ML18101B166

Responds to NRC 951016 Ltr Re Violations Noted in Insp Repts 50-272/95-02,50-272/95-07,50-272/95-10 & 50-311/95-02, 50-311/95-07 & 50-311/95-10.Corrective Actions:Cap Revised as Described in Cover Ltr to Attachment

ML18101B166
Person / Time
Site:	Salem
Issue date:	11/15/1995
From:	Eliason L Public Service Enterprise Group
To:	Lieberman J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
Shared Package
ML18101B165	List: ML18101B166
References
NUDOCS 9601160030
Download: ML18101B166 (50)

See also: IR 05000272/1995002

Text

Public Service Electric and Gas Company Leon R. Eliason Public Service Electric and Gas Company P.O. Box 236, Hancocks Bridge, NJ 08038 609-339-1100

Chief Nuclear Officer & President

Nuclear Business Unit NOV 1 5 1995 * * LR-N95196

United States Nuclear Regulatory

Commission

Document Control Desk Washington, DC 20555 Attn: Mr. James Lieberman

Director -Off ice of Enforcement

Gentlemen:

RESPONSE TO NRC NOTICE OF VIOLATION

INSPECTION

REPORT NOS. 50-272/311/94-32, 50-272/311/95-02, 50-272/311/95-07

AND 50-272/311/95-10

SALEM GENERATING

STATION UNIT NOS. 1 AND 2 DOCKET NOS. 50-272 AND 50-311 On October 16, 1995, the Nuclear Regulatory

Commission (NRC) issued a Notice of Violation (NOV) and proposed a $600,000civil

penalty for violations

identified

by the NRC during four inspections

that occurred between December 5, 1994 and June 23, 1995. The NRC issued to Public Service Electric & Gas (PSE&G) reports for these inspections

on March 30, April 7, May 24, and July 14, 1995. A predecisional

enforcement

conference

was held on July 28, 1995. PSE&G does not dispute the violations

cited in the October 16, 1995 NOV. Therefore, pursuant to 10CFR2.201, PSE&G submits its reply to the October 16, 1995 NOV. An electronic

transfer of funds payable to the Treasurer

of the United States in the amount of the proposed civil penalty will be made on November 15, 1995. As the NRC is aware, PSE&G management

realized that significant

steps were necessary

to reverse the P,erformance

decline at Salem. Therefore, on June 7, 1995, a decision was made to maintain Salem Unit Nos. 1 and 2 shutdown -until performance

improves to acceptable

levels. The self-imposed

shut down sent a significant

message to PSE&G employees.

PSE&G management

is 9601160030

951227 PDR ADOCK 05000272 G PDR

I . ** * * Document Control Desk LR-N95196 -2 -i\!OV-1 5 1995 serious about the changes necessary

for plant safety, personnel

performance, and process improvement.

PSE&G evaluated

the apparent violations

and broader concerns identified

in the four inspection

reports. Based on this evaluation, our July enforcement

conference

presentation

focused on three critical broad areas that had to be improved before acceptable

and long-lasting

changes at Salem could occur. These areas are: (1) establishment

of a culture that will facilitate

improvement, (2) improvement

of self-assessment

capabilities, and (3) ensuring timely and thorough problem assessment

and resolution.

These focus areas and their underlying

problems are a subset of concerns being addressed

in the Salem Restart Plan. The details of the Restart Plan will be formally submitted

on the

and discussed

with you during the public meeting presently

scheduled

for December 1995. In addition to our response contained

in Attachments

1 through 5, we provide below a discussion

of our progress in addressing

the three focus areas . Culture Change Improved personnel

and organizational

performance

is currently

and *will continue to be a focal point for the new management

team and is considered

essential

in establishing

the proper safety culture within the Nuclear Business Unit (NBU) . To aggressively

change the culture of the NBU, most of its top management

has been replaced.

This change signals the most important

factor that distinguishes*present

activities

from those of the past. One of the key characteristics

of the new managers is the ability to lead by example. Personnel

selected for this team have demonstrated

the necessary

leadership

capabilities

as well as the high standards

necessary

to develop a quality organization.

Most of the individuals

come from nuclear units which have had successful

performance

turn-arounds

and operate at an excellent

level. NBU management

has placed an emphasis on the development

and communication

of roles and responsibilities

to the organization, as well as establishing

expectations

for individual

performance.

The following

are examples of initiatives

which have been established

to drive the process of change. 95-4933

• • * Document Control Desk LR-N95196 -3 -NOV 15 1995 First, several of the action plans developed

to support restart recognize

the need for improved definitions

of organizational

and individual

roles and responsibilities.

For example, a Conduct of Operations

document is now being finalized

which communicates

management

expectations

and, as importantly, establishes

the ethic of the Operations

organization.

Roles and responsibilities

for system engineers

have already been defined and communicated

to support the System Readiness

Review Process and system engineer improvement

initiatives.

The goal of these communications

is to establish

the necessary

standards

against which personnel

and organizational

performance

can be measured and held accountable.

Secondly, a Performance

Ranking process has been instituted

to assess individual

performance

in the following

behavioral

areas;

and Leadership, Initiative

and Results Achievement, Job Knowledge, Communication, and Adaptability

and Flexibility.

Individuals

will develop improvement

plans appropriate

to their overall standing.

This process is designed to identify and confront substandard

performance

that has gone undetected

or unchallenged

to date. In addition, personnel

who fail to make prescribed

improvements

will be held accountable, up to and including

discharge.

This ranking process represents

the first of four performance

review efforts to be conducted

within the NBU over the next 18 months. This focus on performance

is intended to re-emphasize

the responsibility

of managers and supervisors

to set and enforce proper

s.tandards

and revise substantially

the quality and productivity

of the workforce.

Finally, managers and supervisors

are being provided training to assist them in identifying, confronting

and correcting

performance

issues. The process being utilized has been implemented

successfully

at other nuclear plants, as well as non-nuclear

companies.

NBU management

has established

the expectation

that line managers and supervisors

attend this training and utilize this process. Two protocol groups have been established

to ensure the process is being ir.,plemented

uniformly

and consistently.

The Managers protocol group has recently developed

the course content and identified

significant

issues to be addressed.

The Executive

protocol group has evaluated

the course content and training to ensure that expectations

for this process have been satisfied.

In the longer term, the Managers protocol group will evaluate . * implementation

of the process to promote consistency

and make r I . 95.4933

• • * * Document Control Desk LR-N95196 -4 -NOV 1 5 1995 appropriate

recommendations

on policy issues to the Executive

protocol group. These actions, effectively

implemented, are expected to improve individual

and organizational

performance

and will provide the infrastructure

for the proper safety culture within the NBU. As the impacts of these actions are measured, appropriate

changes in approach and method will be made to achieve the lasting and profound changes being targeted.

Self-Assessment

Improvement

The long-term

objective

for this focus area is to develop an organization

which instinctively

takes necessary

steps to improve

through effective

self-assessment

and timely corrective

action. A program defining expectations

for assessment

during routine operations

has been developed.

Each Salem department

has identified

specific representatives

to support this program. These representatives

have been trained on the program and its expectations.

To date, all but one Salem Station department

has performed

a self-assessment

using this program. The remaining

departmental

self-assessment

will be completed

in the near future. Issues identified

during these assessments

will be reviewed and incorporated

into the Salem Restart Plan, as appropriate.

A second program, which provides guidance on conducting

self-assessments

for readiness

to return to operation

following

refueling

outages, is being developed.

Salem personnel

are demonstrating

their willingness

to identify deficiencies

and to initiate actions necessary

for correction.

Indications

of this can be seen in the March 24, 1995, "Organizational

Effectiveness

Assessment

Report for Salem Nuclear Generating

Station," and our presentation

during the July 28, 1995 enforcement

conference.

This continues

to be shown by system walkdown results, backlog review, and most notably, the number of condition

reports being generated

on a daily basis. NBU management

has and will continue to monitor, and to the extent necessary

intervene, when self-assessment

related expectations

are not met . 95.4933

• • * * Document Control Desk LR-N95196

Timely/Appropriate

Resolution -5 -NOV 1 5 1995 A consolidated

Corrective

Action Program (CAP) has been implemented

to communicate

NBU management

expectations

on timely problem identification

and resolution

and provides clear definition

of roles and responsibilities.

The CAP was designed using input from other utilities

which have effectively

managed program consolidations

as measured by improved program and station performance.

The consolidated

program includes a low threshold

for reporting

problems, provides aggressive

problem assessment/root

cause determination

expectations

and places management

in charge of root cause and corrective

action completion

times. Results to-date indicate that personnel

are not hesitant to raise issues through the process. The Director -Quality Assurance/Nuclear

Safety Review has oversight

responsibility

for the CAP. He has dedicated

resources, *_under the Manager -Corrective

Action and Quality Services, to fulfill that responsibility.

Measures have been established

to monitor the performance

of the corrective

action process. Recent data indicate overall improvement

in evaluation

completion

times and a reduction

in overdue corrective

actions. Station management

receives daily reports on overdue evaluations

-most of which have resulted from the volume of issues generated

by system walkdowns.

Accountability

for CAP implementation

rests with station line management.

As such, station managers review root cause evaluations

for completeness

and adequacy.

A Corrective

Action Review Board (CARB) has been established

at Salem and the General Manager -Salem Operations

is its chairman.

Completed

root cause assessments

for significant

issues are presented

to the CARB where the adequacy of the cause determination

and selected corrective

actions are evaluated:

A performance

measure has been established

which tracks the acceptance/rejection

rate for CARB presentations.

This indicator

is included in the monthly report to senior management . 95-4933

• • * * Document Control Desk LR-N95196 -6 -NOV 15 1995 A new element, being incorporated

under the CAP improvement

area, is the Operational

Experience

Feedback (OEF) Program. This program is under review to identify needed improvements

in the processing

of internal and external OEF information.

This review includes a validation

of actions taken in response to past OEF items. Improvements

to the OEF process itself will include the establishment

of well defined roles and responsibilities, and standards

of performance

for implementing

organizations.

Performance

measures will also be established

to allow NBU management

to monitor program effectiveness

and assign accountability

if performance

standards

are not satisfied.

These changes are being made in order to better integrate

the OEF program into the operation

of the stations.

NBU management

recognizes

that, in addition to the changes already described, culture improvements

and self-assessment

capability

improvements

are essential

to anchoring

the CAP as an integral part of sustained

performance

improvement.

We will establish

and achieve appropriate

performance

standards

for the CAP at Salem prior to restart . Summary We agree with the NRC. that performance

within the NBU must improve. Our commitment

to maintain the Salem Units shutdown until required performance

improvements

are demonstrated, changes to the NBU management

team, and our aggressive

actions to strengthen

the safety culture within the NBU., illustrate

the fundamental

differences

between our present actions and those of the past. We will not restart the Salem Units until the hardware, important

processes

and programs, and organizational

and individual

performance

reach acceptable

levels. Changes will continue, as needed, to ensure that expectations

continue to be met after resumption

of power operation . 95-4933

I . ** * * Document Control Desk LR-N95196 -7 -NOV 1 5 1995 If you have any questions

regarding

this submittal, please do not hesitate to contact me. Sincerely, Attachments

95-4933

• * Document Control Desk LR-N95196 -8 -C /Mr. T. T. Martin, Administrator

-Region I U. S. Nuclear Regulatory

Commission

475 Allendale

Road King of Prussia, PA 19406 NOV 15 1995 Mr. L. N. Olshan, Licensing

Project Manager -Salem U. S. Nuclear Regulatory

Commission

One White Flint North 11555 Rockville

Pike Mail Stop 14E21 Rockville, MD 20852 Mr. C. Marschall

-Salem (S09) USNRC Senior Resident Inspector

Mr. K. Tosch, Manager, IV NJ Department

of Environmental

Protection

Division of Environmental

Quality Bureau of Nuclear Engineering

CN 415 Trenton, NJ 08625 95-4933

• * REF: LR-N95196

STATE OF NEW JERSEY SS. COUNTY OF SALEM L. Eliason, being duly sworn according

to law deposes and says: I am Chief Nuclear Officer & President

-Nuclear Business Unit of Public Service Electric and Gas Company, and as such, I find the matters set forth in the above referenced

letter, concerning

the Salem Generating

Station, Unit Nos. 1 and 2, are true to the best of my knowledge, information

and belief .

and

before me this /5-t.h day of /puvm/JJ.A_ . , 1995

/biGW£. Notary

Jersey My Commission

expires on KIMBERLY JO BROWN NOTf\RY PUBLIC OF NEW JERSEY My Commission

Expires April* 21, 1998

I I " ** * * Document Control Desk LR-N95196 -1 -ATTACHMENT

1 VIOLATION

I. 10 CFR Part 50, Appendix B, Criterion

XVI, Corrective

Action, requires, in part, that conditions

adverse to quality are promptly identified

and corrected; .and in the case of significant

conditions

adverse to quality, the cause of the condition

shall be documented, appropriately

reported to levels of management, and corrective

action taken to preclude repetition.

• A. Contrary to the above, a significant

condition

adverse to quality existed at the Salem Unit 2 facility from January 26, 1995, until June 7, 1995, in that the Licensee was aware that the No. 22 Residual Heat Removal (RHR) pump minimum recirculation

flow valve would not open on low RHR flow as required to prevent pump failure. Similarly, the Licensee was aware that the same significant

condition

adverse to.quality

existed at the facility from February 9, 1995, until June 7, 1995, for the No. 21 RHR pump minimum recirculation

flow valve. However, prior to June 7, 1995, the Licensee failed to determine

the cause of the valve failures or initiate corrective

measures.

(01013) This is a Severity Level III Violation (Supplement

1) Civil

$100,000 RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

• psE&G does not dispute the violation.

On January 26, 1995, and

9, 1995, different

operating

crews identified

failure of the automatic

open feature for the Residual Heat Removal (RHR) pumps minimum flow recirculation

valves 21RH29 and 22RH29. Both failures occurred as Salem Unit 2 was nearing completion

of its eighth refueling

outage (2R8) . Each failure was observed while the console *operator (a licensed Reactor Operator (RO)) was reducing RHR flow in preparation

to align RHR as an Emergency

Core Cooling System (ECCS) flowpath.

In both cases, the operating

crew initiated

an Action Request (AR) . Troubleshooting

for these valves was subsequently

scheduled

for August 2, 1995 and June 27, 1995, respectively.

Although Operations

personnel

recognized

that valve operability

was Mode-dependent, they did not establish

mode change constraints

when the failure of the automatic

open feature was recognized .

• • * * Document Control Desk LR-N95196 -2 -Attachment

1 (cont'd) In June, 1995, following

Operations

department

identification

of 54 open work orders with potential

operability

concerns, these valves were targeted for immediate

operability

assessment.

Once valve operability

was questioned, the RHR system was operated to test and evaluate valve response.

Valve 21RH29 failed to operate and was declared inoperable.

When tested, valve 22RH29 opened on pump start. The Engineering

Analysis Group (EAG) was tasked with performing

a follow-up

operability

assessment.

The results of follow-up

engineering

evaluations

did not provide sufficient

basis to confirm 22 RHR loop operability.

As a result, with both RHR loops inoperable, at 18:27 hours on June 7, 1995, the operating

crew entered Technical

Specification

3.0.3 and commenced

shutdown of Salem Unit 2. At the time of the initial valve misoperation

events, an Operations

Standing Order and Operability

Determination (OD) Flowchart

were in place to guide Operations

personnel

in making Operability

Determinations.

Licensed operators

had received training on the use of the OD flowchart

during the 1994 fall training segment. Although the Standing Order and OD Flowchart

were available

on January 26, 1995, and February 9, 1995, the operating.crews

did not perform an Operability

Determination

when the operation

of the RH29 valves came into question . ROOT CAUSE ASSESSMENT

The RH29 valve control relays were tested and the most probable cause for

misoperation

was attributed

to failure of the Struthers-Dunn

low flow interlock

relay. PSE&G has determined

that the root cause of the failure to *identify

and correct this condition

adverse to quality was inadequate

management

commitment

to the Operability

Determination

process. This was demonstrated

by the following:

1. The implementation

of NRC Generic Letter (GL) 91-18 operating

philosophy

was not timely and effective

in improving

Operability

Determinations.

2. The implementation

of Operations

Department

procedures (Operability

Flowchart

and Operations

Department

Directive

SC. OP-DD. ZZ-OD02 (Q) (OD-2) , 11 Operability

Determinations")

to improve Operability

Determinations

was ineffective.

3. Less-than-adequate

safety culture within the Operations, Technical

Engineering, and Station Planning organizations, whi.ch was manifested

by a tolerance

for equipment

problems and insufficient

follow-through

to correct these problems .

• • * * Document Control Desk LR-N95196 -3 -CORRECTIVE

STEPS THAT HAVE BEEN TAKEN Attachment

1 (cont'd) The Struthers-Dunn

valve control relays for valve 21RH29 were replaced.

The 22RH29 valve control relays passed in situ functional

testing and will be replaced prior to Unit restart. Salem Unit 2 was shutdown to comply with Technical

Specification

requirements.

To address the less-than-adequate

safety culture issues, PSE&G management

decided that Salem Units 1 and 2 will remain shutdown until performance

improves.

The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

OD-2, "Operability

Determinations" has been revised to provide better guidance and expectations

for performance

of Operability

Determinations.

Operator awareness

of NRC GL 91-18 is being reinforced

during Salem licensed operator training.

These actions assure that management

expectations

regarding

roles and responsibilities

in the Operability

Determination

process are clearly understood

and consistently

applied. As an interim measure, the Operations

department

reviews

Operability

Determinations (OD's) periodically

to ensure that actions and contingencies

are progressing

and/or completed.

The review process is directed by Operations

procedure

OD40 {Q), "Shift Routines." To assess the effectiveness

of the OD process, the Safety Review Group (SRG) is, on an interim basis, independently

evaluating

the OD's and providing

feedback to Operations

management.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

The Operability

Determination

process, including

the OD-2 procedure, is being further enhanced to: 1) improve the Engineering

and Operations

departmental

interface;

2) ensure consistency

between OD-2 and NC.NA-AP.ZZ-0006(Q) (NAP-6) "Corrective

Action Program";

and 3) ensure tracking of Operability

Determination

status. These improvements

to the process will be completed

by March 1, 1996 . f

• • * * Document Control Desk LR-N95196 -4 -DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED Attachment

1 (cont 1 d) PSE&G has identified

and corrected

the cause of the valve failures.

PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

• • * * Document Control Desk LR-N95196 -1 -ATTACHMENT

2 VIOLATION

B. Contrary to the above, a significant

condition

adverse* to quality existed at the Salem Unit 1 facility from December 12, 1994, until May 16, 1995, in that the No. 12 safety related switchgear

ventilation

supply fan failed on December 12, 1994, and the Licensee did not initiate resolution

of the condition

or effect any corrective

measures to resolve the condition

promptly. ( 02013) This is a Severity Level III Violation (Supplement

1) . Civil Penalty -$100,000 RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

In Deceinber, 1994, the No. 12 Switchgear

Penetration

Area Ventilation

System (SPAVS) supply fan tripped on overload protection.

Further investigation

revealed that the fan motor bearings had failed. Repair of the fan motor bearings necessitated

that the fan motor assembly be removed from the system. A Temporary

Modification (T-Mod) was required to maintain system/plenum

integrity

with the fan motor assembly removed. As a result of poor planning and lack of communication, corrective

actions had not been taken to repair the No. 12 SPAVS supply fan when the No. 13 SPAVS supply failed on May 12, 1995. At the time of these failures, no spare supply fan motors were available.

Troubleshooting

reve.aled

that the second fan motor had developed

an internal short to ground. In accordance

with the Salem Updated Final Safety Analysis Report (UFSAR) , normal system operation

requires two of the three 50% capacity SPAVS supply fans to be in service, with the third fan available

in a standby mode to accommodate

failures.

With the failure of No. 12 SPAVS supply fan motor in December, 1994, .station personnel

failed to recognize

that SPAVS was operating

outside the UFSAR assumptions.

On May 12, 1995, two of the three supply fans became

and System Engineering

personnel

were unable to clearly establish

the system's ability to fulfill its intended safety function.

A shutdown of Salem Unit 1 was initiated

on May 16, 1995 .

• • * * Document Control Desk LR-N95196

ROOT CAUSE ASSESSMENT -2 -Attachment

2 (cont'd) PSE&G has determined

that the root cause of this event was ineffective

corrective

action. Involved personnel

failed to recognize

the significance

of losing redundant, important

to safety components.

Due to a less-than

adequate safety culture, prompt corrective

actions, consistent

with the safety significance

of the equipment, were not initiated

as evidenced

by: 1. Failure to repair the first failed SPAVS supply fan motor in a timely manner. 2. Lack of communication

in the System Engineering

organization.

3. Failure to complete the work planning for repair by the issuance of a T-Mod which was not accomplished

prior to the second SPAVS supply fan motor failure. The

Action Program (CAP), in effect at that time, lacked sufficiently

low thresholds

to ensure that conditions

adverse to quality would be identified

and resolved in a timely manner. That same program did not provide clear guidance on the need to perform nor the required content of assessments

to support continued

assurance

of equipment

operability . The following

contributing

factors were also identified:

1. Adequate Preventative

Maintenance (PM) program tasks were not established

for these fan motors. Opportunities

to establish

appropriate

PM's were missed due to lack of follow-through

with regard to industry experience

notifications

and a previous SPAVS fan motor failure. 2. Lack of clear understanding

by Operations

and Engineering

personnel

of the SPAVS design basis. 3. Operations

did not have a tracking system to assure that inoperable

Technical

Specification

systems or support systems would be corrected

in a timely manner. CORRECTIVE

STEPS THAT HAVE BEEN TAKEN On May 16, 1995, Salem Unit 1 was shutdown to comply with Technical

Specification

requirements

when reasonable

assurance

of system operability

could not be established .

• • * * Document Control Desk LR-N95196 -3 -Attachment

2 (cont'd) The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

Preventive

Maintenance

Change Requests (PMCR's) were generated

to create new PM Recurring

Tasks to replace the SPAVS fan motor bearings on a regular basis. All three Salem Unit 1 SPAVS supply fans were inspected

and the fan motors replaced.

• operations

Department

procedure

SC.OP-DD.ZZ-ODlO(Q} "Removal and Return of Nuclear Safety Equipment" has been issued. This procedure

provides guidelines

for removal and return to service of all Technical

Specification

related equipment.

OD-2, "Operability

Determinations" has been revised to provide better guidance and expectations

for performance

of Operability

Determinations.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

A_ll SPAVS supply fans on Salem Unit 2 will be inspected

and the fan motor bearings will be replaced, on an as-needed

basis, prior to unit restart . Process improvements

for the Operating

Experience

Feedback Program (OEF) are presently

under evaluation.

This activity is being managed under the Corrective

Action Program element of the Salem Restart Plan. The Technical

Specification

Action Tracking procedure

has been revised to require the NSS to verify and initial for completed

Technical

Specification

actions and allow for tracking of potential

Technical

Specification

entries. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The No. 12 and 13 SPAVS supply fans were repaired.

PSE&G

have achieve.d

compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

--

I . ** * ** Document Control Desk LR-N95196 -1 -ATTACHMENT

3 VIOLATION

C. The Licensee was informed by Westinghouse

on March 15, 1993, of a significant

condition

adverse to quality involving

nonconservatisms

in the setpoint methodology

for the Pressurizer

Overpressure

Protection

System (POPS) for low temperature

overpressure*

transient

conditions.

1. Contrary to Criterion

XVI, the Licensee took nine months of analysis, from March 1993 to December 1993, to conclude that the corrected

peak transient

pressure would exceed pressure/temperature (P/T) limits as described

in each unit's technical

specifications

limits. After completing

the analysis, from December 30, 1993, and continuing

for approximately

one month, the Licensee dispositioned

the matter of the nonconservatism

in the setpoint methodology

for the POPS by 1) administratively

limiting RCS operation

to two reactor coolant pumps when the RCS was less than 200° F and 2) increasing

each unit's P/T limit by 10%; the latter corrective

action was inadequate

because it utilized as a basis an unauthorized

ASME Code Case (N-514), which the Licensee was aware was not acceptable

pursuant to 10 CFR 50. 55 (a) . ( 03 013) This is a Severity Level III Violation (Supplement

1) Civil Penalty -. $100,000 2. Contrary to Criterion

XVI, in January 1994, following

the Licensee recognizing

the unacceptability

of using unauthorized

Code Case N-514 as a corrective

action to disposition

the POPS setpoint methodology, the Licensee elected to implement

corrective

action by taking credit for the relief capacity provided by RHR system suction relief valve RH3 to augment POPS relief capacity .

I . ** * * Document Control Desk LR-N95196 -2 -Attachment

3 (cont'd) However, as the Salem FSAR (Section 7.6.3.2) describes

the POPS system to include two Power Operated Relief Valves (PORVs) and does not describe Valve RH3, this corrective

action was inadequate

because an evaluation

was not performed

to determine

the acceptability

of the use of Valve RH3 as part of the POPS system. In addition, the Licensee failed to identify that on the receipt of a safety injection (SI) signal, a previously

operating

positive displacement

charging pump's discharge, combined with the discharge

from the high head safety injection

pump that starts on receipt of the SI signal, could have injected water mass into the RCS at a rate that could have prevented

POPS from performing

its function.

(04013) This is a Severity Level III Violation (Supplement

I) Civil Penalty -$100,000 RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

On March 15, 1993, Public Service Electric & Gas (PSE&G) was advised by Westinghouse

of a generic issue involving

a conservative

setpoint calculation

in the analysis of the Pressurizer

Overpressure

Protection

System (POPS) . The Low Temperature

Overpressure

Protection

System (LTOPS) protects the Reactor Pressure Vessel (RPV) against pressurized

thermal shock events as required to comply with 10CFR50 Appendix G criteria ("Fracture

Toughness

Requirements").

PSE&G requested

Westinghouse

to perform a Salem plant-specific

analysis for the cases of one, two or four reactor coolant pumps running. On September

29, 1993, PSE&G received the plant*-specif

ic Westinghouse

results and had evidence that a non-conservative

setpoint (375 psig) could lead to violating

the Technical

Specifications

and Appendix G pressure/temperature

limits. Over a period of three months (September

to December, 1993), Nuclear Engineering

personnel

performed

calculations

to address this concern .

I . ** Document Control Desk LR-N95196 -3 -Attachment

3 (cont'd) On December 30, 1993, the Nuclear Engineering

department

issued an evaluation (MEC-93-917)

which restricted

operations

in Mode 5 to two reactor coolant pumps. The recommended

restrictions

were implemented

via revisions

to the plant's Integrated

Operating

Procedures (IOP's). Nuclear Engineering

personnel

improperly

took credit for American Society of Mechanical

Engineers (ASME) Code Case N-514 (which had not yet received NRC approval)

as part of dispositioning

this issue. Despite the involvement

of multiple departments

during this evaluation

process, numerous opportunities

to recognize

the reportability

requirements

for this issue were missed and, as a consequence, the condition

was not reported to the NRC. On May 26, 1994, another evaluation (MEC-94-630)

was issued whi.ch further restricted

the number of operating

Reactor Coolant pumps from two to one pump in Mode S. The new calculated

transient

values showed that Salem Unit 2 pressure did not exceed specified

limits. However, it was recognized

that Salem Unit 1 could exceed its pressure limit during a mass addition transient

below 2oo*degrees

F. Involved personnel

failed to evaluate the calculated

deviation

from the specified

limit against reportability

requirements.

Likewise, there was a failure to recognize

the need to establish

justification

for continued

operation

while this condition

existed and the need to report * that justification

to the NRC. * On June 13, 1994, Nuclear Engineering

issued calculation

S-C-RC-MDC-1358.

This calculation

inappropriately

took credit for use of a relief valve (RH3) in the Residual ijeat Removal (RHR) system. On November 17, 1994, it was determined

that Salem Unit 1 could operate outside of the design/licensing

basis for the POPS analysis if the following

conditions

existed: 1) a Safety Injection (SI) signal was initiated;

2) Reactor Coolant System (RCS) temperature

was below 200 degrees F; 3) a Reactor Coolant pump was in service; 4) a Positive Displacement

Charging Pump was in service; and 5) power remained available

to a maximum of one Centrifugal

Charging Pump. This discovery

resulted in the issuance of Licensee Event Report (LER) 272/94-017 .

I . ** * * Document Control Desk LR-N95196 -4 -Attachment

3 (cont'd) On February 7, 1995, the NRC approved PSE&G's use of ASME Code Case N-514. At that time, appropriate

10CFR50.59

Safety Evaluations

were performed

for the resultant

changes to the Updated Final Safety Analysis Report (UFSAR) . Implementation

of the ASME Code Case provided additional

margin (10%) and higher pressure/temperature

limits for POPS during the LTOP conditions

and re-established

plant operation

within its design and licensing

bases. In April, 1995, PSE&G issued Incident Reports to identify and evaluate the organization's

inappropriate

actions and their causal factors. ROOT CAUSE ASSESSMENT

PSE&G has determined

that the root causes of this event were: 1. 2. 3. Lack of understanding

of the regulatory

significance

and reportability

implications

of the Westinghouse

analysis results. Specifically, the organization

became too focused on the technical

resolution

aspects of the issue without adequate consideration

of regulatory

requirements.

Lack of supervisor/management

sensitivity

to the need to impJement

existing procedures

and processes

which require timely entry of issues into the Corrective

Action Program (CAP) . Monitoring

of the Corrective

Action process by

was insufficient.

Inadequate

training of engineering

personnel

on the use of ASME Code Cases, requirements

of lOCFRS0.59

and requirements

for regulatory

reporting.

CORRECTIVE

STEPS THAT HAVE BEEN TAKEN The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment .

• • * * Document Control Desk LR-N95196 -5 -Attachment

3 (cont'd) NBU Management

has re-emphasized

the expectation

that supervisory

personnel

must assess issues objectively.

Specifically, supervisory

personnel

must maintain their oversight

role. The Manager -Nuclear Engineering

Design (NED) has verbally reinforced

this expectation

to the engineering

design organization.

The Nuclear Engineering

Design organization

was surveyed relative to any past reliance on unapproved

ASME Code Cases. Based on this survey, no other instances

of unapproved

ASME Code. Case use were identified.

Personnel

involved in this occurrence

have received appropriate

reinforcement

on procedure

compliance, their responsibility

for compliance

with regulatory

requirements, and problem reporting.

Management

has re-emphasized

by internal memorandum

and follow-up

review with engineering

personnel

that the potential

impact on the UFSAR must be considered

whenever design basis calculations, evaluations

or assumptions

are revised. Departmental

procedures

provide clear guidance on these requirements.

The expectation

• for procedural

adherence

was also reinforced.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

Engineering

Design and Licensing

&_Regulation

management

will reinforce

expectations

for organizational

interface

to their personnel.

This will be completed

by March 15, 1996. Lessons learned from this issue will be disseminated

to Engineering

Support personnel

during 4th quarter Operating

Experience

Feedback (OEF) training.

This will be completed

by January 15, 1996. Process improvements

for the Operating

Experience

Feedback Program (OEF) are presently

under evaluation.

• This activity is being managed under the Corrective

Action Program element of the Salem Restart Plan. Specific training on the ASME Code and NRC restrictions

on its use will be provided to appropriate

engineering

support personnel.

This will be completed

by January 31, 1996 .

• • * * Document Control Desk LR-N95196 -6 -Attachment

3 (cont'd) The Engineering

Qualification

training program is being revised to assure that job qualifications

are consistent

with job requirements

and that Engineering

personnel

are trained consistently.

Required personnel

training in Code Job Packages will be incorporated

into the Engineering

Qualification

Guide. This* training will include ASME Code Cases, NC.NA-AP.ZZ-002B(Q) "Code Job Packages" procedure

requirements

and regulatory

reporting

requirements.

The revised Engineering

Qualification

Guides will be completed

by January 31, 1996. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The request to use ASME Code Case N-514 at Salem station was approved by the NRC. PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

I Document Control Desk .* LR-N95196 -1 -* * ATTACHMENT 4 -lST EXAMPLE VIOLATION

D. Contrary to the above, on several occasions, conditions

adverse to quality existed, but were not identified

and promptly corrected, as evidenced

by the following

examples:

1. On June 7, 1994, the Licensee identified

that material management

documentation

for limit switches related to the reactor head vent valves, improperly

classified

the components

as non-safety

related. A nuclear design discrepancy

evaluation

form (DEF) identified

that a switch short circuit could render two head vent valves inoperable

since the components

were powered from the same common circuit. Notwithstanding, the DEF did not identify any concern relative to operability

or safety. In February 1995, the Licensee determined

that non-safety

related limit switches were actually installed

in reactor head vent valves 1RC41 and 1RC43 at Salem Unit 1. Subsequently, the Licensee failed to* perform and document an engineering

evaluation

to demonstrate

the acceptability

of continued

Salem Unit 1 operation

with non-safety-related

parts installed

in a safety-related

application.

RESPONSE -DESCRIPTION.OF

CIRCUMSTANCES

PSE&G does not dispute the violation.

On June 7, 1994, a Discrepancy

Evaluation (DEF) was written to resolve an apparent conflict in safety classification

between the Reactor Head vent valves and their corresponding

position indicating

limit switches for Salem Units 1 and 2. On March 3, 1995, it was determined

that

related limit switches were installed

in two Salem Unit 1 Reactor Head vent valves. Investigation

into this occurrence

indicates

that, in April, 1992, an opportunity

to resolve the noted discrepancy

was missed when a different

DEF on the same subject was dispositioned.

The identified

corrective

actions in that DEF were not carried through to completion .

• • * * Document Control Desk LR-N95196

ROOT CAUSE ASSESSMENT -2 -Attachment

4 (cont'd) PSE&G has determined

that the root cause of this occurrence

was the erroneous

classification

of the Reactor Head vent valve limit switches as non-safety

related. Due to personnel

error, these switches were incorrectly

assigned a non-safety

related purchase class during a spare part Folio Classification

initiative

in 1986. This error in classification

initiated

a sequence of events which resulted in the installation

of non-safety

related limit switches in an application

originally

designed to use safety related components.

The root cause of the failure to resolve this condition

adverse to quality in a timely manner is attributed

to an inadequate

Corrective

Action Program (CAP). The CAP, in effect at that time, lacked sufficiently

low thresholds

to ensure that conditiqns

adverse to quality would be identified

and resolved in a timely manner. That same program lacked centraliz'ed

oversight

of the various mechanisms

to identify and resolve discrepancies.

CORRECTIVE

STEPS THAT HAVE BEEN TAKEN In March, 1995, Nuclear Engineering

Design issued an assessment

to resolve the outstanding

DEF. This assessment

concluded

that the non-qualified

switches did not affect the operability

of the Reactor Head vent valves. * The following

changes were made in the Nuclear Procurement

and Material Management (NP&MM) system: The Purchase Class 4 (PC4) Limit Switch Folio parts were put 11 0n Hold" and were re-classified

as 11 obsolete.11 A New Purchase Class 1 Limit Switch Folio was created. The Reactor Head vent valve limit switch component

ID's were removed from the computerized

Managed Maintenance

Information

System (MMIS). Separate component

ID's were determined

to be unnecessary

as the Bill of Materials (BOM) for the valves contains the Folio information

for the limit switches .

• • * * Document Control Desk LR-N95196 -3 -Attachment

4 (cont'd) The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

Non-safety

related limit switches in the Reactor Head vent valves will be replaced prior to restart of Salem Unit 1. Outstanding

DEF's are being reviewed for impact on plant systems, including

operability

issues. This will be completed

prior to restart of Salem Units 1 and 2. PSE&G is currently

conducting

a review of the MMIS database to determine

if there have been other occurrences

of safety related components

being purchased

as non-safety

related. The scope of _this review will include components

acquired under purchase class "PC4" (non-safety

related).

Any additional

occurrence(s)

of safety related parts in safety related applications, discovered

during this review, will be dispositioned

under the current CAP

which include documentation

of Operability

Determination

and evaluation

for reportability, when appropriate . . This review will be completed

prior to restart of either Salem Unit 1 or 2. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The Engineering

department

has dispositioned

the outstanding

DEF. PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

I . ** * * Document Control Desk LR-N95196

VIOLATION

ATTACHMENT 4 -2ND EXAMPLE 2. On February 24, 1995, Unit No. 1 operators

placed control of a PORV in the manual mode, rendering

it inoperable, and failed to adhere to the Technical

Specification

3.4.3 action statement

which required operators

to close the block valve within one hour. A shift supervisor

discovered

that the PORV had been erroneously

placed in the manual mode and corrected

it on February 25, 1995, about 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> later. RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

On February 24, 1995, Salem Unit 1 was in the process of raising Reactor.Coolant

System (RCS) pressure using Integrated

Operating

Procedure

2 (IOP-2). To support a controller

inspection, the Pressurizer

pressure master controller

was removed and pressure control was placed in manual. This action rendered Operated Relief Valve (PORV) 1PR2 inoperable

and required closing of PORV block valve 1PR7. The operator did not close valve 1PR7 and the oversight

went unnoticed

for approximately

22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />. Although a pre-job brief was performed

prior to this evolution, it did not cover all TS required actions. Specifically, the briefing did not discuss closing valve 1PR7. The Nuclear Control Operator (NCO) and the Nuclear Shift Supervisor (NSS) failed to conduct adequate self-checking.

The NSS failed to maintain the proper supervisory

overview to insure that the Technical

Specification

action was completed.

ROOT CAUSE ASSESSMENT

The root cause of this event has been attributed

to personnel

error on the part of the 'supervisor (NSS) and the control operator (NCO) . A contributing

cause to this event was inadequate

guidance in the Technical

Specification

Action Tracking Log. This log did not prompt operators

to verify that TSAS are completed

when the action statement

is entered .

• • * * Document Control Desk LR-N95196 -2 -CORRECTIVE

STEPS THAT HAVE BEEN TAKEN Attachment

4-2ND example (cont'd) Appropriate

disciplinary

actions were taken for the individuals

involved.

The NSS primary work location has been moved into the respective

Control Room area as of March 3, 1995, to improve oversight

and management

of control room activities.

The Technical

Specification

Action Tracking procedure

has been revised to require the NSS to verify and initial for completed

Technical

Specification

actions and allow for tracking of potential

Technical

Specification

entries. An Information

Directive 95-017 and two separate shift briefings

were completed

for each of the Operations

crews. The Operations

Department

has re-emphasized

the use of checking techniques, peer verification

and expecta.tions

for NSS oversight.

Operations

management

re-emphasized

the conditions

under which the PORV's should be declared inoperable

during Licensed Operator Requalification (LOR) training in segment 4, 1995. Understanding

of Technical

Specification

actions by Operations

personnel

were verified through LOR examinations.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

The Operations

Department

is developing

an Operations

Standards

document which will reference

appropriate

procedure

guidance for conducting

pre-job briefings.

The Operations

Standards

document will be implemented

by November 21, 1995. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The PORV block valve was closed to comply with TS requirements.

PSE&G will have achieved compliance

with 10CFR50 Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

• • * * Document Control Desk LR-N95196 -1 -Attachment

4-3RD example (cont'd) VIOLATION

ATTACHMENT 4 -3RD EXAMPLE 3. On July 6, 1994, safety-related

reactor head vent valve 2RC40 failed to operate (stroke open) during testing while Unit No. 2 was in cold shutdown.

Subsequently, the valve was returned to normal service on July 10, 1994, without any review or assessment

in accordance

with established

procedures;

that is, the Licensee failed to process this occurrence

in accordance

with the applicable "Work Control Process" procedure.

Consequently, this failure of a safety related component

was never documented

and formally assessed relative to preventive

maintenance, operability, actions to prevent recurrence, or generic implications.

RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

On July 6, 1994, the 2RC40 valve failed its post-maintenance

testing due to indications

of reduced flow and dual position indication

problems.

Subsequent

investigation, including

consultation

with the vendor, indicated

that the most probable cause of the valve failing to stroke open was due to boric acid solidification

around the pilot plug. The boron solidification

was suspected

to be the result of valve seat leakage. The Maintenance

Engineer recommended

backflushing

of the valve with demineralized

water and increasing

the Reactor Coolant System (RCS) temperature

to 180 °F to dissolve the boron. This resulted in proper valve operation

and supported

the original root cause supposition.

Therefore, it was concluded

that a temporary

condition

could develop at low RCS temperatures

and pressures

that could result in boric acid binding of the valve. On July 8, 1994, the valve was placed back into service with a recommendation

to evaluate the need for additional

valve preventive

maintenance .

• • * * Document Control Desk LR-N95196 -2 -Attachment

4-3RD example (cont'd) In December, 1994, the Salem Unit 2 head vent valves were replaced as a result of excessive

seat leakage. Similar conditions

had been previously

observed on the Salem Unit 1 valves 1RC40 and 1RC42 and prompted their replacement

in May, 1994. In May, 1995, the vendor disassembled

and inspected

valve 2RC40, which had been removed in December, 1994, to identify any material condition

that could have caused the valve's failure to open. The test results on valve binding were inconclusive

but indicated

that the reported leaking of the valve could be attributed

to steam cutting between the valve and the pilot valve disc due to normal wear. On April 5, 1995, an Incident Report was initiated

and a root cause analysis undertaken

which arrived at much the same conclusions

as that of the vendor. The root cause of the failure of valve 2RC40 to stroke was indeterminate.

The type of degradation

experienced

by the head vent valve would not have alone prevented

it from stroking.

Degradation

of the valve internals, however, was identified

as a causal factor in both the valve leakage and failure to stroke and was attributed

to a lack of preventive

maintenance.

PSE&G has determined

that this failure mode is applicable

only to the Reactor Head vent valves. In April, 1995, a re-analysis

of the Preventive

Maintenance*

requirements

for these valve internals

was completed

and a 54-month inspection

was recommended.

ROOT CAUSE ASSESSMENT

The final root cause for the failure of valve 2RC40 to open was inconclusive.

Probable causal factors include: 1. Lack of preventive

maintenance

on valve internal components.

2. Accumulation

of boric acid precipitate

on valve pilot plug. The root causes for the failure to identify and correct this condition

adverse to quality were: 1. An inadequate

Corrective

Action Program* (CAP). The CAP, in effect at that time, failed to establish

sufficiently

low reporting

thresholds

to ensure that conditions

adverse to quality would be identified

and resolved in a timely manner. 2. Management

failure to establish

and enforce high expectations

for equipment

and personnel

performance .

• • * * Document Control Desk LR-N95196 -3 -CORRECTIVE

STEPS THAT HAVE BEEN TAKEN Attachment

4-3RD example (cont'd) The Reactor Head vent valves 1RC40/42 and 2RC40/41/42/43

have been replaced in May, 1994, and December, 1994, respectively.

Valves 1RC41 and 1RC43 are being replaced during the current outage. The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

Appropriate

Operations

Department

procedures

have been revised. These revisions

include guidance to preclude boric acid accumulation

in the valve body. An Action Request to identify any solenoid operated valves other than the reactor head vent valves that serve as a Reactor Coolant System (RCS) pressure boundary and could potentially

be subject to the same or a similar failure mode, such as boric acid binding to*seat leakage, has been completed.

PSE&G has determined

that this failure mode is applicable

only to the Reactor Head vent valves. NC.NA-BP.ZZ-0002(Z), "Root Cause Analysis Guidelines," has been developed

to provide additional

information

and guidance in the use of various root cause analysis techniques

which have been proven effective

in resolving

both human and equipment

performance

problems.

Within the Salem Maintenance

Department, PSE&G has established

dedicated

resources

to conduct required root cause analyses, develop _and recommend

appropriate

corrective

actions, and assure their proper implementation

and overall effectiveness

through followup assessments.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

New PM Recurring

Tasks (RT's) have been initiated

to implement

a 54-month PM to open and inspect the Reactor.Head

vent valve internals

and to repair as needed. A new Maintenance

Department

procedure

has been issued to provide guidance on the disassembly, inspection

and refurbishment

of the Reactor Head vent valves. These corrective

actions will be completed

prior to restart of the affected unit .

• • * ** Document Control Desk LR-N95196 -4 -Attachment

4-3RD example (cont'd) DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED This condition

was documented

and a root cause analysis was completed.

PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

• • * * Document Control Desk LR-N95196 -1 -VIOLATION

ATTACHMENT 4 -4TH & STH EXAMPLES 4. An oil sample laboratory

report, dated August 4, 1994, recommended

resampling

and changing the oil on the No. 21 high-head

safety injection

pump based upon a ten-fold increase in wear particle concentration.

An oil analysis, dated November 28, 1994, identified

high wear particle concentration

in the No. 22 high-head

safety injection

pump speed increaser

oil. In both these cases, the system engineer, though aware of the findings of the lab reports, did not initiate any follow-up

evaluation

or corrective

measure, nor establish

a bases for operability

or reliability

in view of the apparent degraded condition

of the equipment.

The degraded nature of the equipment

was not entered into the Equipment

Malfunction

Identification

System (EMIS) until March 20, 1995. 5. A lab report, dated October 6, 1994, recommended

resampling

the No. 23 Auxiliary

Feedwater (AFW) turbine lube oil due to a detectable

amount of water contamination

and an increase in wear particle concentration.

However, the degraded nature of the equipment

was not entered into the EMIS until March 27, 1995, and the system engineer did not initiate review, and evaluation, or establish

any basis for equipment

operability

or reliability.

RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

PSE&G acknowledges

the issues identified

in this violation

were not addressed

in a timely fashion. Documentation

of equipment

status was deficient

and inadequately

maintained .

• • * * Document Control Desk LR-N95196 -2 -Attachment

4-4TH & STH (cont'd) ROOT CAUSE ASSESSMENT

PSE&G attributes

the root cause of these occurrences

to: 1. Management's

failure to enforce expectations

regarding

individual's

responsibilities

for the Performance

Monitoring

program. 2. The lengthy turnaround .time for laboratory

analyses (including

radioactive

material handling)

challenged

the ability of the System Engineer to make timely decisions.

The root cause for the failure to identify and correct these conditions

adverse to quality is: 1. An inadequate

Corrective

Action Program (CAP). The CAP, in effect at that time, lacked sufficiently

low thresholds

to ensure that conditions

adverse to quality would be resolved in a timely manner. That same program did not provide clear guidance on the need to perform nor the required content of assessments

to support continued

assurance

of equipment

operability.

CORRECTIVE

STEPS THAT HAVE BEEN TAKEN The 23 AFW Pump was declared inoperable.

This action was completed

within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of when PSE&G received notification

from the laboratory-

that the follow-up

oil sample had been confirmed

to be the wrong grade for the component.

The Corrective

Program (CAP) has been revised as described

in the cover letter to this Attachment.

Roles and responsibilit.ies

within System Engineering

have been defined and communicated

as described

in the cover letter to this Attachment.

Within System Engineering, a component

reliability

group was established

to provide improved focus on equipment

performance

and reliability

issues. The Manager -Component

Reliability

will define and communicate

roles and responsibilities

for tracking

I . ** * * Document Control Desk LR-N95196 -3 -Attachment

4-4TH & STH (cont'd) and trending of performance

monitoring

data. This will be completed

by January 15, 1996. Lube oil abnormalities

from this occurrence

have been documented

by an Abnormal Condition

Report to the System Manager from the Lube Oil Analysis Program Manager. This process will remain in place to document future reports of abnormal indications.

PSE&G has contracted

with a lube oil analysis laboratory

capable of handling radioactively-contaminated

lube oil samples. The laboratory's

ability to handle contaminated

material will reduce the time from sample collection

to condition

determination

by reducing the required count time per sample. CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

The Lubricating

Oil Program is being assessed to identify recommendations

on a comprehensive

lube oil program. The program recommendations

are due by the end of the fourth quarter, 1995. These

will be evaluated

and an Implementation

Plan for approved recommendations

will be established

by the end of first quarter, 1996. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The abnormal Lube oil conditions

were documented, reviewed and evaluated

for operability

impact. PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related -processes

have been

effective

at identifying

and

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

• • * * Document Control Desk LR-N95196 -1 -VIOLATION

ATTACHMENT 4 -6TH EXAMPLE 6. LER 95-05 identified

seven instances, between May 8, 1990 and January 14, 1995, of Pressurizer

safety valves (PSVS) being beyond the 1% tolerance

required by TS 4.0.5 for Unit 1. Four instances

were identified

between November 14, 1994, and January 14, 1995, which involved 2 of the 3 installed

PSVS. In all instances, the vendor notified the appropriate

system engineer by telephone

and written follow-up

reports. However, the responsible

system engineer never initiated

an Incident Report. Consequently, root cause, operability, and reportability

actions were not accomplished.

-DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

Beginning

in May 8, 1990, eight (8) occurrences (total for both Salem Units) of Pressurizer

code safety valves (PSV's) exceeding

the 2485 psig +/-1% lift set pressure were identified.

Seven of those instances

were cited within the Notice of Violation.

An eighth occurrence

was self-identified

and reported to the NRC via LER Supplement

272/95-05-01, dated October 31, 1995. These occurrences

were identified

during testing required by Technical

Specification (TS) 4.0.5. Failure to report these anomalies

resulted from personnel

error in that Incident Reports (IR's) were not written in accordance

with NC.NA-AP.ZZ-0006(Q)

procedure

requirements.

ROOT CAUSE ASSESSMENT

The causes of the lift setpoint variances

are a combination

of variability

due to individual

valve performance

characteristics

and random test variations

which are common for these valves. The specific causes for Salem Station's

variation

are: 1. Minor test loop instrument

error. 2. Valve design limitations.

3. Applied loads from the discharge

piping .

' . ** Document Control Desk LR-N95196 -2 -Attachment 4 -6th example (cont'd) PSE&G has determined

that the programmatic

root cause of this violation

was management's

failure to clearly and adequately

communicate

expectations

regarding

when an IR was required.

Specifically, the System Engineers

did not recognize

the requirement

to initiate IR's for these lift setpoint anomalies, in accordance

with Nuclear Administrative

Procedure

NC.NA-AP.ZZ-

0006 (Q), "Corrective

Action Program" in effect at the time. They also failed to recognize

the reportability

implications

for the out-of-tolerance

valve performance

data. Consequently, the testing anomalies

were not reviewed against the lOCFRS0.73 "Licensee

Event Report" (LER) reporting

criteria and required LER reporting

did not occur. CORRECTIVE

STEPS THAT HAVE BEEN TAKEN PSE&G has performed

engineering

evaluations

as part of the Fuel Upgrade Margin Recovery program. The thermal-hydraulic

analysis indicates

that PSV lift setpoint variances

up to 3% are acceptaple.

The structural

analysis is more limiting, indicating

that variances

of +2.2 to -3.0% are acceptable.

Analyses within the Fuel Upgrade Margin Recovery program are continuing.

The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

,_., Lessons learned from this violation

were incorporated

into the * third quarter Operating

Experience

Feedback (OEF) training for Engineering

Support personnel.

Appropriate

discipline

was taken with personnel

involved in the failure to initiate IR's. Applied loading on the PSV's from the discharge

piping has been* reduced. CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

A single point of contact within the PSE&G organization

will be established

to ensure coordination

of activities

associated

with PSV testing. This will be completed

by March 29, 1996 .

• • * * Document Control Desk LR-N95196 -3 -Attachment 4 -6th example (cont'd) DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The lift setpoint variance conditions

were documented, reviewed and assessed to demonstrate

acceptability.

PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved . l I

I . * * Document Control Desk LR-N95196 -l -VIOLATION

ATTACHMENT 4 -7TH EXAMPLE 7. On March 6, 1995, May 3, 1995, and May 8, 1995, the Salem Unit l staff failed to determine

the cause, correct, or prevent recurrence

of failure of the Containment

100 foot elevation

personnel

airlock to pass its local leak rate test. RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

On March 6, 1995, the Salem Unit l Containment

personnel

airlock on the 100 foot elevation

failed its local leak rate test (LLRT) A work request was initiated

for the Maintenance

Department

to investigate

and correct the problem. Maintenance

technicians

inspected

the door seals and identified

no obvious seal damage but noted that dirt had accumulated

on the seal surf ace near the bottom of the door. The door seal was wiped clean with a damp rag and the LLRT was successfully

rerun. Following

the incident, Maintenance

and Operations

agreed to have Operations

personnel

wipe down the door seal and retest the airlock in the event of another airlock failure prior to contacting

the Maintenance

Department.

This was noted as the corrective

action in Incident Report (IR) #95-204. On May 3, 1995, the airlock again failed the local leak rate test. Operations

personnel

wiped down the door seal and satisfactorily

retested the airlock. The Operations

Department

initiated

IR #95-518 and Action Request (AR) #950503088

to evaluate and document the occurrence.

On May 5, 1995, an LLRT was satisfactorily

conducted indicated

an elevated leakrate.

On May 8, 1995, the airlock failed its LLRT for the third time. The door seal was wiped down and the LLRT was successfully

rerun. Operations

initiated

IR #95-551. and AR #950508110

to troubleshoot

and correct the recurring

condition.

Subsequent

investigation

revealed a .significant

buildup of dirt and hardened grease in the groove on the seal surface which was caused by the gasket set. Seal surface wipedown would not have been effective

in removing * this buildup .

• • * * Document Control Desk LR-N95196

ROOT CAUSE ASSESSMENT

-2 -Attachment 4 -7TH example (cont'd) The root cause of this event has been attributed

to

adequate management

expectations

of system performance

as demonstrated

by: 1. Inexperienced

personnel

were assigned to perform the initial inspection

and corrective

actions. 2. Inexperienced

personnel

were assigned to perform the initial root cause evaluation.

Deficiencies

in both the preventive

maintenance

and surveillance

test procedures

also contributed

to this event. CORRECTIVE

STEPS THAT HAVE BEEN TAKEN The gaskets have been replaced on the Salem Unit 1 containment

personnel

airlock on the 100 foot elevation

and the leakage test was

performed.

The Salem Unit 1 containment

personnel

airlock (130 foot * elevation)

and equipment

hatch gaskets will be replaced prior to restart of Salem Unit 1 . The Salem Unit 2 gaskets on the containment

personnel

airlocks and equipment

hatch will be replaced prior to restart of Salem Unit 2. The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

Procedure

NC.NA-BP.ZZ-0002(Z), "Root Cause Analysis Guidelines" has been developed

to provide additional

information

and guidance in the use of various root cause analysis techniques

proven effective

in resolving

both human and equipment

performance

problems.

Within the Salem Maintenance

Department, PSE&G has dedicated

resources

to conduct required root cause analyses, develop and recommend

appropriate

corrective

actions, and assure their proper implementation

and overall effectiveness

through followup assessments.

Appropriate

Salem Maintenance

procedures

have been revised to include specific guidance on seal inspection, cleaning, and maintenance

to assist in troubleshooting

of leakage problems .

• • * * Document Control Desk LR-N95196 -3 -Attachment 4 -7TH example (cont'd) Appropriate

Maintenance

procedures

will be revised to change the airlock seal lubricant

specification

from Dow Corning 111 to Dow Corning 3451 in accordance

with Nuclear Engineering

recommendations.

The above procedure

revisions

will be completed

prior to restart of either Salem Unit 1 or 2. CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

A Preventive

Maintenance

Change Request (PMCR) has been initiated

to evaluate the need for additional

Preventive

Maintenance (PM) tasks for the containment

airlock gaskets. The PMCR recommends

PM's following

the six-month

Structural

Integrity

Test and gasket replacement

at the end of each refueling

cycle. Appropriate

Operations

Department

procedures

will be revised to provide guidance on maintaining

seal surf ace cleanliness

and for performing

leak rate testing, including

discrete leakage criteria for determining

when additional

corrective

action is required.

These corrective

actions will be completed

prior to restart of the affected unit . DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The cause of the airlock seal f ailu*re occurrences

was documented

and evaluated, and the condition

was corrected.

PSE&G will have achieved compliance

with lOCFRSO Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit 1 or 2 until performance

in this and other areas has improved .

• • * * Document Control Desk LR-N95196 -1 -VIOLATION

ATTACHMENT 4 -BTH EXAMPLE 8. From February 29, 1992 until June 7, 1995, Salem Unit 1 staff failed to correctly

determine

the cause or take action to preclude recurrence

of failures of instrument

lines connected

to the jacket water cooling system for the No. lB and No. lC emergency

diesel generators.

RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

On June 1, 1995, during a lB Emergency

Diesel Generator (EDG) Surveillance

Test, a jacket water leak was identified

at the threaded connection

of a 1/4" pipe nipple to an elbow upstream of instrument

root valve 1DA46B. The failed component

was subsequently

replaced in kind. As part of the root cause analysis for the 1/4" nipple failure, natural

frequency

tests were performed

on all EDG's (at both Salem Unit 1 and 2) at locations

congruent

to-this failure. The'test results showed that piping at specific locations

on this and other EDG units could potentially

experience

damage or fail in response to induced vibrational

stresses.

The testing indicated

locations

with natural vibration

resonance

frequencies

very close to an integer multiple of the frequency

which corresponds

to the EDG shaft operating

speed. The affected EDG's were declared inoperable

pending further analysis.

A review of the past failure and maintenance

history of the Salem Unit 1 and 2 EDG's was performed

to identify occurrences

of similar failures.

PSE&G's analysis indicates

that there have been repeated failures due to yibration-induced

fatigue and the recurrent

nature of these failures was not recognized.

Failure to recognize

this repetitive

problem was due to inadequate

root cause analyses and the fact that the failures were attributed

to a wide variety of causes. Recommendations

stemming from this analysis included design change activities

t6 create more vibration-tolerant

configurations

and maintaining

failed components

for subsequent

laboratory

analysis.

Corrective

actions taken in the past were ineffective

at resolving

the vibration-induced

component

failures, as evidenced

by the recurring

nature of these problems .

• • * * Document Control Desk LR-N95196

ROOT CAUSE ASSESSMENT -2 -Attachment 4 -BTH example (cont'd) PSE&G attributes

the root cause of the piping nipple failure to a design which did not adequately

include tolerance

for vibrational

stresses.

A contributing

cause was a lack of specifications

for dimensions

potentially

critical to vibration

tolerance

in the manufacturer's

documentation.

The root cause of the failure to identify and correct these component

failures was an inadequate

Corrective

Action Program (CAP). The CAP, in effect at that time, had numerous program elements which lacked adequate capacity for integration

and oversight.

The CAP did not facilitate

detection

of common failure elements nor did it ensure that conditions

adverse to quality were assessed for impact on Operability

in a timely manner. CORRECTIVE

STEPS THAT HAVE BEEN TAKEN All affected EDG's were declared inoperable

but available, pending resolution

of the potential

for vibration-induced

failure. Interim contingency

plan guidance was provided to the Operations*Department.

This guidance established

requirements

to maximize the availability

of the demineralized

water supply to fill the EDG jacket water system in the event of a postulated

failure. A short-term

adjustment

to the cantilever

length of the affected piping was made. This action reduced the potential

for resonance

between this piping and the engine/header.

A vibration

tolerance

design review of the EDG's and peripheral

equipment

was conducted.

This review resulted in recommendations

for appropriate

enhancement

modifications

to harden the diesel engines against vibration-related

concerns.

The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

A "lessons-learned" memorandum

relative to this issue was issued by the Manager -Nuclear Engineering

Design (NED) to all appropriate

NED personnel.

rolldowns

to NED personnel

have communicated

the "lessons learned."

• • * * Document Control Desk LR-N95196 -3 -Attachment 4 -BTH example (cont'd) CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

Jacket Water Pressure transmitting

tubing runs will be redesigned

to eliminate

the piping nipples and associated

piping isolation

valves. This work has been completed

for lB EDG. Modification

packages have been prepared for the remaining

five EDG's. The Design Change Process (DCP) checklists

will be revised to include specialty

engineering

review for vibration-induced

failure issues. These changes will be incorporated

at the next revision to the appropriate

procedures.

Maintenance

and Planning Department

training programs will be revised to include specific information

regarding

the general nature of fatigue failure and system vibratory

response.

These corrective

actions will be completed

prior to restart of either Salem Unit 1 or 2. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED The cause of the instrument

line failures was identified

and actions were taken to reduce their susceptibility

to

induced failures . PSE&G will have achieved compliance

with 10CFR50 Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart Salem Units 1 and 2 until performance

in this and other areas has improved.

i ! .

• • * * Document Control Desk LR-N95196 -1 -VIOLATION

ATTACHMENT 4 -9TH EXAMPLE 9. From July 11, 1992 until June 10, 1995, Salem staff failed to determine

the cause, evaluate the potential

safety consequences, and establish

corrective

action for an abnormal condition

affecting

the No. 21 Residual Heat Removal discharge

manual isolation

valve (21RH10) associated

with impact noise from the interior of the valve. (05013) RESPONSE -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

On July 11, 1992, during mode 5 operation, unusual noise was identified

coming from Residual Heat Removal (RHR) system valve 21RH10. A slightly lesser noise was heard from valve 22RH10 and from the Unit 1 operating

RHR loop No. 21. A Salem Technical

Department

Memo (92-138) was issued to inform the Operations

Department

that this noise may be caused by flow-induced

vibrations

from existing play in*the male/female

discs and/or disc arm. On April 21, 1993, a maintenance

activity to open and inspect the valve was completed

and wear marks were found on the downstream

seat in two locations.

The cause of the wear marks was attributed

to "wedge banging against seat ring." No internal pa.rts were found in need of replacement

with the exception

of packing and a gasket. On June 10, 1995, valve 21RH10 was again reported making metallic banging noise internally.

A maintenance

supervisor

did an in-field observation

of the valve and concluded

that the noise was abnormal.

An Action Request (AR) was written documenting

the noise; however, a formal Operability

Determination

to assess the impact of the noise on system functional

capability

was not documented

prior to June, 1995 .

• • * ** Document Control Desk LR-N95196

ROOT CAUSE ASSESSMENT -2 -Attachment 4 -9TH example (cont'd) PSE&G has determined

that the root causes of this event were: 1. Inadequate

performance

by the System Engineer regarding

record keeping and tracking/trending

of equipment

malfunctions. . 2. Inadequate

Corrective

Action Program (CAP) as indicated

by: -Inadequate

management

and supervisory

oversight

of equipment

failure follow-up.

-Lack of documented

engineering

analysis of the physical condition

of the valve. The Corrective

Action Program (CAP), in effect at that time, lacked sufficiently

low thresholds

to ensure that conditions

adverse to quality would be identified

and resolved in a timely manner. That same program did not provide clear guidance on the need to perform nor the required content of assessments

to support continued

assurance

of equipment

operability.

CORRECTIVE

STEPS THAT HAVE BEEN TAKEN On June 15, 1995, Salem System Engineering

completed

a Follow-up

Assessment

of Operability

and determined

that the valve noise did not *adversely

affect the functional

capability

of the RHR system. Work Orders have been issued to open and inspect valve 21RH10 to determine

the reasons for the noise currently

being experienced.

Valve 21RH10 is scheduled

to be opened and inspected

after Unit 2 core off-load.

For the purpose of trending, vibration

data on valve 21RH10 is being taken periodically

and reviewed by the System Manager. This will continue until the loop is taken out of service following

core off-load.

The vendor for the valve was contacted

to obtain recommendations

on actions to be taken. The vendor stated

because of the valve design and its location in a turbulent

flow area, impact noises can be expected.

The vendor did not recommend

any periodic preventive

measures.

The Corrective

Action Program (CAP) has been revised as described

in the cover letter to this Attachment.

L

• • * * Document Control Desk LR-N95196 -3 -Attachment 4 -9TH example (cont'd) System Engineering

Department

roles and responsibilities

have been identified

and clearly communicated

to all System Engineering

personnel.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

Additional

corrective

actions, if any, will be identified

after valve disassembly

and inspection, as stated above. System readiness

reviews are currently

underway and include assessment

of the readiness

of plant systems to support unit restart. Self-assessments

of the effectiveness

of the system engineering

organization

to carry out its roles and responsibilities

will be conducted.

These corrective

steps will be completed

prior to restart of either Salem Unit 1 or 2. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED Salem System Engineering

issued their Followup Assessment

of Operability

for this valve condition

on June 15, 1995 . PSE&G will have achieved compliance

with 10CFR50 Appendix B, Criterion

XVI, when the Corrective

Action Program and related processes

have been proven effective

at identifying

and resolving

conditions

adverse to quality in a timely manner. PSE&G will not restart either Salem Unit l*or 2 until performance

in this and other areas has improved .

• • * * Document Control Desk LR-N95196 -1 -ATTACHMENT

5 VIOLATION

II. 10 CFR Part 50, Appendix B, Criterion

V, "Instructions, Procedures, and Drawings", requires that activities

affecting

quality shall be prescribed

by documented

instructions, procedures, or drawings of a type appropriate

to the circumstances, and shall be accomplished

in accordance

with these instructions, procedures

and drawings.

Instructions, procedures, or drawings shall include appropriate

quantitative

or qualitative

acceptance

criteria for determining

that important

activities

have been satisfactorily

accomplished.

Contrary to the above, following

a modification

in May 1993, that installed

a drain system for the Salem Unit 2 Pressurizer

code safety loop seals, the Licensee did not ensure that an activity affecting

quality was satisfactorily

accomplished

in that the procedure

that directed the installation

of the modification

to the Pressurizer

code safety loop seals drains did not adequately

ensure that the drain valves were properly positioned

prior to plant startup after the modification.

Specifically, valve 2PR66, a valve in a common drain line for the 2PR3, 2PR4, and 2PR5, Pressurizer

safety valves, was left closed throughout

the operating

cycle between May 1993 and October 1994. (06013) This is a Severity Level III Violation.

I) Civil Penalty -$100,000 RESPONSE ** -DESCRIPTION

OF CIRCUMSTANCES

PSE&G does not dispute the violation.

During the 2R7 outage, a design change package (DCP) was implemented

to *add drain lines and drain valve 2PR66 to the Pressurizer

Overpressure

Protection

system. Valve 2PR66 was installed

to drain the line downstream

of the Pressurizer

Safety Valve ioop seals in order to prevent potential

water hammer .

I : ** * * Document Control Desk LR-N95196 -2 -Attachment

5 (cont'd) Final testing of the newly installed

drain lines was completed

on April 27, 1993. On October 19, 1994, in preparation

for the Salem Unit 2 eighth refueling

outage (2R8), valve 2PR66 was discovered

to be closed. Valve 2PR66 being left in the closed position prevented

drainage of the Power-Operated

Relief Valve (PORV) and Pressurizer

Safety Valve loop seal lines and established

the loop seals, thus defeating

the purpose of the design change. After valve 2PR66 was discovered

closed, the computer-based

Tagging Request and Inquiry System (TRIS) was checked to confirm the expected valve position.

The normal position for this valve is "open" in accordance

with TRIS. The exact time when valve 2PR66 was closed and why this occurred is indeterminate.

The most probable period when valve 2PR66 was manipulated

and left closed was determined

to be after flushing activities

were performed

as part of DCP testing. The DCP .included

verification

of the valve positions

during and at the end of the testing portion of the modification.

Valve 2PR66 was documented

to be open after the testing. Subsequent

to the testing, there was a final acceptance

walkdown of the system pr1or to turnover to Operations.

The DCP did not require a written component

list which documented

valve positions

during the walkdown.

As a result, valve 2PR66 was not verified to be open after the DCP, when the system was turned over to Operat.ions.

The Operations

DCP Coordinator

understood

that, in order to approve the design package turnover to Operations

for TRIS revision, it was only necessary

to verify that the component

change had been made in the computer database.

The Operations

DCP Coordinator

signed off the "Change Package Turnover to Operations" checklist

for DCP 2EC-3190, without ensuring that a temporary

valve position lineup (referred

to as an "auxiliary

lineup") had been or* would be performed

prior to returning

the

to power operation.

The Operations

DCP Coordinator

had not received any training related to expected roles and responsibilities

for providing

or receiving

the final component

configurations

after modification .

• Document Control Desk LR-N95196 -3 -Attachment

5 (cont'd) At the time of this event, there existed an excessive

TRIS backlog of 6000 changes waiting to be processed.

The Operations

Staff supervision

failed to take prompt action when the TRIS backlog became unmanageable.

TRIS database maintenance

received an inappropriately

low priority.

This was compounded

by the fact that the TRIS Coordinator

was assigned other collateral

duties. The TRIS Coordinator

did not create an auxiliary

lineup in accordance

with SC.OP-DD.ZZ-OD16, "TRIS Operations." Procedure

SC.OP-DD.ZZ-OD16

does not specify a time limit for performing

an auxiliary

lineup. However, an auxiliary

lineup was expected to have been performed

prior to declaring TRIS database complete. "RC-MECH-001" is a standard valve lineup used to restore affected systems to a ready condition

in preparation

for plant startup. The revision of SC.OP-DD.ZZ-OD16, in effect* at the time valve 2PR66 was added to the database, specified

that the auxiliary

lineup pe completed

and confirmed

in TRIS before the component

is added to its applicable

standard lineups. The auxiliary

lineup for valve 2PR66 was delayed and eventually

never performed.

As a result, valve 2PR66 was not added to the RC-MECH-001

lineup in a timely manner . ROOT CAUSE ASSESSMENT PSE&G has determined

that the root cause of this event was inadequate

commitment

to the DCP turnover process and TRIS maintenance

program by Operations

Management

as demonstrated

by the fallowing: . * 1. Operations

had less-than-adequate

turnover acceptance

of DCP's. Roles and responsibilities

were not clearly defined. Supervision

failed to communicate

expectations

effectively.

2. The Operations

department

allowed the TRIS database to become unmanageable.

The backlog was accepted.

The safety significance

of the backlog on system design and operability

was not adequately

evaluated .

• * Document Control Desk LR-N95196 -4 -CORRECTIVE

STEPS THAT HAVE BEEN TAKEN Attachment

5 (cont'd) The Operations

Department

reviewed TRIS database change requests initiated

from DCP 1 s completed

during the time period from the beginning

of 2R7 to the present. This review encompassed

485 DCP's which have gone to "Part A" closure since the beginning

of 2R7. Part A closure signifies

that the activity has been installed

and the DCP has been turned over to Operations.

PSE&G has evaluated

the elements of the DCP process which ensure that Operations

procedures

and the TRIS database are updated. This evaluation

has determined

that the process is adequate.

The TRIS backlog was reduced to zero in May of 1995. The backlog is being maintained

at zero. Operations

has assigned additional

personnel

as TRIS coordinators.

The Coordinators

are responsible

for all TRIS interfaces

including

procedure

SC.OP-DD.ZZ-OD16.

Operations

Senior Reactor Operators (SRO's) have been assigned ownership

of plant systems. The SRO interacts

with the project managers and System Managers associated

with the DCP from conception.

The SRO accepts responsibility

for system turnover *to Operations.

CORRECTIVE

STEPS TO BE TAKEN TO PREVENT RECURRENCE

Operations

procedure

SC.OP-DD.ZZ-OD16

is being revised. The revision will emphasize

Operations

management's

expectations

and incorporate

the auditing process for TRIS revision requests.

This will be completed

by December 1, 1995. DATE WHEN FULL COMPLIANCE

WILL BE ACHIEVED Valve 2PR66 was correctly

positioned

for existing plant conditions.

PSE&G has evaluated

the DCP process relative to accomplishing

appropriate

valve positioning

after modification

activities

are complete.

This evaluation

indicates

that the process is adequate.

• l , l . [