identified and it appears

that the licensee's corrective actions have been

effective in preventing recurrence of the problem.

The missed firewatch rounds were a

violation of the TS, however, this violation meets the criteria of 10 CFR Part 2 Section

VII.Bfor non-cited violations.

The NRC's disposition of the unresolved item is based on the

17

licensee's identification of the problem, their effective corrective actions, and the apparent

severity level of the violation.

The inspector had no further questions and considered

this

unresolved item closed.

8.2.3

(Closed) Violation 50-387/91-06-01, Inservice Test Program Omission

During an inspection of the licensee's Inservice Testing {IST) program, an inspector

identified that the licensee did not include certain safety related containment instrument gas

(CIG) check valves {1-26-018, 1-26-029, Unit 1; and 2-26-018, 2-26-029, Unit 2) in their

IST program.

Consequently,

these check valves were not tested as required Section XIof

the American Society of Mechanical Engineers (ASME) Code.

During the original

inspection, the inspector found the licensee's implementation of the IST program to be

otherwise good.

The CIG check and solenoid valves provide double valve isolation between the safety related

and non-safety related portions of the CIG system.

The licensee believed that the check

valves did not function as safety related isolation valves and thus did not incorporate the

check valves into the IST program.

However, documentation (piping and instrumentation

diagrams (P&IDs), valve data lists, work authorizations, etc.) identified the check valves as

safety related isolation valves.

An inspector identified this discrepancy,

which provided the

basis for the violation. In response

to the violation, the licensee incorporated the check

valves into the next revision of the IST program.

Section XI of the ASME Code requires

testing check valves on a quarterly frequency; or ifimpractical, on a cold shutdown

frequency.

The licensee submitted a relief request to test the CIG check valves on a

refueling outage frequency as opposed to a quarterly frequency.

The NRC denied the relief

request since the relief request did not address why testing was impractical on a cold

shutdown frequency.

The NRC granted interim relief for one year, ending June 23, 1993,

allowing the licensee to test the check valves on a refueling outage frequency.

The licensee

has agreed to submit a revised relief request discussing why CIG check valve testing is

impractical on a quarterly or cold shutdown frequency.

The licensee tested the Unit 1 CIG

check valves on March 13, 1992 during the Unit 1 sixth refueling outage.

The licensee

tested the Unit 2 CIG check valves on September

14, 1992 during the Unit 2 fifth refueling

outage.

The inspector reviewed the licensee's IST program and noted that the program included the

CIG check valves and the relief request.

The inspector checked the IST valve list against the

Unit 1 P&IDs to determine the extent of valve omissions and identified no deficiencies.

The

inspector investigated testing the check valves on a cold shutdown frequency and found that

the check valves could be tested.

However, testing requires that service air be cross tied to

supply certain CIG loads, causing the containment oxygen concentration

to increase.

Technical Specifications provides limits on oxygen concentration which indicates that this

type of testing may not be feasible for short duration unplanned shutdowns.

The inspector

reviewed the CIG check valve surveillances and identified no anomalies.

Since the licensee

revised the IST program and the omission appears isolated, this item is closed.

C

e

18

8.3

Susquehanna

River Flooding

During March and April, the Susquehanna

River level rose above flood stage many times.

This flooding was the result of snow melt in upstate New York, along with repeated heavy

rain falls. The licensee took actions to cope with this condition.

The inspector evaluated the effects of the flooding on both Susquehanna

units and noted that

ON-000-002, Natural Phenomena provides guidance for high river levels. It requires that,

additional tours be made by operations and security personnel.

The inspector questioned the

licensee on their implementation of this requirement on March 30 and 31.

During the March

30 discussion,

the licensee was unable to provide the details for the increased

operational

tours even though they were implementing ON-000-002.

Discussion held the following day

indicated that shiftly rounds were changed from two to four times per shift. The licensee also

provided additional guidance to touring nuclear plant operators

and to security personnel,

thus, supporting the procedural requirement for more frequent tours.

The difference in actions on these dates was primarily attributable to the wording in Section

3.5 of ON-000-002.

Steps 3.5.2 and 3.5.4 require additional tours by both security and

operations personnel at apparently different river levels which results in unnecessary

redundancy.

Neither of these steps indicate what components or conditions (i,e., screen

clogging, river water makeup pump performance,

etc.) are to be evaluated.

Step 3.5.4

requires action prior to 382" (515'levation) without identifying a specific level.

Step 3.5.5

requires river level monitoring through the Power Control Center (PCC).

The licensee's

security organization tracked river level by contacting Luzerne County Emergency

Management Agency (LCEMA) and did not use the PCC.

The inspector noted the procedure

was general in nature and did not adequately

address

the need for action.

However, it did

not appear to adversely impact the licensee since they successfully managed activities

throughout the flooding.

Overall, the licensee's

management of the river flooding was good despite the procedural

inadequacies.

The inspector has discussed

these procedural inadequacies

with the licensee

-and the licensee has agreed to revise the procedure to address

these apparent weaknesses.

The inspector had no further questions.

8.4

(Closed) Temporary Instruction (Tl) 2515/112 - Licensee Evaluations of Changes

to the Environs Around Licensed Reactor Facilities

Background

The NRC issued Temporary Instruction (Tl) 2515/112, Licensee Evaluations of Changes to

the Environs Around Licensed Reactor Facilities.

The NRC issued the TI to determine ifthe

licensee's programs are adequate in evaluating public health and safety issues resulting from

changes in population distribution or in industrial, military, or transportation

hazards that

could arise on or near reactor sites.

t

I

19

Scope

The inspector reviewed Susquehanna

Steam Electric Station's programs relative to evaluating

public health and safety issues resulting from changes in population distribution, industrial,

military, or transportation hazards that could arise on or near Susquehanna.

The inspector

reviewed the current Final Safety Analysis Report (FSAR), NRC Safety Evaluation Report

(SER), 10 CFR 50.71, 10 CFR 100, and Generic Letter 81-06.

Licensee Evaluation of Changes in the Environs

The inspector questioned how the licensee evaluated changes to the environs with personnel

that oversee updating the FSAR.

The licensee did not have a formal program in place to

evaluate changes

to the site environs.

However, the licensee performed an evaluation and

submitted the FSAR update in response

to inspector questions that were prompted by TI 112.

The inspector considered

this a positive initiative. The FSAR has been updated to reflect

changes

to the site environs.

The update was submitted to the NRC June 30, 1992.

PP&L

previously provided updates to the FSAR that refiected changes

to the site environs.

The licensee plans to implement a program that willrequire periodic evaluation of changes to

the environs.

The licensee will update Section 2.1, Geography and Demography, every 10

years coincident with issuance of the U.S. census.

This is based on the census, which is

done every 10 years.

Section 2.2, Nearby Industrial, Transportation,

and MilitaryFacilities,

willalso be updated every 10 years.

The licensee based this frequency on a history of

relatively few changes to facilities in proximity of the site.

The licensee willevaluate and

update the FSAR between scheduled revisions should a significant change to the site environs

occur.

The individual who was responsible for evaluating the changes to the environs held a

masters'egrees

in Environmental Science and Biology, was a registered Environmental Manager,

and had 22 years experience.

Organizationally, the individual worked in Nuclear

Technology in Allentown (Corporate Engineering) in the Environmental Services Section.

Geography and Demography

The licensee did not identify any significant changes in population distribution during the

- review.

The site demography data has been updated.

The general trend of population has

been decreasing.

There has been a decrease

in urban population and an increase in rural

population.

However, the overall population distribution did not exceed

those predicted in

the original FSAR.

20

Site Proximity Hazards

The licensee did not identify any significant changes in military; industrial or transportation

hazards that could affect public health and safety.

However, the FSAR had been updated

previously to reflect the addition of two natural gas pipelines in the vicinity of the site. The

licensee analyzed the hazards associated

with these changes to the site proximity. These

updates were performed on as needed basis rather than from a formal periodic review

process.

The licensee also updated this section of the FSAR 2.2 in response to the TI. The

updates did not pertain to any new hazards.

Summary

The inspector concluded that the licensee initiated response

to the TI was a strength.

The

inspector found the evaluation was performed by individuals with appropriate qualifications.

The FSAR had been previously updated to reflect the installation of the new natural gas

pipelines.

The inspector concluded this was a positive finding. However the licensee did not

have in place any formal programs to evaluate changes to the site environs and the potential

effects on public health and safety prior to issuance of the TI. Currently the licensee is in

the latter stages of developing a formal program to conduct such reviews and evaluations.

The inspector had no further questions.

This inspection closes TI-2515/112.

9.

MANAGEMENTAND EXIT MEETINGS

9.1

Resident Exit and Periodic Meetings

The inspector discussed

the findings of this inspection with station management

throughout

and at the conclusion of the inspection period.

Based on NRC Region I review of this report

and discussions

held with licensee representatives,

it was determined that this report does not

contain information subject to 10 CFR 2<<790 restrictions.

9<<2

Inspections Conducted By Region Based Inspectors

ate

4/5 - 4/8/93

~eb'eet

EOP Inspection

~lns xction

~Re ort N

.

93-06

~Re o~rtin

~Ins )ear

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Ab reviati

n List

ATTACHMENTl

AD

ADS

ANSI

ASME

CAC

CFR

CIG

CL

CRDM

CREOASS

DG

DX

ECCS

EDR

EP

EPA

EQ

ERT

ESF

ESW

EWR

FO

FSAR

HVAC

IERP

ILRT

I&C

JIO

LCO

LER

LLRT

LOCA

LOOP

MSIV

NCR

NDI

NPE

NPO

NQA

NRC

NSE

OI

- Administrative Procedure

- Automatic Depressurization

System

-.American Nuclear Standards Institute

- American Society of Mechanical Engineers

- Containment Atmosphere Control

- Code of Federal Regulations

- Containment Instrument Gas

- Checklists

- Control Rod Drive Mechanism

- Control Room Emergency Outside AirSupply System

- Diesel Generator

- Direct Expansion

- Emergency Core Cooling System

- Engineering Discrepancy Report

- Emergency Preparedness

- Electrical Protection Assembly

- Environmental Qualification

- Event Review Team

- Engineered

Safety Features

- Emergency Service Water

- Engineering Work Request

- Fuel Oil

- Final Safety Analysis Report

- Heating, Ventilation, and Air Conditioning

- Industry Event Review Program

- Integrated Leak Rate Test

- Instrumentation and Control

- Justifications for Interim Operation

- Limiting Condition for Operation

- Licensee Event Report

- Local Leak Rate Test

- Loss of Coolant Accident

- Loss of Offsite Power

- Main Steam Isolation Valve

- Non Conformance Report

- Nuclear Department Instruction

- Nuclear Plant Engineering

- Nuclear Plant Operator

- Nuclear Quality Assurance

- Nuclear Regulatory Commission

- Nuclear Systems Engineering

- Open Item

OOS

PC

PCIS

PMR

PORC

PSID

QA

RB

RBCCW

RCIC

RG

RHR

RHRSW

RPS

RWCU

SGTS

SI

SO

SOOR

SPDS

SPING

TS

TSC

WA

- Out-of-Service

- Protective Clothing

- Primary Containment Isolation System

- Plant Modification Request

- Plant Operations Review Committee

- Pounds Per Square Inch Differential

- Quality Assurance

- Reactor Building

- Reactor Building Closed Cooling Water

- Reactor Core Isolation Cooling

- Regulatory Guide

- Residual Heat Removal

- Residual Heat Removal Service Water

- Reactor Protection System

- Reactor Water Cleanup

- Standby Gas Treatment System

- Surveillance Procedure,

Instrumentation and Control

- Surveillance Procedure,

Operations

- Significant Operating Occurrence Report

- Safety Parameter Display System

- Sample Particulate, Iodine, and Noble Gas

- Technical Specifications

- Technical Support Center

- Work Authorization

4

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