ML18102A953

Insp Repts 50-272/97-03 & 50-311/97-03 on 970126-0315.No Violations Noted.Major Areas Inspected:Licensee Operations, Engineering,Maint & Plant Support

ML18102A953
Person / Time
Site:	Salem
Issue date:	04/03/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18102A952	List: ML18102A951 ML18102A953
References
50-272-97-03, 50-272-97-3, 50-311-97-03, 50-311-97-3, NUDOCS 9704090281
Download: ML18102A953 (75)

See also: IR 05000272/1997003

Text

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Docket Nos:

License Nos:

R~port No.

Licensee:

Facility:

Location:

Dates:

Inspectors:

Approved by:

U. S. NUCLEAR REGULATORY COMMISSION

50-272, 50-311

DPR-70, DPR-75

REGION I

50-272/97-03, 50-311/97-03

Public Service Electric and Gas Company

Salem Nuclear Generating Station, Units 1 & 2

P;O. Box 236

Haricocks Bridge, New Jersey 08038

January 26, 1997 - March 15, 1997

C. S. Marschall, Senior Resident lnsp~ctor

J. G. Schoppy, Resident Inspector

T. H. Fish, Resident Inspector

R. K. Lorson, Resident Inspector

L. J. Prividy, Senior Reactor Engineer

E. H. Gray, Project ~: * .:nager

8. Smith, NRC Contract Engineer

J. Greene, NRC Contract Engineer

.James C. Linville, Chief, Projects Branch 3

• Division of Reactor Projects

9704090281 970403

PDR _ ADOCK 05000272

G

PDR

EXECUTIVE SUMMARY

Salem Nuclear Generating Station

NRC Inspection Report 50-272/97-03, 50-311197-03

This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers a 7-week pe,riod of resident inspection.

In addition, it includes the results of inspections of steam generator replacement, the

Motor-operated valve program, and the commitment management system.

Operations

Operators continued to demonstrate deliberate control of plant activities and conservative

decision-making. Unit 2 operators demonstrated good awareness of technical specification

requirements in controlling pressurizer auxiliary spray even though a surveillance procedure

did not provide appropriate precautions (Section 03.2). Although the inspectors observed

good overall operator performance, the inspectors noted some weaknesses involving use

of the alarm response procedures, evaluation of an off-normal plant condition, and shift

turnovers (Section 04.2). Plant managers demonstrated leadership and commitment to

excellence in demanding that containment inspection teams implement higher standards

for containment cleanliness and material condition (Section 08.2).

The station implemented a number of programs designed to enhance procedure use and

adequacy. Recent inspection observations indicate good and improving procedure use.

Procedures were reviewed and revised in key station functional areas. The operations

staff appropriately identified operations procedures that required revision prior to restart.

Selected procedures reviewed appeared adequate and generally consistent with the

procedure writers guide. The inspector concluded that procedure use and adherence is

adequate (Section 03.1 ). Implementation of effective operability determination training for

operations and system engineering staff resulted in an effective i:>rocess for developing

operability determinations (Section 02.1 ).

The operations staff implemented extensive corrective measures resulting in significant

im.provement in operator performance since June 1995. Operators demonstrated safety-

conscious decision making, ownership for plant equipment, detailed knowledge of plant

operation, a good questioning attitude, effective communications, procedure compliance,

low tolerance for workarounds, and a tendency to identify and correct deficient conditions.

The inspectors considered the measures to improve performance effective (Section 04. 1 ) .

The operations staff also established, implemented and completed the Operations Restart

Action Plan. Inspectors considered the results of the completed actions effective in

improving: oversight of plant activities, operator training, standards for equipment

condition, communication, and control of plant .operation (Section 08.1 ).

In a letter dated March 18, 1997, NRC issued a violation for two aspects of licensed

operator requalification trainina that did not meet 10 CFR 55.59(c) based on licensee

submittals dated November 7, 1996, January 6, 1997, and February 12, 1997. The two

aspects related to compliance with requirements for an annual operating test for all

operators and for continuous requalification training programs not to exceed 2 years in

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duration. The NRC letter also noted that the operator training has been high quality and

effective, but the violation represents weak program planning (Section 05).

The inspectc1rs concluded that Salem radiation monitors and procedures adequately

addressed the requirements of 10 CFR 70.24 for criticality monitors {Section 08.3). An

independent investigation, in response to a employee concern, effectively demonstrated

that Quality Assurance {QA) management actions had not resulted in toning down QA

inspector findings. The investigation also effectively demonstrated that QA managers had

not taken action to reprimand or otherwise penalize QA inspectors as a result of the QA

inspectors' findings {Section 08.4). The licensee developed and improved their methods

for commitment management {e.g. Commitment Manager and the 30-day look ahead

report), informed responsible personnel of these methods and management expectations,

and began to 'improve commitment management procedures. The NRC Restart Item

(111.14) remains open pending completion of the procedure changes {Section 08.5).

Maintena*nce

The maintenance restart action plan effectively addressed previous performance

deficiencies. The inspectors found that management monitored emergent work and

actively participated in the assignment of priorities to safety significant work.

Maintenance personnel identified new problems and initiated corrective action. For the

activities observed, maintenance technicians used procedures and tools properly.

Management actively monitored performance using trending tools and self assessments.

Additionally, QA provided useful performance assessment. The self assessments and QA

assessments enabled management to continue to improve maintenance performance.

Although performance deficiencies continue to occur, significant reduction in the error rate

and significant improvement in equipment performance indicated that implementation of

the maintenance restart plan resulted in effective maintenance (Section M1 .2).

Inspectors noted that good quality generally characterized the performance of the Salem

Unit 1 steam generator replacement project (SGRP). When workers identified problems,

the managers and supervisors stopped or delayed work until they established an

acceptable course of action (Section M1 .3). Technicians demonstrated good procedure

adherence during repair of the 1 C EDG jacket cooling leak, and during replacement of the

11 SW pump .. Troubleshooting of the 1 C EDG frequency variations was logical. Weak

engineering controls were established prior to changing the type of packing in the 11 SW

pump (Section M 1 .4). Maintenance did not effectively repair a packing leak or adequately

use equipment malfunction identification system tag tracking. Maintenance and

engineering did not adequately support operations in resolving diesel day tank level

indication inadequacies (Section M2.1 ). Technicians properly controlled and conducted

safety-related maintenance on the no. 23 component cooling water pump (Section M3.1 ).

Salem management has improved, and continues to improve, work control effectiveness.

They improved the process, trained personnel, and increased staffing levels in the planning

• and scheduling group. PSE&G's staff addressed the work order backlog and they are

using performance indicators to monitor progress. While personnel could still improve their

performance, the work control staff's response to their self assessment indicated to the

inspector that management would ensure the organization continued to address

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deficiencies. The inspector concluded the work control program is ready to support Salem

restart (Section M8.1 ).

Engineering

Significant progress arid improvements in the MOV program were evident since the last

NRC inspection of July 19.96. The justifications for key program assumptions were

complete and the applied valve factors of Salem Unit 2 MOVs were adequate for GL 89-10

closure, demonstrating design-basis capability. These conclusions were based on the

understanding that PSE~G would pursue additional actions for certain MOVs in Families 6

_and 9 in conjunction with their periodic verification program (Sections E1 .3 and E1 .4).

PSE&G's actions to address pressure locking and thermal binding of motor-operated gate

valves were acceptable (Section E1 .5). PSE&G had developed a good tracking and

trending program and was adequately addressing MOV performance problems (Section

E1 .6). *

Inspectors observed generally good engineering performance during the period with

occasional lapses. During review of an operability determination, station operations review

committee (SORC) members questioned the basis for assurance that containment fan coil

unit (CFCU) modifications did not affect containment integrity. The plant staff did not

address the SORC question, and station management demonstrated lack of follow through

by not ensuring that the plant staff developed a satisfactory response to the containment

integrity question. In response to inspector questions, and prior to entering the affected

mode, SORC approved a 10 CFR 50.59 safety evaluation that adequately addressed the

concern regarding the UFSAR commitments for Type C leak rate testing the CFCU SW

cooling line containment isolation valves (Section E1 .9). As a result of a proposed

modification, an alert system manager discovered an incomplete surveillance of the circuit

for automatic operation of the Pressurizer Overpressure Protection System. The plant staff

immediately devised and completed an effective test. The inspectors noted that TSSIP, *

• phase 2, scheduled for completion in late 1997, would have discovered this deficiency

(Section E 1 . 1 0). The engineering staff conducted appropriate trouble-shooting to

determine the cause of control room ventilation performance problems. The Salem

managers properly elected to correct system deficiencies rather than change the licensing

basis for control room ventilation. As a result of considerable effort, the engineering staff

successfully demonstrated the ability of control room ventilation to perform its design

function (Section E8.1)

Pending satisfactory implementation of the modifications to address the effects of multiple

hot shorts on safe shutdown, the associated NRC Restart Item and Unresolved Items will .

remain open (Section E8.3):

Plant Support

Inspectors concluded that PSE&G had adequately addressed various open items relating to

Emergency Preparedness .

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TABLE OF CONTENTS

EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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I. Operations .................................*..................

II. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Ill. Engineering ......................... * . . . . . . . . . . . . . . . . . . . . . . . . .

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IV. Pla.nt Support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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V. Management Meetings

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Report Details

Summary of Plant Status

Unit 1 remained defueled for the duration of the inspection period.

Operators maintained Unit 2 in Mode 5, Cold Shutdown, for the duration* of the period.

I. Operations

01

Conduct of Operations

. 01 . 1 *General Comments (71 707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of

ongoing plant operations. In general, the conduct of operations was professional

and safety-conscious; specific events and noteworthy observations are detailed in

the sections below. *

02

. * Operational Status of Facilities and Equipment

02.1

Operability Determinations. NRC Restart Item 111.6 (Closed) and Unresolved Item 50~ *

272&311/95-80-01 (Closed)

a.

Inspection Scope (71707)

b.

. Various NRC Inspection Reports, such as 50-272&311 /95-80, documented

unacceptable and poor quality operability determinations at Salem. The inability of

the Salem staff, in the past, to appropriately determine equipment operability

contributed. significantly to the cause of the shut down of Salem Units 1 and 2 in

1995. In NRC Inspection Report 50-272&311 /96-08, section 02.1, the inspectors

reviewed Salem's method for assessing the operability of degraded or

nonconforming structures, systems, and components. The inspectors concluded

that the new operability determination process provided clear guidance for

documenting and tracking the operability of degraded or nonconforming equipment ..

ThE;i inspectors noted, however, that operations and system engineering staff had

not received training on implementation of the new system. As a result, the

inspectors left NRC Restart Item 111.6 open at that time.

Observations and Findings

The inspectors verified that operations and system engineering staff had received

training on implementation of the new system. In addition, the inspectors reviewed

several recent operability determinations and observed the staff presentations of

operability determinations to SORC. The inspectors noted that the station staff

presented comprehensive operability determinations that included consideration of

design and licensing basis information pertinent io the equipment evaluated in the

operability determination. The presentations included operability determinations for

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component cooling water room coolers, containment fan coil units, and others. The

inspectors considered the operability determinations acceptable.

Conclusions

The inspectors concluded that implementation of effective operability determination

training for operations and system engineering staff resulted in an effective process

for developing operability determinations.

03

Operations Procedures and Documentation

03.1

Procedure Use And Adequacy - NRC Restart Item 111.3 (Closed)

a.

b.

Inspection Scope (92901)

The inspector reviewed the licensee's actions to address problems with the use and

adequacy of procedures.

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Observations and Findings

Procedure Adherence

Salem implemented several initiatives to improve performance in procedure

adherence including:

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Site and departmental management reinforced procedure use expectations

through memorandums and site messages.

Salem staff upgraded.procedure use instructions in several areas .

Plant staff conducted procedure use training for operations and maintenance

department personnel.

The inspector concluded that these actions improved procedure adherence. The

inspector performed several observations and reviewed the recent inspection record

to determine the effectiveness of these actions. Recent inspection reports (96-15,

96-17, 96-18) noted generally good and improving procedure adherence

performance. Inspectors also noted good procedure adherence for operations and

maintenance activities monitored this period.

Proc<:?dure Adequacy

The licensee reviewed procedures in the station operations, maintenance,

chemistry, radiological protection, and engineering areas. Plant staff revised or

validated a number of operations procedures including the abnormal, emergency,

alarm response, and integrated operating procedures. They also upgraded

maintenance troubleshooting, Hagan module configuration and calibration, and

foreign material exclusion control procedures. Plant staff targeted specific

enhancements for chemistry and radiological procedures .

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Salem staff updated the procedure writer and reviewer's guide, and developed a

program to train procedure writers on the new guide. The licensee recently

identified additional chemistry procedure enhancements to remove statements that

could lead to mis-interpretation. The licensee reviewed the procedure revision

backlog in the operations, maintenance, chemistry and radiological areas and

identified the procedures that required revision prior to restart.

The inspector reviewed a portion of the operations procedure backlog and di_d not

identify any procedures that required revision prior to restart. Additionally, the

inspector reviewed normal operating procedures and did not identify any technical

deficiencies. Maintenance procedures reviewed during plant observations appeared

adequate.

Conclusions

The station has implemented a number of programs designed to enhance procedure

use and adequacy. Recent inspection observations indicate good and improving

procedure use. Plant staff reviewed and revised procedures in key station

functional areas. They appropriately identified corrected operations procedures that

required revision prior to restart. The inspector considered sampled procedures

adequate and generally consistent with the procedure writer's guide. The inspector

considered procedure use and adherence adequate.

03.2 Control of Pressurizer Auxiliary Spray 171707)

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On March 11, Unit 2 operators stroked 2CV75 (auxiliary spray valve) in accordance

with S2.0P-ST.CVC-0007, /nservice Testing Chemical and Volume Control Valves

in Modes 5 and 6. The reactor operator ensur~d that spray differential temperature

did not exceed 320°F as specified in Technical Specification 3.4.10.2.C. The

inspector noted, however, that S2.0P-ST.CVC-0007 did not provide guidance to

prevent operators from exceeding a 320°F differential temperature and impacting

pressurizer spray nozzle fracture toughness. The reactor operator initiated a

procedure revision request to improve S2.0P-ST.CVC-0007. The inspector

concluded that operators demonstrated good awareness of technical specification

requirements and ensured plant operation within specified limits despite lack of

procedure guidance to limit the differential temperature.

Operator Knowledge and Performance

04. 1 Operator Performance, NRC Restart Item Ill. 7 (Closed)

a.

Inspection Scope (92901)

The inspector reviewed corre~tive actions to address operator performance

weaknesses. The inspector assessed operator performance relative to the restart o.f

the $alem units.

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Observations and Findings

Starting in June 1995, the operations manager acted to increase operations

staffing, improve operator training, and raise operator standards. The operations

manager strengthened shift resources through increased shift technical advisor

(ST A) staffing, hiring seven previously licensed senior reactor operators (SROs) with

significant operating experience, and balancing operating crews based on strengths,

weaknesses, and personalities .. The operations and training staff developed and

implemented a comprehensive two phase training program to improve operator

performance. The first phase involved a comprehensive assessment of licensed

operator knowledge, skills, and attitudes through written, oral, and performance

evaluations. The second phase contained training specifically targeting phase one

weaknesses and involved approximately 500 contact hours. The training focused

not only oil knowledge and skills, but on affecting the cultural shift needed for safe

plant operations.

In recent inspection reports (50-272 and 311/96-17 and 96-18), inspectors

documented good performance in the following areas:

• risk management and safety focus,

• technical specification* compliance,

• intolerance for workarounds,

• identification of degraded conditions and timely corrective action,

• procedure compliance, ..

• operator knowledge,

• questioning attitude,

Ii communication and coordination,

• plant ownership, and

• .awareness of plant equipment status.

Although operator performance continued to improve since June 1995, operators

periodically failed to meet management expectations and, on occasion, NRC

requirements. Operations mar,iagement's prompt and comprehensive corrective

actions for past errors reduced the frequency and consequences of similar

performance lapses. For example, on January 2, 1997, operators experienced a

problem with reactor coolant system (RCS) level indication as a result of an

operator-induced valve misalignment during the RCS fill and vent. Operators

immediately recognized and responded to the problem as a result of their focus on

RCS level. Operations management immediately took comprehensive corrective

action. The valve misalignment had no safety consequence.

Conclusions

Operations management implemented extensive corrective measures and affected

significant improvement in operator performance since June 1995. Operators

demonstrated safety-conscious decision making, ownership for plant equipment,

detailed knowiedge of plant operation, a good questioning attitude, effective

communications, procedure compliance, an intolerance for workarounds, and a

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propensity to identify arid correct deficient conditions. Operator performance

supports restart of the Salem units.

04.2 Routine Operator Performance Observations

a.

Inspection Scope (717071

b.

The inspectors observed the control room operators perform routine plant activities

including transfer of the operating Unit 2 residual heat removal (RHR) heat

exchanger in accordance with S2.0P-SO.RHR~0001, "Initiating RHR" and response

to a low ambient temperature condition in the Unit 1 and Unit 2 service water (SW)

pump bays.

Observations and Findings*

Transferring Residual Heat Removal Loops - Unit 2

The inspectors observed that a reactor coolant pump (RCP) bearing low cooling

flow alarm repeatedly actuated and cleared during transfer of the operating Unit 2

RHR heat exchanger. The control room operator (CRO) attributed the alarm

condition to aligning the component coolin[I water (CCW) flow into the standby

RHR system heat exchanger. The CRO did not refer to the alarm response card

(ARC) and completed transferring the RHR heat exchangers. The RCP cooling flow

alarm promptly cleared upon completion of the transfer evolution, demonstrating

that the alarm did not represent a degraded condition. The inspector considered

that not referring to the alarm response card demonstrated a poor operator practice.

The inspector did not identify any other operator deficiencies during the evolution.

The system manager and the assistant operations manager indicated that they

would review the S2.0P-SO.RHR*0001 procedure to determine if the RHR heat

exchangers could be transferred with less impact on the CCW system flow.

Low Service Water Pump Bay Ambient Temperature Readings

The inspector noted that the logged 1 and 2 SW pump bay ambient temperatures

were between 50 and 58°F during a two day period. The minimum specified log

temperature for these rooms was 60°F. The plant operators properly identified and

circled the out of specification log readings, and verified that an active action

request existed to address the cause for the low room temperature conditions.

The nuclear shift supervisor (NSS) did not know whether the low temperature

condition had been evaluated to ensure that the safety-related components in the

SW pump bays remained operable. The inspector reviewed the Updated Final

Safety Analysis Report (UFSAR), Section 9.4.7.1, and noted that the SW pump bay

room had a low ambient temperature alarm setpoint of 40°F and concluded that the

recorded SW pump bay temperatures did not exceed the room ambient temperature

design limits .

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The inspector discussed this observation with the Operations Manager and learned

that a previous shift had evaluated the impact of the low temperature condition on

the operability of components. The inspector concluded that NSS's lack of

familiarity with this evaluation demonstrated weaknesses in the evaluation of off-

normal plant conditions and the communication of information during shift

turnovers.

c.

Conclusions

The inspector concluded that although routine operator performance is generally

good; some weaknesses were noted involving use of the alarm response cards,

evaluation of an off-normal plant condition, and shift turnovers.

05

Operator Training *and Qualification

In a letter dated March 18, 1997, NRC issued a violation for two aspects of

licensed operator requalification training that did not meet 10 CFR 55.59(c) based

on licensee submittals dated November 7, 1996, January 6, 1997, and February

12, 1997: The two aspects related to compliance with requirements for an annual

operating test for all operators and for continuous requalification training programs

not to exceed 2 years in duration. The NRC letter also noted that the operator

training has been high quality and effective, but the violation represents weak

program planning. For follow-up purposes, this violation will be numbered as VIO

50-272&311/97-03-01.

08

Miscellaneous Operations Issue

08. 1 Operations Restart Action Plan (Closed)

a.

Inspection Scope (92901 l

The Salem Operations Restart Action Plan established a performance based

approach to specify and control the actions required to demonstrate operations

restar:t readiness. The inspector reviewed operations implementation of their restart

• plan and assessed operations readiness for restart.

b.

Observations and Findings

The Operations Manager identified six major areas for improvement, and developed

six problem statements to describe the weaknesses and outline corrective actions.

The inspector closed problem statements nos. 1, 2, 3, and 6 in inspection report

50-272 and 311 / 96-18.

Problem statement no. 4 identified that operations procedures and policies need to

be strengthened to support long-term operational excellence and plant startup. The

inspector reviewed operations' corrective actions and concluded that the adequacy

and use of procedures supported restart of the Salem units (see section 03.1 ). The

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inspector consic!.::.ied the actions to address problem statement no. 4 adequate to

support restart.

Problem statement no. 5 identified that operations' ownership for skills, knowledge,

attitude and training of operators needed significant improvement. Inspectors

reviewed the adequacy of training, NRC Restart Item 111.16, in inspection report 50-

272 and 50-311 / 96-08. Inspectors concluded that the Salem training staff

significantly improved the training programs through implementation of the Salem

Training Restart Action Plan. The PSE&G staff made significant improvements in

training program self-assessments and line management involvement in the training

programs. The inspector considered the actions to address problem statement no.

5 adequate to support restart.

c.

Conclusions

Operations established, implemented, and completed an effective restart action plan

to demonstrate operations' readiness for restart of both Salem units.

oa.2* Containment Cleanliness (71707)

The inspector assessed the Unit 2 containment material condition and housekeeping

as plant staff prepared for mode 4, Hot Shutdown, operation. Early in the period,

five "sparkle" teams led by radiation protection identified approximately 200 minor

deficiencies. The Operations Manager and OA/NSR Director spearheaded a

management effort to upgrade standards concerning plant material condition. Plant

management set higher standards for the inspection teams and the teams identified .

60 additional containment deficiencies. Further management guidance and direct

inspection effort resulted in 40 more documented defiC:iencies. The inspection .

teams identified and removed a significant amount of small debris including paint

chips, plastic bags, loose lagging, tape, cable ties, and discrepancy tags. Plant

management planned to apply the same high level inspection effort to the remainder

of the Salem facility. The inspector noted that plant managers successfully

accomplished two goals: they significantly raised the standards for acceptable

plant cleanliness, and they successfully implemented the standards in the Salem .

Unit 2 containment.

08.3 Criticality Monitors

a.

Inspection Scope (71707)

b.

The inspectors reviewed the Salem Unit 1 and Unit 2 plant design to determine

compliance with the requirements of 10 CFR 70.24.

Observations and Findings

The Salem UFSAR, section 12.1.3.6, states: "A Geiger-Mueller, or equivalent

monitor is located on the operating deck floor (Elevation 1 30 feet) of each Fuel

Handling Building. These monitors are sensitive to gamma radiation and are

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alarmed in accordance with NRC Regulation 10 CFR 70.24; The alarm will sound

locally and in the control room." The UFSAR also states that Salem staff has

written comprehensive emergency procedures to ensure that all personnel withdraw

upon the sounding of the alarm to a designated area of safety. The inspectors

verified installation of the radiation monitors ( 1 R5 and 1 R9 for Unit 1 , _2R5 and 2R9

for Unit 2) described in the UFSAR. *The engineering staff verified that the alarm

setpoints for the radiation monitors met requirements of 10 CFR 70.24 a(1) for

both Salem units. The Salem Operating Procedures and Emergency Plan

Implementing Procedures contain procedures to evacuate the Fuel Handling Building

in the event of high .radiation conditions. The Salem staff intended to review

station procedures for opportunities to improve the procedures with respect to the

requirements of 10 CFR 70.24 a(3). *

Conclusions

The inspectors concluded that Salem radiation monitors and procedures adequately

addressed tfle requirements of 10 CFR 70.24.

08.4 Management Oversight of Quality Assurance and Nuclear Safety Review (QA/NSRl

a.

Inspection Scope (71707)

b.

The inspectors -reviewed the results of an investigation of potentiai adverse

management oversight effects on QA reports.

Observations and Findings

In January 1997, the Employees Concern Program received an anonymous concern:

that certain activities by QA/NSR managers could lead to inappropriate toning down

or alteration of QA reports, and may have resulted in reprimands. The Nuclear

Business Unit (NBU) managers concluded that the nature of the concern

necessitated investigation by an independent source. The NBU managers appointed

the Director, Nuclear Business Support as the investigation manager. The

investigation manager, in turn, chose a nuclear procurement manager and an

outside consultant to conduct the investigation.

The investigators reviewed a random sample of 1996 QA audits and surveillances

for Salem and Hope Creek. They compared the field notes and checklists with the

final reports to determine if findings had changed. The investigators also

intervievJed randomly selected personnel to determine the validity of the concern.

In addition, the investigators reviewed performance appraisals for indications of

reprimands as suggested by the concern.

The investigators found no evidence that QA staff had toned down the findings in

their audits and surveillances. All intervif:wed members of the QA staff confirmed

this conclusion. The interviewed personnel indicated that managers had not

pressured them to tone down their findings with the exception of the occasiona.1

use of abrasive language in their reports. The interviewees all stated that any such

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changes were made with their concurrence, *and if they disagreed the wording was

not changed. The investigators found no indication of reprimands or other

repercussions in the performance appraisals. Although the performance appraisals

contained critical observation of auditors' communication skills, the investigators

considered the observations constructive criticism.

Conclusions

The inspectors concluded that the independent investigation effectively

demonstrated that QA management had not taken action that resulted in toning

down QA inspector findings. The investigation also effectively demonstrated that

QA managers had not taken action to reprimand or otherwise penalize QA

"inspectors as a result of the aA inspectors' findings.

08.5 Commitment Management. NRC Restart Item 111.14 (Open)

a.

b.

Inspection Scope

The NRC Staff identified instances where the licensee failed to meet commitments,

both within the licensee's organizations and ~ith the NRC Staff. The inspector

reviewed licensee actions to insure that plant staff takes effective action to address

commitments.

Observations and Findings

On August 21, 1996, the licensee documented the completion of. a review of a

sampll;l of completed NRC commitments to ascertain whether these commitments

were properly implemented. The sample included 2653 commitments consisting of

98% of commitments made between 1990 and 1995, 58% of commitments made

between 1985 to 1989, 17% of the commitments associated with NRC's NUREG-

0737, and 99% of the commitments associated with NRC's Generic Letter 83-28.

The licensee staff obtained the commitments associated with Salem Units 1 and 2

directly from the original source documents *(e.g .. Licensee Event Reports, response

to Notices of Violations, and docketed correspondence). The results of the review

indicated that less than 2 % of the commitments (45 commitments) had not been

properly implemented due to never having been implemented (7 commitments),

implemented but inadvertently changed (7 commitments), or not properly

implemented (31 commitments). The plant staff verified that all Salem Unit 2

restart commitments had been entered in a commitment management system.

The inspector verified that the licensee had initiated measures to resolve the 45

deficient commitments. In addition, the inspector reviewed a sample of ten

additional commitments, observed the retrieval of these commitments from the

licensee's data base, and confirmed that they were properly managed.

In addition to reviewing completed commitments, the licensee evaluated the

commitment management process to resolve the deficiencies that had resulted in

the failure to properly implement the 45 commitments noted above. The

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evaluation, contained in Performance Improvement Request (PIA) No. 960111309,

resulted in the following short term corrective actions:

A.

Plant management held a meeting with licensing personnel on January 26,

1996 to discuss the issue of commitment tracking.

B.

The staff initiated a 30-day look ahead and overdue report for commitments.

c.

The support staff developed commitment Performance Indicators.

D.

Licensing planned to provide due dates for all commitments in

correspondence to the NRC.

The inspector reviewed the implementation of the licensee's short term corrective

actions and found them useful and well implemented. This is particularly true of

the 30-day look ahead and overdue report, provided periodically to Salem and Hope

Creek to alert responsible individuals to pending or late commitments.

In addition to the above, PIA 960111309 proposed the following long term

corrective actions:

A.

The licensee planned to _establish expectations and standards for

commitment management and communicate them to all licensing personnel.

The inspector observed accomplishment of this objective in meetings held on

March 27 and 29, 1996.

B.

c.

D.

Licensing staff planned to review current Nuclear Department Administrative

procedures and work standards associated with management of

commitments. The inspector could not determine the schedule for.

completion of the revised commitment management procedures. This task is

open pending inspector revi""-' and acceptance of the finalized procedures.

(IFI 50-311/97-03-02)

Licensing planned to clearly communicate commitment management

expectations to NBU managers. The inspector reviewed the statement of

expectations associated with commitment management, forwarded to NBU

management in a memo dated April .29, 1996 and found these expectations

acceptable.

Licensing planned to evaluate other commitment tracking databases and

determine if changes were necessary. The inspector noted that the licensee

utilized several tracking databases to manage commitments. Although the

licensee no longer used A TS to manage. new commitments, it contains old

commitments that still require implementation. The PIA system superseded

ATS but also stopped using it to manage new commitments as of December

31, 1996. The licensee began to use the Commitment Manager database to

manage all commitments as of January 1, 1 997.

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Plant staff planned to perform a self-assessment of the commitment

management process. This licensee has not completed the self~assessment

since it is viewed as a long term verification effort. The inspector did not

consider completion of the self-assessment necessary for NRC closure of

Restart Item 111.14.

The staff planned to evaluate the process for identifying commitments. The

licensee completed this eff_ort as documented in PIR 960111309. The

inspector noted that no list of long term commitments for Salem existed

prior to implementation of procedure NC.NA-AP.ZZ-0030(0), "Commitment

Management", on March 15, 1992. The source documents for these

commitments, however, remain available and computer searchable.

Moreo_ver, the results of the commitment verification process (an

approximately 98 % success rate for fulfillment of commitments) indicate

that plant staff effectively managed commitments although improvements in

the process remain warranted.

Con~!usior.:J

The licensee took action to improve commitment management. The licensee has

developed and improved methods for commitment management (e.g .. Commitment

Manager and the 30-day look ahead report), made the responsible management and

personnel aware of the use of these methods and commitment management

expectations, and began to improve commitment management procedures. When

the licensee completes the improvements to the commitment management

procedures, the NRC will close NRC Restart Item 111.14.

08.6 (Closed) Violations 50-272&311/93-23 (EA 94-003-01013, 01023, 01033,

01043, 01053, 01063, 01073. & 010831 and 50-272&311/96-06-01. 96-01-01 &

96-01-02: Collectively these violations documented failure to follow procedures,

and fell into two categories: Tagging work practices, and verbal and procedural

work control. The licensee conducted root cause analyses and identified the

following causal factors: 1 ) less than adequate supervisory methods (insufficient

management/supervisory oversight), 2) less than adequate verbal communications,

and 3) less than adequate work practices (failure to follow procedures), and self

checking by the individual workers. The inspector reviewed the above analysis and

did not identify any additional contributing factors to those identified by the

licensee.

Corrective actions: The licensee temporarily stopped work to communicate

• expectations with regard to safety and work standards to the workers. Meetings

were held with contractor supervisors and craft personnel to relay the licensee

expectations for safety and adherence to work standards. Operation directives

were issued to re-emphasize the proper sequence of tagging work releases.

Radiation technicians were reminded of the requirements for the release of

materials from the work controlled area. Regarding the 1993 violation, the licensee

established an on-~hift middle management review group to review and assess and

control of maintenance activities.

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The inspector reviewed documentation confirming that the corrective ac.tions stated

above were enacted to correct the immediate concerns.

Actions to prevent recurrence: The licensee took the following actions to prevent

recurrence:

1 .

Directions, from station management, were made annotating the expectation *

that supervisory/managerial. personnel increase the field time spent

2.

3.

4.

5.

monitoring and assessing work, providing direction, and taking appropriate

corrective actions when necessary.

Carefully reviewed the scope of future outages to ensure management

oversight is sufficient for the job tasks.

Decreased the number of vendors from 3 to 2 to provide better licensee

oversight.

Provided better focus on station planning and proposed the establishment of

two separate work control centers by *the end of 1996.

Established an oversight team to; review pre-outage work progress,. monitor

work control progress, and review incidents of previous outages as they

relate to the work standards, contractor control and work control process in

general for lessons learned.

The inspector reviewed the documentation of meetings held by licensee*.

management with all levels of the Salem organization* that identified reasons for the

events and emphasized management expectations for all maintenance work to be .; ..

performed in the future. The inspectors noted that the concern over control of the

scope of outages did not apply,.._ the current outage due to its duration. However,

the licensee plans to address the control of outage scope in the. new work control

process implemented after restart. Inspectors als.o noted that the licensee has

greatly reduced the use of vendors in recent months. The plant managers

implemented the "war room" concept to improve work control center effectiveness.

The oversight team was established. The inspector reviewed selected findings of

the group and determined that they were focusing on the areas that would make

failure to follow procedure problems less likely.

Inspectors will review the effectiveness of corrective actions for tagging

deficiencies as part of NRC Restart Item 111.12 prior to plant start-up.

The inspectors considered the implemented corrective actions adequate, and noted

recent improvements in procedure use and adherence. This item is closed.

08. 7

(Closed) LER 50-311 /96-009: fourteen day followup report regarding 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts

for operations personnel. This LER identified a conflict between the Operations

staff's practice of assigning operators 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> work shifts versus a license

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requirement for 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts (NRC Inspection Report 50-272&311 /96-15 has

details). Salem management requested an operating license amendment to delete

the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift restriction and the NRC has approved this request. Salem staff

implemented ~he amendment (no. 169) on January 13, 1997. This item is closed.

08.8 (Closed) Unresolved Item 50-272&311 /96-08-06: Salem Unit 2 Operating License

does not permit 1 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> operating shifts. This issue is identical to the issue in LER *

50-311196-009. This issue was licensee identified and corrected, and predates the

shutdown of Salem Units 1 and 2. This licensee identified and corrected violation

is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the

NRC Enforcement Policy.

08. 9 (Closed) Violation E94-11 2-04013: PSE&G staff provided inadequate training,.

guidance, and procedures for operators to handle plant transients properly. On

April 7, 1994, events initiated ~y grass intrusion into the circulating water system

led to a rapid power reduction, a reactor trip and a safety injection. During the rapid

p::>wer reduction, Salem operators exceeded allowable shutdown rates and the

reactor temperature dropped below minimum allowable*temperature. The safety

injection resulted in operators filling the pressurizer to solid conditions. During the

recovery from the solid pressurizer condition, neither plant procedures nor operator

' * training was adequate in that the operators were unable to use any procedure

relating to existing plant conditions.

In response to the violation, the licensee.'s staff made numerous procedure changes

to operating and emergency procedures to provide adequate guidance for operators

in handling a future event of this type. Also, the licensee developed a new

procedure to address rapid* load reduction for turbine load reductions of equal to or

greater than 5% per minute. Salem staff trained and qualified all operating crews *

on the new and revised procedures. Operations personnel ran the event scenario at

the Salem simulator and training personnel stopped the scenario at critical points to

discuss lessons learned. The Operations manager required individuals whose

performance was less than expected to complete additional training for

qualification.

The inspector reviewed documentation specific to this i.ncident and confirmed that

Salem staff enhanced the procedures and that operators completed the training.

The generic issue of procedure adequacy and adherence is the subject of NRC

Restart Issue 111.3.1. Salem staff must complete the corrective action for that item

and NRC staff must evaluate the response prior to the restart of Salem Unit 2.

Based ori the response to this violation and the understanding that Salem

management will complete NRC Restart Issue 111.3. 1 prior to restart, this violation is

closed.

08.10 (Closed) Violation 50-27 L & 311 /95-07-03: failure to follow procedures. During

inspections in April and May 1995, inspectors noted five examples of activities in

progress that they judged not to meet Salem procedure requirements. Although

none of the examples was safety significant, the number of examples indicated a

trend of procedure non compliance. PSE&G staff responded to four of the

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examples with appropriate corrective* action and contested one example as not

being a procedure violation. The inspector reviewed the response and samples of

corrective action documentation. The review confirmed that Salem staff completed

procedure changes and training for the four non disputed examples. The inspector

reviewed the response for the disputed example and found the justification

sufficient to withdraw only the fifth example of the violation. The inspector

concluded that the activity, specifically, an attempt to correct a malfunctioning

security door latch, did not require a procedure. Also, Salem personnel later

generated a corrective action to document the replacement of worn parts. The

inspector concluded that the response to this violation was satisfactory. This item

is closed.

08.1 l (Closed) Violation 50-272 & 311 /96-15-02: failure to follow procedures. While

preparing to remove the 1 C 460/230 volt bus from service, operators performed

steps out of sequence. The procedure did not provide for this latitude. PSE&G

staff responded to this violation with several corrective action steps as follows:

Salem management counseled the personnel involved in accordance with PSE&G

site procedures.

The Operations staff revised the procedure to reflect the changed step sequence.

Salem operations management prpvided guidance to all operations personnel via

night orders, a departmental memo, and temporary standing orders.

Salem staff issued Administrative Procedure NC.NA-AP.ZZ-0001 (Q), Nuclear

Procedure System, Revision 10, effective December 6, 1996 and trained operations

personnel regarding use of procedures.

The inspector .found that the corrective action for this specific violation was

acceptable. The generic issue of procedure adequacy and adherence is the subject

of NRC Restart Issue 111.3.1. The NRC staff must evaluate the response to this

issue prior to the restart of Salem Unit 2. Based on the response to this violation

and the understanding that Salem management will resolve NRC -Restart Issue

111.3.1 prior to restart, this violation is closed.

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08.12 (Closed) Unresolved Item 50-272&311 /93-15-04: 50-354/93-11-01. Corrective

Action Program Weaknesses

In the subject inspection, the inspector identified weaknesses in the licensee's

corrective action program (CAP). During a followup investigation concerning a

containment fan cooler unit (CFCU) regulator, the licensee identified minor

weaknesses in the incident report, engineering discrepancy control, a deficiency

report, and work control processes. In this case, the inspector found the processes

to be properly implemented, but noted weak coordination between these processes.

Currently, the licensee has made significant progress in imp~oving the CAP. The

implementation of a single point of entry (Action Requests) for the CAP has virtually

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eliminated the c0nrdination problem between programs and processes. A recently

completed inspection (50-272/96-18) noted marked performance improvement in

the administration and implementation of the CAP. Based on the above, this item is

closed.

08.13 (Closed) Violation 50-272 & 311 /96-08-05 : inadequate procedures. From June

30, 1996 until August 10, 1996, the NRC inspectors identified four inadequate

Salem plant procedures; three were for operating plant safety related systems and

one was for reactor vessel head reassembly. Salem management's response to the

violation stated that plant staff revised the procedures and provided details of those

changes. The response also detailed corrective steps to prevent recurrence. These

corrective actions included steps specific to the procedures identified, such as

_communication to procedure writers and to reviewers, and. more generic corrective

action such as the extensive procedure review for technical adequacy as part of the

Salem Restart effort.

The inspector reviewed the specific procedures identified in the violation and

determined that Salem staff made the required changes. From the review of the

response, the inspector also concluded that other corrective actions were

satisfactory for these specific procedure i1adequacies. Considering the corrective

action already taken and since Salem management will resolve the generic issue of

procedure adequacy prior to restart as part of NRC Restart Issue 111.3. 1, Adequacy

and Use of Procedures, the inspector considered this violation closed.

08.14 (Closed) Violation 50-272 & 311 /96-17-01: failure to perform a safety evaluation

in accordance with 10 CFR 50.59. Operators developed a temporary procedure to

control activities during a total station air outage. Personnel developing the

• procedure incorrectly concluded that the changes to the plant detailed in the

procedure did not meet the criteria of 10 CFR 50.59 to require a safety analysis.

Once questioned by the inspector, Salem staff promptly completed the safety

analysis. NRC Inspection Report 50-272&311 /96-17 documented the fact that the

inspector reviewed the safety analysis and found it acceptable. In response to the

violation, Salem management communicated the event and lessons learned to

operations staff and other department managers, and incorporated these lessons in

the 10 CFR 50.59 training program. The inspector concluded that the corrective

action for this violation was adequate. This item is closed.

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II. Maintenance

M 1

Conduct of Maintenance

M1 .1

General Comments

a.

Inspection Scope !62707)

The inspectors observed .all or portions of the following work activities:

• 950610179:

• 961031038:

.* 960927115:

RHR discharge valve weld repair

1 B EOG Elliot strainer 92 day lube

addition of overpressure device on CFCU return piping

The inspectors observed that the plant staff performed the maintenance effectively

within the requirements of the station maintenance program.

b.

Inspection Scope (61726)

The inspectors observed all or portions o*; the following surveillances:

• S2.0P-ST.DG-0003:

• S2.0P-ST.DG-0004:*

• S1 .OP-ST.DG-0001:

• S2.RE-ST.ZZ-0002:

• S2.0P-ST.DG-0001:

• 52.0P-ST.CVC-0001:

• SC.OP-ST.CAV-0001:

• SC.OP-ST.CAV-0001:

2C diesel generator surveillance test

diesel generator auxiliaries 21 fuel oil transfer system

operability test

1 A diesel generator surveillance test

shutdown margin calculation

2A diesel generator surveillance test

inservice testing - 21 boric acid transfer pump

plant systems control room ventilation

• control room emergency air conditioning system manual

operation

The inspectors observed that plant staff did the surveillar:ice safely, and effectively

demonstrates operability of the associated system.

M1 .2 Salem Maintenance Restart Action Plan (Closed)

a.

Inspection Scope

The inspector reviewed the list of corrective maintenance work orders and a sample

of work orders required for restart. The inspector also reviewed corrective action

documents related to maintenance issues that Salem personnel generated during

the previous month to determine the nature and significance of the problems

identified. In addition, the inspector monitored an ongoing Quality Assurance audit

of maintenance activities and observed maintenance work in progress to gain

additional insight regarding the maintenance program .

b.

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Observations and Findings

Salem maintenance personnel provided the inspector a list of work orders required

for the restart of Unit 2 as of January 31, 1997. The list provided brief

descriptions of 728 work orders and provided the status and priority of these work

orders. From the review of this list, the inspector found four examples where the

priorities were incorrect when compared with the criteria of procedure NC.NA-

AP.ZZ-0009(0), Work Control Process. However, personnel had appropriately.

prioritized the vast majority. Three of the four had a lower priority assigned than

was appropriate. However, work was in progress indicating that they were in fact

getting treated as priority work. Also, for those work orders* on the list that were

of highest priority, the status was "Work In Progress". thus indicating they too were

. in fact receiving priority treatment. The inspector found that this prioritizing

method allowed emergent wor.k that was urgent to be given immediate attention

when necessary.

The Quality Assessment group provided copies of corrective action documents that

documented problems .related to maintenance. These documents, 108 in total,

represented the total related to maintenance issued during December 1996. Of

these, thirty-four were examples of completed work orders which did not resolve

• the original problem. The inspector reviewed these in_ more detail and determined

that although this number was greater than optimum, i.e., zero, the number did not

represent a significant problem in the quality of work being performed (considering

that Salem maintenance was completing more than 1000 work orders per month).

The inspector also noted from his review of the 108 dqcuments that Salem staff

had given adequate consideration regarding generic implications.

The inspector met with the manager of the Salem maintenance department to

discuss the metl-\\ods by which supervisors monitor work in the field. The inspector

learned that the primary method used is a formal Self Assessment Program. The

maintenance manager has set up a program that requires each supervisor to

conduct and document three observations of field work per week, at a minimum.

The observations are performed using an 85-point checklist as a guide.

Maintenance compiles and trends the data periodically to detect weak areas of

performance. Manage.ment can then direct attention to problem areas and apply

corrective action. In addition, the inspector learned that the Quality Assessment

group routinely performs field observations and assessments of maintenance

activities and forwards this information to maintenance.

To assess the acceptability of post maintenance testing, the inspector selected ten

completed work orders that, by the nature of work performed, would require testing

to demonstrate acceptable work completion. The inspector found that each work

order reviewed provided documentation of acceptable retesting, but noted that in

most cases, the description 'at testing requirements, as originally provided in tl:le

work order by the planners, was vague. The inspector reviewed ten more work

orders, the planning for which, had been performed within the past two months.

The inspector found that for each of these more recent work orders, the description

of the post maintenance testing was more specific. Most referenced a specific

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procedure that the technician should use to conduct a suitable test. The inspector

considered these as examples of improvement in the planning of work orders with

regard to describing required post maintenance testing.

The inspector performed field observations of mai.ntenance work iri progress to help

assess the effectiveness of improvements made to the maintenance program. The

inspector observed a calibration of a containment fan coil unit water flow controller,

installation of temporary test equipment on a turbine steam bypass valve,

assembly of a turbine auxiliary cooling pump, and .preventive maintenance for

moisture separator reheater controls. Contractors were working the first two jobs

and PSE&G personnel were working the last two jobs. The inspector found that

personnel were properly using procedures, were storing tools and* disassembled

.equipment properly, and were using measuring and test equipment (M&TE) which

had been properly calibrated. PSE&G personnel were knowledgeable regarding their

work and when in doubt, were contacting their supervisor for assistance.

In addition to the Salem plant maintenance organization, the Maintenance Services

group also performs maintenance work.- Most of the work performed by this group

is related to the site f~cilities such as buildings, traveling screens, heating boiler,

and switchyar:d. However, the group sometimes performs work on_ in-plant

systems such*as service water (a safety* related system), heater drain pumps, and

the turbine. During this inspection period, the Quality Assessment organization :

performed an audit of Maintenance Service activities; As a result of findings from .. *

• that audit regarding the M& TE calibration process and* procedure non-compliance.

within the site services activities, the manager of Maintenance Services ordered a

w.ork stoppage. During this three day stoppage, managers and supervisors *

counseled. technicians regarding procedure use and compliance, quality of work,

safety, identification of problems and use of the corrective action-program and

other applicable topics. The Salem plant management decided that Maintenance

Services would no longer be utilized for safety related work until the Maintenance

Services.management demonstrated r<>adiness for satisfactory work control and

implementation.

Conclusions

The inspector concluded from his observations that the maintenance restart action *

plan was effective. Management is aware of emergent work and actively

participates in the assignment o.f priorities to safety significant work. Overall,

maintenance personnel are willing to identify new problems and initiate corrective

action. For the activities observed, maintenance technicians were using procedures

and tools properly in the conduct of maintenance. Management actively monitors

performance and status utilizing various trending tools and through the use of self

assessments. Additionally, OA provides useful feedback regarding performance.

The inspector considers the assessment program and the QA feedback strengths in

that these feedback processes should enable manage.ment to continue the .

improvement process for the maintenance program. Through the review of

maintenance related deficiency documentation, the inspector concluded that there

are still weaknesses in the maintenance program. However, the licensee has

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significantly improved, and continues to improve the maintenance program. The

inspector concluded that the maintenance program is ready to support restart of

Salem Units 1 & 2.

M1 .3 Steam Generator Replacement Project !SGRP> Inspection Procedure 50001

a.

Inspection Scope

Inspections were performed to obtain an overview of current and planned work,

related procedures, documentation, quality inputs and progress of the .Salem Unit 1

steam generator replacement project (SGRP) .

. Specific areas inspected included observation of reactor coolant system (RCS)

welding on no. 13 replacement steam generator (RSG), feedwater (FW) pipe

welding in the fabrication shop, FW pipe welds in containment, main steam (MS)

pipe machine welding mockup practice; RSG weld planning and extent of weld

supervisory coverage; weld procedures and materials for RCS, MS, FW, steam

generator blowdown (SGBD) *piping and structural steel welding; the pre-service

inspection and inservice inspection (ISi) planning to meet the requirements of 10

CFR 50.55a(g) and .the ASME Code Section XI; adequacy of weld's for ISi, review

of Work Package 3011871086 for RSG no. 14 primary pipe welding; the as-welded

root valves; the Authorized Nuclear Inspector (ANI) involvement in SGRP activities

as documented in work packages; preparation and procedure controls for

Radiography, the quality and acceptability of interim and final Radiographs on the

RCS welds of RSGs 11, 12 & 14; original steam genere1tor (OSGI and RSG moving,

handling, rigging and lifting; observation of movement of the third OSG to and onto

the barge for transport offsite; the prejob briefing for and upending of RSG 11 in

containment; foreign material exclusion (FME) control; the basis for why the new .

insulation for RSGs and piping is acceptable; the*post RSG installation restoration

process including controls and documentation; the Polar crane remote control; Polar

Crane track clamps/seismic restraint interferences; and fire control.

The site inspection included observations of conditions and work in and outside the

containment structure.

b.

Observations and Findings

By March 1 2, 1 997, the 4 original steam generators (OSGs) had been shipped from

the site by barge for burial. The 4 replacement steam generators (RSGs) were in

place in the. Unit 1 containment building with welding of the steam generator

nozzles to the reactor coolant piping complete and accepted by radiographic

examination. Fitup and. welding of the feedwater and main steam piping was in

progress.- Restoration of other items removed as a part of the SGRP, including the

steam generator upper restraints and structural steel, was continuing.

The inspection found that work activities were generally well planned and properly

documented. The machining of the steam generator RCS nozzles and RCS piping

elbow ends to dimensions developed, using computer-based measuring techniques,

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resulted in RCS weld joint fitups that met very close tolerances. The work

packages were being tracked and closed out at a rate commensurate with work

completion. Surveillances of project conditions and specific work activities were

done by project Quality Assurance. In project areas. where problems were

identified, work was delayed or stopped until an acceptable course of action was

established. Examples of problems include the interference of the polar crane

.seismic lug with one of the track hold down lugs during positioning of the fourth

RSG, resolution of upper RSG support details, the selection of a volumetric .ISi

inspection method for the RCS elbow-to-head nozzle welds due to the difficulty of

performing an adequate UT examination of the cast stainless material, and the *

acceptability of the weld surface contour for ISi ultrasonic inspection of the FW

pipe transition pieces to RSG FW nozzles.

The engineering work packages, EWP-1 EA-1243-01 and EWP-1 EA-1243-02 and

PCI Report on Transport Analysis of Nukon Insulation (PCI ltr 90-1079-09), provide

information on the adequacy of the replacement insulation for the RSGs and piping.

These are inputs for the 10 CFR 50.59 evaluation to determine that the thermal

insulation used on the RSGs and that replaced on piping would not interfere with

the flow of water to the containment sump during assumed accident scenarios.

The engineering review of the replacement insulation was noted to be a detailed

process that, although not final, had not identified any unexpected difficulties in the

performance of the RSG arid piping insulation.

Conclusions

The inspections found a generally high level of project performance in the areas

inspected and identified no safety significant project deficiencies. For example,

controlled work packages were in use and project communication was maintained *

by prejob briefings and daily plan of the day meetings. Quality assurance, mainly

by surveillances, was continuirin. Welder qualification testing, control of weld *

materials and component welds were of high quality.

M 1 .4 Routine Maintenance Observations

a.

b.

Inspection Scope (62707)

The inspector observed routine corrective maintenance activities including the repair

of a jacket cooling water leak and restoration of the 1 C emergency diesel generator

(EOG), and the replacement of the 11 service water (SW) pump.

Observations and Findings

ii

1 C Emergency Diesel Generator

The operators identified a leak from 1 C EOG jacket cooling water system following

a post maintenance test run. Maintenance technicians pressurized .the EOG jacket

cooling system and determined that the leak was through the 7L cylinder. The

maintenance technicians removed the cylinder head and installed blind flanges to

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permit additional EOG jacket water pressure testing to ensure that there were no

other system leaks. The inspector observed the pre-evolution. brief, and a portion of

the EOG jacket cooling water pressure test and noted that the brief was thorough,

and that the testing was performed in accordance with procedure SC.MD-PT.DG-

0001, "Diesel Engine Jacket Water Pressure Test." No other leaks were identified,

and the maintenance technicians replaced the 7L cylinder head. A maintenance

supervisor indicated that the failed cylinder head would be shipped to the vendor

for a failure analysis.

During the subsequent post-maintenance testing, operators noticed variations in the

EOG output frequency. The licensee contacted the EOG vendor for technical

assistance and developed a troubleshooting plan for correcting the frequency

problem. The inspector reviewed the troubleshooting plan and determined that it

was logical. During troubleshooting, the licensee identified that the frequency

problem was caused by the electronic governor assembly. Maintena.nce technicians

replaced the assembly and successfully retested the EOG on March 6. The

inspector observed: a portion of tlie testing and noted that it appeared to be well

controlled and in accordance with the procedure.

The inspector reviewed the EOG test data taken during the post-maintenance

surveillance testing in accordance with S1 .OP-ST.DG-0003. The inspector verified

that the EOG starting response characteristics (frequency, engine speed, and

voltage) were acceptable. The inspector concluded that procedure adherence was

excellent throughout this maintenance activity, and that the licensee implemented a

. sound plan for restoring the EOG following the cylinder water leak.

11 Service Water Pump

Th~ 11 service water (SW) pump was replaced in accordance with maintenance

procedure, SC.MD-EU.SW-000, "Johnston Service Water Pump Removal .And

Installation." During the pump removal and installation activities the inspector

observed good procedure adherence, supervisory oversight, and foreign material

exclusion (FME)" controls.

During the post-maintenance testing and packing adjustment, the pump packing

assembly became overheated. The operator secured the pump, however, the heat

generation damaged. the pump shaft necessitating an additional. replacement of the

pump. Condition report (CR) 970228053 was generated to investigate the root

cause(s) for the packing problem. The investigation identified several potential root

causes for the packing problem including inadequate installation* and adjustment

instructions.

The packing was a new style packing and several inconsistencies were identified in

the vendor's guidance rega1~ing adjustment and installation of the packing. The

inspector interviewed* a design engineer and learned that the licensee intended to

replace the pump and install the original style packing. The inspector concluded

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22

. that this occurrence demonstrated poor engineering design control, but noted that

this condition was of minimal significance since the SW system was not required to

be operable for Unit 1 .

c.

Conclusions

Maintenance technicians demonstrated good procedure adherence during repair of

the 1 C EOG jacket cooling leak, and during replacement of the 11 SW pump.

Troubleshooting of the 1 C EOG frequency variations was logical. Weak engineering

controls were established prior to changing the type of packing in the 11 SW pump.

M2

Maintenance and Material Condition of Facilities and Equipment

M2. 1 Packing Leakage and Control of Deficiency Tags

a.

Inspection Scope 1717071

b.

The inspector routinely toured the facility to assess safety-related component

leakage, lubrication, and general conditiun.

Observations and Findings

The inspector identified that numerous safety-related valves exhibited. minor packing

leakage shortly after maintenance personnel had retorqued or repacked the glands

(22RH 18, 2RH71, 2CV54, 21SS116, 215546). Maintenance supervision initiated

a CR (970218215) to investigate the apparent cause of persistent packing leakage.

T.he inspector identified that a planner inappropriately closed a. packing adjustmenL

work request for 22RH18 (22 residtial heat removal heat exchanger outlet throttle

valve) and failed to remove the equipment malfunction identification system (EMl5)

tag. : A maintenance supervisor replaced the inactive EMl5 tag and initiated a work

order to repair the packing leak. In addition, maintenance staff .failed to remove

several other EM15 tags that listed previously corrected or rejected deficiencies

(22CC pump, 21 CC3, 21CC16, 2A EOG jacket water cooler).

The inspector observed inactive EMl5 tags in place identifying inadequate 2B and

2C diesel day tank level indication. On July 29, 1996, engineering closed out CR

960516192 for 2C day tank and on January 21, 1997, the maintenance work-it-

now (WIN) team rejected CM 970116120 on 2B day tank without resolving

operator concerns. The lack of resolution, combined with the inactive EMIS tags,

caused operators to unnecessarily abort a diesel fUel oil transfer pump surveillance

on February 16, 1997, and estimate daily diesel day tank log readings. Following

inspector identification, the operating shift*initiated CR 970218221 to address

diesel day tank level indication.

During the inspection, plant staff and managers separately identified several cases

of problems resulting from ineffective control of EMIS tags. As a result, the

management team planned to inspect the plant to identify and remove inactive

23

EMIS tags. In add:~::m, they intended to develop methods to improve EMIS tag

controls.

c.

Conclusions

The minor material condition deficiencies did not result in any safety consequence,

however, maintenance did not demonstrate effective packing leakage repair or

adequate EMIS tag control. Maintenance and engineering did not adequately

support operations in resolving diesel day tank level indication inadequacies. Plant

managers independently identified problems with EMIS tag controls. _The licensee

planned to systematically remove inactive tags and develop methods to improve

control of the tags.

M3

Maintenance Procedures and Documentation

M3.1 Component Cooling Pump Repair (62707)

The inspector observed* maintenance technicians repair no. 23 component cooling

pump mechanical seah Technicians demonstrated good maintenance practices

• involving foreign material exclusion, safP.ty-related part storage, tagging,* and work

area cleanliness. Technicians appropriately implemented procedure revisions in

accordance with station policy. Technicians properiy documented work and

maintained the procedure .up to date. The supervisor provided good oversight and

direction at the job site. The inspector concluded that technicians properly

controlled and conducted safety-related maintenance on the no. 23 component

cooling water pump.

MB

Miscellaneous Maintenance Issues

MS.1 NRC Restart Item 111.17, Work Control and Planning Program: Work Control Process

Improvement Restart Action Plan (Closed)

a.

Inspection Scope

Salem staff determined that emergent work, work package content; and process

inefficiencies limited work control effectiveness. The inspectors reviewed Salem

staff's resolution of these defic.iencies.

b.

Observations and Finding*s

The Work Control staff, comprising planners and scheduler.s, developed problem

statements to address major areas.for improvement. They' completed the actions

associated with the problem statements and on January 8, 1997, the Management

Review Committee (MRC) affirmed the work control process ready for restart. Each

problem statement is followed by the results of inspection for the area .

.I

,<

24

Problem Statement 1 : The existing work control process requires better definition,

structure, and discipline.

To resolve this problem, the Work Control Manager established new mechanisms

such as a WIN team to. screen and validate corrective maintenance tasks; a Minor

Maintenance program; a process for controlling limiting condition for operation

(LCO) maintenance; a checklist to establish consistency in work package quality; an

automated, on-line process for resolving work-in-progress problems; and a work

package 'completion *. retest, and closure process. s*alem management incorporated

these innovations in a* Work Control Program Manual, and trained the planning and

scheduling staff on the new processes contained in the Manual.

By a sample of

training records, the inspector confirmed planning management trained their staff

. on the Manual. The inspector also discussed the process improvements with work

control members to determine whether the measures were effective and, based on

the responses, concluded the initiatives adequately resolved the problem statement. *

This problem stateme~t is* closed. .

'

• *

.

'

Problem Statement 2: Low staffing levels and process inefficiencies hav.e

contributed to an accumulation of functional area backlogs which contribute to

material and performance deficiencies. The existing backlogs should be reduced to -

levels which permit the application of available resources to the resolution of real

time conditions.

Inspectors reviewed the status and content of the maintenance backlog during the

inspection for NRC Restart Item 111.4.2, Work Order Backlog Reduction Plan. From

. that inspection, the inspectors determined that Salem management was managing

the backlog and the inspectors no longer consider this. issue a restraint to the .

restart of Salem Unit 2. The inspectors documented the details of that inspe-ction in

NRC Inspection Report 50-272,311 /96-18. This problem statement is closed.

Problem Statement 3: Organizational functions interfacing with and supporting the

Work Control Process need improvement.

• *

To aSSE!SS the effectiveness of corrective actions taken by Salem management to

resolve this problem, inspectors attended daily work coordination meetings and - *

performed field observations of work in progress. Each day, representatives of the

principal organizations~ (maintenance, operations, chemistry, radiation protection,

fire protection, and engineering), meet for the sole purpose of discussing a~d * -

coordinating the work items which *maintenance plans to work that day. The

inspectors determined that the representatives were knowledgeable and they

conducted the meetings professionally. In several cases observe,d, operators

postponed or rescheduled work due to conflicts the staff identified during these *

meetings. In other cases, operations pointed out high priority items needing

maintenance to support operation of plant systems. *The inspector found that these

meetings improved coordination of work. From the field observations, the

inspectors determined that technicians were working priority tasks as required, and

were rnceiving support as needed from planning, supervision, and engineering when

problems arose. In one example, technicians could not ,install a pump seal in

*.

25

accordance with the procedure. The technicians stopped work, and held

discussions with engineering to resolve the problem. Later, the staff revised the

procedure to reflect the field requirements.

Inspectors monitored a Quality Assessment maintenance audit that was ongoing

during the inspection period. As part of that audit, Quality Assessment personnel

interviewed maintenance technicians to help assess the effectiveness of work

control. The inspectors. found that technicians recognized a need for more

improvement in work control but all stated that the work control staff made

significant improvements to the process during the past six months. Supervisors

frequently visited the job site, and engineering and planners were readily available

to help resolve problems.

This problem statement is closed.

Problem Statement 4: The Managed Maintenance Information System (MMIS)

needs to be enhanced to support a comprehensive work. control process .

. The Planning staff implemented software changes that made the work order system

more efficient and increased 'task accountability. For example, now work initiators

can assign minor maintenance directly to the WIN team, and senior reactor

operators can electronically approve work orders.

Also, work orders now have a

• required sign-off for job supervisors that signifies they have walked down a task

and it is ready for technicians to work. The inspector confirmed that work control

management t~ained the staff on the modifications and, based on discussions with*

the staff, concluded the enhancements had improved and streamlined the work

control process;

This problem statement is closed.

Problem Statement 5: The performance indicators used to monitor and track work

control process functions do not provide sufficient visibility of process weaknesses.

During this inspection period and in past inspection periods, inspectors reviewed

and utilized Salem performance indicators. The inspectors noted that indicators are

in place to monitor backlog status, job rework rate, work holds due to engineering

and parts requirements, and. other important indicators that enable Salem

management to identify and correct work process weaknesses. This problem

statement is closed.

Problem Statement 6: A systematic, structured Self-Assessment is needed as part

of th.e Work Management Program process control function.

Procedure SC.SA-AP.ZZ-0034(Q), Self Assessment Program, governs*

implementation of self assessments. The. adequacy of AP-34 is the subject of NRC

Restart Issue 111.21, Self Assessment Capability, and ther13fore was not part of

inspecting this problem statement.

'*

• ~ l

.*.;

26

The inspector verified that the work control and planning group performed a self

assessment in accordance with AP-34. The inspector read the assessment and

reviewed QA staff's comments regarding the assessment. The inspector noted the

QA staff made several insightful comments. First, the assessors did not discuss

work control performance with key users of the work control and planning program.

For example, the assessors did not interview personnel from radiation protection,

the work control center, chemistry, or tagging. Second, the assessment team was

made of exclusively planning and work control personnel; no personnel from outside

the organization were members. The QA team provided these comments to the

assessment team leader for resolution. Subsequently, the self assessment leader

augmented his team with representatives from the work control center and

maintenance, then conducted additional interviews with personnel from radiation

.protection, the work control center, and maintenance. The inspector reviewed the*

followup assessme.nt and noted it identified additional areas for improvement. The

inspector concluded that the work control staff adequately implemented the

assessment process. This problem statement is closed.

Problem Statement 7: Ensure functions to support on-line processes are in place

prior to startup.

The inspector noted work control management has implemented the functions that

support the work management process. For example, the inspector determined the

staff has issued the WIN Team D.esk Guide, the Radiation Protection Desk Guide,

identified work week managers, named work group coordinators, and trained the

staff on the Guides and new functions.

This problem statement is closed.

c.

Conclusions

Salem management has improved, and continues to improve, work control

effectiveness. The licensee improved the process, trained personnel, and increased

staffing levels in the planning and scti~-iuling group. The Salem staff addressed the

work order backlog and are using performance indicators' to monitor progress.

While personnel could stm improve performance, work control staff's response to

their self assessment indicated to the inspector that management would ensure the

organization continued to address deficiencies. The inspector concluded the work

control program is ready to support Salem restart.

M8.2 (Closed) Unresolved Item 50-272 & 311 /95-17-03: evaluation of corrective action

regarding Salem Unit 1 steam generator tube inspection weaknesses.

Westinghouse personnel performed the eddy current tes,ting and data analysis as a

contractor to PSE&G dur_ing the 1993 and 1995 outages. The NRC inspection

determined that Westinghouse engineers misinterpreted defects that should have

required plugging of eight tubes. Consequently, Salem technicians did not plug

these tubes. Also, Westinghouse staff used probes that were not qualified for the

application, and data from different style probes did r.ot correlate. Salem

management was very prompt and aggressive in addressing these issues. The

licensee issued a stop work order, arranged for an independent organization to

perform data reanalysis, and developed site specific analysis guidelines for eddy

27

current testing probes. Subsequently, management corrected eddy current testing

weaknesses, contracted with a new vendor for steam generator inspections, and

replaced Unit 1 steam generators. The inspector also verified that, as part of the *

maintenance restart plan, Salem management implemented significant corrective

action during the past months to improve control of contractors. Based on the

information above, the inspector considers this unresolved item closed.

M8.3 (Closed) Violation 50-272&311 /94-14-02: failure to provide adequate training to

maintenance personnel. In July 1994, maintenance personnel attempted to

implement preventive maintenance on the turbine driven auxiliary feedpump. The

objective was to change the oil in the gear box. During the process, technicians

inadvertently added oil to the governor oil reservoir and also disturbed the turbine

overspeed trip device. The turbine subsequently tripped on overspeed during post

maintenance testing.

The inspector completed an inspection on the effectiveness of the maintenance

restart plan and documented the results in Section M1 .2. Maintenance

management addressed the causes of this incident, i.e. poor training, lack of a

questioning attitude, and poor pre-job briefing, in generic maintenance program

improvements described in the restart plan. Salem staff also responded to the

violation with detailed corrective actions that addressed this specific event. Salem

staff counseled the personnel involved, enhanced training modules, and stressed to

first line supervisors the importance of good pre-job briefings. r.he inspector

concluded the corrective measures adequately addressed this issue. This item is

closed.

Ill. Engineering

E1

Conduct of Engineering

E1 .1

Generic Letter 89-10 Motor-Operated Valve Program Review IT /I 2515/109)

!Closed), NRC Restart Issue 111.a.23. Adequacy of Motor Operated Valve Program

!Closed)

Introduction and Purpose

On June 28, 1989, the NRC issued Generic Letter (GL) 89-10, "Safety-Related

Motor-Operated Valve Testing and Surveillance," requested licensees to establish a

program to ensure that switch settings for safety-related motor-operated valves

(MOVs) were selected, set, and maintained properly. Seven supplements to the GL

have been issued to provide additional guidance and clarification. NRC inspections

of licensee actions implementing the provisions of the GL and its supplements have

been conducted based on the guidance provided ir1 NRC Temporary Instruction

2515/109, "Inspection Requirements for Generi~ Letter 89-10," which is divided

into three parts.

• .* .. ~***

.'

.

-:

28

The NRC conducted the Part 1 inspection at Salem in May 1992 as documented in

NRC Inspection Report (IR) 92-80. IR 93-24 reviewed the status of the open items

developed during the Part 1 (program) inspection. A Part 2 (implementation)

inspection, conducted in November and December 1993, was* documented in NRC

IR 93-26. An initial Part 3 (closure) inspection was documented in IR 96-11.

A public meeting was held on November 12, 1996, to discuss PSE&G plans to

complete the Salem Unit 2 MOV program, as well as to discuss the unresolved

issue of MOV program status in the context of 10 CFR 50.9(b). The slides .

presented by PSE&G during the November 12th meeting are attached to this

inspection report. The purpose of this more recent inspection was to review

PSE&G's corrective actions for the findings from IR 96-11 and to again address

~losure of the GL 89-10 program at Salem Unit 2.

El .2

Summary Status of Generic Letter 89-1 O MOVs

a.

lnsi:~ctior Scope

In GL 89-10, the NRC requested notification within 30 days after the MOV design-

basis reviews, analyses, verifications, tests, and inspections have been completed.

In a letter dated March 20, 1995, PSE&G notified the NRC that the committed

programmatic actions taken to address Items a through h of GL 89-1 0 had been

completed at Salem Unit 2. The inspectors reviewed PSE&,G's S-C-VAR-NEE-1.117,

. "Generic Letter 89-10 Closure Summary for the Motor Operated Valve Program as

.Implemented at Salem Unit 2," Rev. 0, and documents associated with all MOVs in

the GL 89-10 program. Using these documents, a valve s~mple was selected that

included examples of all methods used to demonstrate design-basis capability .

. b.

Observations and Findings

PSE&G used several methods to demonstrate MOV design-basis capability which

included verification by:

Valve-specific dynamic test at, or near, design-basis conditions,

Valve-specific test, linearly extrapolated to design-basis conditions,

In-plant information *obtained from .dynamic tests on similar MOVs. and

Electric Power Research lnstitute's (EPRI) Performance Prediction Model

(PPM) applied to MOVs that were not practicable to test.

PSE&G had dynamically tested 46 of the 94 MOVs in the GL 89-10 population at.

Salem 2. PSE&G provided information for the 94 MOVs which were grouped into

16 l'v10V families. The inspectors reviewed special test pack<;1ges and engineering

evaluations for the following MOVs:

22SJ40

2RH1

2CC136

22SJ33

21SJ113

(Family 2)

(Family 6)

(Family 5)

(Family 1)

(Family 3)

E1 .3

MOV Sizing and Switch Settings

a.

Inspection Scope

29

Safety Injection Pump to Hot Leg Isolation Valve

Reactor Coolant System (RCS) Hot Leg to

Residual Heat Removal (RHR) Suction Header

Valve

Reactor Coolant Pump (RCP) Motor Bearing

Cooling Water Outlet Valve

Safety Injection Pump Suction Valve

Containment Spray Pump Discharge Isolation

Valve

The inspectors reviewed valve packages that established the thrust requirements

for MOVs in their GL 89-10 program. These documents included thrust calculations

and test evaluation packages associated with the selected MOVs. PSE&G's

methods for determining minimum thrust requirements were documented in Motor

Operated Valve Program - Appendix 6 "MOV Mechanical Capability Review,"

Rev. 4, dated June 7, 1994, and EE: A.-O-ZZ-MEE-0609, "MOV Program Position

Papers," Rev. 5, dated April 9, 1996. The purpose of this review was to assess

the licensee's justifications for assumptions used in MOV thrust calculations which

form the basis for determining the design-basis* requirements.

b.

Observations and Findings

PSE&G's thrust calculations typically utilized the standard industry equations.

Mean seat diameter was used to calculate valve seat area. Valve factors were

based on the in-plant test results or other industry sources as specified by the

licensee's grouping methodology. A stem friction coefficient of 0.20 was used for

determination of actuator output thrust capability. The licensee applied margin to

account for diagnostic equipment uncertainty, torque switch repeatability, 1*oad

sensitive behavior, and potential valve degradations.

Valve Factor and Grouping

PSE&G classified Salem MOVs into valve families Qased on manufacturer, type, and

ANSI pressure class rating. Some families contained a range of valve sizes.

PSE&G attempted to use in-plant data for justification of valve factors for non-

9ynamically tested MOVs. However, PSE&G did not have* sufficient in-plant test

results to .adequately .cover all valve groups. During the program review, the

inspectors noted that the licensee initially did not provide adequate justification_for

MOVs in Families 6 and 9. However, further discussion resolved -the inspector's

comments as follows:

_-;.

30

Family 6: 14" Copes Vulcan 2500psi Parallel Double Disk Gate Valves

This family consisted of the RCS hot leg-to-AHR suction header valves

(2RH1 and 2RH2). PSE&G was unable to obtain in-plant or applicable

industry data for these valves. To address this issue, the licensee reviewed

the "separate effects" friction test program that.was conducted by EPRI as

part of the Performance Prediction Program (PP~). A friction coefficient of

0.55 was selected based on an expected operational water temperature of

200-300° F. This justification was not considered adequate for program*

closure because the EPRI separate effects testing was only one of many

parts of what the NRC reviewed regarding the PPP.

After discussion with the inspectors, PSE&G revised its valve factor for

these valves to 0;61 which was based on the maximum value experienced

during dynamic in-situ testing at Salem Unit 2. Also, PSE&G intended to

modify valve 2RH1 prior to restart to make it comparable to valve 2RH2~

thereby improving its actuator capability. While both valves were shown to

have adequate design basis capability, the inspectors noted that the valve

factor basis for these valves was still weak and' could be better support~d in

the long term. Based on PSE&G's irtent to pursue an improved valve factor

basis for these valves as part of their periodic verification program an'd

.

modifications to be performed prior to restart, the inspectors concluded that

these valves wer.e acceptable for GL 89-10 closure. An inspector followup

item will track implementation of. issue 2RH 1 and 2. (IFI- 50-J11 /97-03-03)

Family 9: 3" & 4" Velan Flex Wedge Gate Valves

The inspector's comments for this family focused on the power operated

relief valve (PORV) block valves (2PR6 and 2PR7) and the RCP thermal

barrier isolation valves (2CC131 and 2CC190). PSE&G modified the PORV

block valves to operate them based on limit switch control. * The

modification provided ari "available" valve factor (i.e., functional upper limit)

of 0.61 to close the valve. Given this apparent capability, use of a 0.2 stem

friction coefficient, and the application of actuator pullout efficiencies, the

inspectors considered the current settings of the PORV block valves to be

adequate. _However, the inspectors requested PSE&G to confirm the

technical adequacy of the basis for valve factor, and to address any potential

non-predictability for the PORV block valves as part of Salem Unit 2's

periodic verification program. PSE&G agreed and stated* that they will

review the possibility of applying the EPRI PPM methodology for these

valves. An inspector followup item will track implementation of this issue

for valves 2PR6 and 7. (IFI 50-311197-03-04)

For the RCP thermal barrier isolation valves (2CC131 and 2CC190), the

licensee used EPRI PPM test data in a unique manner to determine a

bounding valve factor of 0.64. The unique treatment of the EPRI PPM test

data was described in a vendor (MPR Associates) calculation that was

included as Attachment 24 to PSE&G's Engineering Evaluation S-C-VAR-

31

NEE-111 7. The statistical approach utilized in this calculation was not

endorsed in the NRC's safety evaluation of the EPRI PPM, and was

considered to be unacceptable for GL 89-10 closure.

PSE&G revised the valve factor to 0.54 which was based on the highest

value obtained from testing similar Salem Unit 2 valves. Both valves were

still shown to have positive thrust margins, with 2CC 1 31 the least at 8 % ..

While the inspectors considered this acceptable for GL 89-10 closure,

PSE&G was requested to take measures at the first opportunity to improve

the actuator capability for these MOVs. The inspectors also requested

PSE&G to confirm the technical bc:1sis of the valve factor, and to address any

potential non-predictability for these valves as part of periodic verification.

PSE&G agreed and stated that they will review the possibility of applying the

EPRI PPM methodology for these valves. An inspector followup item will

track implementation of this issue for valves 2CC131 and 190; UFI 50-

311/97-03-05)

Load Sensitive Behavior

Attachment 19 of the Unit 2 Closure Summary documented a statistical analysis of

75 data points, an average load sensitive behavior of 3. 7% and a standard

deviation of 9.6%. Based on this analysis, the licensee's error analysis added 4%

directly as a bias margin and 21 % as a random value that was included with other

uncertainties using the square root sum of the squares method. The inspectors

found the licensee's analysis and load sensitive behavior margin to be acceptable

• for non-dynamically tested MOVs at Salem Unit 2.

Stem Friction Coefficient

PSE&G recently completed a comprehensive stem friction coefficient review of the

results from in.:plant testing. Based on this study, PSE&G increased Unit 2's

assumed stem friction coefficient value from 0.15 to 0.20. The inspectors found

the licensee's stem friction coefficient justification to be acceptable for* Salem

. Unit 2.

.

Degradation Margin

NRC Inspection Report 50-311 /96-11 noted that the licensee's margin to address

potential future valve degradations may not exist if other uncertainties were large

enough to consume the fixed 30% margin that was used to account for these

uncertainties. Recently PSE&G revised their setup methods to include a 5% bias

margin to account for degradations as a part of their standard error analysis.

Results from Salem's periodic verification program will be used to revise this 5%

margin if necessary. The inspectors found this approach to be acceptable .

.;.

~ ..

. j

. (

• • • ~

1

. !

c.

El.4

a.

32

Linear Extrapolation

The inspectors reviewed Section 4.4.5 of the Unit 2 Closure Summary which

contained PSE&G's justification for use of linear extrapolation to account for

differences between dynamic test conditions and design-basis conditions. PSE&G's

justification was based on results from EPRl's PPM. The inspectors did not identify

any concerns with the licensee's general method for extrapolating test results.

However, the inspectors requested that PSE&G review the NRC~s Safety Evaluation

(SE) by the Office of Nuclear Reactor Regulation of Electric Power Research

Institute Topical Report TR-103237,

11EPRI Motor-Operated Valve Performance

Prediction Program,

11 dated March 15, 1996, and EPRl's latest recommendations

related to use of linear extrapolation. The licensee's review was requested to

ensure that adequate disk loading was obtained during testing at Salem Unit 2, and

in*order to improve the reliability of wide extrapolations.

Conclusions

The justifications for key program assumptions were complete and the applied valve*

factors for Salem Unit 2 MOVs were adequate for GL 89-10 closure. These

conclusions were based on the understanding that PSE&G would pursue actions for

certain MOVs in Families 6 and 9 in conjunction with the periodic verification

program for Salem Unit 2 MOVs. * These additional evaluations were agreed to be

formalized in a revision of the Salem Unit 2 GL 89-10 closure summary document

S-C-VAR-NEE-1117.

The inspectors noted that progress was achieved since the previous NRC inspection

as reported in NRC Inspection Report 50-311 /96-11 . The inspectors also noted

that NC.DE-PS.ZZ-0033(0), "Motor Operated Valve Programmatic Standard and

Appendices,

11 was not consistent with PSE&G' s current margin and error analysis

assumptions, as presented in the Salem 2 GL 89-10 Closure Summary document.

Design-Basis Capability

Inspection Scope

The inspectors reviewed dynamic test evaluation packages that were performed in

accordance with Appendix 14 of the Motor Operated Valve Programmatic Standard

and associated test reports for the selected MOVs. The purpose of this review was

to assess P5E&G's efforts to establish des!gn-basis ~apability for all MOVs in Salem

Unit 2's GL 89-10 program.

b. . Observations and Findings

Reactor Coolant System Hot Leg-to-Residual Heat Removal Suction Header MOVs

During the initial review of Salem Unit 2's Closure Summary document, the

ir1spectors noted that the RCS Hot Leg to RHR Suction Header Valve (2RH 1 -

Family 6) had an identified 1 % thrust margin. As noted in Section E1 .3 of this

._

.,

33

report, the licensee had applied a 0.55 valve factor which was inadequately

justified. Further, the inspectors noted that the margin calculation for 2RH1 did not

include any margin for load sensitive behavior (because of limit switch control), or

valve degradation. However, as discussed in Section E1 .3, after further discussion

with the inspectors, the licensee changed the approach to demonstrating design

basis capability by adopting a higher valve factor and agreeing to perform

modifications prior to restart of Salem Unit 2. The inspectors concluded that this

was acceptable for these valves for GL 89-10-closure.

Thrust Margin Improvement

The inspectors noted that several Salem Unit 2 MOVs were scheduled for margin

improvements. However, the following MOVs. had adequate basis for the applied

thrust requirements, but had low thrust margins and were identified by the

inspectors to ensure that they are included in PSE&G's margin improvement plans:

. 2CC136

21BF13

22CC16

22BF13

2SJ4

2SJ5

The licensee was requested to review this list and to include these MOVs as part of .

their margin improvement program. PSE&G personnel agreed to conduct this

review. Closure of these MO Vs under the generic letter program was considered

contingent upon the licensee's agreement .to improve the margin of these MOVs as

part of Salem Unit 2's long term MOV program (IFI 50-311197-03-06).

Pratt Butterfly Valves

'*

Family 16 consisted of 8" and 24" Pratt butterfly valves. The licensee used the

EPRI PPM butterfly model to develop the torque requirements for these valves.

Further, the licensee has initiated Minor Modification package No. S-96-019 to

change the spring packs which will increase the output capability for the four 24"'

valves. However, these modifications were not complete at the time of the

inspection. PSE&G has scheduled these modifications to be completed prior to

restart of Salem Unit 2. The inspectors concluded that the methodology for setting

the torque switches for these valves was acceptable for GL 89-10 closure .

. MOV Thermal' Overloads

During a rncent inspection of the component cooling system as reported in NRC

Inspection Report 50-311 /96-81, the inspectors found that design change DCP

2EC-3249 installed thermal overload (TOL) relay heaters on MOV circuits that were

different than the design basis calculation ES-18.006. The inspectors requested

confirmation that the correct heater sizes were used in the MOV program, NC.DE-

PS.ZZ-0033 (Q). Appendix 5, Electrical Capability Review, of this MOV program

document presented the methodology establishing the degraded voltage factor for

the MOV program analyses. The MOV group maintains a separate file for each

valve in which the TOL heater resistance is used in part of the analysis to determine

the voltage at the valve motor.

..

34

In response to the inspector's concern, PSE&G compared the as-installed TOL

heaters with the TOL heaters used in the analyses. PSE&G identified spray additive

isolation valve 2CS14 and RCP motor and bearing cooling water valve 2CC118

with heaters that were a smaller size than used in the analyses and, because of

their increased resistance, would result in a lower degraded voltage factor than that

used in the MOV program analysis of record. PSE&G reran the analyses for 'these

two valves and reviewed the results with the inspectors. The results of the

reviews indicated that the degraded. voltage factors would decrease by 2 % but the

• valves were still capable of developing sufficient torque under the new degraded

voltage conditions.

PSE&G prepared AR 970116087 to document this discrepancy.

c.

Conclusions

The inspectors concluded that PSE&G had adequately demonstrated design basis

capability for Salem Unit 2 MOVs such that the NRC review of GL 89-10 could be

closed. This inspection also closes NRC Restart Issue 111.a.23, Adequacy of Motor

Operated Valve Program. This conclusion was based on the understanding that

PSE&G would pursue actions for certain MOVs in Families 6 and 9 in conjunction

with the periodic verification program for Salem Unit 2 MOVs.

El .5

Pressure Locking and Thermal Binding

a.

Inspection Scope

The inspectors reviewed the evaluation of gate valves susceptible to pressure

locking (PL) and/or thermal binding (TB) which the licensee had completed in

response to GL 95-07, "Pressure Locking and Thermal Binding of Safety-Related

Power-Operated Gate Valves." As indicated in the licensee's response to GL 95-07.

dated February 13, 1996, PSE&G identified 8 valves (21 CS2, 22CS2, 2SJ 1 2,

2SJ13, 2SJ1, 2SJ2, 21 SJ113, and 22SJ113) that were considered to be

susceptible to PL for Salem Unit 2. In addition, PSE&G identified 4 valves

(21CC16, 22CC16, 2PR6, and 2PR7) that were considered to be susceptible to

thermal binding for Salem Unit 2.

b.

Observations and Findings

PSE&G in_dicated that holes were drilled in 6 of the 8 valves that were susceptible

to PL. In addition, PSE&G modified the procedures for the 21 CS2 and 22CS2

valves to include valve cycling after surveillance testing. The inspectors concluded

that the licensee's modifications were adequate to address the susceptibility of PL

for the modified valves.

PSE&G also indicated that TB concerns were addressed for the PORV block valves,

PR6 and PR7, by modifying the MOV control circuit from torque control to limit

control. It was noted that the unwedging force was significantly decreased

following the modification. The MOV static test trace from the diagnostic

35

equipment (i.e., VOTES) indicated approximately 2673 lbs. of unwedging force for

the PR6 valve. A calibration error of 40% was added to the unwedging force;

therefore, the unwedging force for PR6 was recalculated to be about 3842 lbs.

The inspectors were not able to verify the unwedging force for PR7 due to

diagnostic sensor problems.

By letter dated July 1, 1996, the NRC staff asked PSE&G to supply additionai

information concerning their submittal in response to GL 95-07. By letters dated

August 7 and 30, 1996, PSE&G provided a response to the staff's request for

additional information. PSE&G indicated that the RH-26 valves were not within the

population of valves considered to have a safety-related or important to safety

function to open; therefore, the licensee did not evaluate the susceptibility to PL for

~he RH-26 valves. The inspectors noted that PSE&G's position concerning 2RH26

remained the same during this inspection as it was not included in the scope of the

GL 89-10 program (see Section E1 .2). Regarding the PORV block valves PR6 and

PR7, PSE&G indicated that an evaluation of these valves under conditions

associated with a steam generator tube rupture had been completed. The licensee.

concluded that there was a negligible effect on the required unwedging thrust for

the PR6 and PR7 as a result of a steam generator tube rupture. Accordingly, the

licensee concluded that there was no increase in the required thrust associated with

the PL scenario. PSE&G indicated that valve specific evaluations were performed

with respect to valve and system function; however, no specific training had been

conducted regarding modifications.

The inspectors noted that PSE&G utilized the services of MPR Associates, who

developed an .analytical method to determine a maximum inertial thrust limit below

which TB should not be a concern for the 21CC16, 22CC16, 2PR6, and 2PR7

valves ...* In reviewing the MPR analysis, the inspectors determined that the test data

that was used for this analysis did not completely validate the model to determine

the susceptibility to TB for the PR6 c>~1 PR7 valves. In addition, the inspectors

found that MPR's key assumption in their calculations for deriving a PLfTB model

may not adequately consider transient or steady state temperature gradients in the

valve .body or valve disk.

The MPR analysis included an analytical method that was utilized to demonstrate

that the actuators on the PORV block valves, PR6 and PR7, could develop adequate

thrust to overcome pressure locking. PL thrust requirements for these valves were

calculated by a method of the MPR analysis. The inspectors independently

calculated the thrust required to overcome PL and determine the actuator capability

for the PR6 and PR7 valves and concluded that the actuators were able to develop

the thrust required to overcome PL.

The inspectors noted that a response to one item of the RAI was still required by

the licensee and had not been submitted. The licen~ee indicated that a response to

this item would be submitted to the NRC in th~ near future .

I

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36

c.

Conclusions

The inspectors did not find any immediate safety or operability concerns regarding

' -)

any Salem Unit 2 MOVs. PSE&G's modifications and other actions to address PL

and TB in the short term were acceptable. However, in the long term for satisfying

GL95-07, PSE&G was requested and agreed to determine and confirm at the

earliest opportunity that the unwedging force for 2PR7 is comparable to 2PR6.

Also, PSE&G was requested and agreed to further discuss and resolve with the

NRC questions regarding assumptions and test validation of the MPR Associates PL

and TB analytical model.

El .6

MOV Failures. Corrective Actions, and Performance Trending

a.*

Inspection Scope

b.

The inspectors reviewed two recent MOV fanures concerning component cooling

(CCI water "alve 22CC3 and service wat'3r valve 22SW17. The inspectors

evaluated the causes of the failures, implications of the failures for similar MOVs,

and the comprehensiveness of the corrective actions. These failures were then

reviewed within the context of. PSE&G's methodology to track and trend MOV

performance as described in the MOV program procedure Appendix 18, "MOV

Tracking and Trending Assessment."

Observations and Findin*gs

Torque Switch Failure of 22CC3

During differential pressure (DP) testing of the CC pump discharge header isolation

valve 22CC3 using a variable transformer (i.e., VARIAC) to simulate degraded

voltage conditions, the torque switch failed to open even though the valve closed.

The motor stalled at a torque value of about 5 ft-lb below the torque switch trip

value of 352 ft-lb. The license*e disassembled the actuator and found no significant

mechanical conditions which confirmed the initial thoughts that the actuator was

not the cause of the failure. PSE&G also reviewed the VOTES diagnostic trace,

disassembled the motor, and found no abnormalities. The motor was then sent to

Liberty Technologies for further evaluation off site. Tests of the motor were not

conclusive in determining why the motor stalled during the DP test.

PSE&G replaced the motor on 22CC3 and performed the DP test successfully.

However, PSE&G is still evaluating the 22CC3 failure under an open Action Request

and has postulated that the motor may have stalled because of loose cable

connections associated with the variac used for this degraded voltage test. Further

motor disassembly and inspection was being evaluated to better define the root

cause of the problem. The inspectors concluded that PSE&G was evaluating this

problem consi~tent with the requirements of the GL 89-10 program .

f'

37

Incorrect Torque Switch Setting of 22SW17

Service water isolation valve 22SW17 is a limit-seated butterfly valve which has a

torque switch wired in series with the limit switch. The torque switch is generally

not actuated and it is set to trip at maximum allowable torque for component

protection. On September 4, 1996, PSE&G operations closed 22SW17 under

dynamic loading but did not receive the closed indication. While the valve fully

closed, there appeared to be an indication problem. Operations informed the Salem

MOV program manager who initiated corrective actions to review this and other

similar MOVs for this problem.

On November 1, 1996, during DP testing, 22SW17 failed to fully close on its limit

.switch. Action Request 961101135 was issued to take appropriate corrective

actions. PSE&G discovered that the torque switch setting was erroneously set to

1.0 in lieu of the correct setting of 1.5 for both the open and close directions. This

setting prematurely deenergized the motor causing the valve to stop before

reaching its full closed position. In the subsequent investigation, the licensee

• determined that maintenance personnel had removed the valve and actuator to the

maintenance shop and inadvertently changed the torque switch setting during

"bench testing" in the shop. PSE&G concluded that the incorrect torque switch

setting was due to human error in that new personnel were at fault for not restoring

the torque switch to its proper setting. The inspector noted that the lack of

independent verification of maintenance activities involving torque switch settings

during the maintenance shop work contributed to the failure of 22SW17.

As corrective actions per AR 9611001135, PSE&G was verifying the torque switch

setpoint for each of the limit-seated butterfly valves and other limit seated valves.

In addition, PSE&G will revise the MMIS data base -by providing only the maximum

torque value *and torque switch setting for limit-seated MOVs. This should

eliminate erroneous use of the minimum torque setpoint which is not applicable for

limit-seated MOVs.

The inspectors considered the corrective action for the 22SW17 valve to be

adequate. However, it was noted that the licensee could enhance its independent

verification process in its MOV maintenance procedures. The inspectors considered

this to be an area of weakness requiring thorough licensee evaluation before

closeout of AR 9611001135. The inspectors had no further comments.

Tracking and Trending

The inspectors verified that the licensee has an adequate program, in place, to

annually examine pertinent MOV documentation for trending purposes. *The

inspectors noted that a detailed database was implemented in order to track MOV

test data and MOV failures. The inspectors noted that overall parameters for

monitoring MOV performance were well-de:fined and properly implemented for

tracking and trending purposes. The annual MOV review will be fully documented

in accordance with the requirements of the Salem corrective action program.

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c.

Conclusions

The inspectors concluded that PSE&G was adequately addressing MOV

performance problems by taking appropriate corrective actions. PSE8tG had

developed a good MOV tracking and trending program.

E1. 7

Post Maintenance Testing

a.

Inspection Scope

The inspectors reviewed Salem's MOV post maintenance testing (PMT) practices as

described in procedure NC.NA-AP.ZZ-0050(0), "Station Testing Program."

b.

Observations and Findings

The inspectors verified that the licensee's procedure adequately described the

process of identifying PMT and ensured that components or systems perform as

intended when returned to service, following corrective or preventive maintenance

activities. In addition, PSE&G adequately defined maintenance activities which

would create the need for a PMT of the affec1:ed component or system.

c.

Conclusions

The inspectors concluded that PSE&G *established and implemented an adequate

MOV PMT program as recommended by GL 89-10.

E1 .8.

MOV Program Administration

a.

Inspection Scope

b.

The inspectors reviewed the governing MOV program procedure NC.DE-PS.ZZ-

0033(0) and supporting appendices throughout the inspection and observed how

the various implementing procedures were controlled to fulfill program

requirements. This review included the licensee's efforts regarding periodic

verification of MOV design basis capability in response to GL 96-05.

Observations and Findings

PSE&G prepared a sound Engineering Evaluation s.-C-VAR-NEE-1117 to present the

Salem Unit 2 MOV information in an organized manner for this inspection. The

MOV staff demonstrated a thorough understanding of the MOV issues in presenting

the MOV program for closure. The inspectors requested that PSE&G formally

revise Engineering Evaluation S-C-VAR-NEE-1117 to include the changes discussed

during this inspection. Consistent with the Salem Quality Assurance program

requirements, PSE&G recognized the need to update the MOV program procedure

NC.DE-PS.ZZ-0033(0) and associated MOV calculations to be consistent with the

information presented during this inspection .

..

39

The inspectors reviewed Salem's MOV periodic verification program as describe in

procedure EE:S-C-VAR-NEE-1117, Rev. 0. The inspectors verified that PSE&G has

a surveillance work order in place to perform a recurring task for static testing each

MOV of the GL 89-1 0 program every 5 years or 3 refueling outages, whichever is

later.

PSE&G is in the process of determining periodic verification plans for performing

dynamic tests of GL 89-10 valves. The inspectors noted that the licensee intends

to perform some dynamic testing. This item will be further reviewed under GL 96-

05.

c.

Conclusions

E1 .9

a .

b.

The inspectors concluded that PSE&G was implementing adequate administrative

controls for the Salem Unit 2 MOV program. PSE&G prepared a sound engineering

evaluation to present the Salem Unit 2 MOV information in an organized manner for

this inspection.

Containment Fan Cooling Unit Service Water Isolation Valve Testing

Inspection Scope(37751)

The inspector reviewed the licensee's plan for operation of the containment fan

cooling units (CFCUs) during a planned Unit 2 Mode 4 entry.

Observations and Findings

The inspector attended a Station Operations Review Committee (SORC) meeting

and learned that station management planned to enter Mode 4 with two CFCU

units operational and with the SW cooling supply isolated and drained for three

CFCUs. The CFCUs were removed from service to support installation of a design

change package intended to resolve generic service water (SW) pressure transient

concerns identified in NRC Generic Letter 96-06.

The SORC approved an operability determination which demonstrated that 2 CFCUs

were adequate to support the potential containment cooling requirements for the

Mode 4 entry.

The inspector noted that one SORC member questioned whether the drained SW

cooling lines presented a containment integrity concern.

The inspector subsequently reviewed the updated final safety analysis report

(UFSAR) Table 6.2.-13 which stated, in part, that the SW containment isolation

vc..lves had been exempted from Appendix J, Type C ler;ik rate testing since the

valves were normally open to support CFCU operation. The inspector questioned

whether the basis for the leak rate test exemption as described i.n the UFSAR

remained applicable with the SW lines drained and isolated .

40

The licensee subsequently prepared, and the SORC approved a 10 CFR 50.59

safety evaluation to revise the UFSAR to clarify the basis for not Type C leak rate

testing the SW isolation valves. The 10 CFR 50.59 concluded that these valves did

not meet any of the required categories of valves subject to Type C testing. The

approved 1.0 CFR 50.59 adequately addressed the inspector's UFSAR compliance

concern.

The inspector noted, however, that NRC follow-up was required to get a fully

satisfactory response to the containment integrity question raised at the first SORC

meeting. The inspector concluded that the ineffective follow-up demonstrated a

weak safety perspective by station management.

c

Conclusions

SORC approved a 10 CFR 50.59 which adequa'tely addressed inspectors concern

regarding the UFSAR commitments for Type C leak rate testing the CFCU SW

cooling line containment isolation valves. Station management demonstrated a

, weak safety perspective by not ensuring an appropriate response to the

containment integrity question raised at the SORC meeting.

E1.10 Surveillance 'Effectiveness

a.

Inspection Scope (61726)

Inspectors monitored Salem staff response to an identified surveillance deficiency.

b,

Observations and Findings*

As a result of a proposed modification to the control circuitry for automatic

operation of the pressurizer Power Operated Relief Valves (PORVs), a system

• manager discovered that the surveillance procedure for the Pressurizer Overpressure

Protection System (POPS) did not completely test the operation of the automatic

controls. The surveillance procedure previously required operators to turn off each

chann.el of POPS while technicians inserted a test signal on the input of the circuit.

As a result, plant staff had not demonstrated that the output relays actuated as

required. The plant staff immediately developed a method to test the circuit from

input to output and successfully demonstrated operability of the POPS. The

inspectors considered the previous failures to completely demonstrate operability of

POPS a non-cited violation, since PSE&G shut down both Salem units to correct

long-standing plant deficiencies subjected to NRC enforcement action, and because

the Salem staff identified the violation, and took appropriate corrective action. In

addition, .the violation stemmed from procedure inadequacies existing prior to the

Salem shutdown.

The inspectors noted that the Salem Technical Specification Surveillance

Improvement Project, phase 2, would probably have detected this type of

surveillance deficiency. Since Salem management has not scheduled completion of

TSSIP phase 2 until the end of 1997, the inspectors considered it probable that, if

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41

not for the implementation of the PORV control circuit modification, Salem staff

would have detected the lack of a complete POPS surveillance until well after

Salem Unit 2 restart .

c.

Conclusions

ES

As a result of a proposed modification, an alert system manager discovered an

incomplete surveillance of the circuit for automatic operation of the Pressurizer

Overpressure Protection System. Plant staff immediately devised and completed an

effective test. The inspectors noted that TSSIP, phase 2, scheduled for completion

in late 1997, would have probably discovered this defici~ncy.

Miscellaneous_ Engineering Issues

ES. 1

Control Room Ventilation Modification Testing

a.

Inspection Scope. (71707)

Inspectors observed engineering staff actions to insure that the newly modified

control room ventilation system met design requirements.

b.

Observations and Findings

During the inspection period, the Salem staff expended considerable effort to --

demonstrate that the ventilation system could develop the required positive

pressure in the control room area compared to air pressure in adjacent rooms and

the outside air pressure. Although plant management and staff considered the

possibility of a license change request to change the licensing basis requirement for

differential air pressure, they decided instead to make the system perform as

designed. As a result of trouble-shooting activities, such as temporarily covering

ventilation dampers to assess air leakage from the control room envelope, plant

staff discovered that the switchgear and penetration area ventilation system

(SPAVS) pressurized the rooms adjacent to the control room area. The Salem staff

identified and corrected the leak paths allowing SPAVS to pressurize areas adjacent

to the control room. The engineers subsequently demonstrated the ability of the

control room ventilation system to perform its design basis function.

c.

Conclusions

The inspectors concluded that the engineering staff conducted appropriate trouble-

shooting to determine the cause of control room ventilation performance problems.

The Salem managers properly elected to correct system deficiencies rather than

change the licensing basis for control room ventilation. As a result .of considerable

effort, the engineering staff successfully demonstrated the ability of control room

ventilation to perform its design function .

E8.2

E8.3

a.

42

(Closed) Unresolved Item 50-272 & 311/95-17-02

The inspectors previously identified that a commitment to install a concrete curb at

• the entrance fo each Salem Unit 1 and 2 Emergency Diesel Generator (EOG)

cubicle, contained in a July 26, 1978 letter from PSE&G to the NRC, had not been

implemented. The purpose of the curbs was to prevent the potential spread of

. diesel fuel to areas outside of the individual cubicles .. The failure to implement the

commitment to install the curbs was interpreted as a weakness in the licensee's

commitment management processes.

The inspector toured the EOG cubicles at Salem Units 1 and 2 and noted that

curbs, fabricated from steel angle (approximately 3 inches high) with caulking, had

.been installed. at the entrance to each Unit 2 EOG cubicle; no curbs had been

installed at the Salem Unit 1 EOG cubicles. The licensee indicated that the caulking

is resistant to diesel fuel oil.

The inspector reviewed the process that the licensee used to change the

commitment from installation of concrete curbs to installation of caulked steel

curbs. In response to a request from the inspector, the licensee provided "FORM.,4,

NUCLEAR BUSINESS UNIT; COMMITMENT CHANGE EVALUATION SUMMARY

FORM" Which addresses the EOG curb commitment change and was approved on

November 1, 1996. The "FORM -4" is an enclosure to the licensee's procedure

NC.NA-AP.ZZ-0035(0), Revision 5, dated December 27, 1995 and is* to be used in

Step 5.1.4 for "Changes to commitments made to the NRC in response to GLs,

Notices of Violations (NOVs), Inspection Report Followup Items, and Bulletins."

The inspector noted that "FORM-4" follows the process of the "NEI Guidelines for

Managing NRC Commitments - Revision 2", dated December 19, 1995 that was

endorsed by NRC letter dated January 24, 1996. Based upon the review of the ... :

subject "FORM 4", the inspector found the change in commitment, and installation

of the caulked steel curb, to be acceptable.

The inspector noted that the licensee had closed the commitment tracking form for

the Unit 1 and 2 commitment without implementing the installation of curbs at the

Unit 1 EOG cubicles. The licensee responded to this finding by opening a new*

commitment, using the Commitment Manager database, to assure installation of the

curbs at Unit 1 . Based upon installation of the curbs at Unit 2 and the commitment

to install the curbs at Unit 1, this item is closed.

NRC Restart Item 111.1, Unresolved Items 50-272&311 93-80-06, 07, and 08

(Open) - Appendix R jumpers and program discrepancies, including fire barrier

penetrations

Inspection Scope

NRC Inspection Report 50-27 2, 311 /93-80, identified nine Unresolved Items. This

inspection addresses three of these items: URI. 272/311-93-80-06, non-

conservative assumptions, licensee using only one spurious operation per fire

incident; URI 272/311-93-80-07, requirement to perform repairs for Hot Shutdown

--~

b.

c.

43

contrary to SER statement; and URI 272/311-93-80-08, licensee method of

protecting equipment from damage by fire.

Observations and Findings

By letters dated August 2, 1993, and October 26, 1993, the licensee submitted

additional information. By letter dated January 25, 1996, the staff sent its

evaluation which concluded that Salem's safe shutdown capability was

unacceptable because redundant trains of equipment necessary to achieve and

maintain hot shutdown conditions may be damaged by a single fire and the

licensee's analysis for fire-initiated spurious signals was inconsistent with the

established staff positions promulgated in Generic Letters 81-12 and 86-10.

By letters dated June 19, 1996, and December 2, 1996, the licensee committed to

implement certain modifications to resolve the NRC concerns. The modifications

are needed to meet the requirements of Appendix R to 10 CFR Part 50. These

include the installation of isolation transfer switches for the required safe shutdown

functions controlled by the alternative shutdown system and the modification of the

control circuits for certain motor operated valves in order to resolve the concern

about multiple hot-short spurious damage from associated circuits in the fire area.

The licensee proposed to implement all of the modifications prior to restart of Unit

1, and, for Unit 2, during the first refueling outage following restart. In response to

an NRC request, the licensee provided, in a letter dated February* 18, 1 991,

compensatory. measures that will be taken until the modifications are implemented

on Unit 2.

By letter dated March 17, 1997, the staff determined that reliance on

these compensatory measures is not appropriate to provide adequate protection of

public health and.safety, and, therefore, concluded that the modifications are

• required to be in place prior to its restart.

Conclusions

Pending satisfactory implementation of the modifications proposed by the licensee

in its letters of June 19, 1996, and* December 2, 1996, the staff concludes that

URI 272/311-93-80-06, -07, and -08 remain open. The basis for this conclusion is

contained in the NRC letter dated. March 17, 1997.

EB.4

(Closed) Unresolved Item 50-272&311 /96-06-02: failure to perform a 10 CFR

50.59 safety evaluation for a degraded emergency diesel generator jacket water

after-cooler heater condition regarding the UFSAR requirements. The jacket water

after-cooler heater was inoperable for approximately one year yet Salem engineers

performed no safety evaluation. Subsequently, engineers performed a safety

evaluation for this condition and prepared a UFSAR change request to clarify the

function of the after-cooler heater. The inspector reviewed the safety evaluation

and the UFSAR change request and found they satis~actorily resolved this issue.

Management resolved the generic issue of tir.ieliness and adequacy of the 10 CFR

50. 59 process as part of the response to NRC Restart Issue Ill. 11, Engineering

Problem Resolution, Including Safety Evaluations (NRC Inspection Report 50-

272&311 /96-16). This unresolved item is closed.

'*

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44

EB.5

(Closed) Violation 50-272&311 /96-07-04: failure to evaluate a deviation and

submit a report within 60 days of discovery per 1 OCFR21. On March 15, PSE&G

published an industry report that described recent failures of safety related 4. 16 KV

breakers. PSE&G staff did not report this as required by 1 OCFR21 until July 1,

1996. Salem staff provided and documented training for licensing, operations, and

engineering personnel to heighten awareness of reporting requirements and to

improve inter-departmental communication. Additionally, Salem management

performed a review of corrective action documents for Salem and Hope Creek to

identify any other potentially reportable deficiencies and found none. The inspector

considered the corrective actions adequate. This item is closed.

EB.6

(Closed) Unresolved Item 50-272&311/96-12-03: AHR minimum flow line flow

_indicator was described in the UFSAR but does not exist in the plant. The inspector

reviewed UFSAR change notice No.96-154 and the 10 CFR 50. 59 Safety

Evaluation for the change. The change deleted the informat.ion in UFSAR Section

6.3.5.3 regarding the AHR minimum flow line flow indication. The inspector

concluded that this was a satisfactory resolution to the conflict between the

UFSAR anq the existing plant configuration. The inspector noted that Salem staff

had not yet made this change to the UFSAR but the existence of the change notice

provided reasonable assurance the staff will make the change. This item is closed.

EB.7

!Closed) Unresolved Item 50-272&311/96-07-01: a fuel handling building sump

pump unot running" alarm was mentioned in the UFSAR but does not exist in the.

plant. The inspector reviewed UFSAR change notice No. 96-1 21 and the 10 CFR

50.59 Safety Evaluation for the change. The change removed the reference to the

alarm and provided additional information regarding monitoring of the sump level.

The inspector concluded that this was a satisfactory resolution to the conflict

between the UFSAR and the existing plant configuration. The inspector noted that

Salem staff had not yet made this change to the UFSAR but the existence of the

change notice provided reasonable assurance the staff will make the change. This

item is closed.

EB.8

(Closed) Violation 50-311196-13-01: failure to perform the required lnservice

Inspection of the pressurizer spray nozzle inner radius. On August 19, 1996, Salem

staff determined that, contrary to the requirements of Technical Specification 4.0.5., engineers had not performed the first 10 year inspection of the pressurizer

spray nozzle inner radius weld. The inspector reviewed PSE&G's response to this

violation and reviewed documents which provided evidence of the corrective action

taken. The inspector found that engineers performed the inspection and the results

were satisfactory. Management reviewed the Salem Unit 2 lnservice Inspection

database for first 10 year inspections and found one additional pressurizer weld

that engineers had not inspected. In the LEA Salem staff issued as a result of this *

event, the licensee committed to perform a similar review for Salem Unit 1 prior to

mode 6. The cause of the missed inspections was insufficient administrative

control of the computer data input and review. Previously, a vendor was

responsible for the data base. Presently, Salem staff controls the database. Also,

the database now has inherent program controls linking completed inspections with

the inspection schedule, thus providing an extra measure of precaution to prevent

• '

45

missing inspections. The inspector concluded that response and corrective action

to this violation was satisfactory.

This item is closed.

EB.9

(Closed) Unresolved Item 50-272&311 /96-01-04: update FSAR to state that full

core off-load is a routine practice during refueling outages. During an inspection, an

NRC inspector pointed out that although full core off-load is routine during refueling

outages at Salem 1 &2, the FSAR referred to the practice as "unusual". Since

then, Salem staff has amended the FSAR to state "The system design considers the

need to totally unload a reactor at the time when spent fuel is in the fuel pooL"

The inspector considers this resolution acceptable. This item is closed.

EB.10 (Closed) Inspector Followup Item 50~272&311 /96-08-07: update FSAR to state

~hat full core off-load is a routine practice during refueling outages. This issue is

identical to Unresolved Item 50-272&311/96-01-04. This item is closed.

The inspectors updated or closed the following items which had been identified in

past MOV program inspections. These items had been identified in Inspection

Report 50-272/311/96-11).

EB.11 (Closed) Violation 50-311/96-11-01: In NRC Inspection Report 50-311/96-11

violations were identified concerning inadequate test *control measures during

dynamic testing conducted on valves 2CV68 and 2CV69 (Charging Header Stop

Valves). The inspections determined that the differential pressures assumed by the

dynamic test analysis were uncertain because: 1) the upstream pressure

instruments did not account for the presence of pressure control valves located

between the pressure instruments and the test valves, and 2) the test procedure

specified the use of a downstream pressure gage with an abnormally wide range

which provided insufficient sensitivity for the expected test conditions. More

importantly the que~tionable test data obtained was used as the valve factor basis

for. the PORV block valves (2PR6 and 2PR7).

In response to the violation, PSE&G issued Performance Improvement Request No.

00960725067 dated July 29, 1996, and took the following actions:

PSE&G was no longer using the Charging System (2CV68 and 2CV69) testing to

justify the valve factors for the* PORV block valves. (See Section E1 .3 of this

report.)

PSE&G personnel retested 2CV68 and 2CV69 and was able to reduce the effect of

the upstream pressure drop contributed by pressure control valve 2CV71 . This

testing resulted in reasonable valve factors except for one test that was still

abnormally low. PSE&G personnel were unable to explain this result.

Licensee personnel reviewed other Unit 2 dynamic tests to identify if similar test

control mistakes were made. Flow paths were reviewed to identify flow

restrictions and f)ressure instrument locations were evaluated to assess the

adequacy of the pressure data that w*as obtained. Plant walkdowns were also

performed in some cases. This review revealed other cases where the pressure

\\

46

instrument locations and the system alignment could be improved. Based on this

review, proposed changes to the dynamic test procedures were under consideration

at the time of this inspection. PSE&G personnel considered these changes fo be

enhancements and the existing testing results were not seriously affected by the

existing test alignments. Also, a revision was made to the test evaluation

procedure to prompt the technician to review the pressure data and ensure that the

observed pressures are reasonable. The inspectors noted that a further procedure

cau.tion may be appropriate to review overall test conditions and data acquisition

when test results appear to be abnormal. Finally, licensee personnel stated that

they intend to use continuous pressure data acquisition during future tests (where

possible) to improve accuracy of test results.

_To assess these licensee's actions, the inspectors reviewed a dynamic test

performed on 22SJ.40 in November 1994, where the apparent valve factor was

0.11. The inspectors noted that the downstream pressure gauge was left closed

during the closing stroke. This was done because the pressure gauge range was

limited to 100 psig and leaving it on line would have damaged the gauge. Licensee

personnel justified this action because the system flow discharged into the reactor

cavity and the back pressure present at the outlet of the test valve was a function

of the cavity water level which would have had no significant change and hence

minimal impact on the test results. While this item was not identified or

documented as part of the licensee's review and corrective actions, the inspectors

concluded that PSE&G took adequate corrective actions to resolve the concerns

regarding this violation which is now closed.

ES. 12 !Closed) lnsoector Followup Item 50-311196-11-02: Complete load sensitive

behavior study for Salem Unit 2. To establish an adequate load sensitive behavior

margin for MOVs that cannot be dynamically tested, the licensee was expected to

analyze Salem's dynamic test results to support the generic letter program

assumptions. This study was not available during the last inspection. However, as

• documented in Section E1 .3 of this report, PSE&G has completed an acceptable

load sensitive behavior study and has established adequate margins for MOVs at

Salem Unit 2. Therefore, the licensee's actions adequately addressed this concern.

ES.13 (Closed) Inspector Followup Item 50-311196-11-03: Complete stem friction

coefficient study for Salem Unit 2. To adequately assess MOV thrust capability

under design-basis conditions, the licensee was expected to analyze Salem's stem

friction coefficient performance to support the generic letter program assumptions.

This study was not available during the last inspection. However, as documented

in Section E1 .3 of this report, PSE&G has completed an acceptable stem friction

coefficient study for Salem Unit 2. The inspectors found the licensee's actions

acceptable and considered this item closed.

ES.14 (Closed),,lnspector r-oilowup Item 50-311196-11-04: Revise test feedback method

to include margin for valve degradation. PSE&G's methods for feeding back results

from the MOV dynamic test program did not include a specific margin for potential

valve degradations. However, as documented in Section* E1 .3 of this report,

PSE&G has revised their MOV setup methodology for Salem Unit 2 to specifically

~-

..

-~*;I

-'~

.~ -,

47

include a 5% margin for potential valve degradations. The inspectors found the

licensee's actions acceptable and considered this item closed.

ES. 1 5 (Closed) Violation 50-311196-11-05: Incorrect assumpt_ions in. the mechanical

design calculations for the residual heat removal suction header valves {2RH1 and

2) resulted in low torque switch settings. The incorrect settings for these risk

significant pressure isolation valves created the possibility that they might not close

under design-basis conditions since the torque switch was wired in series with the

limit switch for these limit-controlled MOVs. PSE&G responded to the Notice of

Violation by letter LR-N96332 dated November 1, * 1996 that stated the corrective

actions to be taken to prevent recurrence.

• .The inspector specifically verified that PSE&G had .corrected the mechanical design

calculations for 2RH1 and 2 such that the torque switch settings would not prevent

full closure of these MOVs. A heavier spring pack had to be installed for 2RH 1

since the required torque output was beyond the capability of the original spring

pack. Both valves were then static tested satisfactorily with diagnostics to assure

their operability. The inspector also verified that the licensee had checked other

limit controlled MOVs, including butterfiy valves, and confirmed that they were not

impacted similarly. Additional remarks concerning the switch settings and

capability of these MOVs are included in Sections E1 .3 and E1 .4 of this report. The

inspector concluded these actions to be appropriate for closing out this item.

E8.16 !Closed) Inspector Followup Item 50-311196-11-07: Request for PSE&G to

increase the capability of marginal MOVs. This issue was addressed again in this

report as discussed in Section E1 .4. PSE&G has agreed to review measures to

improve the capability of certain MOVs in conjunction with periodic verification

. efforts in response to GL 96-05. The inspectors concluded that these actions were

acceptable for closing this item.

E8.17 (Closed) Inspector Follow Item 50-311196-11-08: Verify MOV switch setting

requirements for Pratt service water system butterfly valves. PSE&G had not

verified the adequacy of vendor-provided torque requirements for the Pratt butterfly

valves that were located in Salem Unit 2's service water system. None of these

valves were practicable to test in situ under dynamic conditions. As documented in

Section E 1 .4 of this report, the licensee used the EPRI PPM butterfly model to

develop the torque requirements for these valves. Based on PSE&G's application of

the PPM in accordance with EPRl's guidance and the NRC's safety evaluation (as it

relates to use of the butterfly model), the inspectors found the licensee's actions

acceptable and considered this item closed.

E8.18 (Closed) Inspector Followup Item 50-311196-11-09: An independent assessment of

the Salem MOV program to evaluate its readiness for closure was conducted in

August 1995 by two individuals who were MOV project members at another

nuclear f~cility. The as*.;essment appeared to be highly constructive with strengths

and weaknesses noted and various recommendations presented for assuring Salem

MOV program closure. However, PSE&G had not established firm management

controls for providing action plans or addressing the other items in the independent

• "

48

assessment report. Action Request (AR) 960725184 was issued to evaluate the

independent assessment, incorporate any appropriate recommendations, and

complete any necessary changes to the Salem MOV program by October 25, 1996.

The inspector reviewed PSE&G's actions to resolve this AR and determined that no

new issues were identified in this subsequent review of the MOV program

independent assessment. PSE&G was adequately addressing the various

recommendations of the independent assessment. The inspector concluded that

this issue was resolved.

E8.19 (Open) Unresolved Item 50-311196-11-10: Resolve configuration control issues

regarding the impact on the MOV program due to p!ant modifications and EOP

changes. In June 1996 PSE&G identified a problem concerning past plant changes

that had been implemented without appropriate consideration given to the impact

ori MOV design~basis setpoint documents. These plant changes included design

change packages, temporary modifications, and emergency operating procedures.

PSE&G issued AR 96060711 6 to identify comprehensive corrective actions to

evaluate and correct potential problems. The inspector reviewed the findings and

status regarding these corrective actions and determined that, while substantial

progress has been made to resolve this configuration control issue, AR 96060711 6

has not been completed. The licensee considAred that this AR had been completed

to provide the assurance that there were no MOV configuration control issues that

could impact existing MOV switch settings. The inspector noted that the NRC

identified TOL issue on MOVs in Section E1 .4 of this report, although only one

instance and concluded to have minor safety consequences, challenges the

thoroughness of PSE&G's corrective actions of AR 960607116. This item will

remain unresolved pending PSE&G's uncompleted actions to address all engineering

areas exposed to the configuration control issues in this AR.

E8.20 (Closed) Unresolved Item 50-311196-11-11: PSE&G had submitted an MOV

program closure letter on March 20, 1995, for Unit 2 and had not amended this

letter. In light of this fact and the nature and extent of the findings in NRC

Inspection Report 50-311 /96-11, a question regarding compliance with 10 CFR

50.9, "Completeness and Accuracy of Information" was raised. This issue was

identified as an Unresolved Item. The issue was discussed at a public meeting held

on November 12, 1996, between PSE&G and the NRC. PSE&G indicated that

engineering evaluation A-O-ZZ-MEE-0926 served as a technical basis for the Salem

Unit 2 MOV program closure letter. PSE&G m_aintained that then:i was no

significant negative information that developed subsequent to the March 20, 1995

letter which would have warranted an amended response. MOV changes that were

• made were considered to be minor enhancements to improve performance and were

not significant deviations from the MOV program technical basis.

The inspector determined that the design verifier of engineering evaluation A-0-ZZ-

MEE-0926, in accordance with the recommendation of the licensing engineer

responsible for the March 20, i 995 letter, had prepared an internal memorandum

on March 9, 1995, which summarized the technical basis for how PSE&G had

completed requested actions a. through h. of GL 89-1_ 0. In reviewing this *

document and based on interviews with the cognizant technical and licensing staff

',

49

personnel responsible for the March 20, 1995 letter, the inspector concluded that

there were no clear factors regarding MOVs subsequent to this letter that would

have warranted an amended response. In this regard the inspector noted that the

MOVs of most concern in the internal memorandum of March 9, 1995, were PR6

and 7 and CC131 and 190 and these MOVs continued to be discussed during this

inspection. The inspector concluded that PSE&G has been closely monitoring the

performance and capability of these MOVs which is consistent with the intent of

GL 89-10. In summary, the inspector concluded that the question regarding

compliance with 10 CFR 50.9 had been resolved in that there was not a compliance

problem. This unresolved item is closed.

ES.21 Review of Updated Final Safety Analysis Report !UFSARl Commitments

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

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

plant practices, procedures, and/or parameters to the UFSAR descriptions. While

performing the inspections documented in this report, the inspector reviewed the

applicable portions of the UFSAR that related to the areas inspected. The

inspectors verified that it was consistent with the observed* plant practices;

procedures, and/or parameters.

P8.1

!Closed) Unresolved Item 50-272&311 /96-15-03: description of backup radiological

instrumentation in Salem's Emergency Plan was incorrect.* The Emergency Plan

incorrectly stated that radiologicalinstrumentation was available in the Training

Center laboratory for use as backup to the Emergency Off site Facility, however,

technicians did not calibrate that instrumentation. Salem management revised the

Emergency Plan to state that backup equipment is available at the station and at

other licensed facilities such as Peach Bottom or Limerick. The inspector found this

)

solution acceptable. This item is closed.

j

P8.2

!Closed) Unresolved Item 50-272&311 /96-15-04: description of media training

program in Salem's Emergency Plan was incorrect. Salem staff revised the

Emergency Plan to accurately describe the present method of informing local media

personnel cf emergency plan activities. The present method is to send local media

ar1 information calendar followed by a phone call inviting them to the annual

emergency preparedness exercise. The inspector found the resolution*to be

satisfactory. This item is closed.

P8.3

(Closed) Violation 50-272 & 311 /94-112-05014: incomplete reporting of

information to the NRC regarding the April 7, 1994 inadvertent safety injection

event. The Salem Emergency Plan required that operators report specific

information to the NRC within 60 minutes. The required information includes

systems affected, actuations and their initiating signals, causes, effect of event on

' .

50

the plant, and actions taken or planned. The inspector verified that the Emergency

Plan, Attachment 5, now provides clear guidance regarding technical information

which must be included when reporting emergency events. Also, Attachments 6

and 7 allow operators to assign an additional communicator if necessary.

Additionally, in December 1996, NRC inspectors observed mini-drills for

Salem/Hope Creek and found that "Offsite notifications were timely, and

professionally completed" (NRC Inspection Report 50-272&311 /96-18 has details).

Inspectors also verified that training modules used to qualify and requalify

designated communicators provided sufficient information relative to reporting. The

inspector concluded Salem staff took appropriate action to resolve this violation.

This item is closed.

P8.4 .!Closed) Violation 50-272 & 311/95-81-04: inadequate equipment to support the

emergency response. In October 1995, the control room overhead annunciator

alarm system failed and the system provided no indication that the failure had

occurred. This condition rendered the equipment inoperable so that PSE&G staff

was not able to meet the requirements of the Emergency Classification Guide

(ECG). Section 10 of the ECG requires an alert declaration if "Loss of most or all

( > 75%) overhead annunciators (excluding a scheduled test or maintenance activity

for which preplanned compensatory measures have been implemented) and fifteen

minutes have elapsed since the loss of annunciators."

PSE&G staff addressed this issue in their response to NRC Restart Issue 11.40,

Overhead Annunciator Failures. NRC staff conducted a recent inspection to review *

PSE&G's actions to resolve these equipment problems and the inspectors concluded

the corrective action was satisfactory for Salem Unit 2. The inspector documented

the results of that inspection in Inspection Report 50-272 & 311 /96-13 .. Because

the issue is closed for Salem Unit 2 and is being tracked to completion for Unit 1 by

NRC Restart Issue 11.40, this violation is closed.

V. Management Meetings

X1

Exit Meeting Summary

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

conclusion of the inspection on March 19, 1997. The licensee acknowledged the findings

presented.

Licensee representatives were informed of the purpose and scope of the MOV inspection

at an entrance meeting conducted on January 13, 1997. Findings were discussed

periodically with the licensee throughout the course of the inspection. The inspectors met

with the principals listed below on January 17 and January 24, 1997 at which time a final

exit meeting with the licensee was conducted to summarize preliminary inspection

findings. The licensee acknowledged the preliminary findings and conclusions, with no

exceptions taken. The bases for the inspection conclusions did not involve proprietary

information, nor was any such information included in this inspection report, except for the

MPR Associates TB and PL analyses reviewed by NRR and referred to in Section E1 .5.

' .

51

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

should be considered proprietary. No proprietary information was identified.

X3

Management Meeting Summary

On February 5, 1997,Mr. Leonard J. Callan, NRR Executive Director for Operations visited

the Salem site. A copy of the licensee handout is attached .

INSPECTION PROCEDURES USED

Tl 2515/109:

Inspection Requirements for Generic Letter 89-10, Safety-Related

Motor-Operated Valve Testing and Surveillance

IP 37551:

Onsite Engineering

IP 50001:

IP 61726:

Steam Generator Replacement Inspection

Surveillance Observations

IP 62707:

Maintenance Observations

Plant Operations

IP 71707:

- IP 92901:

Followup - Plant Operations

ITEMS OPENED, CLOSED, AND DISCUSSED

• Opened

50-272&311 /97-03-01

50-311197-03-02

VIO

. operator trafning and qualification

IFI

management commi<::ment process

!:>0-3 l 1 /97-03-03

50-311197-03-04

50-311197-03-05

IFI

verify commitment regarding 2RH1 and 2.

IFI

verify commitment regarding 2PR6 and 7.

IFI

verify commitment regarding 2CC 131 and 1 90.

Closed

50-272&311/95-024

LER

50-311 /96-09 _

LER

50-272&311 /93-23

VI Os

(EA, 94-003: 01013, 01023,

01033,01043,01053,

01063, 01073 & 01083)

EA94-112: 04013

VIO

EA94-112: 05014

VIO

272&311/93-15-04

URI

50-272&311/94-14-02

VIO

50-272&311 /95-07-03

VIO

50-272&31; /95-17-02

URI

50-272&311 /95-17-03

URI

50-272&311 /95-80**01

URI

"Technical Specification Violations: differential

pressure of the fuel handling building ventilation

system" (discussed in 50-272 and 311 /96-06

fourteen day followup report regarding 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

shift for operations personnel

failure to follow procedures

PSE&G staff provided inadequate training

incomplete reporting of information to the NRC

regarding April 7, 1994 inadvertent safety

injection event

corrective action program weaknesses

failure to provide adequate training to

maintenance personnel

failure to follow procedures

failure to implement a commitment to install a

concrete curb at the entrance to each Salem

Unit 1 and 2 EOG cubicle

evaluation of corrective action regarding Salem

Unit steam generator tube inspection

weaknesses

operability determinations

~--~

-:J

• )

. ~

~,

*.

2

50-272&311/95-81-04

VIO

inadequate equipment to support the emergency

response

50-272&311/96-01-01

VIO

failure to follow procedures

50-272&311 /96-01-02

VIO

failure to follow procedures

50-272&311/96-01-04

URI

update FSAR to state that full core off-load is a

routine practice during refueling outages

50-272&311/96-06-01

VIO

failure to follow procedures

50-272&311 /96-06-02

URI

failure to perform a 10 CFR 50.59 safety

evaluation

50-272&311/96-07-01

URI

a fuel handling building sump pump"not running"

alarm was mentioned in the UFSAR, but does

not exist in the plant

50-27_2&311 /96-07-04

VIO

failure to evaluate a deviation and submit a

report within 60 days of discovery per 10 CFR

21

50-272&311 /96-08-05

VIO

inadequate procedures

50-272&311 /96-08-06

URI

Salem Unit 2 operating license does not permit

1 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> operating shifts

50-272&311 /96-08-07

IFI

update FSAR to state that full core off-load is a

routine practice during refueling outages

50-311/96-11-01

VIO

Inadequate test control and application of MOV

test data

50-311196-11-02

IFI

Basis for load sensitive behavior margin used in

thrust calculations

50-311196-11-03

IFI

Basis for stem friction coefficient used in thrust

calcul.ations

50-311 /96-11-04

IFI

Basis for valve degradation margin used in thrust

calculations

50-311196-11-05

VIO

Inadequate design control of switch settings for

MOVs 2RH1 and 2

50-311196-11-07

IFI

Request to improve thrust margin for selected

MO Vs

50-311196-11-08

IFI

Evaluate torque requirements for Pratt butterfly

valves

50-311 /96-11-09

IFI

PSE&G to evaluate and document response to

MOV program independent assessment

50-311/96-11-11

URI

Resolve question regarding Salem Unit 2 MOV

program completion in the context of 10 CFR

50.9(b)

50-272&311/96-12-03

URI

AHR minimum flow line flow indicator was

described in UFSAR, but does not exist in the

plant

50-311 /96-1 3-01

VIO

failure to perform the required inservice

inspection of the pressurizer spray nozzle inner

radius

50-272&311/96-'!5-02

VIO

failure to follow procedures

-

50-272&311 /96-15-03

50-272&311 /96-15-04

50-272&311 /96-17-01

Discussed

50-272&311 /93-80-06

50-272&311 /93-80~07

50-272&311 /93-80-08

50-311/96-11-10

URI

URI

VIO

URI

URI

URI

URI

3

description of backup radiological

instrumentation in Salem's Emergency Plan was

incorrect

description of media training program in Salem's

Emergency Plan was incorrect

failure to perform a safety evaluation in

accordance with 10 CFR 50.59

non-conservative assumptions, licensee using

only one spurious operation per fire incident

requirement to perform repairs for Hot Shutdown

contrary to SER statement

licensee method of protecting equipment from

damage by fire

review PSE&G's corrective actions to resolve

design interface problem regarding impact on

MOVs from modifications and EOP changes

. ' . '

• • ~i

~

• ~

..

-i

AIT

AR

ATS

CAP

cc

CFR

CFCU

DP

ECG

ECG

EOG

EMIS

EPRI

GL

IR

LCO

M&TE

MMIS

MO Vs

MRC

NBU

NO Vs

NRC

PDR

PIR

PL

PMT

PORV

PPM

PPP

PSE&G

RCP

RCS

RHR

SE

SNM

SR Os

STA

TB

TOL'

TS

TSSIP

UFSAR

WIN

LIST OF ACRONYMS USED

Augmented Inspection Team

Action Request

Action Tracking System

Corrective Action Program

Component Cooling

Code of Federal Regulations

Containment Fan Cooler Unit

Differential Pressure

Emergency Classification Guide

Emerg~ncy Classification Guide

Emergency Diesel Generator

Equipment Malfunction Identification System

Electric Power Research Institute

Generic Letter

.Inspection Report

Limiting Condition for Operation

Measuring and Test Equipment

Managed Maintenance Information System

Motor-Operated Valves

Management Review Committee

Nuclear Business Unit

Notices of Violations

Nuclear Regulatory Commission

Public Document Room

Performance Improvement Request

Pressure Locking

Post Maintenance Testing

Power Operated Relief Valve

Performance Prediction Model

Performance Prediction Program

Public Service Electric and Gas

Reactor Coolant Pump

Reactor Coolant System

Residual Heat Removal

Safety Evaluation

Special Nuclear Material

Senior Reactor Operators

Shift Technical Advisor

Thermal Binding

Thermal Overload

Technical Specifications

Technical Specification Surveillance Improvement Program

Updated Final Safety Analysis Report

Work-it-Now

• .

  .

-

.

ATTACHMENT

PUBLIC SERVICE ELECTRIC AND

.GAS

SALEM.NUCLEAR GENERATIN~G

STATION

GENERIC LETTER 89-.10 PROGRAM

.

.

..

lfff/

PURPOSE OF MEETING

A) DISCUSS UNRESOLVED ITEM FOR THE MOV

PROGRAM CLOSURE

B) DISCUSS ACTIONS REQUIRED BY PSE&G

BEFORE RESTART

(A)

GENERIC LETTER 89-10

CHRONOLOGY OF EVENTS

MOVEng.

Sukm 1&2

PECO

Comments on

Sah:m 2

\\'k!gin

PECO 111ird

Assessment

PECO

PECO

I lope Creek

Sulcm I

Closure

extended

Party*

presentc:d to

assessment to

Assessm.:nl

closure

Oulngc shifts

Closure

?'-

Letter

shutd0\\\\11

Assessment

PSE&GMgt.

Mgt.

Report issued

inspc:ction

to Unit 2

Letter

lnsr

3/20/95

611195

8/25/95 -

9n/95

9/28/95

10/5/95

Feb-96

3/15/96

6/25/96

112

8/31/95

11:

I

I

I

I

I

I

.

{1}

{2}

{3}

11/12/96

• • . '! .**

(A)

(tJBASIS FOR SALEM 2 CLOSURE

SUBMITTAL

CLOSURE LETTER SENT 3/20/95 UPON COMPLETION OF 2R08

. ITEMS A THROUGH H CONSIDERED COMPLETE

. DOCUMENTATION FOR EACH VALVE EXISTED IN

INDIVIDL)AL EVALUATIONS

ENGINEERING EVALUATION A-O-ZZ-MEE-0926 ISSUED 12/23/94

JUSTIFIED AfSUMPTIONS BASED ON ANALYSIS OF EPRI DATA

. 0.5 VALVE FACTOR

. 0.15 STEM COEFFIC.JENT

. 30 o/o MARGIN

DP TESTING JUSTIFIED THAT PROGRAM ASSUMPTIONS WERE

GOOD PREDICTORS OF VALVE THRUST REQUIREMENTS

. EXCEPTIONS WERE EVALUATED ON A CASE BY CASE

BASIS BY APPROVED PROCEDURES AND THE TARGET

THRUST WA~ INCREASED

1sEe FIGURE 1)

I f/f2)§g

. . . ... *-

. . .. ~ -* '.:_ ~ ....... "......

. .

~--*.

'

\\ ...

TARGET THRUST BASED ON 0.5 VALVE FACTOR AND 30% MARGIN Vs. MEASURED

THRUST AT HARD S!:AT CONTACT.

-**--*--.. -* .. ---

---*---------------*---*---**-*---**--**-*** -- ............... _**----*--*----*--**---................. . .................... *--- .... *-****--*----.

-*---. -*--*----*--...... ___ _

Figure 1

• .,.

1111/

... :'. ...

(A)

(2) REASON FOR THIRD PARTY

ASSESSMENT

.* ..* j,

,.,

ASSESSMENT WAS REQUESTED AS PART OF A REVIEW OF ALL

ENGINEERING PROGRAMS FOR RESTART IN AUGUST, 1995

THE MOV PROGRAM WAS ONE OF THE PROGRAMS THAT WAS

REVIEWED

THERE WERE NO SPECIFIC CONCERNS REGARDING THE MOV *

PROGRAM WHICH INITIATED THE ASSESSMENT REQUEST

11111

(A)

(2) THIRD PARTY ASSESSMENT

RESULTS IDENTIFIED STRENGTHS, WEAKNESSES AND RISKS TO

CLOSURE

RESULTS COMMUNICATED TO MANAGEMENT

. PRESENTATION BY PECO TO PSE&G MANAGEMENT 9/7/95

. MOV ENGINEER MEMO SUMMARIZED RESULTS 9/28l95

. FINAL REPORT ISSUED 10/5/95

RESULTS NOT ENTERED INTO CORRECTIVE ACTION PROGl~AM

NEW PROGRAM

. UNDER A STARTUP AND LEARNING CURVE

. PROGRAM WEAKNESSES WERE NOT CONSIDERED

CONDITIONS ADVERSE TO QUALITY

ACTIONS TAKEN IN RESPONSE TO WEAKNESSES WERE Nor

WELL DOCUMENTED

. . .

1111/

.(..,: .... *--*-'*

(A)

• (2) RESPONSE TO THIRD PARTY

ASSESSMENT

ADDITIONAL STATIC AND DP TESTING WAS SCHEDULED

PRESENTATION WAS MADE TO MRC IN SEPTEMBER, 1995 (MTG.95-035). IMPORTANCE OF ADDITIONAL STATIC AND DP

TESTING TO SUPPORT CLOSURE WAS EMPHASIZED

THE REVISED CLOSURE DOCUMENT COMPLETION WAS BASED

ON THE OUTAGE SCHl;DULE. COMPLETION DATES SLIPPED

AS THE OUTAGE SCHEDULE CHANGED. THE LAST PUBLISHED

DUE DATE WAS 6/30/96

THE EXISTING SALEM 2 CLOSURE DOCUMENT EE: S-C-ZZ-MEE-

0906 WAS SUPERSEDED BY EE: S-C-VAR-NEE-1117

SCHEDULED TO BE COMPLETED BY NOVEMBER 30,1996

1111/

(A)

. (2) SALEM RESTART PLANS

.

.

(SEPTEMBER, 1995)

CLOSURE FOCUS SHIFTED FROM EPRI AND INDUSTRY DATA

TO SALEM SPECIFIC DATA FOR JUSTIFICATION OF

.

ENGINEERING ASSUMPTIONS.

~

A SIGNIFICANT AMOUNT OF ADDITIONAL STATIC TESTING

WAS SCHEDULED TO INCREASE MARGIN

. UNIT I - 36 STATIC VOTES TESTS, 4 'VALVE INTERNAL

DCP's, 3 SPRING PACK I GEAR RATIO DCP's

.

. UNIT 2 - 30 STATIC VOTES TESTS

ADDITIONAL DP TESTING WAS SCHEDULED TO PROVIDE

. GREATER CONFIDENCE IN ENGINEERING ASSUMPTIONS

. UNIT 1 - 16 DP TESTS SCHEDULED

. UNIT 2 - 11 DP TESTS SCHEDULED

..

'>

(A)

(3) BASIS FOR SALEM 1 CLOSURE

SUBMITTA.L

GL 89-10 ITEMS A THROUGH H WERE CONSIDERED COMPLETE. AS PART OF THE

IMPROVEMENT PLAN, ADDITIONAL TESTING WAS SCHEDULED TO INCREASE.

MARGIN

LICENSING WAS REQUESTED TO PROVIDE UNIT 1 SCHEDULE INFORMATION TO

ENABLE NRC TO INITIATE THE CLOSURE REVIEW PROCESS.' YNIT 1 WAS THE

LEAD RESTART UNIT AT THAT TIME

TENTATIVE MID-JULY, 1996 CLOSURE INSPECTION DATE WAS ESTABLISHED IN

FEBRUARY, 1996 BASED ON COMPLETION OF UNIT 1 MOV WORK IN EARLY

APRIL, 1996

RESTART PRIORITY SHIFTED IN MARCH, 1996 FROM UNIT 1 TO UNIT 2. ALTHOUGH

ITEMS A THROUGH H WERE CONSIDERED COMPLETE, MARGIN ENHANCEMENT

ACTIVITIES WERE NOT COMPLETED

THE NRC WAS NOT REQUESTED TO RESCHEDULE THE CLOSURE INSPECTION

BASED ON THE CHANGE IN THE LEAD RESTART UNIT

SALEM UNIT 1 CLOSURE LETTER ISSUED JUNE, 1996

• --**it.

~

) .

SUMMARY

SALEM CLOSURE BASED ON DP TEST RESULTS AND INDUSTRY

EXPERIENCE

SALEM STAFF BELIEVED THAT THE ISSUES IDENTIFIED IN THE

THIRD PARTY ASSESSMENT DID NOT CHALLENGE THE ABILITY

TO CLOSE GL 89-10

PSE&G FAILED TO CONSIDER THE IMPACT OF THE CHANGE OF

THE LEAD RESTART UNIT AND SCHEDULE SLIPPAGE ON THE

SCHEDULE FOR THE CLOSURE

~ .

.--

.

f

(B)

ACTIONS REQUIRED FOR SALEM 2

RESTART

TEST CONTROL VIOLATION (CV68 & 69)

. TEST PROCEDURES REVISED

. VALVES RE-TESTED

. NO GfNERIC ISSUES WERE DISCOVERED

. -UNIT 2 COMPLETED - SEPTEMBER, 1996

DESIGN CONTROL VIOLATION (RH1 & RH2)

. CALCULATIONS REVISED

. VALVES RE-TESTED

. NO GENERIC ISSUES WERE DISCOVERED

. UNIT 2 COMPLETED - AUGUST, 1996

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(B)

ACTIONS REQUIR~ED FOR SALEM 2

RESTART

CLOSURE DOCUMENT

-

ENGINEERING EVALUATION TO BE APPROVED BY NOV. 30,

1996

>> BASIS FOR ENGINEERING ASSUMPTIONS

>> JUSTIFICATION FOR VALVE FAMILIES

-

UNIT 2 CALCULATIC?N REVISIONS, IF REQUIRED, TO BE

.-COMPLETE BY MODE 2

.

• ~*'-*'

"~:.

(B)

ACTIONS REQUIRED FOR SALEM 2

RESTART

JUSTIFICATION FOR VALVES IN UNIT 2 FAMILIES 3 AND 9.1 WILL

BE ENHANCED PRIOR TO MODE 6 .

CONFIGURATION CONTROL

-

OVER 400 DCP's REVIEWED WITH MINIMAL IMPACT - .

COMPLETE

-

REVISED EOP's AND AOP's REVIEWED WITH MINIMAL

IMPACT - COMPLETE

-

TRAINING OF OPERATIONS PROCEDURE WRITING STAFF

TO PREVENT RECURRENCE - COMPLETE

STATUS OF ADDITIONAL DIFFERENTIAL PRESSURE TESTING

16 UNIT 2 VALVES TESTED, THE ONE TEST REMAINING

REQUIRES THE CONDENSATE SYSTEM TO BE IN SERVICE.

V'JILL COMPLETE PRIOR TO MODE 3.

1111/

(B)

ACTIONS REQUIRED*FOLLOWING

SALEM 2 RESTART

REVISE AND UPDATE MOV PROGRAM DOCUMENTATION FOR

ENHANCEMENTS BY MARCH 31, 1997

-

CALCULATION REVISIONS

-

PROGRAM DOCUMENTATION ENHANCEMENTS